As tempting as it may be for utilities to ignore the growth of distributed energy resources (DER), they must plan for integration of this form of generation. To help power providers develop a strategy to accommodate increasing DER penetration, Smart Electric Power Alliance (SEPA) has published a two-volume report, Beyond the Meter: Planning the Distributed Energy Future.
The utility industry is changing and many of the changes are being driven by consumers seeking new energy choices, technology advances leading to lower costs and better performance and new policies. Both utilities and their customers will have to work together to ensure grid reliability as distributed energy resource (DER) penetration increases. Engineering consultants Black and Veatch collaborated with SEPA to provide a new strategy to become a proactive distribution planning utility.
The UEF program committee asked utility and government representatives to weigh in on the topics they wanted to discuss in the exclusive session dedicated to those groups. Not surprisingly, the responses reflected California’s unique situation, even as they echoed the findings of the Utility Dive survey.
Energy storage The question that was No. 1 in the minds of survey respondents was, “What is the value of energy storage for customers, utilities and the grid?” It is not hard to connect the dots between energy storage and concerns about distributed energy policy and aging grid infrastructure that ranked high in the Utility Dive survey. But in California, a combination of legislative and market forces have made energy storage specifically a relevant topic.
Most people automatically think about battery systems when they hear energy storage, and six utilities in the state have already installed and are experimenting with that technology. However, thermal storage—using available renewable electricity to heat water or make ice for later use in heating or cooling—is a proven technology in use at eight California utilities. Pacific Gas and Electric has the state’s only pumped storage project, which uses renewable energy to pump water to a higher-altitude reservoir where it is released to generate hydropower when needed.
Utilities and battery manufacturers still have much to learn about storage batteries, from funding and installation to operation and maintenance to best uses for the systems. Riverside Public Utilities enlisted the University of California Riverside as a research partner to discover more about solar-plus-storage capabilities. Imperial Irrigation District installed 30 megawatts (MW) of storage last October. System operators find it valuable for balancing intermittent solar power during weekdays, but also note that it takes 220 tons of air conditioning to control battery temperatures. Maintaining constant battery temperature is crucial to extending the life of batteries. Tucson Electric Power (TEP) chose to lease 10 MW of storage from Next Era and Eon as a way of easing through the learning curve. The system supports 40 MW of solar and provides ancillary services for TEP.
So far, the business case for storage has yet to be made because utilities are still discovering the values associated with it. Also, each utility will have to learn how to maximize storage on its own system. Planning and rate design will play a critical role in unlocking the value of the technology. But utilities can’t afford to hang back, as big, energy-intensive businesses like data centers are already investigating going off-grid with their own solar-plus-storage systems. These customers may prove to be important partners for power providers seeking to meet storage mandates.
More to offer Stagnant load growth appeared in the Top 10 Utility Dive survey results, a harbinger of reduced revenues utilities can expect from distributed generation and storage technologies. California utilities seem to be ahead of the curve in this respect, interested in exploring new business models to grow services and build relationships. Many roundtable participants have begun to create programs and services that offer customers more than kilowatts.
A number of industry surveys indicate that most consumers still rely on their power providers to help them sort out claims about electrical products and services. Utilities can leverage this trust to get customers to take a holistic approach to energy use, installing weatherization and efficient appliances and systems before moving on to renewables.
The City of Palo Alto Utilities (CPAU), for example, offers comprehensive home audits and free concierge service that customers can call with any question about energy use. The service is just starting to take off as CPAU hones its message and outreach strategy. “Ongoing customer communication is critical, and not just for specific programs,” observed CPAU Key Account Manager Bryan Ward. “The issues are complex and education is tough, but the more customers understand, the more they can make good decisions for themselves.”
When the customer is ready to install a solar array, the utility has a vested interest in making sure the job is done right. Roseville Electric Utility’s Trusted Solar Advisor program has been highly successful in helping its customers make educated decisions about solar installations. The “Solar Guy,” Energy Program Technician David Dominguez, has even become something of a local celebrity. Roseville is considering expanding the program to other services, like electric vehicles and energy storage. The moral of Roseville’s story is that personalizing a program can take it to a whole new level.
EVs, rate design central to discussion Of course, you can’t have a discussion about new utility services without the subject of electric vehicle charging stations coming up. Roundtable participants represented a number of different approaches to this service. Burbank Water and Power installs level 1 (standard household) charger outlets on customers’ property and offers a rebate to customers to install a level 2 (240-volt) outlet.
CPAU facilitates permitting and filing for residential and commercial charger installation and for transformer upgrades. Multifamily units, nonprofits and schools are eligible for rebates for chargers, but high-tech businesses in CPAU’s territory didn’t need an incentive to install the technology. The important thing, most agreed, was that utilities need to be involved in pushing out EV chargers, both for the new revenue stream and to ensure effective deployment and implementation.
EVs and technologies like home automation—another behind-the-meter product utilities could offer—lend themselves to load shifting, especially in residential settings. To take full advantage of such demand response strategies, utilities will have to design rates that give customers a reason to participate. The Public Utility Commission of California has called for robust time-of-use rates, which would present utilities with another customer education challenge. Power providers will also want to make sure that vendors of behind-the-meter services are giving consumers honest and accurate information and appropriate support.
Energy efficiency ain’t easy The final roundtable issue was one that is relevant across the country, but again with special significance to California: What hurdles are you encountering integrating and managing more energy efficiency in your mix?
In addition to the state getting half of its electricity from green energy by 2030, California buildings must also increase energy efficiency by 50 percent. As any utility program manager can tell you, the more successful you are at reducing your customers’ energy use, the harder it is to find new savings. The overall trend toward higher efficiency standards for appliances and equipment, along with some of the toughest building codes in the U.S., is already making it more difficult to design effective efficiency programs.
Encouraging customers to make energy-efficiency improvements is further complicated by the fact that electricity rates may continue to rise anyway. Consumers don’t generally care about the intricacies of load resource balance or system optimization, issues that resist simple messaging. To make matters worse, third-party vendors rarely bother to explain to their customers how installing a measure will actually affect their home utility bills—if they, themselves, understand.
When the subject is energy efficiency, talk always circles back to flat and falling revenues, something affecting almost everyone on the panel. Sacramento Municipal Utility District attributes a noticeable decline in sales to building codes. EV charging and electric water heating could help to make up some load, especially since most water heaters in the state are still gas units. But CPAU found few takers for a pilot program offering customers a generous rebate to install electric heat pump water heaters.
Change still only constant There is still plenty of low-hanging efficiency fruit that utilities have not yet picked, though participants acknowledged that it may be getting more expensive to reach. The “free” electricity from a solar array is a lot more appealing to customers than elusive “savings” from an energy-efficient appliance. It is enough to make utilities wonder if the best days of energy-efficiency programs and incentives are behind them.
And yet, industry research shows a strong correlation between energy efficiency and customer satisfaction. Such programs give utilities a chance to interact with customers in a way they wouldn’t get to otherwise. Board members may continue to support a traditional program that does not contribute much to financial or operational goals because they see the public relations value of it. If utilities are going to phase out traditional energy-efficiency programs, they will need to find other ways keep customers engaged and happy.
The two hours scheduled for the UEF Pre-Forum Roundtable passed quickly and—spoiler alert—we did not resolve our most pressing issues. That is likely to take trial, error and perhaps an appetite for risk that is hard to square with our historic mission of reliability and affordability. But it did remind us that customer relationships must be viewed as part of the solution.
A leader in solar water heating programs is now adding 15 megawatts of photovoltaic energy to its electricity supply. Valley Electric Association (VEA) has constructed a 54,000-panel solar plant on 80 acres of desert near the California-Nevada border and plans to sell the power to members at a lower price than their current electric rates.
The community solar project located just north of Pahrump, Nevada, VEA’s home town, produces enough electricity to power 2,500 homes. The goal of the plant, according to VEA CEO Thomas H. Husted, is to give members more choice of energy resources.
Members were showing interest in solar but weren’t able to install their own arrays, said Kristin Mettke, VEA executive vice president of Engineering and Compliance. “Also, there aren’t many large solar contracting companies in our service area,” she said. “This project was a good way to offer solar to our members at an economy of scale.”
VEA plans to turn the project into a subscription program. For now, however, the clean electricity is helping the co-op meet its growing demand with a low-cost resource.
Partnering to protect wildlife Even projects intended to save money—and the environment—come with complications, however, and the community solar project was no different. The chosen site was home to sensitive plants and the threatened Mojave Desert tortoise, so accommodations had to be made.
VEA and solar contractor Bombard Renewable Energy worked with the U.S. Fish and Wildlife Service to develop a habitat conservation plan to minimize the disturbing effects of construction “It gave us the opportunity to try different approaches,” observed Mettke.
Measures included relocating tortoises to a temporary habitat before beginning construction and installing temporary fencing and tortoise-proof access gates to prevent them from returning. The completed project had a permanent security fence with tortoise access points to allow the animals to reenter the site.
To provide habitat for the tortoises, the native vegetation was mowed, crushed or trimmed, rather than removed. Increasing the height and spacing of the PV panels and installing them to follow the natural undulations of the land will also allow the vegetation to recover more quickly after construction.
Solar water heater pioneer The community solar project continues VEA’s tradition of using solar solutions to provide members with affordable power. In 2009, the co-op launched what was, at the time, the largest solar hot water program in the country.
For around $30 per month paid on-bill, members can install a Rheem solar water heating system. This highly efficient technology uses the sun’s heat to reduce the need for conventional hot water heating by as much as two-thirds. Members can save about $250 to $540 in annually and enjoy 50-100 percent greater hot water capacity.
With 835 systems installed to date, the program avoids more than 3,000 pounds of carbon dioxide emissions annually while building local workforce skills. VEA estimates that solar water heating will save members about $34 million over the next 20 years by decreasing peak power demands and delaying future upgrades to capital infrastructure.
Planning next steps Now that the solar project is completed, VEA has begun to talk with battery vendors about adding backup storage. “A battery system would complement solar power and help with resource adequacy and shoulder times,” said Mettke.
The co-op is also developing a subscription program that would allow members to lease panels. The program would be introduced through VEA Ambassadors, members who take an active interest in the day-to-day operations of their utility and who offer feedback on VEA initiatives, activities and policies from a consumer perspective. The Ambassadors were instrumental in rolling out VEA’s solar hot water program in 2009.
The solar hot water program and now the utility-scale community solar project have given VEA valuable hands-on experience developing and integrating renewable generation. That expertise may someday come in handy for developing cost-effective clean energy projects for California. The co-op became the first out-of-state utility to join the California Independent System Operator balancing authority in 2013, a move that could present such opportunities to VEA. It would be a challenge, but if it strengthens member relations and builds local workforce skills, Valley Electric Association is up to it.
The top five issues utilities identified as their biggest challenges will no doubt sound familiar to WAPA customers, whether or not they participated in the survey:
Physical and cyber security
Distributed energy policy
Rate design reform
Aging grid infrastructure
Reliable integration of renewables and distributed energy resources (DERs)
The results of the survey, disclosed in late March, found that 72 percent of respondents see physical and cyber security as either “important” or “very important” today, making it the industry’s most pressing issue in 2017. A total of 65 percent considered distributed resource policy either important or very important. Rate design reform ranked as important for 31 percent and very important for 32 percent of respondents. As for aging grid infrastructure, 34 percent of survey respondents see it as important today, while another 28 percent say it is very important. The reliable integration of renewables and DERs finished in the top five with 60 percent identifying it as an important or very important concern.
State regulatory model reform, the aging utility workforce, changing consumer preferences, compliance with state power mandates and stagnant load growth rounded out the top ten issue responses.
Two years ago, physical and cyber security ranked as sixth, behind aging infrastructure, aging workforce, current regulatory models, stagnant load growth and federal emissions standards.
More than 600 electric utility employees from the U.S. and Canada took online questionnaire, offered to Utility Dive readers in January. Investor-owned utilities represented 54 percent of the survey respondents, followed by municipal or public power utilities (32 percent) and electric cooperatives (14 percent).
Among other key takeaways in the 2017 report, the survey found that utilities are most confident in the growth of utility-scale solar, distributed energy resources, wind energy and natural gas generation over the next 10 years. They also expect coal generation to decline significantly, while nuclear generation will stagnate or retire, depending on the region. Utilities consider uncertainty over future energy policies and market conditions to be the most significant challenge associated with the changing power mix, according to the survey.
Region played a role in how utilities viewed challenges. The majority of respondents across the country identified physical and cyber security, DER policy and renewable energy and DER integration as serious issues. However, that concern was markedly stronger in the West Coast, Great Plains, Rocky Mountain and New England regions. Utility Dive noted that those regions feature states with both robust DER growth and utility reform dockets to reshape power sector business models for DER deployment.
Rate design reform and aging infrastructure were of greater concern on the West Coast, while utilities in the Southwest and South Central states were the least worried about those issues.
You can download the report for free and see how your responses stack up to those of your colleagues. Then, share your thoughts on these issues with Energy Services, let us know how you are handling them and how you would like us to help you address them.
Representatives from IID joined Coachella Energy Storage Partners (CESP), electric industry leaders and local and state officials, Oct. 26, to launch the 33-megawatt (MW), 20-megawatt-hour (MWh) system. IID installed the lithium-ion BESS to increase reliability while integrating renewable energy resources into the local grid. The storage system allows the utility to balance power, arrest frequency decay, provide spinning reserve, mitigate large fluctuations of energy, increase voltage stability and deliver “black start” power restoration capabilities for the nearby El Centro gas generation plant. A black start is the process of restoring an electric power station or a part of an electric grid to operation without relying on the external transmission network.
Integration poses challenges The dedication ceremony was the culmination of more than three years of assessment and planning.
Like many utilities, IID is feeling the pressure of increasing amounts of renewables on its electric system. Those pressures are likely to grow as the state pushes toward its goal of a 50-percent renewable energy supply by 2030, especially since IID is located in such a resource-rich area. IID’s grid already carries 900 MW of clean energy—mostly geothermal and solar—with another 1,200 MW of new generation seeking to interconnect to its system.
“Specifically, the integration of solar generation was affecting our balancing authority, and our control performance standard began to suffer,” said Jesse Montaño, IID manager of planning and engineering.
Battery storage was a cost-effective solution to address ramp, regulation, capacity, ancillary services, system reliability and power quality. It is also environmentally friendly because smoothing the power supply and providing a spinning reserve are functions usually performed by expensive fossil fuel generation.
Putting pieces in place After settling on the appropriate battery storage solution, IID issued a bond and drew on its capital spending budget to finance the $38 million project.
CESP won the district’s solicitation for 20 to 40 MW of grid-scale energy storage, beating out eight other vendors in the final round to serve as general contractor for the project. The company chose the energy project management company ZGlobal Inc. to oversee construction and General Electric to build the system.
GE supplied a comprehensive package which includes the lithium-ion battery with its inverters, plant controls, transformers and medium-voltage switchgear in a single enclosure. This is one of GE’s largest energy storage projects to date and one of its few lithium-ion storage projects. The company recently rebooted its lithium-ion battery business and also won a contract in April for an 8-MWh battery energy storage system for Con Edison Development in Central Valley, California.
Now playing Construction took about one year to complete, demonstrating that a storage battery can be sited and deployed relatively easily. However, every system is different and poses its own challenges to integration. “The BESS replaces some of our need for spinning reserves, but it was continually reacting to mitigate the slow ramping capabilities of IID’s generation fleet,” said Montaño. “We had to adjust reaction parameters on the BESS in order to economically and reliably balance the system.”
Testing followed so that when the BESS came online in October, it was ready to provide benefits to IID and its customers. On top of the operational benefits of increasing reliability and bringing more flexibility to the utility’s system, the BESS offers economic advantages, as well. It enables load shifting that reduces the need for expensive spinning reserves and is expected to result in significant cost savings to rate payers over the life of the project.
Every utility has a different power mix and different load, so battery storage must be evaluated on a case-by-case basis. But IID’s project illustrates many of the technology’s potential benefits and should give power providers elsewhere in the country much to think about.
As distributed energy resources (DER) become more prevalent, states across the country are seeking to design consistent and durable valuation and compensation schemes for these resources. What’s a Watt Worth? presents three novel approaches to valuing distributed energy resources (DER) from California, New York and Texas. Speakers will cover locational valuation of DER and DER in wholesale markets, locational net benefits analysis of distribution resource plans and distribution-level markets for DER.
The Distributed Generation Interconnection Collaborative (DGIC) aims to share knowledge on distributed photovoltaic interconnection practices and innovation. Registerfor this free webinar and sign up to receive quarterly updates on DGIC activities.
Source: National Renewable Energy Laboratory, 8/8/16
The amount of solar power installed in the U.S. has increased 23-fold in the last seven years, from 1.2 gigawatts in 2008 to an estimated 27.4 gigawatts in 2015, with one million systems now in operation. A key challenge to furthering solar deployment is the ability to integrate distributed generation sources like rooftop solar panels into the grid while balancing that generation with traditional utility generation. This FOA aims to support companies working to meet that challenge while keeping reliable and cost-effective power flowing.
ENERGISE specifically seeks to develop software and hardware platforms for utility distribution system planning and operations that integrate sensing, communication and data analytics. These hardware and software solutions will help utilities manage solar and other distributed energy resources on the grid and will be data-driven, easily scaled-up from prototypes and capable of real-time monitoring and control.
Funds are being offered for projects addressing two topic areas:
Topic Area 1 covers near-term projects to develop commercially ready, scalable distribution system planning and real-time grid operation solutions compatible with existing grid infrastructure to enable the addition of solar at 50 percent of the peak distribution load by 2020. A one-year field demonstration with utility partners is required.
Topic Area 2 covers projects that tackle the long-term challenge of developing transformative and highly scalable technologies compatible with advanced grid infrastructure to enable solar at 100 percent of the peak distribution load by 2030. DOE will require a large-scale simulation to demonstrate performance and scalability.
DOE’s SunShot Initiative will oversee the projects funded by this opportunity. The program expects to make 10 to 15 awards altogether. Awards for Topic Area 1 will likely range between $500,000 and $4,000,000 each. For Topic Area 2, DOE anticipates making awards of between $500,000 and $2,000,000 each.
New alternatives to conventional generation are already changing capacity planning, portfolio evaluation and resource procurement decisions. Many planners—even experienced ones—may be wondering how to address these issues while still ensuring reliable and economic operation of the bulk power system.
This course will show attendees how to plan their future resource mix in the face of uncertainty. They will gain an understanding of the effect public policies, such as environmental regulations, have on the resource mix and system operations. Presentations will cover strategies for successfully integrating variable resources, storage technologies and demand-response programs into a comprehensive plan.
The agenda is designed to offer something for professionals involved in every aspect of power delivery, from utility system planners and power system operators to emerging technology vendors. Developers of transmission, renewable energy, energy storage and demand-response projects will benefit from the course, as will regulators and lawmakers.
Learn from experts The instructors bring decades of experience in resource planning to an information-packed schedule. Attendees will learn planning basics, including commonly used calculations, from Michael Henderson, the Regional Planning and Coordination director for Independent System Operator New England. Brian Walshe, president of ION Consulting, will discuss how these principles apply to specific scenarios and how factors like regulations, environmental policies and fuel supplies can affect them.
The case of Hawaiian Electric Company (HECO) offers a close look at the real-world impact of aggressive renewable energy goals on resource planning. HECO Renewable Energy Planning Director Dora Nakfuji will be on hand to share her utility’s experiences.
Here to help The EPTC will continue to be a resource to help utilities keep pace with rapid-fire changes in the electric industry. Randy Manion, Western’s Renewable Resource Program manager, will discuss plans to enhance the training center’s course offerings to include advanced renewable integration training using the EPTC’s unique model power system. Dr. Bri-Mathias Hodge, manager for the Power System Design and Studies Group at the National Renewable Energy Laboratory, will join Manion to talk about NREL’s Visually Informed Wind Forecasting Decision Making Platform Project.
“The EPTC is moving forward on several fronts to make this happen,” said Manion. “We have partnerships underway with the National Renewable Energy Laboratory involving advanced visualization tools for control room operators. We are establishing an EPTC Utility Working group with support from some of the electric utilities leading the country in actively addressing renewable integration. Also, Western is developing an EPTC roadmap with our core partners including the Bureau of Reclamation and Army Corps of Engineers,” he added.
Resource Planning for Power Systems will take place at the EPTC in Golden, Colorado, convenient to several hotels and restaurants. The cost is $795, with discounts available for government employees, including municipalities. If you work for a government agency, wish to register multiple people, have questions or need more information, please contact the registrar at 720-491-1173.
This webinar will highlight the services and operations of the California Independent System Operator, the West’s only organized regional transmission market. Participants will gain an understanding of the emerging Energy Imbalance Market (EIM) and its governance, and how the EIM supports wind integration.
The emerging EIM offers Western utilities new market opportunities—and challenges—to integrate wind power and other renewables onto their systems. The industry expects the EIM to improve reliability and lower the cost of renewable energy integration.
Scheduled speakers include Don Fuller, a CAISO representative, who will provide an overview of services and operations of the independent system operator’s organized market. Fuller will contrast CAISO to how other balancing authorities operate in the Western Interconnection. The presentation will highlight the EIM service now being offered to utilities and BAs outside the CAISO footprint.
Rebecca Wagner, Nevada Public Utilities commissioner and chair of the EIM Transitional Committee will provide her perspective on expanding the EIM. Wagner’s presentation will also cover how the market governance will allow parties outside of California to have a formal role in the EIM development.
Register today to learn more about how the emerging EIM can benefit your utility. The webinar will take place from 3 to 4:30 p.m.
Afterward, the presentations will be posted on the 4CWRC website. For questions or more information contact Meghan Dutton.