SRP and EPRI Study EVs’ Impact on Grid
The end is near for a study by Salt River Project (SRP) and EPRI on the impact of electric vehicles (EVs) on the future grid.
The goal of the study, which will wrap up this year, is to determine what impact the increase in energy consumption will have on the grid as more chargers are installed in homes and businesses to meet demand.
FleetCarma data loggers were installed on the vehicles of 100 SRP customers who volunteered to participate in the study. The data loggers, which plug into the onboard diagnostic port of vehicles, gather charging information such as time, duration and location.
“We wanted to see where and how EVs will impact our system,” said Kelly Barr, SRP’s senior director of environmental management and chief sustainability and compliance executive. “We also wanted to learn how our customers with electric vehicles selected and utilized our pricing options to determine which price plan worked best for them.”
SRP decided to conduct its own study because Arizona drivers and climate are different than other parts of the country. Drivers in SRP’s service territory tend to use their vehicle air conditioners more, which impacts the EV’s range.
Based on results of 100 participants, preliminary data found:
“- Roughly 4,400 current EV owners in SRP’s territory use more than 9,121 MWh of energy a year, which equals the average energy consumption of about 652 homes.
“- At SRP’s system peak at about 5 p.m., these vehicles also use more than 1 MW of electricity, which is equivalent to about 200 homes.
“- Time-of-use (TOU) price plans were effective at incentivizing EV drivers to charge later than they normally would, which will help SRP meet customer demand without needing to add power plants.
“- Current EV drivers are often referred to as “early adopters,” and they tend to be more aware of the savings they can see by utilizing TOU plans and charging at certain times of the day. SRP hopes to educate future EV owners on the benefits and encourage them to use TOU programs and avoid charging during peak times.
The study began in June 2016 and is expected to end this year. SRP will conduct a second study later this year with some of the newer EVs that have a battery range of more than 200 miles, such as the Chevy Bolt and Tesla Model 3.
PG&E Rolling out new Time-of-Use Rate in April
Pacific Gas & Electric (PG&E) will roll out a new electric time-of-use rate that it says will make energy use more efficient, minimize peak demand challenges and give customers more rate options.
Starting in April, about 150,000 residential PG&E electric customers will move into the new rate, although they have the option to choose another plan. The peak pricing will be from 4 p.m. to 9 p.m. every day with the off-peak or lowest price in place during the other 19 hours.
“PG&E is committed to working together with our customers to ensure they understand how small shifts in when they use energy can make a big difference for the environment,” said Laurie Giammona, senior vice president and chief customer officer, in a statement. “We recognize that customers use energy differently and will provide information and tools to give customers greater control over how they use energy and help them choose the rate plan that best meets their needs.”
The time-of-use rate encourages a shift in usage to times when demand is lower and renewable resources such as solar are more plentiful, PG&E said. The utility will offer bill protection for the first 12 months to allow customers to try the new rate plan risk-free.
While customers who take no action will transition into the new time-of-use plan in April, they will have the option of keeping their current plan or choosing an alternate rate plan.
The rate plan is part of a statewide effort in which PG&E and other utilities are working with the California Public Utilities Commission (CPUC). Customers for the first phase were randomly selected from across the service area to represent diversity in climate, household size and energy usage, among other factors.
PG&E plans for a full rollout of the new time-of-use rate plan starting either in late 2019 or late 2020, pending a decision by the CPUC.
California is committed to greater adoption of clean energy resources, but faces the challenges of the so-called “duck curve.” The duck curve illustrates how demand is low but renewables production high during an early part of a typical day when customers are away from home and then reverses in the evening. This creates the potential for over-generation early in the day and inadequate power in the evening.
CAISO Unveils Plan to Take
Grid Reliability Reins of its System
The California Independent System Operator (CAISO) announced plans to become its own reliability coordinator and offer these services to other balancing authorities and transmission operators in the western United States.
CAISO has given notice of its withdrawal to its current reliability coordinator, Peak Reliability, and to each of its funding members, effective September 2019.
Reliability is an essential element of operating the electric grid, and CAISO has supported a single reliability coordinator in the Western Interconnection to provide the most comprehensive and coordinated view of the system.
The likely departure of the Mountain West Transmission Group (MWTG) from Peak and resulting increased costs to all participants, and Peak’s partnership with PJM to offer market services, caused CAISO to believe it is now necessary to pursue its own withdrawal. The ISO, therefore, will provide these services for its own footprint as soon as possible, and to other parties across the West, at reduced costs.
“The ISO reluctantly takes these steps and will collaborate with the rest of the funding parties to ensure continuity of reliability services and to avoid any party being adversely affected financially,” said Steve Berberich, president and CEO of CAISO. “We will now seek to provide reliability coordinator services to our own system, as well as to other interested parties in the Western Interconnection.”
A reliability coordinator is responsible for complying with North American Electric Reliability Corp. (NERC) and regional standards, including providing oversight, monitoring operational and security risks, acting or directing action to preserve system reliability and providing leadership in system restoration following a major reliability event.
The reliability coordinator services the CAISO is contemplating will include outage coordination and day-ahead planning, in addition to real-time monitoring for reliability.
CAISO is extending its withdrawal period from the required 18 months to 20 months to ensure seamless coordination with Peak Reliability’s members on the transition. During that time, the ISO will work through an open and transparent process with all interested stakeholders to complete necessary tariff changes, oversight functions and certification processes from NERC and the Western Electricity Coordinating Council (WECC) in a timely manner.
The ISO plans for its new reliability coordinator unit to be certified and operational by spring 2019.
By Rod Walton, Senior Editor
Dominion Buying SCANA After Nuclear Project End
Dominion Energy is buying troubled South Carolina holding utility SCANA in a deal estimated at almost $15 billion, the companies announced in January.
The deal, if completed, also promises close to $3 billion in payments or write-off benefits for those South Carolina utility customers served by SCANA’s subsidiary.
SCANA, through its South Carolina Electric & Gas (SCE&G) unit, has held a huge stake in the failed work to build two new nuclear reactors at the V.C. Summer Station. The utility and its partner, state-owned Santee Cooper, abandoned work on Units 2 and 3 this summer after years of delays, billions in cost overruns and contractor Westinghouse’s bankruptcy filing.
A Dominion spokesman said that the merged company will not restart development of the Summer nuclear station.
Dominion’s offer includes about $7.9 billion stock and, including debt, totals about $14.6 billion. The all-stock merger, if completed, would result in an immediate, average cash payment of $1,000 to SCE&G customers within 90 days of closing, according to the release.
News reports have indicated that the customer payments could total about $1.3 billion.
“We believe this merger will provide significant benefits to SCE&G’s customers, SCANA’s shareholders and the communities SCANA serves,” Dominion CEO Thomas Farrell said in a statement. “It would lock in significant and immediate savings for SCE&G customers—including what we believe is the largest utility customer cash refund in history—and guarantee a rapidly declining impact from the V.C. Summer project.”
The deal also promises a write-off of $1.7 billion in V.C. Summer’s 2 and 3 capital and regulatory assets. This means that amount will not be collected from customers and speeds up the overall customer-cost timeline to 20 years instead of previously proposed 50 to 60 years.
Dominion’s offer also vows to complete the $180 million purchase of natural-gas fired Columbia Energy Center at no cost to customers.
“Dominion Energy is a strong, well-regarded company in the utility industry and its commitment to customers and communities aligns well with our values,” said Jimmy Addison, CEO of SCANA, in the announcement. “Joining with Dominion Energy strengthens our company and provides resources that will enable us to once again focus on our core operations and best serve our customers.”
SCANA shareholders will receive 0.6690 shares of Dominion Energy common stock for each SCANA share, according to the release. The combined company will provide electric and natural gas to more than 6.5 million customers in eight states, making it one of the largest utility holding companies in the U.S.
If approved by regulators, the merger would be completed by 2019.
EnSync Energy Sells PPA for 790 kW Solar Project in Hawaii
EnSync Inc., doing business as EnSync Energy Systems, a developer of distributed energy resources (DERs), announced the sale of a 20-year power purchase agreement (PPA) for a 792-kW solar project for a residential community in Hawaii. It did not disclose the buyer. The project will serve over 200 individual meters—with the flexibility to add more meters—and is grid-tied. It will export unused energy to the grid under the Customer Grid-Supply (CGS) tariff.
Using its proprietary modeling technology, EnSync Energy performed significant technical and financial analyses to optimize project sizing and setup for delivering the least expensive and most reliable electricity. EnSync Energy modeled, for example, how unit vacancy interacts with residential load volatility and concluded that a grid-tied project design could protect the value generated by the solar project. The resulting design, execution and successful PPA balanced load needs, special permitting requirements and CGS utility arrangements to maximize savings were considered.
EnSync Energy said in a release that its modular technology approach also enables the residential complex to easily scale capacity in the future.
“The many complexities of creating a PPA for this large residential development project, with so many units and individual load and production profiles, are indicators of the challenges our solutions address and the value we bring to the residential marketplace,” said Brad Hansen, CEO and president of EnSync Energy in the release. “Our capability to perform increasingly intricate analysis and modeling, in addition to applying expertise in policy implications, enables us to construct a customized PPA that benefits all stakeholders economically.”
This site is one of more than 22 contracted commercial projects in Hawaii, which will account for more than $33.4 million in electricity sales over the terms of the agreements.
Construction will commence in the coming months, according to the release.
By Rod Walton, Senior Editor
Schneider Details Milford Microgrid,
Partnership with Carlyle-Financed Startup
Schneider Electric announced major collaborations on the microgrid front during DistribuTECH 2018, including a $4.5 million municipal project in Connecticut and a partnership with a new energy-as-a-service company backed by a $500 million capital commitment from the Carlyle Group.
The financial world is seeing the potential in behind-the-meter energy solutions worldwide and wants in, Mark Feasel, vice president of Schneider Electric’s smart grid and microgrid segment, said during a briefing during DistribuTECH week.
“There are more bankers walking around here at DistribuTECH than any year in the past,” he said.
The most immediate news announced by the Boston-based firm was a $4.5 million microgrid project with the city of Milford, Connecticut. It will team gas-fired combined heat and power generation with energy storage and could be solar-ready for future additions.
The microgrid will power five critical facilities in Milford, including a senior center, middle school, city hall, government center and apartments for the elderly. Construction has begun and should be completed by the first quarter of 2019, Feasel noted.
City leaders were concerned after seeing what happened with Irma and voted to approve a project that will provide protection against grid outages, he said. The project is funded partially by a grant from the Connecticut Department of Energy and Environmental Protection, with Milford funding the generator and battery energy storage system. Schneider provides the design, electrical equipment and grid management expertise.
“More and more, we’re seeing the negative impacts of 500-year storms on entire regions,” Feasel said. “The unprecedented nature of these storms is causing municipalities to come to grips with the need to offer resilient power and a shelter and microgrids that operate independently in the event of a grid outage. . . The microgrid will offer Milford residents peace of mind.”
Many of Schneider’s previous microgrid projects combined solar power with storage and a backup generator. Milford chose the gas-fired option because of its low-cost and lower emissions profile.
“It’s greener than what they have today,” Feasel noted.
The generator will need to run 24 hours a day. He also pointed out that about 40 percent of microgrids have a gas-fired generation component, about the same percentage as solar.
The company’s microgrid profile took a potentially even bigger leap by detailing its partnership with Dynamic Energy Networks. The startup, which is a portfolio company of investment giant Carlyle, looks to jump up into the microgrid space soon, buying and operating assets with power sold back to the customer on long-term deals.
A graphic delivered during the presentation indicated that the U.S. microgrid market is expected to exceed 3.7 GW by 2020. Dynamic Energy Networks is set up to move soon on various projects, using Schneider as a technical partner well-versed in microgrid installation and control technologies.
“We see this as a fast-growth path and it needs a lot of capital,” said Karen Morgan, a longtime renewables executive who is CEO of Dynamic Energy Networks. “We feel we can get into the market quickly.”
The company certainly will consider existing projects to acquire, she added. However, Schneider’s front-line engagement with microgrid construction can move that into fledgling projects.
Taking the operational financial burden off of municipal, commercial and industrial customers is a key driver for future transactions, Morgan pointed out. The business plan of buying the power at long-term predictable costs should be more attractive to top leaders who want cleaner energy and resiliency against outages, Morgan predicted.
“This is a C-suite solution,” she said. “Schneider has been in this a long time and is a leader. I think we’re hitting a tipping point.”
By Rod Walton, Senior Editor
SEPA, Collaborators Tackle DERMS Standards at DistribuTECH
The march to develop industry-agreed standards for distributed energy resource management systems (DERMS) took a major leap forward on Jan. 22, as utilities and vendors connected in the effort and offered thoughts on the best path ahead.
The Smart Electric Power Alliance (SEPA) hosted its annual Grid Management Working Group focused on DERMS requirements, drawing nearly 150 participants to discuss the needs for standards which address dangers like cybersecurity, load curves and reserve power flow as well as potential functions such as aggregation and voltage control. The working group met at the Henry G. Gonzalez Convention Center, site of DistribuTECH 2018, which occurred Jan. 23-25.
“The group was formed to do something that was not done very well in the past,” said Vibhu Kaushik, director of grid modernization efforts at Southern California Edison (SCE), one of the utilities driving the push for DERMS standards that can then be adopted by vendors. Kaushik pointed out that SCE is facing 5,000 rooftop solar applications per month in its service territory and might see electric vehicle adoption rise 25-fold to meet clean emission goals over the next two decades.
SEPA got the ball rolling two years ago at DistribuTECH 2016. Since then, distributed energy resources (DER) have proliferated as solar panel costs fell, but industry standards struggled to keep pace.
The “DERMS Terms” movement, as some call it, is working to change that.
“The whole objective for SEPA is driving multiple stakeholders’ collaboration to set the direction and provide clarity around DERMS,” said Sharon Allan, chief innovation officer for SEPA. “That clarity reduces risk for everybody” from ratepayers to utilities and vendors.
SEPA has released a DERMS requirements document for comment among industry participants. Utilities will benefit by being able to acquire systems that are more likely to provide standardized capabilities—such as inverters—while vendors are guided in their own product development efforts.
Mike Ratliff, chief technical officer with Enbala, said that clarity is key. The phrase DERMS creates some confusion industry wide because some think it’s all about coordinating solar panels and reserve power while others think it’s about smoothing out the load curve or is a new version of demand response.
“I think about new power systems,” Ratliff said of DERMS’ capabilities. A new-level DERMS control would remove the dangers of managing high solar photovoltaic penetration, he added.
Pacific Gas & Electric (PG&E) also has learned lessons on ways to manage DER spread out across the grid, said Sameer Kalra, who helps oversee that utility’s technology strategy and innovation efforts.
“We’re looking at near-term non-wires alternatives projects,” Kalra said. “The whole planning is changing in a key way. DERMS is still not available off the shelf.”
That could change soon if the continued Grid Management Working Group efforts prove fruitful. SEPA hopes to produce a more detail document in the next year with the goal of seeing standardized DERMS products showing up the marketplace by 2020 or soon thereafter.
POWERGRID International Names Project of the Year Award Winners
Innovative projects from across the U.S., including one developed by a non-utility, won the 2018 POWERGRID International and DistribuTECH Projects of the Year awards on Jan. 23, DistribuTECH 2018’s opening day. Winners were revealed during the keynote address at the Henry B. Gonzalez Conference Center in San Antonio.
The editors of POWERGRID International —the official publication of the DistribuTECH Conference & Exhibition—selected one wining project in each of four categories: Distributed Energy Resource Integration, Grid Optimization, Demand Response/Energy Efficiency, and Customer Engagement.
Teresa Hansen, Editor in Chief of POWERGRID International and conference chairwoman for DistribuTECH, said this year’s awards reflect the changing nature of smart grid dynamics.
“The grid is becoming ever more technically complicated and diffused with things like sensoring, AMI data analysis and distributed energy resources,” Hansen said. “This year’s winners prove that the next era of the smart grid is now. It’s becoming less controlled in the traditional way, as proven by the fact we have a non-utility winner for the first time in memory.”
The winner for Distributed Energy Resource Integration was Blue Lake Rancheria, a tribal reservation in northern California, chosen for its microgrid project that operates within the Pacific Gas & Electric service territory. Public Service Electric & Gas won the Grid Optimization Project of the Year for its Energy Strong Advanced Technologies D-SCADA Program. The winner for Demand Response/Energy Efficiency Project of the Year is Kansas City Power & Light’s Residential and Small Business Demand Response program. The Customer Engagement Project of the Year is Sacramento Municipal Utility District’s Distribution Operations Transformation.
A more detailed article about the 2018 POWERGRID International and DistribuTECH Projects of the Year will be featured in the March issue.