James P. Fama, Edison Electric Institute
A new Edison Electric Institute (EEI) report, “Transmission Projects: At A Glance,” offers a closer look at transmission projects that EEI member companies are building or planning. The projects highlighted in the new EEI report total nearly $56 billion (nominal dollars) in expected transmission system investments from 2009 through 2020 and are a portion of total transmission investment anticipated through 2020 by EEI member companies.
This investment is on top of the nearly $58 billion (in 2008 dollars) that electric companies invested between 2001 and 2008 in maintaining and expanding the nation’s electric transmission network.
The fourth edition of “Transmission Projects: At A Glance” presents its information within three major categories of electric company transmission investment: transmission line and nonline system investments, transmission supporting the integration of renewable resources, and transmission-related smart grid projects.
Although the focus of the report is to present representative projects within the three broad transmission categories noted, transmission projects can and do address an array of purposes and deliver a number of benefits. These include projects to relieve congestion, enhance regional reliability and reduce system losses, integrate renewable resources and deploy advanced monitoring systems to enhance situational awareness. Most projects highlighted in the report are multifaceted; that is, they are not developed solely to meet any specific purpose and can fall into more than one transmission investment category.
Also, several of the projects in the report are in proposal stages; their costs and benefits are subject to additional review and an assessment of alternative projects. Nevertheless, they represent new transmission investments advancing in the electric power industry.
Following is a closer look at the three broad categories of transmission investment highlighted in the EEI report:
Transmission Line and Nonline System Investments. This category is intended to include new lines, line rearrangements and line re-conductoring projects, as well as those projects that do not add circuit miles but improve transmission reliability or add transfer capability. Examples of nontransmission line projects include: substation projects, equipment replacements (i.e., transformers, wave traps or phase shifters) and the addition of reactive compensation, such as static VAR compensators (SVC) or dynamic reactive sources.
Interstate projects highlighted in the report that span the three broad investment categories described account for some 10,000 circuit miles of transmission and represent a $39 billion (nominal dollars) investment. Because these projects span more than one state and involve numerous entities at federal, state and local levels, they face significant challenges for siting, permitting, cost allocation and cost recovery. Transmission projects within a single state represent an investment of some $16 billion (nominal dollars).
Projects representative of this investment category include the Mid-Atlantic Power Pathway (MAPP), Potomac-Appalachian Transmission Highline (PATH), and Trans-Allegheny Interstate Line (TrAIL) projects in the East, CAPX 2020 in the Midwest and the Energy Gateway and Canada-Pacific Northwest-California Transmission Project in the West.
Transmission Supporting Integration of Renewable Resources. These projects, whether transmission line or nontransmission line, support the integration of a renewable energy resource, including solar power, wind power, hydroelectricity, geothermal, biomass and biofuels. Highlighted projects reflect the addition or upgrade of nearly 12,900 circuit miles of transmission, with an accompanying transmission investment cost of some $37 billion (nominal dollars). These types of transmission projects again have the potential to address purposes including resource interconnection, reliability and congestion relief.
Projects representative of this category of investment include Northeast Energy Link and Hydro-Quàƒ©bec-New Hampshire Line in the Northeast; Green Power Express, Buffalo Ridge Incremental Generation Outlet (BRIGO), Prairie Wind and Tallgrass in the Midwest; the Northwest Mountain States Transmission Intertie (MSTI), West Canada-Pacific Northwest-California Transmission Project and Tehachapi Renewable Transmission Project (TRTP) in the West.
Transmission-related Smart Grid Projects. The smart grid category includes transmission projects that use digital technology to improve reliability, security and efficiency (economic and energy) of the electric system. Examples include: integration of energy management systems (EMS) and supervisory control and data acquisition (SCADA) systems to area and regional control systems; time-synchronized, high-quality measurements from phasor measurement units (PMUs); dynamic line ratings and the associated measurement equipment; smart grid-enabled distributed controls and diagnostic tools helping the transmission system to respond to imbalances and limiting their propagation; and transmission and substation automation.
The projects highlighted in the report represent a $436-million (nominal dollars) investment. Note that the representative projects in this report applied a minimum project investment threshold of $50 million for transmission and nontransmission line projects, and $20 million for transmission supporting the integration of renewable resources and smart grid.
Examples of the smart grid projects in this report include the New York Independent System Operator (NYISO), PJM, Midwest Independent System Operator (MISO) and Western Electricity Coordinating Council (WECC) member system’s synchrophasor technology deployment. Company-sponsored investments include ITC Holdings Corp.’s Michigan Electric Transmission Co. (METC) SCADA Redirection Program, which integrates the operations of METC electric systems to an independent ITC EMS/SCADA system, the Northeast Utilities Optical Fiber Composite Overhead Ground Wire Project, Southern California Edison’s Transformer Online Monitoring System, and Southern California Edison’s wide-area situation awareness system.
James P. Fama is executive director of energy delivery for the Edison Electric Institute. To obtain a free copy of “EEI Transmission Projects: At A Glance,” visit the website, http://eei.org/newsroom/energynews/Pages/20100305.aspx.
ABB and the Ventyx Acquisition – Why Now, What Next?
By Charles W. Newton, Newton-Evans Research Co. Inc
Editor’s note: On May 5, ABB, the global power and automation technology group, announced that it will acquire Ventyx, a software provider to global energy, utility, communications, and other asset-intensive businesses, for more than $1 billion from Vista Equity Partners.
The May 2010 announcement of the ABB acquisition of Atlanta-based Ventyx is likely to serve as a wake-up call to the major competitors of ABB in the electric power T&D and operational smart grid market, primarily the likes of Areva T&D, GE and Siemens. This week’s acquisition puts ABB squarely in the heart of “smart grid” activities—both from an operational perspective, where it has been a global market co-leader, and now set to gain a significant market position in the burgeoning enterprise utility smart grid software market, a perspective beyond that of any direct competitor.
ABB will now be in a better position for more smart grid-related opportunities than any other of the IT-centric smart grid players, none of whom can compete directly in the operational side of smart grid with smart field equipment offerings. Overall, this eases utilities’ shopping and procurement burdens. ABB’s acquisition of perhaps the best available and largest independent energy industry applications software provider positions ABB for a larger role in the more than $100 billion market for operational equipment and energy enterprise software.
Ventyx has grown in recent years through a combination of strong organic growth and especially well-thought-out inorganic growth through its acquisition of market segment leaders in a number of smaller energy applications software areas. In this regard, the company’s roadmap to marketplace success has been similar in many respects to that of Quanta Services. Both companies also serve gas energy and telecommunications markets. Both firms (Ventyx and Quanta) have relied on inorganic growth measures to fuel expansions, and both have successfully integrated multiple acquisitions of their own.
Many firms with a history in the energy industry are now part of ABB, by virtue of its acquisition of Ventyx. A partial list of brands that are now part of ABB-Ventyx includes MDSI, Indus, Global Energy, New Energy Associates (once part of Siemens Energy) and the energy trading software recently acquired from Houston-based The Structure Group (the highly regarded nMarket offering). By virtue of its acquisition of Ventyx, ABB is now a global leader in energy trading and risk management (ETRM), which will enable its Houston-based energy management systems business unit to more effectively compete with its traditional competitors.
The bigger question for the industry is what will be the industry’s reaction to ABB’s acquisition of Ventyx? Will others rush to make their own enterprise IT acquisitions? Of the three major competitors, GE Energy is probably the best-positioned with an array of IT offerings to accompany its operational side equipment and automation offerings. However, Siemens and Areva T&D, as well as GE, have the ability to match almost any utility or ISO/RTO request for proposals related to smart grid initiatives, either directly, with partners or via project-specific teaming arrangements.
Newton-Evans’ assessment of Ventyx in the North American market for applications that Newton-Evans has recently measured indicates that Ventyx is the major (or a leading) participant in the following market segments:
- Energy trading and risk management—20-25 percent
- Customer information systems —18-22 percent
- Mobile workforce management —30-33 percent
- Asset management software— 25-30 percent
- Power generation analytics solutions—20-25 percent
Ventyx also is an international leader in each of these markets. Global shares of its offerings are typically above 10 percent in served segments.
In terms of the size of the total energy market now addressable by ABB, the value has been increased from transmission and distribution to automation and now to enterprise IT. The acquisition adds an incremental 7 to 10 percent to the company’s addressable global energy market, totaling annual opportunities well in excess of $200 billion. In 2009, ABB total revenues exceeded $32 billion.
Experts Say Public Wireless Networks are Appropriate for Smart Grid Applications
By Teresa Hansen, editor in chief
Public Wireless Networks make sense and can work with existing private networks to provide the communications link necessary for electric utilities to create a smarter grid. This was the consensus of four panelists, three from top public wireless carriers and one from the Federal Communications Commission (FCC), who spoke at the SmartSynch Conference 2010 in late April in New Orleans.
Nick Sinai, FCC’s energy and environment director, told the audience that the recently released National Broadband Plan, which includes a chapter addressing the relevance, considerations and recommendations for smart grid, is a five to 10 year vision for the nation’s broadband networks. He said there is no simple answer when it comes to electric utility applications and that creating a communication system to support smart grids will be complex and will require multiple paths.
Sinai was clear about one thing, however: commercial networks should be part of electricity providers’ smart grid communications networks. Public networks will remove impediments and make it possible to leverage existing infrastructure, he said. Sinai believes open standards need to be developed, security issues need to be addressed and best practices need to be shared. He also believes that not only should the FCC promote a broadband initiative, but states should also get involved.
The three other panelists, Chris Hill, AT&T’s Mobility Product Management vice president, John Horn, T-Mobile’s M2M national director, and Mansell Nelson, Rogers Wireless M2M & Partners’ vice president, are happy with the National Broadband Plan and hope it convinces those in the electric utility industry that public networks make sense and can work with private networks.
An audience member questioned the panelists about public networks’ bandwidth availability, especially during disasters, such as earthquakes and hurricanes, when the volume of cellular phone calls increases dramatically in the disaster area. This is a time in which bandwidth availability is paramount for utilities.
Sinai said the FCC is working with the Department of Homeland Security to prioritize packet data. In addition he said the FCC needs to learn more about the reliability and security of commercial wireless networks.
Hill said the functionality of AT&T’s network is being enhanced to support higher level security traffic.
The audience also questioned the panel about latency, which refers to delays typically incurred in network data processing.
T-Mobile’s Horn said that latency decreases with each generation of new technology, but it becomes more expensive.
“Does the smart grid really need 3G?” he asked. “Most studies show that 2G is adequate for smart grid applications.”
Sinai said the smart grid covers a broad area and latency needs depend on the application.
One issue that drew a lot of attention and discussion was interoperability. Nelson with Canada-based Rogers Wireless said interoperability starts at the standards level.
“This needs to be solved, and then things will start to happen,” he said. “Apps that we never dreamed of have been developed for cellular. The same will happen in the utility sector if we find sensible standards and make it easy for companies and customers.”
Nelson said many companies, including companies using Rogers Wireless’ networks, are investing heavily in the cellular sector. He said services and products can be provided by companies other than Rogers Wireless using Roger’s networks, in much the same way he expects smart grid applications to be delivered some day.
Nelson said an ecosystem needs to be developed to make this happen. Vendors will help drive and develop this ecosystem. He stressed the importance of making technology and applications easy for customers to adopt.
Sinai said the federal government is taking a role in standards, including those that will affect commercial carriers. He said commercial carriers, such as those represented on the panel, need to get involved in this standards development process.
One of the biggest issues on the audience’s mind was how the cost of a public network compares to that of a private network.
Horn said investments in the cellular infrastructure far outweigh investments in any other alternative communications infrastructure.
“I don’t believe all utility applications should use public (wireless) networks,” he said, “but the bulk of the applications can be operated with public networks.”
Cellular companies are good at what they do—building, maintaining and operating public networks, Horn said. “We do a good job of making ourselves invisible and that allows others to manage their needs using our network.”
Hill said a big misconception about cellular networks today is that they are as expensive as private networks. He said studies show that the actual cost of using public networks is less than that of private networks when management and ongoing operational costs are included. He said estimates show that an electric utility will spend $110 million over 10 years for a private network compared to $54 million during 10 years for a public network that performs the same functions. Another advantage of a public vs. private network is that utilities don’t have to add the cost of a public network to their capital expenditures when considering rate base.
“In most every scenario, public costs less than private,” Hill said. “Cost is not the issue anymore.”
These panel members clearly believe that public wireless networks can provide much of the functionality that will be needed to transition to a smarter grid. They also believe that using public wireless networks instead of private networks will save utilities millions of dollars.
PG&E to the World: Read Our Notes on Smart Meters
In the midst of a California state government investigation involving Senate hearings and an independent review of its smart metering program, Pacific Gas & Electric (PG&E) released nearly 700 pages of documentation detailing both the program and customer issues with the meters on May 10, 2010.
The 45 reports included within those 667-odd pages reach back to August 2006 and were originally intended for the eyes of the California Public Utilities Commission (CPUC) and the Division of Ratepayer Advocates. As of May 10, all the reports are posted on the PG&E website. PG&E also promised to continue to post smart meter updates weekly.
Some industry mainstream and regulatory reporters and bloggers believe the announcement of the reports’ availability is directly linked to the investigation into customer complaints about smart meters that started to build in late 2009. The investigation continued this year with Senate hearings and an ongoing independent investigation commissioned by the CPUC with Structure Group on the issues with PG&E’s smart meter push. (The $1.4 million contact with Structure Group will initially be paid by the CPUC, but it has, according to its background materials on the investigation, “ordered PG&E to reimburse the CPUC for the expense of the contract.”)
A number of reports after the May 10 release of the documents on the PG&E smart metering program (called SmartMeter) characterize Senior Vice President and Chief Customer Officer Helen Burt’s coinciding May 10 press conference as an “apology” about the smart metering program. Burt apologized, however, not for the program itself or for problematic meters but for not listening more directly to customers about issues.
“That kind of customer service is just simply unacceptable,” she told reporters gathered for the press conference. “We’re going to do a better job of contacting our customers so they don’t have to contact you.”
PG&E has stated that less than 1 percent of the smart meters installed have caused inaccurate customer bills. The CPUC noted that it received less than a thousand complaints on PG&E’s smart meters (numbers on varying documentation range from 600 to 900 complaints).
During an April 26, 2010, state Senate meeting, Burt told the committee that PG&E’s smart meters were “99.9 percent accurate” and that the few meters with issues—she noted 8 specific problems—had been fixed.
“[99 percent] is a success rate that represents a significant advance over traditional meter technology,” Burt said upon the release of the reports. “We have confidence in this technology and in our program. At the same time, we recognize that some customers question whether they can have faith in our SmartMeter program, and, frankly, in PG&E.
“We recognize that even having less than 1 percent of meters with issues is still 50,000 customers, and that’s too many,” Burt said.
PG&E is pledging action, notifying the public that it will initiate the following customer service solutions:
- Expanding its recently announced side-by-side meter testing program.
- Increasing the number of its customer answer centers to address questions and concerns.
- Using a dedicated SmartMeter customer call center to ensure specialized and expedited handling of customers’ smart meter questions.
- Adding 165 additional customer service representatives.
- Revamping customer communications around the installation of SmartMeter devices.
- Communicating with customers multiple times, and in multiple ways, about their new device and how it can empower them to control and reduce their energy use.
- Calling all customers who receive an estimated bill for two billing cycles to explain the reasons for the bill estimate and facilitate payment arrangements.
PG&E had installed 5.5 million smart meters at the end of April 2010. The final goal is 10 million.
The full text of the released reports can be found at: www.pge.com/SmartMeterCPUCreports
EYE ON EUROPE
Smart Metering in Western Europe Report Reveals Trends
At the beginning of 2009, there were some 253 million electricity meters, 109 million gas meters and 3 million district heating meters in the European Union. As part of the efforts to build a sustainable energy system, traditional mechanical utility meters are being replaced by smart devices.
Regulations largely drive European smart meter adoption. Most western European countries have adopted a policy of regulation-driven introduction of smart meters. Sweden was first, followed by the Netherlands, Ireland, Norway, France, Italy and Spain. The U.K. and Finland are the latest countries to announce regulated rollouts in October 2008 and February 2009, respectively. Denmark seems likely to move in the same direction. Nationwide projects led by publicly owned energy companies are underway in Portugal and Malta.
Except for Italy where the rollout is already almost complete, the larger countries have long timeframes. France and Spain have deadlines at the end of the 2010s, while the U.K. has set the target date to 2020. Common EU energy policies play an important role in this development. The third energy package, approved by the European Parliament in April 2009, proposes that 80 percent of all electricity customers should have smart meters by 2020. It defines guidelines for supplier changes, energy consumption information and service-quality level monitoring, which are difficult to meet without smart meters.
Italy was the first European country where smart meters were deployed at a massive scale in the first half of the 2000s. By 2011, all Italian electricity customers will be covered by the technology. Sweden, however, became the first country to achieve 100 percent penetration in July 2009 following a regulation-driven rollout. The other Nordic countries are following, with Finland and Norway looking to introduce smart metering legislation by 2013, while Denmark has seen strong uptake of the technology without any regulatory requirements.
Spain and Ireland are expected to display high volumes from 2011, with France and most likely Portugal following in 2012. By 2013, these countries alone will account for more than 70 percent of total shipments.
Elsewhere in Europe, the market prospects are more uncertain. The U.K. likely will see the start of large-scale smart meter deployments within five years, given that no unexpected events cause delays. The Netherlands appeared to be on track for a nationwide rollout starting in 2010, but with the recent political setbacks, the implementation of smart meters is delayed until 2013 at the earliest. Germany likely will not see major short-term market developments, but it appears likely that some of the large distribution system operators will go ahead with large-scale installations by the mid-2010s, regardless of the regulatory situation. The market prospects in central Europe are uncertain, but there are good reasons to believe that the pilots and early deployments seen today will evolve into major projects by the mid-2010s.
The full report on Smart Metering in Western Europe may be ordered through Berg Insight, http://berginsight.com.
More PowerGrid International Issue Articles
PowerGrid International Articles Archives
View Power Generation Articles on PennEnergy.com