Officials in Puerto Rico, New York Unveil Modernization for Storm-Damaged Grid
By Jeff Postelwait, Online Editor
Officials in Puerto Rico and New York unveiled a plan to modernize the island territory’s power grid following the widespread devastation of Hurricane Maria.
Puerto Rico Gov. Ricardo Rossello and New York Gov. Andrew Cuomo said a greater amount of federal aid to the territory could establish a storm-hardened power grid based on renewable energy.
The plan is based on New York’s power grid renovations that state underwent following 2012’s Hurricane Sandy, which was the second-costliest hurricane in U.S. history.
“The rebuild recommendations are based on experience with power system recovery, rebuilding, and hardening from hurricanes encountered on the U.S. mainland over the last decade. The recommendations include the use of modern technology and incorporate lessons learned from the successful rebuild efforts in other regions post natural disasters, such as Hurricane Sandy in New York,” according to a report released by the governors, FEMA, the Puerto Rico Electric Power Authority, and a host of U.S. mainland utilities and Department of Energy national laboratories.
The assault of Maria is an opportunity to build a more resilient power grid that also pollutes less, according to the report’s authors.
“A transformed electric power system for Puerto Rico is one that is designed with the resiliency to withstand future storms and is built with modern grid technologies and control systems,” according to the report.
Specifically, the plan calls for: smart grid investments, microgrid technology, undergrounding power lines, upgrading and reinforcing power poles, effective vegetation management techniques, and installing controls systems for distributed energy, among other measures.
The plan has an estimated cost of about $17.6 billion. Cuomo and RossellÃ³ have asked the federal government for nearly $95 billion in total recovery funds, separate from the power grid plan.
Transmission lines could be strengthened with new metal monopole towers and high-strength insulators. Damaged transmission lines were one cause of widespread outages after Maria.
The plan also calls for flood-resistant electrical substations, as was done in the New York City area after Sandy. Upgrades to the distribution system include new concrete and galvanized steel poles and a new control center.
On the power generation front, the plan would relocate power facilities located near the ocean or rivers.
The plan also includes using advanced sensors and intelligent fault interrupting devices and developing a condition-based asset management program.
“One of the key features of the ‘build back better’ strategy is to rebuild the T&D system using design standards capable of withstanding high Category 4 storms, with sufficient design margins to ensure high survivability for Category 5 events in areas where damage is most likely to occur,” according to the report.
FERC Approves Sempra Energy Deal for Texas Transmission Firm Oncor
The Federal Energy Regulatory Commission issued an order late in 2017 authorizing Sempra Energy’s $9.5 billion acquisition of Texas-based transmission giant Oncor Electric Delivery, pushing the merger one key step toward completion.
San Diego-based Sempra is actually buying control of Oncor’s bankrupt parent company, Energy Future Holdings Corp., which holds about 80 percent of Oncor. Sempra made its surprise bid back in August, beating out Warren Buffett’s Berkshire Hathaway Energy and other previous suitors.
If it clears all hurdles, the Sempra-Oncor deal could be completed by April. However, it still faces the Texas Public Utility Commission (TPUC), which previously has rejected Oncor bids by NextEra Energy and Hunt Consolidated, citing concerns about debt and impact on customers.
Sempra and Oncor filed their joint application with the TPUC back in October. The application added that Sempra plans to finance the purchase price with a final targeted transaction capital structure that uses a combination of about 65 percent equity and 35 percent long-term debt issued at the Sempra level.
Immediately following the closing of the proposed transaction, Sempra would extinguish all debt that resides above Oncor at EFIH and EFH, reducing it to zero immediately following the closing of the proposed transaction and maintain it at zero going forward, the application noted.
Headquartered in Dallas, Oncor is a regulated electric transmission and distribution service provider, made up of approximately 122,500 miles of lines and more than 3.4 million advanced meters, making it the largest utility in Texas. Using cutting-edge technology, more than 3,900 employees work to safely maintain reliable electric delivery service to over 10 million Texans.
Sempra Energy, based in San Diego, is an energy services holding company with 2016 revenues of more than $10 billion. The Sempra Energy companies’ more than 16,000 employees serve approximately 32 million consumers worldwide.
Berkshire Hathaway Energy’s leadership thought it had snapped up Oncor as late as July for $9 billion in cash and other considerations. Energy Future debtholder Elliott Management, however, was critical of the deal, and Sempra jumped in late to counter Berkshire Hathaway’s offer.
Two previous companies tried and failed in their bids to buy Oncor, which owns and operates one of the largest grid transmission networks in the country. Three years ago, Hunt Consolidated and partners offered to buy Oncor out of EFH’s bankruptcy proceedings, but that potentially $20 billion deal was scuttled partially due to reported resistance from Texas regulators.
In 2016, Florida-based utility giant NextEra Energy made an $18 billion bid for Oncor. It was rejected twice by the TPUC over concerns about debt leverage and potentially negative impact on ratepayers.
NYPA Shows off Digital-Heavy Integrated Smart Operations Center at HQ
By Rod Walton, Senior Editor
New York Power Authority (NYPA) has unveiled a major step toward its goal of becoming the first all-digital utility in the U.S.
Gov. Andrew Cuomo and a host of political and energy players lauded the fully digitized power asset monitoring and diagnostic center near its headquarters in White Plains, New York. The facility known as the Integrated Smart Operations Center (iSOC) oversees operations and outputs from NYPA’s 16 power plants and more than 1,400 miles of transmission lines.
The command center is a key step in CEO Gil Quinione’s vow to make NYPA the nation’s first all-digital public power utility and “sets a new standard in utility asset management,” he said at the event. “By using advanced data analysis to monitor all our assets simultaneously, we can continue to provide low-cost and reliable power while making smart and efficient operating decisions in real time.”
GE Digital is providing the predictive analytics software to forecast and hopefully prevent equipment failures and outages. NYPA plans to integrate additional monitoring capabilities on the GE Predix application platform in the future, according to the release.
“We applaud this tremendous step for NYPA as the authority leads the way for digital transformation in the power and utility industry. Our collaboration can serve as an example for how GE’s digital solutions are purpose built for industry, increasing efficiency and productivity in some of the most complex operations,” said Bill Ruh, CEO of GE Digital and chief digital officer of GE.
NYPA began using the system to monitor its 500-MW power plant in Queens in December 2016 and has now expanded its use to monitor all of its generation and transmission assets. Data is collected from more than 24,000 strategically deployed sensors embedded in equipment and analyzed for signs of normal aging. Data highlights are displayed in real time on an 81-foot video wall, where more than a dozen data screens draw attention to significant deviations. NYPA engineers can then promptly address potential issues with plant operations managers.
Also housed on the 25,000-square-foot all-digital floor will be NYPA’s New York Energy Manager and its Advanced Grid Innovation Laboratory for Energy, which uses “big data” analytics to simulate, develop, deploy and integrate the next-generation electric grid, further positioning New York State as a leader in electric grid research.
EIA Report Shows AMI Penetration Heading Closer to 50 percent
By Rod Walton, Senior Editor
Smart metering in the United States may be pinging near the point of no return, according to new federal statistics.
The U.S. Energy Information Administration (EIA) reported recently that installations of smart meters nationwide have doubled since 2010. By the end of 2016, the EIA reported, electric utilities had installed about 71 million advanced metering infrastructure (AMI) meters, covering about 47 percent of the nation’s 150 million electricity customers.
One-way meter to utility communication was more prevalent until 2013, but two-way AMI devices have been gaining ground since then, based on data collected in the EIA’s annual electric utility survey.
Washington D.C. has the highest smart-meter penetration at 97 percent, followed closely by Nevada at 96 percent. Other states at 81 percent or higher include Oklahoma, California, Georgia, Maine and Michigan, among others.
Texas had the busiest year in 2016 installing smart meters on more than 100,000 customer accounts. A handful of states have less than 20 percent AMI penetration, including Louisiana, New Mexico and Iowa, among others.
Automated meter reading (AMR), or one-way communication meters, rose from about 30 million customers in 2007 to slightly less than 50 million a decade later. AMI rollout, meanwhile, expanded dramatically from nearly zero 10 years ago to about 70 million smart meters at last count.
Residential customers accounted for about 57 million of the smart meters in 2015, while the commercial and industrial sectors total 7.3 million and 300,000, respectively, according to the EIA annual report.
Standard, or non-AMR and non-AMI meters, stood at nearly 38.5 million in 2015, about 430,000 less than the previous year.
Despite this growth, the U.S. still falls behind other nations when it comes to AMI rollout. Navigant Research reported earlier this year that China led with 68 percent of tracked installations.
Last year, Navigant said that North American smart meter rollouts had plateaued, buoyed only by installations involving utilities such as ConEdison and Hawaiian Electric.
The Smart Grid Investment Grant program, part of the Obama-era recovery plan, helped push AMI growth from 2009 to 2012. Since then, however, the pace of rollout has slowed.
Work Begins on $100 Million Entergy
Louisiana Transmission Project
By Corina Rivera Linares, Chief Analyst, TransmissionHub
Entergy Louisiana began construction on an approximately $100 million technological upgrade to its electric power transmission grid in Jefferson Davis Parish in Louisiana.
The project will enhance reliability, increase transmission capacity and help ensure the availability of affordable power now and into the future for the parish, the company said.
The upgrade covers about 900 square miles, almost all of which is within Jefferson Davis Parish, and encompasses the construction of some new transmission lines, as well as rebuilding many existing lines, the company said. Both the new and rebuilt sections of line will use steel structures that can withstand winds of up to 140 miles per hour and employ reinforced high-voltage wire that will move power more reliably and efficiently, the company said.
An Entergy spokesperson in December told TransmissionHub that there are multiple new lines and existing lines that will be rebuilt as part of the Southwest Louisiana 69kV Improvement Project.
“We will be replacing the existing Colonial Welsh (138-kV) tap line with two new (138-kV) lines (Henning-Lake Charles Bulk and Henning-Bayou Cove),” he said. “We will be installing a new (69-kV) line between the new Henning Substation and the existing Carter Substation. We will also be rebuilding the existing Carter-Serpent and Compton-Elton (69-kV) lines. Finally we will be installing two new (69-kV) lines from the new Henning Substation to the Line 13 Tap location.”
The hub of the project will center around the new Henning substation, the company said in its statement, adding that most of the construction will take place between the Compton and Elton substations along Louisiana Highway 395, across farm fields between the Carter and Serpent substations, and along Louisiana Highway 90 between the Derouen and Lawtag substations.
In total, about 58 miles of lines will be added or upgraded, the company said.
Depending upon weather and other variables, the project is currently scheduled to be completed by February 2020, Entergy said.
The company also noted that it has developed a communication plan to keep communities, businesses, institutions and government agencies up to date on the project’s progress.
Noting that it has identified a few locations that will require brief service interruptions as a result of the project, Entergy said that it will provide advance notice to all affected customers so customers can plan accordingly.
Work in Mississippi
Entergy on Nov. 30 said that Entergy Mississippi is investing more than $2.5 million in improvements in four Mississippi Delta counties-Bolivar, Humphreys, Leflore and Sunflower counties-that will harden the system against storms and outages, while also making it more resistant to cyber-attacks and physical threats.
Entergy said that it has completed or is working on the following projects in these counties:
Vegetation management-The company is spending nearly $800,000 to trim vegetation from 325 miles of line and 13 circuits.
Substation work-Nearly $200,000 will be spent at the South Cleveland substation for maintenance and repair with the bulk going toward the installation of a Vanquish fence, specialty fencing that deters animal intrusions, which is a common reason for outages.
Equipment replacement – More than $1.6 million will be spent replacing and upgrading existing equipment.
In a Nov. 16 statement, Entergy said that Entergy Mississippi is investing some $10 million in making energy service in the communities in Hinds County, Miss., even safer and more reliable-the investment is in addition to nearly $16.6 million being spent on similar projects in Jackson, Miss.
Entergy said that it has completed or is working on the following projects in Hinds County:
Vegetation management – The company is spending more than $1.6 million to trim vegetation from 515 miles of line in Clinton, Byram, Terry, Edwards and Bolton.
Substation work – Some $6.2 million will be spent on two new distribution substations that will be in service by the end of 2017 or early 2018, the Tinnin Road substation in northern Hinds County and the Wynndale substation south of Byram.
Equipment replacement – More than $2.2 million will be spent replacing and upgrading existing equipment, with nearly $500,000 of that going toward reliability projects that address areas that have experienced numerous outages over a short period of time.
In both statements, company officials said that the investments are part of a multi-year investment designed to strengthen all parts of Entergy’s grid to help reduce power outages.
Entergy noted that last year, it spent more than $66.5 million on reliability projects in its 45-county Mississippi service area.
PG&E, Enel Ink Deal on 85-MW Energy Storage
Pacific Gas and Electric Co. (PG&E) submitted six energy storage contracts totaling 165 MW to the California Public Utilities Commission. The utility also has signed an 85-MW deal with Enel.
California’s Energy Storage Decision requires investor-owned utilities to procure 1,325 MW of storage by 2020. PG&E’s share is 580 MW. Since 2015, PG&E has signed contracts for 79 MW of new energy storage capability.
Italian firm Enel S.p.A., through its U.S. renewables company Enel Green Power North America Inc., signed three capacity storage agreements with PG&E for a total capacity of 85 MW/340 MWh. Under the agreements, Enel will build the Kingston, Cascade and Sierra stand-alone lithium-ion energy storage projects, which will all be located in California.
“The signing of these agreements marks an important step forward in our Group’s plan to strengthen its presence in the energy storage market and expand this business in the U.S., and California in particular, which are at the forefront in the development of this market,” said Enrico Viale, head of Enel Global Thermal Generation. “Utility-scale storage applications are a key focus area for Enel in view of the great benefits they offer in terms of grid balancing and reliability. We are proud of the progress we have made in this field so far and look forward to growing our storage portfolio even further.”
The energy storage systems will connect directly to PG&E’s grid and will charge the lithium-ion batteries when there is an abundance of renewable energy. The energy stored in the batteries will then be delivered back to the grid during times of peak demand, increasing grid reliability, while also easing congestion.
The three facilities, all located across Central and Northern California, are the 50 MW/200 MWh Kingston project, the 25 MW/100 MWh Cascade project and the 10 MW/40 MWh Sierra project. The projects are developed with Sovereign Energy Storage, an independent developer of large-scale utility battery energy storage projects. All three are expected to be operational by 2023, pending review and approval by the California Public Utility Commission as well as local and regulatory agencies.
By the end of 2017, PG&E forecasts that about 33 percent of its retail electric deliveries will come from renewable sources. Energy storage will help integrate many of those resources, such as wind and solar, which are intermittent or provide peak output during times of low demand.
Fortum Cuts Solar Power Deal With Russian Company
Stem, Mitsui Commence Energy Storage VPPs in Japan
Energy storage firm Stem and Mitsui & Co. are building an aggregated fleet of industrial customer-sited energy storage in Japan. With this network of energy storage systems, Stem launches its international efforts and establishes a foothold in one of the most dynamic energy markets worldwide.
The Japanese Ministry of Energy, Trade and Infrastructure (METI) endorsed Mitsui and Stem in a competitive solicitation to develop distributed virtual power plants (VPP) for grid benefit. Mitsui and Stem will initially deploy more than 750 kWh across multiple sites to form a flexible and fast-responding distributed resource.
This pilot will help inform Japan’s plans to develop aggregated demand response resources as flexible capacity to manage the variability from increased renewable energy resources on the grid.
Artificial intelligence (AI)-driven energy storage generates value for Japanese commercial customers by reducing their energy costs and providing them tools for greater control over their energy use. Stem’s predictive analytics and machine learning, coupled with its Power Monitor and Powerscope user interface tools, provide the data and analytical insights needed for robust facility energy management. Stem captures energy data on a one-second basis, dispatches on a five-minute basis and stores terabytes of data to the cloud.
METI will be testing deregulated services and markets as Japan undergoes a dramatic redesign of the country’s nearly-300 GW electricity market. In the aftermath of the 2011 Fukushima Daiichi nuclear accident, the Japanese government embarked upon the largest deregulation of an electricity market worldwide.
The restructuring will promote renewable energy and help modernize the Japanese electric grid by introducing competitive services and flexible resources. Japan’s dense urban areas cannot easily accommodate additional generation resources, making customer-sited virtual power plants that leverage the real-time balancing and intelligence offered by energy storage particularly essential.
Building on its industry leadership in Hawaii, California, Texas and New York, Stem will use its experience with aggregated customer-sited energy storage to increase local grid performance. In this deployment, Stem will operate multiple sites outside of Tokyo for Mitsui and host customers, leveraging its VPP experience and Athena artificial intelligence software. The first system is located at the Shinwa Kankyo Recycling Center in Yoshikawa City, Saitama Prefecture, in the service territory of Tokyo Electric Power Co.
The initial sites within the VPP network are the first of planned projects in Japan for Stem and Mitsui and a base for further Asian expansion.