http://calcomenergy.com/site/california-goes-all-in-for-renewable-energy#When:23:18:00ZCalifornia Goes All In for Renewable Energy
California again demonstrates its energy leadership with the signing of Senate Bill 100 by Governor Jerry Brown. SB100 puts California on a path to use 100 percent clean electricity by 2045. The ambitious measure by the world’s fifth largest economy sets the stage for rapid innovation and expansion of the clean energy industry in California, already the largest market for solar in the U.S.
SB 100 also advances the state’s existing Renewables Portfolio Standard, which establishes how much of the electricity system should be powered from renewable energy resources, to 50 percent by 2025 and 60 percent by 2030.
California’s Clean Energy Leadership
Solar provides jobs, economic development and environmental benefits for all Californians. The state’s early leadership in renewable energy has led to the creation of a robust market for product innovation and large-scale development of renewable projects. Nearly 3,000 solar companies in the state employ more than 86,000 people, with nearly 830,000 installations to date, according to the Solar Energy Industries Association.
CalCom Energy is a proud part of that legacy as a developer of solar farms and energy projects for California agriculture and water districts. This month we celebrated a unique distinction among California solar companies – for the third straight year, we made the list of the Inc 5000, celebrating the fastest growing private companies in America. This year we came in #7 among California energy companies with a 638% growth rate.
We measure our growth not in percentage points but in the savings and sustainability benefits we help our customers achieve. They are the true leaders in energy innovation. By making the smart decision to go solar, our customers are saving money while creating a more resilient and sustainable food and water supply.
In signing SB100 into law, Gov. Brown acknowledged that there is still work to be done: “It’s not going to be easy and it will not be immediate, but it must be done,” Brown said.
We are proud to be part of California’s clean energy leadership – and excited for the new day ahead.
http://calcomenergy.com/site/darrigo-phase-4-time-lapse-video#When:22:33:00ZTracking a Solar Farm Installation with Time-Lapse
Windy conditions were no match for our tireless crew installing a 2.2 MW addition to the D’Arrigo Farms solar project. The system was installed in just under 13 weeks from first shovel to commissioning, a phenomenal turnaround for a project this size.
We set up a video camera to capture the entire installation in time-lapse. As you can see, there
is plenty of fog in Salinas Valley, but this system will function exceedingly well in sun, wind or fog, churning out an additional 1.8 MWh (AC) per year.
This was the fourth phase of D’Arrigo Farms’ solar installations – now totaling 5.5 MW for the
premier grower and shipper of fruits and vegetables in California.
The system features 6,614 Boviet Solar modules, 46 Huawei Inverters and a single-axis tracker from NEXTracker Inc., which enabled maximum installation flexibility and optimizes production. The existence of a wind farm on the same utility substation initially presented concerns about anti-islanding, but our Director of Engineering Tim McDuffie, P.E. used the opportunity to work with the utility team to perform a study proving that anti-islanding upgrades would not be necessary, saving the customer additional time and money.
http://calcomenergy.com/site/quantum-shift-five-habits-of-change-leaders#When:20:49:00Zby Dylan Dupre, President & CEO
Recently I took five days away from being CEO of CalCom Energy to attend Quantum Shift – an intense business conference hosted by KPMG at the University of Michigan’s Stephen M. Ross School of Business. Quantum Shift participants are CEOs from around the country selected after a rigorous application process – and they represent 40 of the fastest growing companies in the U.S.
One of the Ross School’s founding principles is that business can be an extraordinary vehicle for positive change. With growth comes change. And so, more than anything else, the Quantum Shift Network is about change, and the people who lead it. So here are my top takeaways – which I’ll call the top five habits of Change Leaders:
“Business is the most powerful force on the planet for positive change.” SCOTT DERUE, EDWARD J. FREY DEAN, STEPHEN M. ROSS PROFESSOR OF BUSINESS
#1: Drive vs. Experience Change.
Anticipating change is never easy. But we all know that change is constant. In the solar industry, we are well accustomed to the “solar coaster”–that up-and-down economic cycle controlled by policy changes, shifting incentives, and the threat of tariffs. I was reminded at Quantum Shift of the need to stay above the fray and drive our business in a strategic direction regardless of short-term inflection points.
At CalCom, we recently made the strategic decision to change our name from CalCom Solar to CalCom Energy to reflect our belief that the industry is expanding. No matter where the solar coaster takes us, the world is changing the way it’s powered, and the clean energy revolution is here to stay. We are committed to driving this change rather than waiting for it to happen.
#2: Advocate for your customers to find innovation.
Innovation is hard. That’s why so many businesses avoid it. But here’s my secret to discovering your path to innovation: It’s about the customer experience. If you’re truly advocating for your customers’ needs, you will have no problem identifying where innovation is needed most.
When we listen to our customers at CalCom—some of the biggest companies in California agriculture– we hear their frustrations over energy costs, water supply, and the always looming threat of drought. We understand their profit margins are getting narrower as operating costs increase. We know that any energy solution we propose must reduce costs in a practical, “real-world” way while providing our customers with the operational flexibility they seek. We are working with our customers to reduce energy consumption and help them understand patterns so they can manage their energy spend smarter and more cost effectively.
This is innovation drawn directly from customer experience and advocacy.
#3: Surround yourself with your opposite.
We all do it – hire people who are exactly like us. But really, we should be doing the opposite. Not every employee is an innovator. Managers are good at managing. Salespeople want to sell. I’m a firm believer in letting everyone do their best at what they love to do. If you surround yourself with your opposite, you’re bound to run into some conflict. But a little healthy conflict is good for business and provides well-rounded perspective to fill in our blind spots.
#4: Say it in two sentences.
I call this the “head nod test.” When you describe your latest idea or innovation, do people start nodding their heads or do they give you a blank stare? If you can’t explain your idea or innovation in two sentences, it probably doesn’t make sense. Pay attention to how people respond to your ideas–ask questions, probe their concerns, and find out what’s underneath. You’ll probably find that you can improve upon your idea without giving up your central thesis.
#5: Innovate from the Outside In.
Sometimes you have to step away from your organization—if only for a few days—to see where innovation is needed. When I took the reins at CalCom Solar, I knew we were capable of great things. CalCom was already known for building some of the most innovative solar energy systems in the agriculture industry. I wanted to expand that vision to help farms become more sustainable, as well as work with water agencies and utilities.
Today, four years later, I’m proud of our achievements – our tremendous growth, being recognized by Quantum Shift and as well as the Inc 500. But more than that, I’m proud of our team’s passion for clean energy, innovation, and our ability to drive change.
The future will be more resilient, less reliant on fossil fuels, and more sustainable for our kids because of the work we do every day with customers who are leading the way. This is our true achievement.
http://calcomenergy.com/site/how-public-agencies-can-monetize-solar-and-storage-incentives#When:13:00:00ZGovernment Entities Can Take Advantage of Valuable Programs to Build Solar And Energy Storage. Here’s How.
Solar and energy storage are appealing to public agencies for a number of reasons. Advanced energy systems enable water districts, schools and other government entities to save taxpayers’ money while achieving sustainability goals. Unfortunately, public sector customers are not allowed to take advantage of the federal Investment Tax Credit that makes renewable energy a great value for so many commercial businesses.
The good news is public customers can optimize their solar or energy storage investment through several key programs and financing options.
Self-Generation Incentive Program (SGIP)
The most recent addition to California’s renewable energy incentive programs is the Self-Generation Incentive Program (SGIP). This program enables public entities to install advanced energy systems like energy storage on the customer side of the meter and receive significant rebates.
Battery storage is particularly helpful for reducing high demand charges by storing energy and discharging it when energy use is highest. Storage also helps with the shift to time-of-use rates as customers can store the electricity they generate on site when rates are low and consume the energy later in the day when rates are higher.
For public entities serving low-income communities in California, the SGIP Equity Budget creates an additional incentive to install solar + energy storage. The Equity Budget allocates 25% of SGIP funds for customer-sited energy storage projects in disadvantaged areas.
The SGIP budget steps down after each allotment is met, so it pays to act fast to receive maximum rebates.
Power Purchase Agreements
One of the best ways a public agency can monetize tax benefits is through a power purchase agreement (PPA). With a PPA, your facility acts as a host for a PV system, and a third-party financier (like CalCom) passes on a portion of the tax savings in the form of reduced, long-term electricity rates. PPAs are great for water districts and schools because they require no upfront capital investment, and no maintenance of the system since it’s owned by the financier. You get a guaranteed low rate of clean energy for 15-20 years, and usually a buy-out option around year six.
Renewable Energy Self-Generation Bill Credit Transfer (RES-BCT)
Another way public entities can squeeze the most value out of a solar project in California is to utilize the Renewable Energy Self-Generation Bill Credit Transfer (RES-BCT) program. RES-BCT allows a local government with one or more eligible renewable generating facilities to export energy to the grid and receive generation credits to benefitting accounts of the same local government—defined as any city, county, special district, or other public agency.
One of the hardest acronyms in the business (just think “Respect” and you’ll remember it!), RES-BCT is incredibly valuable for public sector customers because it enables them to optimize savings from solar across remote locations as long as they’re in the same city or county.
NEM and NEMA
Net Energy Metering (NEM) is the basic building block of the solar industry in California – and likely will be for several years to come. NEM enables customers to earn the full retail value of the clean energy they produce on site by crediting their utility bill for any excess energy. While this can get complex, CalCom has a top-notch team of utility bill analysts that work with every customer to ensure they’re getting the full value of their energy credited on their bill every month.
Next Step? Free Energy Assessment
To find out which program is right for your water district, school or public agency, contact us.
http://calcomenergy.com/site/why-not-to-wait-for-solar#When:13:00:00ZThe Time is Ripe for Agribusinesses and Public Agencies to Go Solar
The solar industry has been growing at a blistering pace over the last 10 years, leading to a record-breaking installation rate across the country – from homes to businesses to solar for agriculture and public agencies. More than 2,000 farms in California rely on on-site solar generation – more than any other state, according to the USDA’s most recent report – although other states are catching up fast.
“Solar farms” have sprouted up across the country as thousands of landowners, dairies, ranches and agricultural processors have chosen to add solar to unused land – saving operational costs and generating additional revenue. Public-sector agencies like water districts – swimming in fiscal challenges from California’s water crisis – have found solar’s predictable, long-term energy cost equally attractive.
But over the last six months or so, clouds have begun to appear on the solar horizon. With recently imposed tariffs on imported solar panels and cells, as well as the expected sunset of the solar Investment Tax Credit (ITC), many have begun to ask, does it still make sense for your farm, agribusiness or water agency to install solar?
The answer, unequivocally, is yes. Now is a better time than ever before to go solar. Here’s why:
Solar Prices: How Low Can They Go?
The cost of installing solar has plummeted nearly 70% since 2010, according to SEIA. Most of this price decrease has come from solar hardware, such as solar panels and inverters. The cost of solar will continue to decline with technology innovations and installation efficiencies. But as time goes on, the tariffs will have some effect on panel pricing. The time to lock in low solar pricing with maximum incentives is now.
The Solar Investment Tax Credit (ITC) is stepping down – but not yet. So act fast.
Time is the tyrant to take full advantage of tax incentives. For years, the federal government’s ITC has provided a boost to the industry as homes and businesses could get up to 30% of their installation costs back in a dollar-for-dollar a tax credit. In 2015, SEIA lobbied hard to get the ITC extended, but the credit is still expected to sunset over the next three years, providing 26% in 2020 and 22 percent in 2021. After 2021, the residential credit will disappear while the commercial and utility credit will drop to 10% “permanently.”
No Tax Appetite? No worries! But other solar incentives are time-sensitive too.
Even if you can’t take advantage of the tax incentives, there are other ways to gain maximum cost benefits from solar energy. For example, public agencies can monetize tax benefits through a power purchase agreement (PPA), in which a third-party financier passes down a portion of the tax savings in the form of a long-term price guarantee.
Another way public agencies can squeeze the most value out of a solar project in California is to utilize the Renewable Energy Self-Generation Bill Credit Transfer (RES-BCT) program. RES-BCT allows a local government with one or more eligible renewable generating facilities to export energy to the grid and receive generation credits to benefitting accounts of the same local government—defined as any city, county, special district, or other public agency. The benefiting account may be at remote locations within the same city or county, which helps these entities optimize savings from solar across their districts.
Local utilities must install a certain amount of MWs of RES-BCT projects. So again, the sooner you act, the more likely you are to benefit from this program.
Next Step? Free Energy Assessment
To find out how much you could be saving with solar, drop us a line. CalCom has been installing large-scale solar projects in California since 2013 and our specialty is finding the right solution for each customer’s needs. We’ll analyze your energy use and provide a free assessment of how your business or public agency can generate the most value from solar.
As California continues to lead the nation in solar installations, the CalCom Solar team has found our conversations in the agribusiness and water sectors shifting to the next phase of energy efficiency and cost savings: battery storage.
In this post, we will discuss the growing use of battery technology, also known as an Energy Storage System (ESS), as part of new or existing solar installations, how the technology can save your business or public agency real dollars, and how best to fund a new project or retrofit with an ESS (including taking advantage of all eligible incentives and rebates).
Understanding Demand Charges
The driving force for ESS installations is utility demand charges. Demand charges are typically based on the highest average electricity usage within a defined time interval (usually 15 minutes) during your billing period. This demand charge rate is the ‘high water mark’ grid demand in a given month and establishes your demand charge rate for the entire month. So, turning on heavy machinery or HVAC even for 15 minutes can increase your demand charge for the whole month. These demand charges often represent a whopping 30%–70% of a commercial electric bill. (NREL)
Why Battery Storage + Solar Works for Agriculture and Water Districts
When an ESS is installed alongside a PV system as part of a behind-the-meter installation, your system has the ability to respond quickly and deliver power when needed most. This is how the battery typically provides the most value—through demand charge management and demand response. In short, when your facility has a spike in demand (aka the ‘high water mark’), either through increased energy use such as seasonal activities like harvesting or processing, or an uptick in water needs, for example, strategically deployed energy via an ESS can lower this demand charge, producing potentially thousands of dollars in savings.
The chart below, created by the Clean Energy Group, a nonprofit research firm, explains how peak demand charges can be mitigated using ESS.
The benefits of ESS go beyond just extra savings. An ESS can help provide the energy your agribusiness or water agency relies on through both resiliency and by minimizing dependence on the grid – which as we’ve seen in California can be susceptible to outages, downtime for grid maintenance, and inclement weather. If your business or agency needs to have uninterrupted power for activities such as refrigeration, time-sensitive distribution, or even safety compliance – an ESS can help ensure these activities continue during outages, ensuring your revenue stream or delivery of services.
Financing Options for Your Energy Storage System
Whether you purchase your ESS or decide to take advantage of a lease or power purchase agreement (PPA), there are a number of financing opportunities that can make an ESS system work for your business or agency.
Most notably, California recently reopened its Self-Generation Incentive Program (SGIP). This rebate program can offset the cost of installing an ESS with your solar array. The SGIP program provides a cash rebate equal to approximately 35% of the battery costs, whether it’s on a new solar + storage project or an existing solar array. Even better, with funds offered through the SGIP Equity Budget, local government agencies, educational institutions, non-profits, and small businesses in qualifying areas are eligible to take advantage of the rebate.
The SGIP can be utilized along with a number of other eligible incentives and rebates. This includes the ITC 30% tax credit (and 5 accelerated MACRS schedule). With a combination of these incentives and rebates, an agribusiness or water agency could see assistance of 10-15 cents on the dollar, easily amounting to many thousands of dollars on a large ESS.
Though some of these rebate applications can be time-consuming, CalCom Solar’s experts will work directly with you to ensure you take advantage of all eligible incentives and maximize the ROI of your project.
Finding the Right Energy Solution For You
When you are ready to talk battery storage, CalCom Solar has the knowledge and experience to assess its potential for your particular needs. As the #1 commercial solar installer in PG&E’s service area, we have established a track record of high ROI installations by an understanding of our customers’ needs and deploying the right technology solution for each situation.
CalCom Solar prides itself on its high performing solar energy systems, and this level of commitment applies to ESS installations as well. As our CEO Dylan Dupre shared in a letter to customers in October of last year, integrating storage with a solar PV system can create immediate savings, and can give you peace of mind that your operations are not prone to demand spike charges or grid outages.
CalCom Solar’s commitment to our customers will give you confidence that all stages of your ESS and solar PV integration journey will exceed your expectations - from planning to installation, to proactively monitoring of your system using our VistaWatt System.
To find out how your agribusiness or water district can maximize your energy savings with an EES, contact email@example.com.
http://calcomenergy.com/site/calcom-solar-ranks-1-in-commercial-solar-installations-for-pge#When:14:00:00ZLeading the Solar Charge for Agriculture
The rankings are in—and CalCom Solar is proud to claim the #1 spot for commercial solar installations for customers in PG&E’s service area, the largest in the state. The company was ranked #7 overall for solar installations among more than 1,200 solar installers who do business in California, according to the California Solar Energy Industries Association (CALSEIA).
CEO Dylan Dupre credits his team for their hard work installing more than 50 MW of large-scale solar farms and projects for agricultural businesses in 2017. “CalCom Solar has achieved this level of success with a solution-oriented approach. Rather than reacting to the small problems, we respond with process solutions, so that interconnection issues are solved at a high-level. We actively seek opportunities to work proactively with customers, utilities, advocacy groups, and public utilities commission. This approach ultimately benefits our customers, CalCom Solar, and the industry,” stated Dylan Dupre.
The market for solar has boomed over the last several years, bolstered by a 55% decrease in solar prices over the last five years, according to SEIA. But 2017 was a rocky year as the national climate for solar policy created confusion in the market. The Section 201 Trade Case loomed over the industry for much of 2017, tightening the supply of modules. CalCom Solar weathered the storm with an unwavering commitment to the industry – and long-term supplier relationships that kept projects on track.
http://calcomenergy.com/site/three-ways-solar-can-reduce-the-energy-density-of-agricultural-crops#When:14:00:00ZA growing number of agricultural companies are starting to consider the nexus of water, energy and food in how they run their operations – not just for environmental reasons, but because it makes good business sense.
Every farmer intuitively understands the relationship between water, energy and food. Crop production is highly dependent on the right amount of water. Irrigation is highly reliant on energy. And energy is an increasingly expensive commodity that affects both water and food. Like any commodity, energy must be managed.
Every step of the food supply chain is powered by energy. The goal of any agricultural company is to increase yield while decreasing cost. One of the chief ways to do this is by implementing a smart energy management strategy to lower the energy density of your crop.
Precision farming plus solar and storage can play a pivotal role in a farm’s smart energy management strategy to help reduce operating costs and improve the bottom line while ensuring more sustainable farming practice—and a more sustainable future.
Let’s look at the ways a farm today uses energy – and how those costs can be managed.
At every step of the food supply chain (from “field to fork,” as some like to say), energy is being consumed. Energy density is a helpful measure we use with our agriculture customers to determine how efficient their production is from an energy standpoint.
A smart energy management solution takes into account:
how much energy is used to pump water to grow crops
how much energy is used to harvest and process crops
the seasonality of your crop and market demands driving your success.
Energy Use #1: Irrigation
Irrigating crops is one of the most energy-intensive stages of the food supply chain. Having an accurate measure of crop irrigation is indispensable for planning and budgeting purposes. But electricity costs for pump irrigation vary from season to season, and even by the time of day. How can you know if you are irrigating crops on an optimal schedule that keeps costs as low as possible?
The first step is to measure how much energy you’re using.
We aggregate the energy load data on every irrigation meter and then take it one step further – by analyzing that data against the utility rate tariffs in your area for that time of year, and specific times of the day.
The end result is an irrigation strategy that takes into account energy costs as well as seasonal load requirements to ensure optimal yield at the lowest possible cost.
Energy Use #2: Harvesting and Processing
No matter what crop you’re growing, harvest takes energy. And not just human energy – although that is substantial. Today’s crop processing facilities invest in technology and automation to increase efficiencies and ensure the freshest product. From automated sorting and packing systems to high-volume bagging and boxing machines, these systems rely on increasing amounts of energy.
Crain Walnut Processing is one of the largest growers and processors of English Walnuts in California and has been involved in the industry for over 50 years. The Crain family’s commitment to state-of-the-art processing and packing facilities requires a growing reliance on energy – which is offset by 3MW of solar power for their Red Bluff, CA facility. For all its efforts in sustainability, CWS has achieved accreditation as a Non-GMO Verified and Sustainably Grown Certified facility.
During harvest, many facilities operate 24/7. By combining a PV system with battery storage, processing facilities shave peak demand charges from a utility bill, further reducing the energy density of the crop.
Energy Use #3: Seasonal Freshness and the Cold Chain
Critical to the success of a season’s crop is the storage of the product through the distribution chain. While the electricity loads of cold storage facilities are substantial, the good news is that this is one the easiest links in the cold chain to offset with renewable energy.
Since 1918, Moonlight Companies have delivered the finest fruits from California’s heartland to customers around the globe. Moonlight has struck a fine balance between environmentally responsible farming practices, dedication to a safe working environment for their people, and ongoing investments in the latest technologies that return ROI. These elements, which are fundamental to a triple bottom line approach, allow Moonlight to give the consumer the freshest, juiciest fruits delivered at the peak of ripeness. The solar power system installed at Moonlight uses the latest solar PV technology, and it saves the company an estimated $300,000 per year, which will continue for the next 25 years – not to mention the avoidance of thousands of metric tons in carbon dioxide emissions over the system’s life.
Solar: A Smart-Energy Solution
A smart energy management system incorporating solar can help your operation drastically reduce the energy density of your crop – while maintaining a sharp focus on yields. In our next post, we will discuss how CalCom Solar is helping its customers further reduce energy density with battery storage systems.
http://calcomenergy.com/site/growing-a-solar-harvest-monterey-countys-largest-solar-project-gets-bigger#When:14:00:00ZThis week, CalCom announced an exciting addition to Monterey County’s largest privately owned solar project for D’Arrigo Bros. of California, a premier grower, packer and shipper of quality fruits and vegetables based in Salinas. D’Arrigo is adding another 1.1 megawatts (MW) to the project to their Gonzales site, bringing the company’s total solar capacity to 3.3 MW.
A fourth phase adding another 2.2 MW of solar power is expected to come online in the 1st half of 2018, and when CalCom Solar completes the project, a grand total of 5.5 MW will power D’Arrigo’s substantial cold storage and fruit processing operations.
D’Arrigo has made a commitment to sustainability that includes increasing amounts of renewable energy, said John D’Arrigo, President/CEO and Chairman of the Board of D’Arrigo Bros. of California.
“We’ve always championed sustainability as a core business practice and it is gratifying to see the fruits of our labor to operate our business on clean energy. We run on solar not only because of its sustainability benefits, which are significant, but because solar energy is fundamentally a smart business decision,” said D’Arrigo.
In addition to significant financial savings, the supplemental 1.1 MW will also help reduce CO2 emissions. Over 25 years, the system will offset carbon emissions equivalent to removing 8,750 cars from the road and 132 million pounds of coal burned. The solar power will directly generate energy to reduce 14 ranch meters within a 1.25-mile radius.
Distributors of the popular Andy Boy brand of Broccoli Rabe, D’Arrigo Bros were one of the first farms to ship fresh fruits and vegetables from California to New York. The solar PV system they’ve built over the past few years is yet another demonstration of their leadership in an industry where freshness is paramount and energy costs are at an all-time high.
CalCom Solar works with agricultural operators throughout California to reduce their energy costs through solar PV installations that optimize available land and rooftops. Though a Power Purchase Agreement, an agribusiness can go solar with little to no upfront costs, drastically reducing their cost of energy. Growers who wish to purchase the solar equipment outright can benefit from a 30% federal tax credit.
http://calcomenergy.com/site/happy-holidays-from-calcom-solar#When:14:00:00ZTop 5 Reasons to be Optimistic in 2018
CalCom Solar has had a great year and we wish you all the best for a happy, healthy 2018. With all the challenges in our industry this year, we felt it was a good time to take stock of all the reasons to be optimistic about clean energy in 2018!
The US installed more than 2 gigawatts (GW) of solar in Q3 2017 despite pricing and policy uncertainty – showing the market will be resilient no matter what decisions come down the pike with the Section 201 case.
Commercial and industrial installations of solar grew a whopping 22 percent year over year – signs that solar is expanding into every segment of our populace.
California has had an amazing year in solar – more than 100MW of new solar capacity installed in Q3 alone – and emerging markets like Texas and Florida posted more than 100MW in Q3 as well.
CalCom Solar has its best year ever – and installed 30 MW in 2017 for farms and agricultural businesses this year. Next year promises to be even better!
We will expand our services to new states and even a new country in the coming year. Watch this space for a very exciting announcement in Q1!!
We are grateful to be working in the best industry there is. And we are especially grateful for our customers – the dedicated farmers and agricultural businesses who supply our country with fresh, healthy food all year long. Your leadership and innovation never cease to amaze us.
We look forward to serving you and continuing to be your clean energy partner in 2018.
Until then, have a safe and happy holiday season!
http://calcomenergy.com/site/is-your-solar-investment-doing-its-job#When:14:00:00ZSolar projects are long-term investments and, like all investments, you need a reliable way to measure them. Owners and investors of solar projects for agriculture and water districts understand that after the last panel goes in and the system is commissioned, the first question is always this:
Is our PV system performing as it should be?
At CalCom Solar, our philosophy is simple. We recognize our customers want to maximize the performance of their energy assets and have confidence in their expected return on investment. We partner with our customers to operate and maintain the performance of their solar energy assets. If any issues arise, we have systems in place, experienced operators and the track record of success to proactively monitor your investment and determine the best course of action to quickly diagnose and resolve issues before they become a liability.
Predictable ROI for 25 Years – and Beyond
If you’ve invested in a solar energy system, you need to have a strategy in place to make sure your system keeps doing what it’s supposed to do for 25 years and beyond. Unlike other solar companies our size, we invest in both the systems AND the people to ensure this kind of performance. Our dedicated team of asset managers and project analysts are constantly watching your systems to provide actionable analytics for you and your team.
Calcom Solar takes a holistic approach to solar asset management – with constant monitoring of both the performance and the savings your system is producing. Our Remote Operations Center keeps tabs on your system with two-way communications that allow for remote fixes. We actively try to avoid truck-rolls to reduce costs and liability. We work as partners to our customers, assisting them to make the most cost-effective decisions for their systems.
Managing Solar for Ag and Water Transparently
At CalCom Solar, we are constantly assessing the potential consequences of any component malfunction so that if it happens we can advise our customers honestly about the best way to handle the issue.
Utilizing extensive data analytics and remote monitoring, we can tell our customers what the impact of any downtime will be. We base our recommendations on your system to determine the cost of any loss in production compared to the cost to address the issue. For example, a 1.1MW system is estimated to produce 2,190,291 kWhs in the first year. A soiled panel typically costs $158 per day in lost power production. If you pay $2,000 for panel washing, that investment will pay off in two weeks.
We even know what the potential losses are in summer vs. winter. If your string inverter goes down, that’ll cost you $25/day in the winter, $45-50/day in the summer. This tells the customer if they should wait for a vendor to fix an issue or if it’s worth investing in a time and materials warranty with us to address issues more quickly.
We believe in sharing this information with our customers transparently, so they can make informed decisions about their solar asset. At the end of the day, solar projects are like any other mechanical device that needs to be actively managed. We manage our customer’s solar asset as if it’s money in the bank. Because as long as the sun continues to shine, that’s exactly what it is.
http://calcomenergy.com/site/calcom-solar-saves-california-agricultural-customers-thousands-on-net-metering-bills#When:14:00:00ZAggregated Net Metering Bills Got You Down?
Do you have a stack of utility bills cluttering your desk right now? Going solar saves agribusinesses thousands of dollars in energy costs every year. But too many times companies leave sizeable sums on the table by not understanding their utility’s net energy metering aggregation (NEMA) bills.
Aggregated net metering in California has been an advantage to farms, water districts, and other landowners who want to go solar because it enables them to share bill credits across meters on different contiguous properties. But tracking the billing of these systems can be so complex that it requires the services of full-time accountant just to ensure you’re getting the proper bill credits.
We know you have better things to do than auditing utility bills – so we do it for you! We saw early on the challenges NEMA billing presented to customers, and began building our own data analysis team to address the problem.
We want to make sure you’re getting every penny of savings you deserve by going solar. In 2017 alone, CalCom Solar helped customers find an additional $585,000 in overpayments and overbillings. While savings vary by customer, we recently discovered a utility bill error that saved one of our customers $60,000.
Using your CalCom Solar vistawatt™ dashboard, you can see how much energy your company has used, how much solar you produced, and how much you saved. But that’s not all.
Here are five key pieces of information you’ll get from vistawatt™:
How much energy use did we offset with solar?
How much of the energy offset was direct vs. allocated?
How much did solar reduce our energy bill?
Did our utility bill us/credit us correctly?
Are our meters on the optimal utility rates?
In addition to helping you understand your utility bills, CalCom Solar’s Energy Bill Analytics Services (EBAS) team has developed a deep understanding of utility bill rate structures. We understand the nitty gritty of demand charges and time-of-use charges. We can help maximize your savings through rate schedule optimization and shifts in usage behavior to avoid peak demand charges.
Just one more way CalCom Solar is working for you to harvest the awesome power of the sun.
You can access your vistawatt™ system here. To learn more about vistawatt™ and find new ways to maximize your energy savings, contact us at firstname.lastname@example.org
http://calcomenergy.com/site/maximizing-solar-savings-with-energy-storage-systems#When:13:00:00ZOne of the most frequent questions I get from customers is about the potential of battery storage systems to maximize savings from a solar project. I thought I would provide an example of how an energy storage system (ESS) can help optimize your savings from solar.
Electricity bills are made up mainly of two key components: energy charges and demand charges. Energy charges are determined by applying a $/kWh rate to every unit of energy consumed from the grid and recorded by your utility meter during a billing period. Demand charges, by contrast, measure your ‘high water mark’ grid demand in a given month, so turning on heavy machinery or HVAC even for 15 minutes can increase your demand charge for the whole month.
Over the past 10 years, demand charges have been rising faster than energy charges, with an annual increase of 3%-10%. Demand charges typically make up 30%-50% of our customers’ utility bills.
An integrated solar PV system and energy storage system (EES) can maximize total utility bill savings – both energy charges and demand charges. California’s recently reopened Self Generation Incentive Program (SGIP) helps customers install ESS and save on their energy bills. The SGIP program will provide a cash rebate equal to ~35% of the battery costs, along with the availability of a 30% tax credit and 5 accelerated MACRS schedule. Your net is probably 10 – 15 cents on the dollar with over 80% returned in tax benefits and rebates. SGIP incentives can amount to hundreds of thousands of dollars on a large ESS.
CalCom is a leader in integrating energy storage with PV to maximize savings for our customers. We have industry expertise and partnerships with leading suppliers to design and install an ESS that will reduce your demand charges, complementing savings from your PV system to maximize your total energy savings.
Storage will also play a key role in helping you prepare for future changes to utility time-of-use rates, as well as further increases to demand charges. If you’re ready to move forward with a PV System and ESS, CalCom Solar will prepare an SGIP application on your behalf. If awarded the rebate money, there are several steps to meeting SGIP requirements and claiming your incentive; CalCom Solar will assist you throughout this process.
To find out how your farm, water district or other California business can maximize your solar savings with an EES, feel free to contact email@example.com
Dylan Dupre, CEO CalCom Solar
http://calcomenergy.com/site/finding-your-passion-how-a-small-solar-business-became-an-inc.-5000-leader#When:13:00:00ZIn August 2017, CalCom Solar was named to the top 25 of the Inc. 5000 for the second year in a row. Dylan Dupre, CEO of Calcom Solar, shares lessons learned along the way to building a renewable energy company with a 9,675% growth rate.
Much has been written about following your passion. The idea that passion and purpose – not circumstance, not background, and certainly not money – can drive a person to succeed in life seems intuitive. But it’s surprising how few people put this theory into practice.
In that sense, I’m one of the lucky ones. I decided to follow my passion into the clean energy space not long after graduating from UC Berkeley. I knew I wanted to be involved in an industry that I was passionate about and that was doing good for the planet. I had traveled the world enough to see that sustainable development and renewable energy had the potential to improve the lives of millions of people suffering from pollution, poverty, hunger and lack of access to fresh water.
When I got home from my travels, I got a job at a solar energy company. It was an ideal opportunity to see a solar company grow from the ground up – and I learned a lot about how homeowners and businesses make the decision to go solar. I worked at SPG Solar for 10 years – eventually rising through the ranks of residential and commercial sales to become VP of Sales.
Farming the Sun With Solar Energy
In November 2014, I made the decision to work for CalCom Solar based in the Central Valley of California, to focus on a segment of the market I had learned desperately needed renewable energy solutions: the agriculture industry. I saw an inextricable link between agriculture, water and energy—and an increasing reliance of farmers on fossil fuel energy to grow our food.
This hasn’t always been the case. Before the industrial revolution, farmers relied on a sole energy source to grow food – the sun. Photosynthesis was the mechanism that grew plants, and plants fed livestock, creating fertilizer that further promoted plant growth.
Of course, photosynthesis still works today – we haven’t gotten so mechanized that plants grow themselves. But now, farmers rely on energy to fuel every other part of the food production process—from irrigation pumps to farm equipment to food processing and machine automation.
CalCom was founded to address the growing industrialization of agriculture – by providing energy solutions that harvest the sun to more sustainably power a farm’s electricity needs. In so doing, we are transforming the way we produce our food and building a more sustainable future. We’re enabling our customers to turn a liability – energy expenses – into a capital asset that generates savings and incremental revenue for years to come
Building a Triple Bottom Line Future
Sustainable development and renewable energy are good for the planet, good for people, and good for business. This is the triple bottom line – people, planet, and profits. Many companies are adopting the TBL approach to more fully measure their performance. Public companies like GE, Proctor & Gamble and 3M now report on all aspects of the TBL–from environmental to social to economic—and are saving money and operating more sustainably at the same time.
At CalCom, this is our purpose: saving our customers money by enabling them to operate sustainably. And that passion and purpose inform every decision we make as a company.
In It’s Not What You Sell: It’s What You Stand For, author and branding expert Roy Spence says, “Purpose doesn’t make decisions easy, it makes them clear.” When your organization’s purpose is clearly understood, it’s easier to make a choice between one direction and another.
Many leading companies today are making the decision to build a cleaner, brighter future by going solar. Target, Walmart, and Apple – three of the top corporate users of solar – are teaching the rest of corporate America that sustainability can be a core element of a brand’s purpose. Today, 2 percent of the U.S. population shops at a solar-powered Walmart – a company whose purpose, by the way, is not to make money, but to
Having a purpose-driven business isn’t the entire reason we rose to the top of the Inc 5000. Hiring good people and putting them in positions to succeed is another. As former Apple CEO Steve Jobs famously said: “it doesn’t make sense to hire smart people and tell them what to do; we hire smart people so they can tell us what to do.” We work hard to create the right kind of culture – where talented people are empowered to find intelligent energy solutions.
We’re also on the front lines of technology – and seek the best innovations to solve our customers’ problems. Calcom was one of the first solar energy providers to capitalize on Net Energy Metering Aggregation (NEMA), generating millions in additional savings compared to non-NEMA projects, and is now quickly moving into solar + storage energy solutions to help our customers save money on demand charges and optimize energy use with load shifting and variable operating costs.
At the end of the day, our decision to focus relentlessly on our customers – and help them power their operations with clean energy—is the reason we’ve continued to thrive. We are proud to have made the top 25 of the Inc 5000 two years in a row, but awards and accolades aren’t the fuel that fires a business. For us, that’s the sun. And it’s not going away any time soon.
What is causing interconnection delays for solar EPC firms in California and what can industry stakeholders do to fix the problem?
Thanks in large part to the recent influx of solar distributed energy resource (DER) generation, the California utility grid is becoming saturated much faster than anyone ever expected. Saturation in this context refers to the maximum solar capacity beyond which the electric power system becomes unstable, which varies circuit by circuit and also has holistic implications at the system level. Investor-owned utilities (IOUs) currently lack many of the data sets and analytical tools needed to properly assess the impact of DER saturation. As a result, many projects are languishing in a seemingly endless cycle of interconnection review studies and grid upgrades. In this article, I explore how we got here, illustrate some of the interconnection challenges and consider some potential remedies.
In spite of the recent rise of DER generation—which includes demand management as well as distributed energy storage and variable renewable resources—the basic architecture of California’s electric power system remains much the same today as it was 100 years ago: a relatively small number of centralized generation sources push power out to electric consumers across a vast long-distance network of high-voltage transmission lines and medium-voltage distribution lines.
How Did We Get Here?
Though this system has served California fine to date, it is not particularly well suited to meeting the state’s future needs, which are changing due to shifts in environmental and energy policies. More Than Smart is a nonprofit organization whose mission is to help policymakers and industry stakeholders transition to a 21st-century electric power system. The authors of its report “A Framework to Make the Distribution Grid More Open, Efficient and Resilient” (see Resources) note: “There is a recognition that California is at a crossroads with respect to the future role of the electric system generally and the distribution system specifically.”
The rise of virtual net metering. With the implementation of net energy metering (NEM) and California’s Rule 21, which details interconnection, operating and metering requirements for DER projects, the state’s IOUs enabled customers to generate renewable power for use in offsetting a specific load. The interconnection method used to apply for the NEM tariff was typically a line- or load-side tap, landing behind an existing meter. In general, this interconnection did not create a problem for the local utility system because the customers consumed most, if not all, of the generation at the source, and backfeed across the point of interconnection was minimal.
However, in 2014, the advent of net-energy metering aggregation (NEMA) changed the dynamic because it permitted load offset using virtual net metering. Generation customers can now create power anywhere on their property and export it directly back to the electric grid. The utility then nets that generation against their aggregated electrical consumption over one or more meters. The customer pays the difference or, in the instance of a surplus, receives a credit to offset future consumption.
On paper, this seems straightforward, and it has allowed customers to install larger solar projects to offset multiple meters. The problem this creates for IOUs is that, while the load is virtually offset, they must study a stand-alone generation system as an exporting facility. While the rules on how the utility compensates the customer differ from those for a traditional exporting facility, the overall impact on the utility distribution system is the same as if the facility were an export project.
In addition, the advent of NEMA promoted the use of the NEM tariff on a much broader scale than previously anticipated. The benefits of net metering are no longer limited to small roof-mounted residential systems; the door is now open for much larger ground-mounted projects all the way up to 1 MWac to interconnect under the NEM tariff. As shown in Figure 1, the rate of nonresidential NEM interconnections across all IOUs has grown 246% since 2014.
Integrating increasing amounts of DER generation is an inherently challenging project. The authors of the Electric Power Research Institute (EPRI) report “The Integrated Grid: A Benefit-Cost Framework” (see Resources), note: “The question is about the ways in which DER interacts with the power system infrastructure. The formula for this answer has multiple dimensions. Beneficial and adverse circumstances can arise at differing levels of DER saturation. The interaction is dependent on the specific characteristics of the distribution circuits (design and equipment), existing loads, the time variation of loads and generation, environmental conditions, and other local factors. Benefits and costs must be characterized at the local level and the aggregated level of the overall power grid.”
With this in mind, we have to expect long interconnection timelines with large non-NEMA projects, as reliability engineers must extensively model the impact these systems have on the electric power system. However, very large PV systems can connect directly into the transmission system, bypassing the distribution system altogether. Though NEM and NEMA projects initially experienced shorter engineering review timelines, these projects are now hitting a wall in areas where IOUs deem the existing utility infrastructure inadequate to support additional DER generation.
In effect, a large portion of the electric power system is not designed for back feeding from the distribution systems into the transmission level. The antiquated protective devices at the substation and transmission level are designed for power flowing to the distribution system, not from it. As a result, increasing numbers of relatively small DER projects fail to pass the Rule 21 fast-track interconnection review process, and then they must undergo detailed studies with significantly longer timelines.
During a recent distribution-level substation walkthrough, I had an experience that offered a microcosm of the situation we are in. The purpose of the visit was to help a client understand the IOU’s proposed upgrades related to direct transfer trip (DTT), a protection scheme that manages unintentional islanding—and that can do so faster and more reliably than the anti-islanding protections in an inverter. (Islanding refers to a situation where an inverter-based distributed generator continues to energize a power-system circuit.) The utility’s protection engineers were concerned that an additional 1 MW of distributed generation (DG) could back feed the substation and support an unintentional island.
During this walkthrough, the person charged with managing the substation on a day-to-day basis pointed to a voltage regulator and said: “That’s going to be a problem.” This statement confused all of us until the substation manager explained that the voltage regulator had been installed 70 years ago. This meant it had analog controls, which could not accept the digital commands that utility operators need to send to a voltage regulator to enable DTT. Admittedly, I initially thought the substation manager was exaggerating the age of the equipment, but when we walked over to the voltage regulator, he pointed out the year printed on the nameplate: 1946.
Though it is just one piece of hardware, this voltage regulator is emblematic of the challenges associated with transitioning a 20th-century power system into a 21st-century infrastructure. Some of the technology that the utility employs, while perfectly functional, is antiquated. When the utility installed that voltage regulator back in 1946, nobody could have dreamed that a solar power plant would necessitate its replacement in 2016. This single voltage regulator serves hundreds, if not thousands, of customers. Taking it offline, while manageable, requires a substantial amount of coordination within the utility system to ensure no loss of service. The system operator will need to take lines out of service, reroute feeders and so forth. There is no room for error in a system where reliability is of the utmost importance. To manage these risks, the utility typically conducts these change-outs when the load is at a minimum so the potential impact is as low as possible, which in this case is between the months of November and February.
In this particular case, the IOU conducted a detailed study related to the proposed project in March 2016 per Rule 21. Since the IOU identified the need for specific substation upgrades, we requested that the utility place the project in the 2016–17 upgrade window. However, projects in the queue from the previous year had reserved all of the spots in this year’s upgrade window. As a result, the upgrades required to interconnect this project will have to wait until the 2017–18 upgrade window.
This sort of delay stacking is directly due to DER saturation, and antiquated equipment compounds the problem. Had there been enough load to offset the combined generation, the vintage voltage regulator could have gone right on functioning into perpetuity. Instead, what would normally have been an interconnection process of 3–6 months became a project of 18–24 months. It is important to keep in mind that we are not talking about a 50 MW utility-scale project, but rather a NEMA project with a generating capacity of less than 1 MW.
These timelines impact system owners by delaying their ability to realize returns on their investment. Without these returns, loan terms are subject to higher rates and the financial viability of a project drops significantly. As a result, many owners choose to walk away from projects rather than wait out a substation upgrade, which has a crippling financial impact on the solar industry in California and severely slows down DER interconnection.
Amanda Johnson is the utility interconnection manager at JKB Energy, a solar integration firm specializing in commercial and agricultural solar projects in California’s Central Valley. Johnson has firsthand experience with interconnection delays. “Many of our customers are subject to substation upgrade requirements when building solar projects that are close to the upper end of the 1 MW limit for a NEM or NEMA project,” she says, “despite the fact that these customers pull the same amount of energy from the grid throughout the year.” Whenever this happens, interconnection timelines increase to allow for the necessary engineering reviews and equipment upgrades.
According to Brad Heavner, CALSEIA’s policy director: “Trend lines for large and small systems have been moving in opposite directions. While the California IOUs have done a great job of automating the interconnection process for standard rooftop systems, new roadblocks keep emerging for large systems. We used to hear complaints about 4-month delays turning into 9-month delays, but we are now hearing about 2-year delays.”
Part of what makes these scenarios so commonplace is an outdated way of approaching distribution network design and upgrades. Utilities can no longer stop at the transmission level in envisioning the utility grid as a network. For elevated levels of DER penetration to become sustainable, the network platform mentality must percolate down to the distribution level.
Think of the transmission system as a freeway designed for one-way traffic flow, where substations are off-ramps to the smaller feeder roads that represent the distribution system. With the rise of DER generation on these distribution circuits, traffic suddenly wants to flow back onto the freeway. This two-way traffic flow disrupts the system, causing congestion as well as reliability and safety concerns. To mitigate these problems, the system operator must begin an extensive infrastructure upgrade process to convert each of these off-ramps into combination on- and off-ramps. The process is costly and time-consuming; we have all experienced how freeway upgrades tend to make traffic worse before it gets better.
This is analogous to the interconnection challenges in California today, with one big traffic jam of DER generation projects all trying to get on the same freeway at the same time. This situation leads to frustrated customers and impatient solar companies. It is unfair, however, to place the blame for the problem on the IOUs. Increased participation in the NEMA tariff program has resulted in an ever-increasing number of applications to interconnect. Compounding the problem, the amount of DER generation simply overwhelms the existing distribution system. When I asked CALSEIA’s Heavner which specific area seems to be the most congested, he responded: “California.”
Fresno County, a major hub in PG&E’s utility system, is a good case study for this phenomenon. As shown in Figure 2, Fresno County is a hotbed for nonresidential solar interconnections.
The rate of interconnection for nonresidential NEM projects in Fresno County has grown more than 250% since 2014. Current interconnection processes cannot keep pace with the upgrades required to interconnect these projects in a relatively short time frame. This is simply a case of too much solar, too soon.
While California’s environmental and energy policies envision integrating more than 15 GW of DER generation into the state’s electric power system, these projections may underestimate the grid transformation that is underway. Because of the scale and the capital-intensive nature of the grid investment required to meet these goals, stakeholders must plan and invest wisely. The More Than Smart report elaborates: “As distribution infrastructure is largely depreciated over several decades, investments in this decade may need to be useful to 2040. The implication for California is that the current annual utility distribution investment of nearly $6 billion is effectively a 25-plus year bet on a future [that] will likely be quite different than we can imagine today.”
Creating a sustainable 21st-century grid requires mixing and matching new data with emerging technologies. While many potential solutions are on the horizon, there is no silver bullet. The end solution will probably come from all of the stakeholders, each working to solve small pieces of the overall puzzle. When used in conjunction with rapidly advancing smart grid communications, this combined contribution will have a substantial impact on the overall problem of excessive DER congestion.
Better modeling can generate the data needed to identify weaker areas of the utility grid and incentivize solar DER development in the appropriate areas. R&D roadmaps should include allocations to understand new phenomena such as islanding, and IOUs and regulators should implement solutions to these problems in a reasonable and targeted manner. Smart inverters have the potential to provide the level of control that IOUs require to curtail and prevent overgeneration. Energy storage systems can provide customers with an unprecedented ability to control when and how their systems produce energy.
Given the scale of the existing power system and the investment necessary for its modernization, the authors of the More Than Smart report argue that distribution planners should start by evaluating the existing system and developing a baseline model of its capabilities. Once this exercise is complete, distribution planners and reliability engineers can stress-test this baseline model against a set of future scenarios. By identifying capability gaps in this manner, stakeholders can determine the grid upgrades that provide the best return on investment.
The More Than Smart report explains: “Analysis today requires both the traditional power engineering analysis, as well as an assessment of the random variability and power, flows across a distribution system. Such an analysis would include real and reactive power flows under a variety of planned and unplanned situations across a distribution system, not just a single feeder. Evolution to a more network-centric model for a distribution system to enable bidirectional power flow underscores the need for a fundamental shift in planning analysis.”
To facilitate this shift, California Assembly Bill 327 calls on IOUs to develop distribution resource plans that identify optimal locations for DER deployment, as well as ways to optimize the value of these resources. As part of these efforts, IOUs and other stakeholders are participating in working groups, which More Than Smart is facilitating, to establish two new planning tools: locational net benefit analysis (LNBA) and integrated capacity analysis (ICA).
Laura Wang, project director for More Than Smart, explains: “We envision that the IOUs will use both tools [LNBA and ICA] to meet the objective of Assembly Bill 327, which asks IOUs to determine optimal DER locations on their distribution systems. Developing these tools is expected to be an iterative process. IOUs will continue learning from the implementation process, the working group will refine the methodology as smart inverters become standard, and the [California Public Utilities Commission (CPUC)] makes a final decision on how these tools should be used.”
One challenge to overcome is that there is no consensus on when and how to compensate solar DER producers for avoided costs. According to a February 1, 2017, CPUC memo: “[The LNBA Working Group emphasizes] that the LNBA addresses the narrow question of evaluating DERs in single locations against certain distribution upgrades that are already in IOU distribution system plans, and should not be construed as the advancement of a comprehensive, location-specific utility avoided–cost calculator that could be used to proactively identify high-value locations for DER deployment.”
The ultimate goal of the LNBA is to identify the locational value of DER, ideally at a granular level based on a model of the entire electrical system. While a lot of work remains to be done, the LNBA tool will one day determine how DERs are compensated in California. Whereas IOUs can currently react to power quality issues only after they become a problem, the LNBA will eventually allow IOUs to identify problem areas in advance and promote specific DER functionality in certain markets by setting a premium price for these services.
The ICA, meanwhile, is unlike any utility analysis ever attempted and thus will undergo slow and methodical development. At the conclusion of this process, the ICA will provide each IOU with the ability to quickly study any part of its grid and will allow stakeholders to swiftly assess a proposed interconnection location. The first objective is to identify how much DER generation developers can add at any interconnection point on the distribution system. The second is to bring DER generation into utilities’ annual planning of the distribution system by identifying the best sites for future DER development.
These analyses represent a paradigm shift in the way IOUs view distributed generation, as they will transform solar DER projects from a liability to an asset on heavily congested portions of the utility grid. The LNBA will ultimately determine future NEM rates. The ICA will transform a reactive interconnection process—wherein developers are subject to the long review timelines in the Rule 21 tariff—into a proactive process. Gone will be the days of waiting for months only to find out that your proposed system location is on the worst possible distribution line in an IOU’s service territory.
IOUs need to devote greater resources to understanding new problems that arise from expanded transmission network penetration. One example of a relatively new, and often misunderstood, the problem is islanding. With the implementation of UL 1741, which requires all certified inverters to shut down within 2 seconds of grid de-energization, reliability engineers generally agree that there is no need to worry about an island forming and continuing in perpetuity. What is less clear is the extent to which they need to worry about the impacts of a temporary short-duration island.
Overcurrent protective devices manage fault conditions by sensing when a sharp surge in current hits a circuit over a brief period. The problem is that if a fault occurs during a temporary island, the circuit has already been interrupted; therefore, there is no device available to clear the excess current. While a few extra seconds of inverter operation might not seem like a long time, it is more than enough time to generate overcurrent conditions that could damage electrical equipment and negatively affect power quality.
The safety and reliability tests in Screen P of the Rule 21 engineering review analyze the potential for temporary islanding. (See “Rule 21 Engineering Review Process,” pp. 32–33.) These tests are relevant to the interconnection discussion because many projects that fail Screen P face longer interconnection timelines. This is so the IOUs can design and implement DTT, SCADA visibility reclosers or other mitigation techniques to negate the threat of extended run-ons at the substation or transmission network level. The issue of temporary islanding begs further analysis. We need to understand not only the conditions required for a temporary island to occur but also the potential implications.
In an August 2016 project report for the California Solar Initiative (see Resources), General Electric Energy Consulting recommends five updates to the PG&E interconnection process:
To date, PG&E has only implemented items 4 and 5 at any level. This situation highlights a larger problem: IOUs are mandating major upgrades based on an incomplete understanding of new phenomena. In addition, the IOUs mandate these upgrades with no oversight from the CPUC. For its part, the CPUC has no technical personnel on staff and therefore lacks the resources to adequately assess and review such issues.
In initial review: Raise the screening limit from 15% peak load to 60% of the estimated simultaneous load; the estimated simultaneous load will be based on conversion factors as was defined and implemented in Task 2 Report: Statistical Analysis of PV Generation and Load Balance.
In supplemental review: Keep the existing minimum daytime load screen when SCADA data is available, and allow 80% of the estimated simultaneous load by maintaining the power factor of the section below 0.98 inductive.
In detailed review: Allow up to 105% of simultaneous load by detuning circuits to maintain the power factor between 0.95 and 0.98 inductive, to address islanding concerns if needed.
In protection requirements: Modify the Direct Transfer Trip exemption bulletin to enable the quick interconnection of certified inverters rated less than 1 MW if there are no significant machine-based generators on the island.
In protection requirements: Eliminate reclose blocking for all certified inverters by lengthening reclose time on high-penetration feeders to 10 seconds.
A California bill signed into law in September 2016 establishes an expedited review process for such circumstances that includes an independent engineering expert. However, the state legislature has not approved the funds needed to enact this bill, so the IOUs will continue to have unchecked power to implement such policies.
For their part, IOUs say that they make many of their policies, such as anti-islanding, with an abundance of caution. However, the CPUC should encourage IOUs to take a closer look and analyze whether their determinations are appropriate or whether they have gone overboard because they lack the data for an informed decision. In addition, the solar industry must request, encourage and support technical policy review when new data supports a revised approach.
Most UL 1741–certified inverters are capable of much more than just producing kilowatts. Technicians can program them to absorb or create reactive power and to play an active role in power-factor correction. In a more traditional sense, DER projects can also supplement existing power plants during periods of high demand. The missing piece of the puzzle in the current interconnection model is a lack of understanding as to where we need these services and under what circumstances we should implement them.
On utility-scale projects, dedicated substations provide a secure, reliable means for utility visibility, control and curtailment of PV systems. This is not the case on smaller DER systems because they typically do not connect through a substation. As a result, IOUs have no visibility into the quality or quantity of power those DER systems are producing. At a basic level, an IOU cannot even confirm whether the system is producing power at all. Smart inverters can help bridge the gap and allow IOUs some basic functional control of and visibility into DER systems.
Seizing on this opportunity, in 2013 the CPUC, IOUs, and solar industry stakeholders convened a working group to explore the role that smart inverters can play in easing grid congestion. In a June 2016 Solar Builder article (see Resources), Brian Lydic, senior standards and technology engineer at Fronius USA, explains: “Seeing the need for not only frequency tolerance but grid-supportive functions in general, the California Public Utilities Commission and the California Energy Commission convened the Smart Inverter Working Group (SIWG) in early 2013 to start developing recommendations of technical requirements for inverter-based DER in California.”
A recent result of the SIWG is the implementation of UL 1741 Supplement A (SA). This supplement is a step toward allowing IOUs the visibility and control they need to handle high levels of DER penetration. Beginning on September 8, 2017, all California IOUs will require the design of new Rule 21 solar applications around inverters certified to UL 1741 SA. This supplement specifies an enhanced testing protocol that UL describes as an “advanced inverter grid support utility-interactive test plan” that addresses anti-islanding (with advanced features active during test), low- and high-voltage ride through, low- and high-frequency ride through, a must-trip test, ramp rate (normal and soft start), specified power factor, volt and VAR modes, and optional tests including frequency watt and volt watt. These functions have the potential to turn highly congested areas of DER from a burden to a blessing.
Additional controllability is theoretically a great asset in the context of managing overall grid congestion, but the reality is that changing operational parameters will result in lower returns on investment. The CPUC needs to explore how and when to compensate customers for grid support functionality. Lydic concludes, “In general, any of these changes will allow for higher-penetration levels and thus benefit the PV industry, but care must be taken that revenues are not unduly affected.”
Security is another area of concern, especially with regard to communication and control protocols. Tying inverters or any portion of a DER system into the utility SCADA system immediately opens a channel for hacking and potential security breaches. A safe, reliable communication system can help mitigate these risks. Any smart inverter certification program must specify a simple, widely implementable communication protocol. Ideally, the circumstances that activate grid-stability functions (and possibly reduce production) in San Diego will be the same as those in Sacramento. The CPUC should clearly define how IOUs exercise smart inverter functions and ensure consistent implementation of these standards throughout California.
Energy storage systems
As shown in Figure 3 (p. 30), increased solar generation capacity is changing California’s daily power production curve. A 2013 California Independent System Operator (CAISO) report first identified the duck curve. This term describes the shape of the daily power production curve due to periods of significantly lower electrical demand in the middle of the day followed by a steep ramp-up in the afternoon and early evening. This profile stands in stark contrast to the traditional two-peak bell curve model of power consumption, where power peaks during the midday hours, drops a little and then ramps back up during the early evening.
A side effect of identifying the duck curve is that IOUs are asking the CPUC for a change in the time of use (TOU) periods, allowing them to charge more for energy during the ramp-up period in the late afternoon rather than in the middle of the day. This change in TOU periods will result in a significant reduction in the value of power for NEM customers but will help IOUs reduce peak afternoon demand.
Energy storage is another way for utilities to flatten the duck curve. Storage can both pull up the trough of the curve (the duck’s back) and push down the peak of the curve (the duck’s tail). It is possible to deploy both large-scale and distributed-scale energy storage to address California’s duck curve. On a large scale, for example, the utility could divert excess solar generation into utility-scale energy storage systems at the substation or subtransmission level. These front-of-meter storage assets can reduce the overall impact of DER backfeeding onto the transmission network and allow IOUs to store reserves for use during the late afternoon or early evening ramp-up periods. A complementary option is to use smaller-scale energy storage systems at the customer level. Solar-plus-storage systems are a perfect fit for these behind-the-meter applications.
Advances in power system analyses, such as the ICA tool, are going to prove crucial for identifying the best areas in which to apply distributed energy storage resources. An IOU could install a large battery bank, for example, and then incentivize solar development in that area. Essentially, the IOU would be creating a giant energy storage reservoir and asking the solar industry to help fill it. The overall effect would be greater solar development and a smoother, more stable load profile, creating a win-win scenario for IOUs and solar developers alike.
No solar developer wants to tell customers that their small ground-mounted system could potentially have a 3-plus–year delay in interconnection. Sometimes this delay does not present itself until the developer is already 6 months into the process. Customers often do not understand or have the patience for such setbacks. However, areas of the distribution grid that were once prime DER locations have now become saturated, resulting in nightmare scenarios for developers and customers alike.
Johnson at JKB Energy shares an example: “Not only do many customers experience substation upgrade requirements, but also some have had to upgrade the same substation more than one time. On multiple occasions, existing customers have sought to install additional solar capacity on a distribution circuit they were already interconnected to only to face additional upgrades—in some cases, within 12 or 18 months of the previous substation upgrade.” She continues: “Instead of mandating that the IOUs anticipate future solar generation capacity, the CPUC requires prompt distribution upgrades based on the existing interconnection queue. The lack of pre-emptive upgrades on the utility substation infrastructure has caused significant impacts to customers’ bottom lines.”
Developers and EPC firms should do everything in their power to set reasonable and accurate interconnection timelines, which may mean informing customers that the path to interconnection could be a long and arduous journey. One useful tool in setting expectations is the revamped Rule 21 pre-application report. For a nominal fee, companies can get access to grid minimum loading data, utility equipment sizes, utility equipment ratings and other real-time site-specific utility data. With some technical understanding, they can use these data to identify distribution and service level upgrades prior to submitting an interconnection application. The data contained in the expanded pre-application can be crucial in the early determination of the overall interconnection cost and timeline.
Engagement. When I speak to colleagues, many of the same topics come up across the industry: new tracking technologies or magic widgets that boost production, innovative ideas on how to save a buck in wire management and so on. Many people simply do not understand that grid congestion is a major issue. What good does a fancy new tracking system with impeccably concealed wiring do if you cannot plug the project in?
To develop and advance solutions to California’s interconnection problems, we need more industry engagement. The more we debate, write about and analyze these obstacles, the faster we can overcome them. Companies that participate in the discussion have a distinct advantage because they will understand the coming changes. They can proactively develop the business mechanisms to get the most out of future innovations while everyone else is just playing catch-up.
Kenneth Sahm White is the economics and policy analysis director at the Clean Coalition, a nonprofit working to expedite the transition to a 21st-century energy system. White explains: “We are actively engaged in regulatory policy development through official proceedings and working groups related to procurement, interconnection, full valuation, planning, pilot programs, and development of markets, tariffs and compensation for the range of services that distributed energy resources can provide to customers, utilities, and transmission operators. We advocate for policies and programs that typically overlap with growth and cost reduction in all renewable energy industries.”
Groups such as the Clean Coalition and CALSEIA are instrumental in consolidating the solar industry’s concerns and presenting a clear and effective message to the appropriate parties at the CPUC or in the IOUs. These groups also provide training and discussion forums to develop proposals for policy changes that impact the entire industry. Heavner emphasizes the importance of working together as a unified industry via groups like CALSEIA: “We need everyone to join forces to take solar to the next level.”
Tim McDuffie / CalCom Solar / Visalia, CA / calcomsolar.com
Electric Power Research Institute, “The Integrated Grid: A Benefit-Cost Framework,” February 2015
General Electric Energy Consulting, “California Solar Initiative Final Project Report: Quantification of Risk of Unintentional Islanding and Re-Assessment of Interconnection Requirements in High Penetration of Customer-Sited PV Generation,” August 2016
Lydic, Brian, “How California’s Rule 21 Inverter Requirements Expand Grid Capacity and Limit Energy (Revenue) Generation,” Solar Builder, June 28, 2016
More Than Smart (previously the Greentech Leadership Group), “A Framework to Make the Distribution Grid More Open, Efficient and Resilient,” August 2014
CalCom Solar is excited to announce major progress with Southern California Edison’s (SCE) Net Energy Metering Aggregation (NEMA) billing.
Over the past year, CalCom Solar has been working with SCE to improve the transparency and timeliness of their NEMA billing. After months of advocating on behalf of our customers, CalCom Solar uncovered errors in SCE’s underlying NEMA billing calculations. As a result of these errors, some customers have been under-compensated for their solar generation. SCE has recognized the error, and we’re happy to report that SCE is now rolling out a fix and has committed to crediting impacted customers.
SCE NEMA customers should receive a letter from SCE in the next month explaining the issue, and SCE has committed to re-billing all current customers by the end of July 2017. Customers who already have NEMA solar systems installed and operational may receive additional credits if SCE’s incorrect billing methodology was under-valuing their solar energy.
Andrew Hoffman, CalCom Solar’s Senior Director of Strategy and Market Development, says this is “a game-changer for our SCE customers. SCE customers haven’t been getting the full value for their solar investments. We’re happy to report that SCE has committed to fixing these issues and improving the overall net energy metering experience for our customers moving forward.”
Current SCE NEMA customers can also request a credit hold on their account until SCE completes its re-billing process this summer. For new customers, SCE’s fix should be in place so customers receive correct bills from NEMA billing setup.
In response to the many questions and concerns we’ve received on behalf of our customers, CalCom Solar has launched a new billing analysis tool called vistawatt. Vistawatt clearly shows how much solar energy has been generated, and to which meters solar credits are being applied. Vistawatt also offers an in-depth look at how energy is being consumed at each meter, enabling the customer to make informed decisions about how to optimize energy usage and maximize solar savings.
CalCom Solar is extremely proud of all the hard work it has done on these issues and is excited about this progress on behalf of our customers. CalCom Solar remains committed to working with SCE, PG&E, and the CPUC on behalf of our customers and the California solar industry.
For more information on vistawatt or how we can help with your NET Metering bills call 559.667.9200 or request a demo online at www.calcomsolar.com.
http://calcomenergy.com/site/webinar-solar-field-of-dreams-tracking-your-solar-om-investment#When:13:00:00ZTitle: Solar Field of Dreams: Tracking your Solar O&M Investment
Date: Tuesday, March 21, 2017
Time: 2 PM Eastern Daylight Time / 11 AM Pacific Daylight Time
Duration: 1 hour
Join Jason Smith, President and COO of CalCom Solar, and other #solar industry leaders as they discuss how to maximize returns on your investment in solar energy.
More solar systems were installed worldwide in 2016 than any year to date, and the vast majority of these systems were ground-mount, utility-scale—a trend that is expected to continue for several years. As the solar market matures, developers and system owners are realizing that long-term, operations and maintenance issues can have a profound effect on a project’s financial performance. Savvy investors know that to ensure optimal returns, O&M considerations for all system components must be evaluated as part of a project’s overall economics -well before breaking ground on any project. Horizontal, single-axis trackers (SATs) are now the leading choice among trackers since they can deliver 20-30% more energy without the added cost and complexities of dual-axis tracking or azimuth systems. But many developers have concerns about the presumed costs of maintaining SAT systems. For instance,
1. Do the O&M expenses of SATs nullify their incremental energy performance?
2. Do SATs achieve a lower levelized cost of energy (LCOE) overall?
3. Will parts be available for the life of my project?
4. Will my (SAT) partner be viable in the future?
5. Will my O&M practice and cost change over time?
These questions and more will be answered by industry leaders whose experience spans California’s farmlands, Brazil’s first and largest solar power plant (Pirapora), and some of the largest U.S. utility-scale solar projects. Marty Rogers of NEXTracker will center this discussion around the O&M cost considerations of decentralized over centralized single-axis trackers.
Vice President of Global Asset Management and Support,
President and COO,
Vice President, Renewable Energy,
McCarthy Building Companies
Principal and Executive Consultant,
http://calcomenergy.com/site/nem-2.0-changes-and-2016#When:13:00:00ZAs you consider installing or adding on to your solar system, we want to keep you up to date on the latest developments on Net Energy Metering (NEM) and NEM 2.0. The state first set up NEM to help customers save money with solar back in the early 2000’s. The program established a cap on the total amount of solar that could be installed with each utility under the NEM system.
PG&E is projected to reach its cap in Fall 2016. SCE solar growth has been slower, so they aren’t likely to hit the cap until Summer 2017. Once the utilities hit their caps, any solar array that goes into operation will have slightly different provisions under a new program called NEM 2.0.
NEM 2.0 is not very different from the original NEM and maintains the key provisions that make solar work for Ag:
You can still aggregate the load of multiple meters behind one solar array (called NEM Aggregation, or NEMA)
The reconciliation process for billing (called a true-up) is still on an annual basis, so solar can still offset your costs even if you have seasonal operations
The new tariff still pays back solar generation at the full retail rate of electricity instead of a lower wholesale or generation rate
You maintain 20 year certainty (‘grandfathering’) under the NEM 2.0 program, just as under the original NEM
There are also some changes under NEM 2.0 – some good and some not-so-good:
GOOD: There is no longer a system size cap of 1 MW, so if your load is large enough for a bigger system then that will be allowed. Systems that are larger than 1 MW may incur additional fees, however, so it may still make sense to cap your system at 1 MW. CalCom Solar can help you evaluate the options and make the best decision.
NOT-SO-GOOD: The utilities will be adding some new charges to NEM 2.0 customers. The charges are called nonbypassable charges (NBCs), and they cover things like energy efficiency and nuclear decommissioning costs. The new fees amount to about ~$0.02 / kWh and apply to all net load pulled through the meter. The more load your solar system offsets on the meter it’s connected to, the less this will impact you.
NOT-SO-GOOD: There are also some new fees for application and interconnection, but they’re pretty manageable (only $200-300 per solar system).
GOOD: We can help optimize your installation to minimize interconnection and NBC costs, while also ensuring the system is ideally located for your operations.
As you sort through the NEM 2.0 changes, feel free to reach out to us with any questions. CalCom will help you navigate the new program to ensure that you get the best payback for your solar system.
One final note: We’ve heard some misinformation recently about what’s needed to secure NEM versus NEM 2.0. Some companies are promising to secure NEM 1 before a solar system is even built, which is incorrect. We can help you walk through the requirements and timelines. Or click here to review PG&E’s web page about them.
http://calcomenergy.com/site/calcom-solar-moving-to-new-larger-facility#When:13:00:00ZDue to record growth and increasing capabilities, CalCom Solar is moving into a new, larger facility at the end of April, 2016. Our new address will be:
635 S. Atwood Street
Visalia, CA 93277
The 6,500 square foot space will provide enhanced capabilities for our customers, including 3 conference rooms and four - 50” television monitors mounted for individual or collaborative use by Operations & Maintenance Monitoring. In addition, a 36-seat training room will allow CalCom Solar to host seminars and training for customers and employees.
To accommodate our current year-to-year growth, the new location is able to house twice as many employees as our current space. A 25-unit cubicle system provides team members with greater privacy while still maintaining a team work environment. Nine 9 private offices—all with white boards walls—also provide plenty of space for confidential meetings with clients.
http://calcomenergy.com/site/net-energy-metering-extension-for-solar-is-great-for-ag-operations#When:14:00:00ZThe California Public Utility Commission (CPUC) formally signed the December 15, 2015 draft NEM decision at their January 28, 2016 Voting Meeting, extending the positive aspects of Net Energy Metering to new solar energy customers. This is great news for Ag operations in California!
“We are pleased with where things ended up on NEM,” said Andrew Hoffman, Senior Director of Strategy & Market Development. “The PUC is making a statement that distributed generation is an important piece of our energy and environmental future in California.”
One of the most important aspects about the approved program is the continuation of Net Energy Metering Aggregation (NEMA). This is a huge plus for agricultural customers.
With the extension of NEMA, growers, cold storage facilities, processors, packagers, water districts, etc. will continue to be able to deploy a single, centralized solar array for multiple service points. The bottom line impact is higher solar ROI. This is due to lower initial capital costs and greater flexibility in shifting offsets to respond to crop rotations, seasonal flucations in usage at different service points, changing irrigation patterns, etc.
http://calcomenergy.com/site/regulatory-relief-for-solar-customers-thanks-to-calcom-solar-efforts#When:14:00:00ZEliminating Red Tape is a Fundamental Part of CalCom Solar’s Customer Service Ethic
CalCom Solar was recently able to achieve regulatory relief for California solar customers. Thanks to our efforts, PG&E agreed in January 2016 to change its interconnection requirements for commercial and industrial distribution generation (DG) systems sized between 40kW and 1MW. The new policy will cut solar deployment costs significantly for CalCom Solar customers—as well as for other solar installations throughout California.
Previously, PG&E had an expensive and outdated requirement for the addition of SCADA reclosers to solar arrays built in their service area. A recloser is a kind of circuit breaker that automatically “recloses” after it has been tripped. They’re used to detect and correct momentary interruptions. Since many short-circuits last only a second or so, a recloser improves service continuity by automatically restoring power to the line after a brief fault. However, these reclosers have added millions of dollars to interconnection costs for PG&E customers over the last several years. Further, solar customers with systems sized between 40kW and 1MW—which can be a common size system for Ag operations—bore the burden of these higher costs.
In order to eliminate this excessive expense for our customers, CalCom Solar invested time and effort in an extensive research project. Based on our findings, Calcom Solar was able to develop and present a winning case to PG&E. As a result, PG&E agreed to revise its DG protection requirements for systems sized between 40kW and 1MW. In effect, this revision will eliminate the need for costly SCADA reclosers (PG&E’s technical criterion has been updated to ‘other machine or uncertified DG (on the distribution line) >10% of project’).
Bottom line? For future solar array deployments, PG&E will now only require reclosers in special circumstances.
CalCom Solar has several existing projects which will benefit retroactively from this modification, saving our customers thousands and thousands of dollars.
This elimination of unnecessary regulation would not have succeeded without our deep expertise and commitment to maximum solar efficiency. We’re proud that our efforts will cut costs and speed solar interconnections—not just for the water districts, growers, cold storage facilities, processors, and packers who are our customers—but for solar customers throughout California.
http://calcomenergy.com/site/is-pge-boiling-the-frog#When:13:00:00ZEight PG&E “micro” rate changes in the past 27 months—a new one took effect this month—have pushed the Ag rate that affects most growers 13% higher. 2014 is starting much the way 2013 ended. Dry. Snowpack is currently 1/3 of normal in one of the largest water storage reservoirs in the US, the Sierra Nevada Mountains. With higher water delivery costs, reduced or eliminated surface deliveries, and increased groundwater pumping in 2014 and beyond, let’s examine how this is impacting agriculture energy use.
Is PG&E boiling the frog?
How do you boil a frog? If you put it into boiling water it will jump right out, but if you slowly increase the temperature the frog will stay in the pot till the bitter end. PG&E is the nation’s largest electric utility with as much as 20% of their electricity used to move water throughout the state of CA. Historically, PG&E would put in for massive rate increases every 2-3 years and then try to keep the frog in the pot.
PG&E offers 89 electrical rates to customers in CA. While this is confusing, the large majority of Ag customers are on an electricity rate called AG-5B. These customers have seen their rates increase 8 times in the last 27 months, for a total increase of 13%. That is one half of a percent per month. What does that mean financially? That same water that cost you $100 an acre-foot 2 years ago, will cost you $112 an acre for this year. Or looking at a farming operation with a $200k yearly electricity bill…they will pay $24k more for electricity than they did to start 2012. Small but measurable increases as the frog continues to slowly boil in more expensive water.
Energy is no longer the smallest expense in your operation
When I first started dealing with agriculture clients in CA, I was told that “energy was a distraction” or that it was “not worth the time.” This is simply no longer the case. For many operations, it is now the second largest expense, trailing physical assets expenses, but comfortably ahead of crop maintenance. Five years ago, electricity/energy was 5% or less of total cost to produce your yearly crop. With the rate increases, less surface water is available, a deeper water table/bigger wells, and a larger amount of permanent crops, it it is now making up 15% or more of the yearly total expenses.
Not all hope is lost.
Aggregated Net Metering (ANM) goes into effect in the first quarter of 2014 for electrical customers in the PG&E, SDG&E, and SCE territories and allows Ag customers to integrate power generation into their operation. Self-generating your own power was not always attractive to agriculture customers, but things have changed:
With ANM you can install one centrally-located power-producing asset (solar, wind, digester, etc.), at the location you choose and choose which electrical meters you want to offset each and every month. This means a 70% to 80% savings on your utility bill with a typical system payback of 4-6 years.
The utilities hate that you have this option, but they are required to offer it until it exceeds 5% of the electric utility’s aggregate demand. Considering that you can depreciate your own electrical system the same way as other equipment in your operation, and can offset 30% of the system costs through the Federal Investment Tax Credit (ITC)...you can see why more and more customers are making the move to generate their own power.
Nic Stover is CEO at CalCom Solar where he focuses on agriculture-specific energy issues throughout California. You can follow him on Twitter at @agenergyman or connect with him on @LinkedIn
http://calcomenergy.com/site/anm-nema-update#When:14:00:00ZOriginally implementation of Aggregated Net Metering (ANM), also known as Net Energy Metering Aggregation (NEMA), scheduled for mid February, but the PUC is working to resolve additional issues (protests) lodged by the public on the January 15 supplemental advice letters received from PG&E, SCE, and SDG&E. There are similarities among the companies in how they will institute ANM/NEMA, but also some key differences. We’ve created a ANM/NEMA FAQs page, but let’s review some of the details here.
PG&E has not directly stated their policy on how often they’ll allow users to switch between meters to be offset. SCG&E allows regular updates; SCE is more restrictive. The goal is to be able to choose which meters you offset on a regular basis, so that if you change from pumping surface water to a deep well motor, you can offset that meter right away. We will continue to monitor this.
Existing solar facilities can be rolled into ANM/NEMA – it’s not just for new generators.
New transformers and other upgrades might be needed to connect large new generating facilities to the utility, sometimes the upgrades are at the utilities’ own cost, but there may be delays for studies and construction.
Get into this queue sooner rather than later! Remember that the utilities are required to offer ANM/NEMA only until the total capacity of renewable energy generated exceeds 5% of their own aggregate demand. Between that and interconnection delays, the sooner you start to go solar, the sooner you’ll start to save money.
http://calcomenergy.com/site/understanding-electric-bills#When:14:00:00ZWhen you buy electricity, you’re charged by the kilowatt-hour (kWh). If you use 1000 watts for 1 hour, that’s a kilowatt-hour. Utilities also charge commercial and ag users a Demand Charge, which is based on the flow of electricity used during the single highest 15 minute period of a month.
Let’s go over some commonly used terms and see how they relate to your electric bill(s) and our photovoltaic systems. Photo (light) + voltaic (electricity): electricity produced from light. Often called PV, to save time.
Volt: electrically, voltage is the measure of the potential to do work, like water pressure in a garden hose.
Ampère, or Amp:amperage is the flow of electricity, like water flowing through a hose. So, the monthly Demand Charge is based on the maximum amperage required over any one 15-minute period. In the water hose metaphor, demand is a measure of how much the nozzle is opened and consequently how big the hose has to be to maintain pressure (voltage).
Watt: a measure of electrical power that equals volts times amps. In a water hose, a small flow at high pressure could have the same power as a larger flow at lower pressure. So, 10 amps at 480 volts = 4800 watts. Likewise, 20 amps at 240 volts = 4800 watts.
Watt-hour: a measure of energy that equals watts times time. Using the water analogy, energy would roughly equate to the amount of water moved over a given time period. You could use 100 watts for 2 hours for 200 watt-hours, or 200 watts for 1 hour for 200 watt-hours.
We install PV systems to offset the kilowatt-hours or megawatt-hours you use. Kilo means one thousand and is abbreviated as kW. So, 1000 watts is 1kW. One million watts is a megawatt (MW). Many growers can now use Aggregated Net Metering (ANM offsets multiple meters with one PV system) to offset up to a MW of electric usage.
We typically offset the costs of 95% of your electric usage with a properly sized PV system. The actual PV system size will vary depending not only on the size of the motors you’re offsetting, but the amount you use them. We use advanced Ag rate forecasting to determine what, exactly, offers you the best ROI.
http://calcomenergy.com/site/anm-nem-to-proceed#When:14:00:00ZIf you are an Ag operation with more than one meter, this is important news for you.
PG&E has offered California’s Solar industry – and our solar Ag clients – some great news, agreeing to comply with [the new net energy metering (NEM) legislation*] “because many potential customers have expressed an interest in the NEM Aggregation option and PG&E seeks an approved program as soon as possible”.
PG&E will set its billing service fees to a $500 cap, which translates to 20 accounts using a one time set up fee of $25 per account. This is great news as we can enroll all of your wells, boosters, ranch houses, shops, street lights, whatever and not have to worry about paying for each one.
It also clarifies which other meters can be included – those on “contiguous” parcels. PG&E has agreed to a fairly broad interpretation of that word, including parcels that are divided by a street, highway, or public thoroughfare provided they are within an unbroken chain of otherwise contiguous parcels that are all solely owned, leased or rented by the customer generator.
This allows growers to keep your best crop land producing. One centralized solar system will offset numerous meters from anywhere on the “contiguous” properties. Offset whatever meters you have on those contiguous lands. Offset a ranch house, a booster, and a deep well one month. Then the next month maybe offset just your deep wells. You get to pick which meter to offset. If water or crop patterns change, you can adjust which meters to offset. This allows you to take control of offsetting your most expensive power.
PG&E has also agreed to implement a 30 day “effective date” request, meaning that this tariff will be available as of February 15.
Utilities will be required to offer Aggregated Net Metering only until the total capacity of renewable energy generated exceeds 5% of the electric utility’s aggregate demand. In other words, this is a window of opportunity that is closing quickly, not a door left open indefinitely. The Federal Investment Tax Credit (ITC) is still available for renewable energy projects through the end of 2016.
*This law has gone by various names, so don’t be confused: Virtual Net Metering, Aggregated Net Metering, Net Energy Metering are all basically the same.
http://calcomenergy.com/site/solar-means-business#When:13:00:00Z32,800 US businesses have now installed solar PV systems, an increase of 40% from 2012. “Solar allows businesses of all sizes to lower their energy expenditures, improve their bottom line, and gain a competitive advantage,” according to a just published industry report, Solar Means Business. The report highlights Fortune 100 companies’ solar installations.
The report highlights top reasons well-run American businesses are turning to solar:
http://calcomenergy.com/site/agriculture-benefits-from-aggregated-net-metering#When:13:00:00ZFor agricultural businesses, controlling electric costs just became easier and less expensive. The California Public Utilities Commission (CPUC) has approved Aggregate Net Metering (ANM), which offers two new important provisions. First, individuals can choose the best location on their property to place a solar energy generation system, unrestricted by meter location. Second, this solar system can now offset multiple meters, not just one. One system can now offset your irrigation, residences, shop, or other parts of your operation.
Importantly, the solar generation system no longer needs to be at the meter site, which has long been a concern for growers worried about displacing valuable crops. The solar power system does need to be on the same or adjacent land as the meter(s), but that offers considerable flexibility to landowners and businesses.
Glenn Bland, CEO of CalCom Solar, and a Central Valley businessman since 1987, is excited by the potential.
“Solar costs have already dropped 60% since 2011. Now that our Ag clients can put in a larger central solar electricity system, it will further reduce both installation and maintenance costs. Businesses can also still leverage capital and tax incentives to lock in energy security over the next three decades. “
Meter Aggregation had been on hold pending the approval of Resolution 5-4610. Utilities were concerned that Aggregated Net Metering would increase the costs for non-participating electric consumers. But the CPUC found that,
“allowing eligible customer-generators to aggregate their load from multiple meters, pursuant to Senate Bill (SB) 594 will not result in an increase in the expected revenue obligations of customers who are not eligible customer-generators.”
Meter aggregation does not increase the NEM cap, which is presently set at 5% of an electric utility’s aggregate peak demand, but it will increase the speed at which that cap is used up by large customers installing solar or other renewables. Legislation also still caps each solar system at one megawatt (1 MW) of generated energy – which, typically, would offset numerous meters.
The electric utilities now have 14 days in which to file a Tier 2 Letter revising their NEM tariffs to enable meter aggregation.
http://calcomenergy.com/site/solar-industry-consolidation#When:13:00:00ZIndustry consolidation is part of growth. We’re suggesting you invest in solar installations, not solar manufacturers.
In the early 1900s, the auto industry had over 350 manufacturers. Now there are less than a dozen serious players.
The same thing is now driving solar: hundreds of manufacturers churned out solar panels for a relatively small market of buyers. Fierce competition in solar manufacturing has meant lower prices for consumers - solar panel prices have dropped 80% in the past few years - but has caused some manufacturers to fail and others to be bought out. That’s the beauty of the free market.
The solar industry is on solid ground. Germany, Japan, and China are massively investing in PV installations. California is required to meet 33% of its energy usage with renewables by 2020. The electric utilities have to partner with us to fill those quotas. This is the perfect time for you to invest – great Federal Investment Tax Credits available, support from the utilities, and low cost PV components.
And, because CalCom Solar buys only top quality, “Tier 1” solar panels and products, we offer excellent, long term warranties. Guaranteed.
http://calcomenergy.com/site/cleaning-solar-panels#When:13:00:00ZIs cleaning solar panels worth the time and effort? How much does dirt affect electric power generation?
A new study by UC San Diego reviewed solar panel efficiency during 2010’s 145 day drought here in California. The result? Less than a 0.05 percent efficiency loss per day for most residential systems – hardly enough to make cleaning worth it. Financial losses for larger commercial systems are greater, but not huge.
That said, we find it’s different for our ag clients – blowing dirt from tilling and harvesting can decrease panel efficiency by as much as 15-20%. It’s easy to know when that’s happening with our installations, as all offer daily (and hourly!) monitoring of electrical output. When you do see production decreasing, clean the panels.
There are two easy ways to do this. Some growers install simple sprinkler systems that can be activated as needed for a quick wash. Some just use a portable water tank to hose off the panels 1-2 times a year. Plain water is enough to clean the panels of basic dirt. Bird droppings may require a bit of a scrub – we recommend using NO soap (or, aluminum safe soap). Use a long handled, soft brush. NEVER climb up onto the array.
CalCom does the routine maintenance on your system the first year, and we also offer ongoing yearly contracts to clean your inverters and panels and check all connections.