Pacific Gas and Electric Co. (PG&E) recently announced the completion of its Cornerstone Project, an initiative that helped the utility achieve record electric reliability delivered to its customers in 2013.
The multiyear effort was created to improve electric service for customers by focusing on reducing the frequency and duration of customer outages.
“The technology and the upgrades we have invested in allow us to deliver the safe, reliable and affordable service our customers expect and deserve,” said Patrick Hogan, vice president of asset management, electric eperations for PG&E. “While we are proud of the reliability improvements that the Cornerstone Program achieved, we won’t stop working to improve service for all our customers.”
In 2010, PG&E was authorized by the California Public Utilities Commission to invest $357 million to improve electric distribution system reliability through a three-year program that leveraged existing infrastructure to minimize costs and fully realize reliability benefits for customers. The program contributed to improved electrical service by focusing on three areas:
- Installing intelligent switches on more than 500 electrical circuits. Through December 2013, more than 230,000 customer interruptions have been avoided by using this smart grid technology. In the event of an outage, instead of waiting for a crew to arrive on scene to restore circuits manually, the new devices do it automatically, often within minutes. Utility workers installed automated intelligent switches on nearly 400 circuits in 2013. In total, more than 500 circuits have been enabled with this advanced self-healing technology.
- Upgrading rural circuits. PG&E installed more than 5,000 sets of fuses and 500 line reclosers on more than 440 of the worst-performing rural circuits to isolate service interruptions and minimize their impact on customers. The installation of this equipment has resulted in a 33 percent reduction in the number of customers’ experiencing sustained outages from 2010 performance levels.
- Enhancing substations and circuit interconnectivity. Technicians replaced and upgraded substation equipment to improve operational flexibility and added circuit capacity to maintain or restore service when electricity needs to be rerouted in the event of an outage. These upgrades also had the benefit of handling an increase in demand during heavy loading conditions, such as hot summer days.
PG&E continues to make progress in safely delivering reliable service throughout northern and central California. In 2013, not only did customers experience the fewest service interruptions in company history, but the average length of an outage for a PG&E customer fell to an all-time low. Customers have seen a 40 percent improvement in the average duration of a service disruption and a 27 percent improvement in the number of customer interruptions since 2006. The Cornerstone Program was a key component in this performance.
The company is focused on continuous improvement to ensure customers receive the safest, most reliable and affordable service possible. In its 2014 rate case, PG&E applied to carry on these successful reliability improvement programs on behalf of all its customers.
GE Lands Multiple Series Compensation Jobs
The Flexible AC Transmission System (FACTS) product line from GE’s Digital Energy business has won several key customer orders in the second half of 2013.
During the next 12 to 18 months, GE will be working with the following utilities from around the world to install and commission series compensation systems, providing each with more reliable and efficient power.
Beta Engineering California LP for San Diego Gas & Electric’s (SDG&E’s) East County (ECO) Substation Project. GE’s scope of work for the project includes a 500-kV, 449-MVAr gapless series bank on an engineered equipment package (EEP) basis (including commissioning support). Beta Engineering will provide the construction and overall site management for the job. The primary application of the series compensation system is to provide compensation between SDG&E’s new ECO substation and its existing Miguel substation. The job is expected to be commissioned in 12 months (August 2013-August 2014).
Florida Keys Cooperative. GE’s scope will include a 138-kV, 56-MVAr gapless series bank on an EEP basis (also including commissioning support). The bank will be installed in the Islamorada substation near the coast. The challenges of wind speeds and environmental conditions were key customer requirements, which GE’s design was able to meet. In addition, GE was able to meet the aggressive schedule of commissioning the bank in less than 12 months. UC Synergetic, a wholly owned subsidiary of Pike Corp., is the prime contractor for the project.
Energàƒa Argentina Sociedad Anàƒ³nima (ENARSA). GE will be working with Isolux-Cartellone its engineering, procurement and construction (EPC) partner in Buenos Aires, Argentina, at the Puerto Madryn substation. It will provide engineering, project management and series capacitor equipment for a 500-kV, 378-MVAr series compensation system. Plans are to deliver equipment for the project before the end of 2014.
NorthWestern Energy, Montana. The scope of GE’s work on the project includes EPC of a 230-kV, 117-MVAr gapless series bank. In addition, GE will provide factory testing and installation of the series bank. The system will be used to increase the power flow on the Mill Creek-Peterson transmission line when the series capacitors are inserted, thereby increasing the overall transfer capability of the line. The project is expected to be in service by October.
Western Area Power Administration (WAPA). GE will upgrade four, dual-segmented banks for WAPA during the next four years starting with the Maxwell substation in 2014 followed by the Olinda North and South substations and finishing with the Tracy substation in 2017. An upgrade to bank platforms and ground controls is planned for each substation during the next four years. Key milestones for each bank upgrade are drawing approvals, factory customer witness testing, delivery of equipment, installation of equipment, training and final drawings and instruction books.
SCE to Throw Capital Weight Behind Distribution Investments
by Rosy Lum, TransmissionHub
Southern California Edison (SCE) has a capital expenditure (Capex) forecast of $15.1 billion to $17.2 billion for 2014-2017.
Most of that capital spend will be on distribution system projects as the company’s transmission projects wind down, said Jim Scilacci, chief financial officer of Edison International, during the company’s 4Q13 earnings conference call Feb. 25. Edison International is the parent company of SCE.
Edison International CEO Ted Craver also was on the call.
“SCE continues to target high levels of infrastructure replacement and reliability investments while meeting public policy requirements,” Craver said.
SCE is estimated to spend $4.1 billion, $4.5 billion, $4.4 billion and $4.2 billion in 2014, 2015, 2016 and 2017, respectively, on distribution, transmission and generation investments. Generation investments by far constitute the smallest portion of the Capex program, with transmission investments’ constituting a modest portion and distribution investments’ constituting most of the capital spend.
Transmission investments included in the 2014-2017 period include ongoing project costs, including updated transmission cost estimates for the Tehachapi project, Scilacci said.
“We still have more work to do in terms of Tehachapi cost approvals,” Scilacci said.
The company plans to submit revised costs by the end of the year to reflect Chino Hills and Federal Aviation Administration cost increases the project has experienced, he said. Cost recovery lies with the Federal Energy Regulatory Commission (FERC), he said.
For the Devers to Colorado River transmission project, SCE in November 2012 submitted an advice letter to the Colorado Public Utilities Commission to raise the cost cap for the project from $545.3 million in 2006 dollars to $840 million in 2012 dollars.
“We now feel that project will come within that cost cap, and that positions that well for ultimate cost recovery at FERC,” Scilacci said.
The 2014-2017 Capex forecast neither includes spending for storage projects to address reliability issues raised by the outage of the San Onofre Nuclear Generating Station (SONGS) nor transmission projects included in the California Independent System Operator’s (California ISO’s) resource plan, Scilacci said.
“Potential expenditures for projects like these are currently under consideration,” Scilacci said.
The California ISO in its 2013-2014 transmission plan recommends two projects for SCE, representing $712 million of investment.
SCE in its 2015 general rate case filed in November 2013 requested approval of a “significant increase” in infrastructure replacement spend for the 2015-2017 rate cycle, Craver said.
“This investment is primarily aimed at our distribution system,” he said. “The rate case application also forecast a need for sustained investment at these levels out through 2020 and beyond. Therefore, we continue to anticipate significant rate base growth for the foreseeable future.”
SCE has forecast a rate base of $27 billion to $29 billion by 2017 and a growth rate of 7 to 9 percent annually through this period.
In its 2015 general rate case, SCE requested authority to spend $15.58 billion on California Public Utilities Commission (CPUC)-jurisdictional projects during 2013-2017.
“A major focus in 2014 is to ensure we invest capital dollars authorized by the California PUC for infrastructure replacement and reliability projects,” Scilacci said.
SCE in the general rate case also requested to set base a revenue requirement of $6.46 billion effective Jan. 1, 2015. The request represents a 3.3 percent increase over authorized 2014 levels, the company said in the filing. The company also forecast revenue requirement adjustments of $318 million for 2016 and $317 million for 2017.
The general rate case proceeding is in the early procedural stages, but the company expects evidentiary hearings to be scheduled for this summer, Craver said. The CPUC has yet to establish a schedule.
For 2013, SCE capital spending was $300 million below the projected estimate of $3.5 billion, primarily because of transmission delays and lower costs on two completed renewable transmission projects, as well as delayed infrastructure replacement spending, Scilacci said.
Rosy Lum is chief analyst of TransmissionHub. Reach her at email@example.com or 347-799-2802.
FPL Welcomes Hatchling at First Bald Eagle Nesting Site
Florida Power & Light Co. (FPL) announced that a bald eagle has hatched atop the first nesting platform the company constructed for the iconic bird.
FPL built an independent pole and platform southwest of Daytona Beach in Volusia County after a bald eagle nest was identified on one of the company’s transmission structures.
FPL, with permits from the Florida Fish and Wildlife Conservation Commission (FWC) and the U.S. Fish and Wildlife Service, relocated the bald eagle nest to the new 70-foot high platform during fall 2013. Within 45 days of the nest’s transfer to the platform, a pair of eagles made their new home in the nest. The original location of the nest posed a safety hazard to the eagles and needed to be removed, but viable nesting trees were not present in the immediate area.
“At FPL, we take seriously our commitment to environmental stewardship,” said Randall LaBauve, vice president for environmental services at FPL. “We strive to provide our customers with the most reliable electric service at the lowest cost, while balancing the need to maintain Florida’s special ecosystem and protected wildlife that live throughout our service area.”
State Bald Eagle Population on the Rise
Fewer than 100 nesting sites existed in Florida when the bald eagle population was first surveyed in 1973, according to the FWC. More than 1,450 nests were documented during the 2012 FWC annual statewide survey of known eagle territories. Florida has one of the densest concentrations of nesting eagles in the lower 48 states and has more nests than any state other than Alaska and Minnesota, according to the FWC.
Currently, more than 900 nests exist in the counties served by FPL.
“We appreciate FPL’s efforts to discourage eagles and other large birds from nesting on high-voltage utility structures, and provide safe, alternative nesting platforms where it is appropriate,” said Michelle van Deventer, FWC bald eagle plan coordinator.
Company is Steadfast in Commitment to Environmental Stewardship
FPL has been a leader in the protection of bald eagles, along with other protected birds, for nearly three decades. In 2013 as part of FPL’s installation of new, more storm-resilient power lines in Manatee County, the company preserved nests and provided additional nesting options for the threatened Southeastern American Kestrel. The company also provides nesting platforms for osprey to avoid their nests’ being built on power line structures, which could affect customers’ electric service.
The company’s avian protection plan provides employees with an overview for protecting birds that is consistent with industry and federal guidelines.
Oncor’s Advanced Grid Project Boosts Overhead Power Line Capacity
The final report has just been published on the Department of Energy (DOE)-funded project in central Texas that focused on the use of dynamic line rating (DLR) to provide real-time information on conductor temperature. System operators then use that information to make fully informed decisions on how hard they can drive their overhead power lines.
Oncor, a transmission and distribution utility, successfully completed a DOE Smart Grid Demonstration Program (SGDP) that shows the real-time information provided by Nexans’ DLR technology can increase the power-carrying capacity of existing overhead line assets and reduce congestion.
For the core component of the SGDP, Oncor installed the DLR technology on eight 138-kV to 345-kV transmission circuits in central Texas, where it enabled power capacity to be increased by up to 14 percent. Oncor continually looks for new technology that will bring added value to the Texas market, which is what DLR does. This will help Oncor continue to deliver reliable service to all of its customers and continue to drive the economic growth in the Oncor service territory.
“Technologies like DLR give transmission owners like Oncor significantly increased visibility and flexibility to operate more reliably and efficiently,” said Tip Goodwin, DLR project manager at Oncor. “That’s important not only for our residential customers, but also for the more than 400 communities we serve who are looking to grow existing businesses and attract new businesses. While electricity infrastructure may not receive the headlines that tax incentives do, economic and reliable electricity is at the top of the list of priorities for businesses.”
The Nexans DLR technology employs an algorithm that transforms real-time sensor data into a conductor temperature and calculates the maximum current capacity—the DLR—which maintains the overhead line sag within safe clearance limits. The DLR is updated every five to 10 minutes and provides operators with much clearer visibility than traditional static line ratings, which use predetermined weather assumptions, and ambient-adjusted ratings, which take into account the ambient air temperature.
“The SGDP Project has been a complete success, having demonstrated that Dynamic Line Ratings are a practical and efficient tool to increase the capacity of a transmission line, which will enable transmission providers and system operators to mitigate congestion, increase system reliability and redeploy capital to its most efficient uses through a least regrets strategy,” according to the final report.
DLR was being evaluated as a potential key component of Oncor’s five-year capital investment program that will average $1 billion per year. The program’s strategy is to invest in technologies and equipment to improve reliability and efficiency of the company’s infrastructure, said Jim Greer, Oncor chief operating officer.
“Our investment program is not about just adding more infrastructure,” Greer said. “We want to be able to use our existing assets more efficiently and effectively because that’s a more economical use of our investment dollars. DLR clearly demonstrated that we could improve the efficiency of our existing assets in an economical manner. Already we are looking at other areas of our grid where we can install this capability for future investments. This is good for Oncor, the state grid and ultimately, all of the customers we serve.”
The report highlights the following conclusions and breakthroughs:
- Increased line capacity. DLR provided up to 14 percent additional capacity above the ambient temperature-adjusted ratings. The incremental capacity was available from 83.5 to 90.5 percent of the time.
- Reduced congestion. The project found that 5 percent additional capacity could relieve congestion by up to 60 percent on the target lines with DLR installed, and 10 percent additional capacity practically would eliminate all congestion on the target lines. Congestion on the Oncor transmission lines in 2011 and 2012 cost more than $148 million and $197 million respectively.
- Market integration. The integrated DLR (iDLR) system at Oncor feeds real-time conductor ratings to the Electric Reliability Council of Texas (ERCOT), the market operator, which then incorporates the additional capacity into its Security Constrained Economic Dispatch process. With zero operator intervention, DLR capacity is used to increase market efficiency.
- Transmission planning. By providing additional capacity on transmission lines where a full upgrade cannot yet be justified, DLR can be used in the planning process to enable a least-regrets capital strategy.
- Best practices. The project authors have developed a guide to assist other transmission owners who are considering DLR technology for their own systems.
The report is available for download at www.smartgrid.gov/sites/default/files/FTR_Final_Oncor_DE-OE0000320.pdf.
EYE ON the world
Ontario premier announces new Advanced Energy Centre to be based at MaRS
Ontario Premier Kathleen Wynne recently announced the creation of the Advanced Energy Centre, a partnership between the public and private sectors and MaRS Discovery District that will drive economic growth and sustainable job creation.
Uniting founding industry partners Capgemini and Siemens, as well as utility and government representatives, the centre will work collaboratively to consolidate and extend Canada’s early lead in next-generation energy technologies such as those in the energy data and energy storage space to capture new domestic markets and transform the local successes into international market opportunities for Ontario.
“This centre will help our entrepreneurs become global leaders in energy technology while creating good jobs here in Ontario,” Wynne said. “By partnering with the private sector, we are building our knowledge economy, driving innovation and keeping Ontario competitive.”
The centre will build upon innovative and cost-effective conservation initiatives such as the Ontario Green Button, a program launched by the Ministry of Energy and MaRS Discovery District that gives consumers greater visibility and control over their energy usage. The centre also will work with its partners to assist Ontario’s energy entrepreneurs and developers who are looking to deploy Ontario smart grid solutions globally through international partnerships.
“The transformation of energy networks and infrastructure is estimated to create a $3 trillion global market by 2020,” said Ilse Treurnicht, CEO of MaRS Discovery District. “I’m thrilled that MaRS will be working with entrepreneurs, government and industry stakeholders to ensure that leading Canadian innovations capture a significant share of this growing export market.”
Paul Murphy, the former president and CEO of Ontario’s Independent Electricity System Operator (IESO), has been named the founding chair of the centre’s advisory board.
“The cooperation of the public and private sectors is key to the success of this effort,” Murphy said. “By combining our proven energy sector expertise with our disruptive innovations, the centre will be a game changer when it comes to exporting our energy solutions.”
The announcement was made at the Canadian Energy Innovation Summit, which was convened by Wynne in her capacity as the chairwoman of the Council of the Federation. Held at MaRS, the event brought together business, policy and government leaders from across Canada to provide input on the broader Canadian Energy Strategy being developed by the Council.
MaRS Discovery District is a mission-driven innovation centre in Toronto. MaRS supports entrepreneurs who are building Canada’s next generation of growth companies. Its ventures have created more than 4,000 jobs and in the past three years alone have raised more than $750 million in capital and earned more than $375 million in revenue.
Siemens delivers world’s first vegetable oil transformer in 420-kV capacity range
|Attending the commissioning of the vegetable oil-cooled and insulated large power transformer from Siemens in the Bruchsal-Kàƒ¤ndelweg substation are, from left, Rainer Joswig, managing director of TransnetBW GmbH; Cornelia Petzold-Schick, lord mayor of the city of Bruchsal; Beatrix Natter, CEO of the transformers business unit at Siemens Energy; and Martin Konermann, managing director of Netze BW GmbH (formerly EnBW Regional AG).|
The first environmentally friendly transformer in the 420-kV capacity range from Siemens has been commissioned by the Baden-Wuerttemberg, Germany, power grid operator TransnetBW. The world’s first power transformer insulated and cooled using vegetable oil links the 380-kV extra-high voltage level with the 110-kV grid of the subordinate distribution grid operator in the Bruchsal substation. This ensures that the power transported via the extra-high voltage lines to Bruchsal is fed into the 110-kV grids of the distribution system operator and that this power arrives safely and reliably at households and industry throughout the region.
The special feature of this transformer is the material that fills it. This marks the first time that vegetable oil is used with this voltage category instead of mineral oil for insulation and cooling. The vegetable oil is more environmentally friendly and much less flammable than mineral oil.
“The use of this groundwater-neutral and biodegradable insulating oil, with its high level of environmental compatibility, was the decisive factor for us choosing this transformer,” said Michael Schàƒ¤fer, head of systems technology at TransnetBW.
The insulating oil for this new transformer is produced solely from renewable, plant resources and is completely biodegradable. This is but one of Siemens’ decisive contributions to environmental sustainability. The new power transformer for the Bruchsal-Kàƒ¤ndelweg substation is the world’s first transformer at the 420-kV extra-high voltage level for which no water hazard classification must be issued. As a result, this transformer can be installed and operated in water conservation areas or in zones subject to stringent environmental protection restrictions.
“The properties of this vegetable oil are not only beneficial to the environment but also offer the customer cost advantages over transformers cooled with conventional mineral oil,” said Beatrix Natter, CEO of the transformers business unit at Siemens Energy. “The biodegradability of the insulating oil means that additional collecting vessels and separation systems are no longer required at the installation location, resulting in cost savings for these items.”
Other important aspects are the substantially higher flashpoint and combustion point of the vegetable oil compared with that of the mineral oil used up until now. The lower flammability of the insulating oil also provides the transformer with a higher fire protection classification. This means that the fire protection system can be optimized accordingly and the transformer can be operated favorably in densely populated residential areas. Vegetable oil-based transformers and the associated service are part of Siemens’ environmental portfolio. Some 43 percent of its total revenue stems from green products and solutions.
DNV GL opens new Asia Pacific headquarters in Singapore
DNV GL, the world’s leading ship classification society and one of the world’s leading risk and sustainability service providers with more than 500 employees in Singapore, consolidated its operations in its new headquarters to meet the growing demand for its services in the region.
The new headquarters officially opened Feb. 28 in a ceremony led by S. Iswaran, minister for the Prime Minister’s Office, second minister for Home Affairs and second minister for Trade & Industry Singapore, and DNV GL President and CEO Henrik O. Madsen.
The new office will house DNV GL operations for Singapore and the surrounding Asia Pacific region. This means that DNV GL’s expertise and regional management team will be under one roof. The relocation to a new, technologically advanced building will create greater synergies across its four key business areas: maritime, oil and gas, energy and business assurance.
“Singapore is one of the main Asia Pacific locations for the head offices of large international companies, and many of our customers are also located here,” Madsen said. “Besides, Singapore’s vision is very much aligned with DNV GL’s, especially when it comes to research and development work to address the challenges faced in both the offshore oil and gas exploration and clean energy industries.
“Designed to accommodate our growth over the next 20 years, the relocation of the Singapore office also comes at the perfect time. The merger of DNV and GL last September has created a need to integrate the operations of both companies and the new office enables us to do that seamlessly in Singapore.”
DNV GL also will sign memoranda of understanding (MOU) with the National University of Singapore and the Nanyang Technological University for joint R&D activities.
“We are delighted to work with such well-established research institutions,” Madsen said. “We firmly believe that our collaborative innovation model will contribute to Singapore’s fast-moving industries. Also, as an independent foundation with a strong technology base and risk management as our core area of expertise, we will continue to fill a unique role in creating trust and confidence among industry stakeholders.”
DNV GL’s new office brings together 500 employees from the company’s previous four offices on the island. The office combines intelligent building structures and efficient energy consumption. Some of the green initiatives by DNV GL include:
- Central air conditioning set at 25 C for energy efficiency;
- The implementation of motion-based sensors for energy-efficient lighting control;
- Waste management: Individual wastepaper bins have been replaced by central general and recycling waste collection areas; and
- Reduction in paper use: badge and password-access printing to limit waste.
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