Perry and Pruitt Appointments May Signal End of World (and We May be Fine)

By Rod Walton, Senior Editor

Rick Petty
Scott Pruitt

Donald Trump’s plan to appoint two southeast U.S. conservative icons for key energy and environmental posts may dim the lights of clean energy advocates who hoped he would see things their way.

But should they despair? Many critics took to the airwaves and Twitter to decry Trump’s announced nominations of former Texas Gov. Rick Perry and Oklahoma Attorney General Scott Pruitt to head the U.S. Energy Department and the Environmental Protection Agency, respectively. Surely these were signs of the coming climate apocalypse: Perry is a man who only five years ago talked of getting rid of the energy department, while Pruitt has sued the EPA numerous times, including the recent legal fight over the Clean Power Plan (CPP).

Pruitt may have been the biggest stunner among Trump’s controversial cabinet announcements. He has sued the EPA over just about every major edict affecting power plants, including regional haze, cross-state pollutions rules and finally, the CPP, which calls for a 32 percent reduction in carbon dioxide emissions from power plants by 2032.

Saturday Night Live even used its cold opening December 10 to make a funny, if biting, point about Pruitt’s nomination (and that of school choice advocate Betsy DeVos to head the Department of Education). Actor Bryan Cranston revived his Breaking Bad meth dealer Walter White as the Trump appointee to head the Drug Enforcement Administration.

Other opponents responded by going the metaphorical route, comparing the anti-EPA Pruitt running that agency to “Gandhi taking over the Defense Department” or putting the “fossil industry fox in charge of the climate-change henhouse.”

But some have encouraged those freaked out to calm down, that there’s only so much either Pruitt or Perry could do to damage their massive agencies. Plus, some might even be surprised at how well clean energy and smart grid advancement may survive during those terms.

“There are statutory limits to what any agency head could do,” said Austin Whitman, director of regulatory affairs for FirstFuel, a firm focused on cloud-based digital engagement for energy companies.

“He can’t single-handedly repeal those laws or single-handedly dissolve the EPA,” Whitman, who admitted that he is more of a regulatory expert than a legal scholar, said. “There are certain things he can do with regard to funding, focus and legal challenges.”

Whitman also urged caution on the reaction to Perry’s appointment. Yes, Perry called for the shutdown of the Department of Energy (when he could remember to name those agencies he would eliminate as a prospective president). But, no, he could not or did not derail much of the clean energy growth in Texas and likely won’t do so from Washington D.C.

“Perry has a reputation for standing up for his constituents. So while we can expect him to shape the DOE research agenda in support of traditional oil and gas based on his Texas background, Texas is also home to more than one-fifth of the onshore wind capacity in the U.S., which benefits ranchers and property owners as well as electricity users-so he won’t be able to ignore this group,” Whitman said.

APS, AES Bring Energy Storage to Arizona Customers

Arizona Public Service (APS) has signed on to 4-MW energy storage agreement with AES Energy Storage that will provide enough storage capacity to power 1,000 homes. The pair of 2-MW AES Advancion energy storage arrays will be deployed as part of the APS Solar Partner Program (SPP) and represent AES’ first installation in Arizona.

The Solar Partner Program studies the use of smart inverters and energy storage to examine how best to integrate solar onto the grid in areas with a high penetration of solar while still maintaining reliability for customers. Through SPP, more than 1,500 customers had photovoltaic rooftop solar panels, totaling 10 MW, installed on their homes at no charge, and receive a $30 monthly bill credit for the next 20 years for their participation. The information APS gains from this study will help craft what the future of renewable energy integration looks like for utilities across the country.

“The best renewable energy is the type a customer never thinks about. A light goes on, a load of towels gets washed and life goes on as reliably as ever before, all powered by the sun,” said Scott Bordenkircher, APS’s director of technology innovation. “This is the future APS looks toward as it studies energy storage.”

The two Advancion battery arrays will be installed in Surprise and Buckeye, which have a total of 120 SPP customers and a high penetration of solar. The batteries will deliver energy to customers at the time of day when electricity is in the greatest demand and is most expensive.

APS anticipates Arizona’s energy needs will be approximately 25 percent higher by 2025. The company plans to meet 50 percent of that growth with renewable energy and energy efficiency.

APS-Advancion system being installed in Arizona.

Courtesy AES

AES’ Advancion has more than 3 million megawatt-hours of delivered service across a fleet of deployed energy storage projects spanning three continents. In 2015, AES opened up the Advancion platform to third-party ownership, and this project with APS will be among the first utility-owned Advancion battery storage arrays.

The pair of 2-MW Advancion energy storage arrays began installation in November 2016 and are expected to become operational in early 2017.

Interior Department Approves 3,000-MW TransWest Express Project

Bureau of Land Management

Following eight years of comprehensive federal environmental review, the Bureau of Land Management (BLM), U.S. Department of the Interior has signed its Record of Decision (ROD) approving the TransWest Express (TWE) transmission project.

The TWE is a high-voltage, direct current (HVDC) electric transmission system being developed by TransWest Express LLC to directly and efficiently access diverse renewable energy supplies while reducing greenhouse-gas emissions. This significant energy infrastructure will add 3,000 MW of “backbone” transmission capacity between the Desert Southwest and Rocky Mountain regions.

A ROD is the final step for agencies in the environmental impact statement process. A notice of availability of the ROD for the TWE project will be published in the Federal Register.

BLM’s ROD follows the May 1, 2015, publication of the TWE Project final environmental impact statement. The final environmental impact statement reflected years of detail-driven environmental analysis, public input and collaboration among 50 federal, state and local cooperating agencies.

The BLM ROD approves issuing a right-of-way grant for the TWE project on BLM-managed land, which represents about 60 percent of the 730-mile route.

“The Western U.S. needs new interregional transmission infrastructure like the TWE project, which will allow California and other Desert Southwest utilities to directly access high-capacity Wyoming wind to balance and diversify their generation portfolios in a cost-effective manner,” said Bill Miller, president and CEO of TransWest, an independent transmission developer.

“Today’s important federal permitting milestone further advances the TWE project’s progress and brings this critical infrastructure project one step closer to construction-creating employment opportunities across the West.”

The project’s construction is estimated to create up to 1,500 direct construction jobs each year for an estimated three-year construction period.

The TWE will extend from south-central Wyoming, to the site of a potential interconnection near Delta, Utah, and then to the Marketplace Hub near Hoover Dam in southern Nevada, which provides interconnections to the California, Nevada and Arizona grids.

PJM Approves Changes to Transmission Expansion Plan

By Corina Rivera Linares, Chief Analyst, TransmissionHub

PJM Interconnection’s board has approved changes of nearly $260 million to the Regional Transmission Expansion Plan (RTEP) to incorporate baseline and network upgrade changes.

The approved facility upgrades were presented to the Transmission Expansion Advisory Committee in November, PJM said, adding that all of the approved projects will be incorporated into the RTEP.

PJM said that the board authorized $259.34 million for:

“- Construction of new baseline reliability upgrades totaling $158.11 million and associated cost allocations for the upgrades

“- Changes to previously approved RTEP baseline upgrades for a net increase of $47.26 million

“- Addition of facilities, network upgrades and withdrawal of cancelled facilities related to the interconnection queue for a net increase of $53.97 million

Among the projects approved were the:

“- Reconductoring of the entire Dequine-Meadow Lake 345-kV circuit No. 2 in the AEP Transmission Zone, at an estimated cost of $6.6 million; the required in-service date is June 1, 2021

“- Reconductoring of the entire Dequine-Eugene 345-kV circuit No. 1 in the AEP Transmission Zone, at an estimated cost of about $22.2 million; the required in-service date is June 1, 2021

“- Adding a second 345/138-kV transformer at the Chamberlin substation in the ATSI Transmission Zone, at an estimated cost of $3.8 million; the required in-service date is June 1, 2021

With the newest changes, PJM said that it has authorized more than $29 billion in transmission additions and upgrades since the first RTEP began in 2000.

PJM also said that its board has approved the 2016 Installed Reserve Margin (IRM) Study results of 16.6 percent for 2017-18.

The board approved the IRM and associated parameters for each of the next four delivery years based on results from PJM’s annual IRM Study, PJM said. It noted that those parameters are key inputs to the reliability pricing model auctions; the IRM study also satisfies the requirements of the resource adequacy standard for the ReliabilityFirst Corp.

The study results re-set IRM for the delivery years of 2017/2018, 2018/2019, 2019/2020, and establish the initial IRM for 2020/2021, PJM said, adding that the study examines the 11-year planning horizon, from June 1, 2016, through May 31, 2027.

Based on results, PJM said that it recommended a 16.6 percent IRM for the 2017/2018, 2019/2020, and 2020/2021 delivery years, and a 16.7 percent IRM for the 2018/2019 delivery year.

Analog Devices and China Electric Power Research Institute Collaborate to Improve Smart Substations

Analog Devices Inc. (ADI) announced a collaboration with the China Electric Power Research Institute (CEPRI) to improve reliability of smart substations. The ADI-CEPRI team will engage in joint laboratory and field research to drive innovations advancing the reliability of smart substations.

CEPRI’s expertise in the analysis of electrical systems, combined with ADI’s smart energy capabilities, will offer engineering solutions that solve complex grid challenges and enable the transition to the digital grid, according to the release.

“Reliable electricity is the lifeblood of modern society,” said Rick Hess, executive vice president Analog Devices. “By improving reliability in smart substations, this collaboration between ADI and CEPRI will ensure China’s utility users enjoy enhanced productivity, comfort and safety.”

ADI offers applications including high reliability signal processing and sensing technologies for the protection, monitoring and control of electric power systems. CEPRI is a multi-disciplinary and comprehensive research institute within the State Grid Corporation of China, the largest electric utility company in the world and a leader in the adoption of smart grid technologies.

“Analog Devices is a world leader in the development of high-performance, high-reliability signal processing, measurement and sensing technologies. CEPRI has rich experience in the area of system application, testing and inspection, and power grid operation analysis,” said Jianbo Guo, president of CEPRI. “Both parties can carry out innovative and complementary cooperation. By combining the strengths of electric power systems and electronic systems, this cooperation will advance the reliability of smart substations.”

Cross-functional groups from both companies-including members of ADI’s energy systems engineering and semiconductor reliability teams, and CEPRI’s departments of high-voltage, relay protection, power automation and metrology-will identify specific reliability issues, jointly create innovative solutions, hold technical workshops and draft international standards, all with the ultimate goal of continuing to improve the resiliency and reliability of smart substations.

CPFL Energia Investing in MRT Transmission Network to Link São Paulo Grid

Brazilian private power utility CPFL Energia is investing in deployment of a new microwave radio transmission network that will interconnect its São Paulo operational sites including substations and data centers in that city.

The new network will replace an existing analogue super high frequency (SHF) network that reached its end of life, offering a high capacity communication ring interconnecting over 27 sites including electric power substations, operational centers and a CPFL data center, the company reporting. For this project CPFL awarded Siae Microelettronica together with its partner CMA to deliver a full turnkey solution including network design, deployment and training. The network will be fully managed and based upon the latest digital microwave radio platform, offering integrated ring protection.

ADI-CEPR ceremony

“The integrated ring protection mechanism, and multiple radio management from a single compact network element, offers CPFL the opportunity to minimize the equipment on site, minimizing the cost effort for the renewal of their backbone” says Raphael Macedo, sales leader for vertical markets in Brazil.

“CPFL is already a user of Siae Microelettronica radio systems and relies on the high quality of its products” said Jefferson Alberto Scudeler, automation and smart grid manager in CPFL, adding “This network enables us in offering a better service and modern management of our São Paulo infrastructure.”

CPFL holds 12.4 percent of the Brazilian electricity market share with 7.8 million customers in the states of São Paulo, Rio Grande do Sul, Paraná and Minas Gerais. It is the nation’s third largest electric utility after Eletrobras and CEMIG. Sales by the CPFL’s eight distribution units totaled nearly 58,000 GWh last year.


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ARPA-E Awards $33 Million to Fund Innovative Technologies for Distributed Energy

The U.S. Department of Energy’s Advanced Research Projects Agency-Energy (ARPA-E) announced $33 million in funding for 12 innovative projects as part of its newest program-Network Optimized Distributed Energy Systems (NODES). NODES project teams will develop technologies that coordinate load and generation on the grid to create a virtual energy storage system. The teams will develop innovative hardware and software solutions to integrate and coordinate generation, transmission and end-use energy systems at various points on the electric grid. These control systems will enable real-time coordination between distributed generation, such as rooftop and community solar assets and bulk power generation, while proactively shaping electric load. This will alleviate periods of costly peak demand, reduce wasted energy and increase renewables penetration on the grid.

“The NODES program continues ARPA-E’s commitment to investing in technologies that can provide options for our energy infrastructure and its arising operational challenges,” said Dr. Ellen D. Williams, ARPA-E director. “The research and development of these grid control technologies will make the concept of virtual energy storage a practical reality. The result will enhance the resiliency, security and flexibility of our nation’s electrical grid and allow the U.S. to make the best use of its abundant renewable energy resources.”

The NODES program aims to create a new approach to management of the two-way flow of power to and from homes and businesses that consume and deliver electricity back to the grid. The resulting virtual energy storage will manage the intermittency of renewable energy, the lack of electricity production when the sun is not shining and the wind is not blowing. The expected benefits of these technologies include improving grid efficiency, reducing CO2 emissions in power generation and significant system cost savings. The program’s goal is to enable more than 50 percent use of renewable power on the grid.

The 12 projects are:

University of Vermont, Burlington, Vermont ($1,537,904)-Packetized Energy Management: Coordinating Transmission and Distribution. The University of Vermont (UVM) will develop and test a new approach for demand-side management called packetized energy management (PEM) that builds on approaches used to manage data in communication networks without centralized control and requires a high level of privacy.

University of California San Diego, La Jolla, California ($2,338,485)-Distributed Grid Control of Flexible Loads and DERs for Optimized Provision of Synthetic Regulating Reserves. The University of California, San Diego will develop coordination algorithms and software using intelligent control and optimization for flexible load and DERs to provide reliable frequency regulation services for the bulk power grid.

Arizona State University, Tempe, Arizona ($3,000,000)-Stochastic Optimal Power Flow for Real-time Management of Distributed Renewable Generation and Demand Response. Arizona State University will develop a stochastic (randomly determined) optimal power flow (SOPF) framework, which would integrate uncertainty from renewable resources, load, distributed storage, and demand response technologies into bulk power system in a holistic manner.

Stanford University, Stanford, California ($3,500,000)-Open and Scalable Distributed Energy Resource Networks. Stanford University will develop Powernet, an open-source and open architecture platform for scalable and secure coordination of consumer flexible load and distributed energy resources (DER).

General Electric Global Research, Niskayuna, New York ($3,900,000)-Synthetic Reserves From Aggregated Distributed Flexible Resources. General Electric Global Research, along with its partners, will develop a novel distributed flexibility resource (DFR) technology that aggregates responsive flexible loads and DERs to provide synthetic reserve services to the grid while maintaining quality customer service.

National Renewable Energy Laboratory (NREL), Golden, Colorado ($3,900,000)-Real-time Optimization and Control of Next-generation Distribution Infrastructure. The NREL project will develop a comprehensive distribution network management framework that unifies real-time voltage and frequency control at the home and the DER controllers’ level with network-wide energy management at the utility/aggregator level.

Pacific Northwest National Laboratory (PNNL), Richland, Washington ($2,700,000)-Multi-scale Incentive-based Control of Distributed Assets. PNNL will develop and test a hierarchical control framework for coordinating the flexibility of a full range of DERs, including flexible building loads, to supply reserves to the electric power grid.

Regents of the University of Minnesota, Minneapolis ($2,950,000)-A Robust Distributed Framework for Flexible Power Grids. The University of Minnesota will develop a comprehensive approach that addresses the challenges to system reliability and power quality presented by widespread stochastic renewable power generation.

Northwestern University, Evanston, Illinois ($2,692,845)-A Novel Hierarchical Frequency-based Load Control Architecture. Northwestern University and its partners will develop a frequency-based load control architecture to provide additional frequency response capability and allow increased renewable generation on the grid.

DNV GL, Chalfont, Pennsylvania ($2,150,000)-Enabling the Internet of Energy through Network Optimized Distributed Energy Resources. DNV GL together with its partners will develop an innovative Internet of Energy (IoEn) platform for the automated scheduling, aggregating, dispatch and performance validation of network-optimized DERs and controllable load.

National Rural Electric Cooperative Association (NRECA), Arlington, Virginia ($1,335,507)-GridBallast-Autonomous Load Control for Grid Resilience. NRECA will develop GridBallast, a low-cost demand-side management technology that will monitor grid voltage and frequency and control the target load in order to address excursions from grid operating targets.

Eaton Corp., Menomonee Falls, Wisconsin ($3,311,532)-Cloud-Based Cascaded Multi-rate DER Control for Synthetic Regulating Reserves. Eaton Corp. proposes to develop and validate a disruptive cloud-computing solution that will provide agile and robust synthetic regulating reserve services to the power grid.

New Study Provides Solar PV Business Model Impacts for Utility Participants

The Smart Grid Research Consortium (SGRC) recently announced that it has initiated a new multi-client study to forecast and analyze business model impacts of residential solar photovoltaic (PV) over the next decade. SGRC multi-client applications reduce the cost for individual utility participants by joint funding of common portions of the research and analysis framework development. Business model analysis is conducted independently for each utility participant.

“US residential solar PV installations increased 69 percent in the last year according to the most recent GTM and SEIA (Solar Energy Industry Association) national market analysis. This translates to new PV output of about one point eight gigawatts from 400,000 new installations. The steady improvement in economics of solar PV, including PV/battery systems promises to continue the industry’s exponential growth, impacting nearly every electric utility” said Dr. Jerry Jackson, SGRC research director. “Minimizing negative utility business model impacts requires proactive strategies that recognize each individual utility’s exposure to PV impacts, ranging from net metering revenue loss to additional investments in voltage control to accommodate PV clustering along feeders.”

Market penetration of new residential PV systems is modeled for each utility at the ZIP area level based on data from more than 7 million customers and 400,000 PV installations. Optional feeder-level forecasts also are available. These resources have been applied for a variety of solar and other distributed energy companies including Geostellar, Sun Edison, Sungevity, Sharp, Toyota, Ingersoll Rand, United Technologies, Bloom Energy, Ice Energy, Aisen and many more.

Each utility participating in the study will receive its own report and briefing. Reports include a review of recent PV and battery market developments and a discussion of likely future developments based on comments from industry experts. Analysis results include annual ZIP-detailed utility PV and PV/battery forecasts, PV output, revenue impacts, financial impacts of alternative rate designs and potentials for utility control of PV/battery systems for demand response. Annual forecasts will be provided for 10 years. Business model analysis reflects each utility’s hourly loads, PV hourly output, utility avoided costs, current utility rate structures, net metering and other utility, federal and state incentives and programs and other factors that impact the utility business model.

Study results will be provided to participating utilities beginning March 15.

The Smart Grid Research Consortium (SGRC) began as a Texas A&M University research and service project in 2010 and transitioned to an independent consulting organization the following year.

Pepco’s Fitzgerald Honored With IEI Leadership Award

The Edison Foundation’s Institute for Electric Innovation (IEI) awarded Kevin Fitzgerald, executive vice president and general counsel of Pepco Holdings Inc. (PHI), with its inaugural Technology Leadership Award. The award, which IEI will present annually, recognizes visionary thinking in pursuit of our energy future.

“It is our privilege to recognize Kevin for his tremendous contributions, leadership and vision, which have greatly benefited the electric industry,” said Lisa Wood, IEI executive director. “His involvement with IEI and his work with industry technology partners have been extremely valuable; Kevin has a strategic vision of the future energy landscape.”

Fitzgerald has been chair of IEI’s Technology Partner Roundtable since 2013. During his tenure, the IEI Partner Roundtable expanded, adding renewable energy, energy storage and data analytics companies.

“Our industry is undergoing a major transformation as electric utilities are forging partnerships with tech companies to utilize new technologies to offer more services to our customers,” said Bob Rowe, NorthWestern Energy president and CEO and IEI co-chair. “Kevin is a real leader and visionary in working to bring technology partners and thought leaders together with utilities to discuss how we collaborate as the industry evolves.”

“IEI provides a forum for the exchange of ideas on the future of the electric power industry, and through his work with IEI, Kevin has played a critical role in facilitating discussions about the adoption of new technologies to benefit customers and the policies that will help support the industry’s technological transformation,” said Scott Prochazka, CenterPoint Energy Inc. president and CEO and IEI co-chair.

Fitzgerald, who has more than two decades of experience in the industry, joined PHI as executive vice president and general counsel in 2012. Kevin is a recognized industry leader in M&A, regulatory policy and strategic planning. He spearheaded development of PHI’s vision of the 21st Century electric utility model.

Survey Reveals Brand Trust Among Texas Retail Electric Providers Varies

Cogent Reports announced that Texas Retail Electric Providers (REPs) have a brand trust level of 748 (on a 1,000 point scale), a good initial score for these retailers. The top four providers have an even higher combined average brand trust score of 752. The top four providers, Ambit Energy, Bounce Energy, Champion Energy Services and StarTex Power, also were named Texas Retail Electric Provider Most Trusted Brands, according to the survey.

Not all REPs in the state have high trust levels among their customers, however. The survey shows a 200-point spread between the highest- and lowest-scoring providers.

“We know that brand trust is the basis for market share growth as customers are not likely to do business with retailers they do not trust,” said Chris Oberle, senior vice president at Market Strategies International, which did the interviews for the report. “Customers also tend to be loyal to companies they trust and are also more likely to recommend those companies to others. And, customer loyalty increases financial returns for these electric providers.”

This is the first time retailers have been benchmarked on brand trust in the Texas market, the largest deregulated electric market in the country. Another finding shows that REPs that have been able to position themselves as trusted providers also have higher customer engagement ratings. This means that REPs will be more effective at offering other value-added products and services to their customers.

“It is clear that after over a decade of deregulation and electric choice in Texas, retail electric providers have built brand images in the market,” Oberle added. “Consumers should only select an REP with high brand trust, as that provider will be more financially viable and they can count on it to be good to its word on the promises it makes.”

Market Strategies interviewed a sample of 878 Texas electric consumers aged 18 or older in November 2015. Market Strategies International is a market research consultancy with deep expertise in consumer/retail, energy, financial services, healthcare, technology and telecommunications.

ABB Supplying Technology for Chinese Smart Substations

Swiss firm ABB will install a 363-kV disconnecting circuit breaker (DCB) with fiber optic current sensor (FOCS) integrating three substation functions-circuit-breaking, disconnecting and current measurement-in one single component, reducing the space needed for a substation bay by up to 70 percent.

In the integrated smart grid-enabling switchgear the FOCS replaces the conventional current transformers required for measurement and protection and enables grid automation. This will be the first commercial installation of this technology at this voltage level, which is the backbone voltage level of the grid in northwest China.

The DCB with FOCS is part of the technology being supplied by ABB for State Grid China Corp.’s (SGCC) next-generation smart substations project. This project will use state-of-the-art software and power technology to enable remote control, protection, automation, monitoring and diagnostics for these substations, as well as to allow both a reduction in their operating costs and footprint. The resulting smaller footprint minimizes environmental impact.

The substations will contribute to a more efficient, flexible and reliable national grid and also build the backbone for the increasing renewable power in China. According to China’s National Energy Administration, the installed power capacity of China’s renewable energy exceeded 400 million kW, in 2014, accounting for more than 30 percent of the total installed power capacity, making China the largest user of renewable energy. ABB will provide the DCB with FOCS equipment for the smart substation in Fuping, Shanxi province, which will supply power for a rapidly developing industrial area there.

As a result of replacing conventional equipment with smart technology, the footprint of air-insulated switchgear bays in a substation can be significantly reduced with a potential space saving of 70 percent. In addition, several tons of equipment can be removed from a high-voltage substation, while substation safety is enhanced and installation time, design, operation and maintenance costs as well as environmental impact are lowered.

AES Energy Storage Inks Battery Supply Deal With LG Chem

AES Energy Storage and LG Chem announced a multi-year agreement that provides access to a gigawatt-hour (GWh) of lithium-ion battery capacity with the option to procure additional capacity for the AES Advancion energy storage solution.

The agreement covers the supply of several of LG Chem’s battery modules that have been designed and configured for AES’ Advancion grid-scale energy storage solution. The agreement provides access to batteries to meet the needs of Advancion installations currently under construction and allows AES to purchase additional batteries to meet the growth for future Advancion system sales. For reference, 1 GWh of batteries is capable of powering 250 to 1,000 MW of energy storage installations, depending on the needs of the customer.

The global grid-scale energy storage sector has entered a new growth phase, with more than 1,400 MW of advanced energy storage projects announced or in operation today, compared to less than 60 MW just six years ago. Navigant Research projects that more than 11 GW of energy storage capacity will be installed annually by 2020 across 22 countries. AES previously announced installations for various customers in six countries totaling 384 MW in operation, construction, or late stage development, representing the world’s largest fleet.

LG Chem competes in the market for electric vehicle and hybrid electric vehicle battery systems. Battery cells for automotive and stationary storage systems are at facilities in Korea and the United States. The supply agreement covers battery modules with configurations ranging from 30 minutes to 4 hours of discharge duration.

PG&E Disappointed With Net Metering Proposal by California Regulators

By Tom Tiernan, Senior Analyst, Transmission Hub

Pacific Gas & Electric (PG&E) said a proposed decision from a California Public Utilities Commission (CPUC) judge on net energy metering “falls well short of what is needed to ensure sustainable growth of solar” resources in the state.

The proposed decision attempts to create a successor to the existing net metering program, which has seen the growth of solar photovoltaic facilities installed on-site at customer facilities, while several utilities have asserted that current net metering customers do not pay their fair share for the use of the transmission and distribution networks.

Under 2013 legislation, the CPUC was directed “to ensure that customers pay their appropriate share of costs while encouraging a sustainable customer-sited renewable distributed generation program,” the CPUC said in a Dec. 15 statement. The proposed decision by ALJ Anne Simon “attempts to strike a balance between these requirements,” the CPUC said.

The proposed decision would continue the existing net metering structure while making some adjustments, including adding a one-time interconnection fee that is likely to be between $75 and $150 for net metering customers, the CPUC said.

The proposed decision also calls for net metering customers to pay nonbypassable charges to support low-income customers and energy efficiency measures on all energy they use from the grid, regardless of the amount of energy they export to the grid.

Historically, net metering customers have paid only the nonbypassable charges if over the course of a year they have used more electricity from the grid than their on-site facilities produced, the CPUC noted.

The proposed decision also calls for new net metering customers to use time-of-use (TOU) rates. Customer who sign up for net metering in 2018 or later must use TOU rates as soon as they sign up, while customers who sign up before 2018 must use TOU rates beginning in 2019, when all residential customers are placed on TOU rates, the CPUC said.

Parties of record in the proceeding may file comments on the proposed decision, the CPUC said.

PG&E did not wait long, issuing a statement that said the CPUC “must do more” to ensure that rooftop solar can grow as a resource in California for years to come.

Nearly 20 years ago, customers were provided with substantial incentives to install rooftop solar facilities, and under those outdated rules, “rooftop solar users can effectively pay nothing for their use of the grid to both buy and sell electricity,” PG&E said. “In addition, they are paid more than market rates for excess electricity that they generate, despite solar costs falling more than 50 percent in the last six years.”

The incentives amount to nearly $1 billion annually across the state, which is offset by the rates paid by non-solar customers, PG&E said.

In a brief statement, SolarCity CEO Lyndon Rive said his company supports the proposed decision, even though the plan to require new solar customers to be on TOU rates “is concerning.” TOU rates would reduce the motivation for installing solar facilities, and that was seen in 2007 when TOU rates were briefly mandated for solar customers, Rive said.

Although TOU rates “can send helpful signals about when to use electricity, we urge the PUC to closely examine the impacts of mandating time-of-use rates,” he said.