NEWS

Siting, Investment, Regionalism the Hot Topics at 8th Transmission Summit

By Bob Fesmire, ABB
In March, Infocast conducted its eighth annual Transmission Summit in Arlington, Va. FERC Chairman William Kelliher was on hand for the keynote address and outlined the major issues that panelists would grapple with during the summit.

Topping the list was the Energy Policy Act of 2005 (EPAct) and its effect on transmission investment, followed closely by the challenge of stimulating that investment. Running throughout the conference, though, was an emphasis on regional cooperation-particularly between state siting authorities-in the planning and siting of transmission projects.

Kelliher spelled out the status quo, noting that congestion costs have been rising since 1998, costing consumers hundreds of millions of dollars every year. Investment has picked up, but mostly in upgrades of existing lines. In fact, since 1999 the United States has seen an increase in circuit miles of only 2.5 percent on the nation’s high-voltage transmission system. Kelliher offered five reasons for the trend:

  1. FERC-allowed ROI for new projects is too low.
  2. Siting, especially at the state level, is too difficult.
  3. There’s uncertainty in federal regulatory policy.
  4. Other uses for capital in the industry win out over transmission.
  5. Regulated utilities deliberately under-invest in transmission to boost profits in wholesale markets.

    Given the first three, it’s not surprising capital would be directed elsewhere, and Kelliher was quick to downplay No. 5. While the ROI question remains open, siting and regulatory uncertainties have been at least partially addressed in EPAct.

    FERC’s much-anticipated backstop siting authority came up several times, usually in the context of a question. Poonum Agrawal of the DOE’s Office of Electricity Delivery and Energy Reliability discussed it in relation to the establishment of National Interest Electric Transmission Corridors (NIETCs), noting that the jury is still out on what constitutes a “failure to act” on the part of a state siting authority. What happens, she asked, if a given state has not received the necessary impact studies or other required materials to render a siting judgment? When does the clock start for the one-year limit on state-level decision making? These are questions that may only be answered by a judge’s ruling, but all the conference participants expressed hope that FERC would not find it necessary to exercise its newfound authority.

    From the state regulator’s perspective, there was broad support and occasionally overt enthusiasm for regional state committees. Regulators from California to Arkansas to North Carolina all agreed that regional transmission planning and coordination of permitting processes is vital to solving the transmission puzzle. Each, however, stopped short of expressing willingness to cede siting authority to a multi-state compact as envisioned under EPAct. It’s worth noting, as did AEP vice president of transmission Mike Heyeck, that many of the roadblocks in the permitting process have a federal agency’s name on them. Heyeck said most of the 14 years it took his company to site its 735-kV project, now under construction, was spent obtaining permits not from state authorities but from federal ones. Unfortunately, EPAct offers no remedy for delays at the federal level.

    Siting, of course, is only part of the equation. On the investment side, Wall Street’s representatives at the conference were bullish on transmission. Regulated returns, lack of competition or commodity risk, and a straightforward business model all make for an appealing investment. Those qualities have made for a success story at ITC, as noted by CEO Joseph Welch. Interestingly, Welch also cited the company’s formula tariff as a key to its success. While ITC does leave some money on the table by not negotiating each deal individually, the certainty associated with the formula tariff is worth it, Welch said.

    The idea of taking the specifics of who pays off the table was echoed in the context of cost allocation by National Grid’s Terry Schwennesen and AEP’s Mike Heyeck. Both expressed support for the approach taken in New England, which eliminates wrangling over who benefits from a given project by spreading the cost among all the states in the region. Arkansas PUC chair Sandy Hochstetter advocated for cost allocation based on beneficiaries, noting that SPP’s process reevaluates who those beneficiaries are at least once every five years.

    The Transmission Summit concluded on an optimistic note with a review of several exciting technologies that are either in use or in development. HVDC, FACTS devices, high-temperature superconductors, and a new generation of monitoring and control systems all promise to improve capacity. DOE is investing in R&D in all of these, as well as energy storage and systems integration for distributed generation and large wind farms.

    Bob Fesmire is a communications manager in ABB’s power technologies division and a regular contributor.

    Data the Buzz at GITA’s 29th Annual in Tampa

    Approximately 1,850 attendees and 100 exhibitors gathered in Tampa, Fla., April 23-26 to take in the Geospatial Information & Technology Association’s (GITA) 29th annual conference. Attendees and exhibitors strolled the tropical pastels-painted hallways of Tampa’s convention center to get the inside track on geospatial technology from vendors, users and industry experts. Attendees and speakers came from as close as the Bay Area and Tallahassee and as far as Japan and Australia.

    GITA’s scope is far-ranging, well beyond our own power industry. This year’s conference included tracks in electric, gas, public sector, water, telecom and pipeline areas. With titles ranging from “The Alphabet Soup Guide to Managing an Enterprise GIS project” to “GIS: A Foundation for Field Automation,” the 45-minute educational sessions at GITA’s conference offered insider tidbits from all GIS-related areas.

    In the session “Data-The Critical Investment,” speaker Ron Kistler, director of the IT & GIS services department with Bay County Florida, asked attendees just what they were coming to the session for. “Do you expect a cookbook?” he queried. “Do you expect me to have all the answers?” He recalled attending his first show with “notebook and pencil in hand” eagerly awaiting that person who would tell him how to fix everything, solve all the problems, get to the heart of each issue. Much to his disappointment, it didn’t turn out to be quite so easy. Instead, he found that the approach was more symbiotic, a sharing experience that really taught him to ask the right questions instead of look for a single pat answer.

    “This session is not intended to provide answers for you,” he added. “But, hopefully, it will give you some questions to ask.”

    One question on everyone’s mind during that session: How important is data?

    Kistler’s answer? “Data is absolutely critical,” he said. “It’s the foundation of every system.” He pointed out that-among other advantages-good data allows a utility to know where assets are in relation to customers and to operate and maintain systems efficiently. Unfortunately, as Kistler went on to say, data isn’t perceived as important within most companies and utilities. In fact, it’s often seen as someone else’s job. He hears complaints like “the maps are never right,” but when pressed as to whether the individual submitted a change, he would hear excuses about time constraints and, again, job limitations. He stressed that this attitude must be changed.

    “Everyone in the organization is responsible for maintaining and updating the data,” he said. “And, data must be considered a corporate asset. Protect the investment.”

    He suggested that this major investment, data, have seven focuses to maintain its integrity-the most important of which is training the people of the company to understand, maintain, update and use the data. Without those trained people, the data can be underutilized and stagnate. Kistler believes that data maintenance is everyone’s job and, in fact, he ponders this question: Should data maintenance be a condition of employment?

    Of particular interest to attendees at GITA was the educational session “Integrating GIS and Work/Asset Management Systems” from EPCOR’s Maurizio Brotto. In fact, it resembled a rock concert. Space left about 10 minutes into the session was SRO (standing room only).

    EPCOR, a utility from Edmonton, Alberta, recently dealt with just what their session title entailed. Brotto detailed an extended case study about the process, much to the edification and amusement of the shoulder-to-shoulder crowd. He noted that some of the older employees were rather unhappy with this nascent automation, preferring, instead, “The Wall”-a large bookcase of 47 binders that was the old system of mapping and management. But, the older employees weren’t the only problem EPCOR encountered. They also came across more modern workers who were all about capturing info and data, although some weren’t sure exactly the intent.

    Like Kistler, Brotto concentrated on getting the audience interested in questions: asking the right ones, digging deeper.

    “We would ask them [the ones capturing data], “ËœWhy do you capture that information? What is it for? Why is it important?’ They would oftentimes say, “ËœI don’t know.'”

    Brotto suggested one major lesson for other utilities from EPCOR’s experience: Ask those questions. “Learn what information you really need,” Brotto said.

    And, also like Kistler, Brotto stated that people are the key-and not where a company should look for savings.

    “Training is not where you cut your costs,” he emphasized.

    In addition to the conference sessions, GITA’s exhibit floor featured 100,000 square feet of exhibit space for related products and services from approximately 100 exhibitors.

    California PUC Approves BPL Regulatory Framework

    The California Public Utilities Commission (PUC) took action to foster the deployment of a new broadband over power lines service to California consumers.

    “BPL has the potential to bring broadband Internet services to communities who do not have broadband service available today from the telephone companies or cable companies. In fact, in other communities that already have DSL and cable modem service BPL can provide a third broadband “Ëœpipe’ to customers, thereby increasing competition and consumer choice,” said PUC President Michael R. Peevey. “BPL can also provide benefits to electric customers by enabling valuable “Ëœsmart grid’ applications that could improve electric system reliability and support money-saving energy management technologies.”

    “As the home of Silicon Valley, California should be a broadband leader in the nation,” Commissioner Rachelle Chong commented. “In taking a light touch approach to regulate BPL, this decision sets the table for electric utilities to bring a new flavor of broadband technology to Californians.”

    BPL systems deliver high-speed data signals over existing power lines. BPL data is transmitted at a much higher frequency than electricity, so the BPL signal can occupy the electric wires without interfering with power delivery.

    BPL technology is evolving quickly, with a handful of pilot projects being run in the state. The PUC expects its decision will foster additional BPL projects.

    “This is a nascent technology with technological, market, and financial hurdles before it,” commented Commissioner John Bohn. “By removing unnecessary regulations from its path, we free BPL entrepreneurs to invest and take the risks they want, while protecting ratepayers from any downside.”

    The Commission today adopted guidelines for electric utilities and companies that wish to develop BPL projects. The Commission’s BPL guidelines address several key issues:

    • Allow the flexibility of third parties or electric utility affiliates to invest in and operate BPL systems;
    • Require utilities to follow affiliate transaction rules for transactions between a utility and BPL affiliate to protect against cross subsidies and other anticompetitive concerns;
    • Maintain the safety and reliability of the electric distribution system;
    • Require companies installing BPL equipment on utility infrastructure to pay pole attachment fees;
    • Align investor risks and rewards, including ratepayer/shareholder sharing of any access fees exceeding the pole attachment fees; and
    • Exempt certain types of BPL-related transactions from regulatory review.

    Current Announces $130M to Accelerate Smart Grid

    Current Communications Group says it has gained $130 million in equity investments from new and existing investors to accelerate deployment of BPL-enabled “smart grid” electric utility networks and alternative broadband communication services.

    New strategic equity investors are TXU Corp., for which Current will provide smart grid capability over the majority of TXU Electric Delivery’s lines, representing more than 2 million customers in Texas; General Electric Co.; EarthLink Inc., which will serve as a retail provider of Current’s broadband services; and Sensus Metering Systems, a provider of water, gas and electric utility metering and AMR solutions. Existing equity investors include Duke Energy Corp., EnerTech Capital Partners, Goldman, Sachs & Co., Google Inc., Hearst Corp. and Liberty Associated Partners.

    Current uses BPL technology to create a multipurpose high-speed data network by placing advanced digital equipment on electric distribution networks. This makes it possible for an electric utility to monitor and control-in real time-the millions of components in the electric distribution network. The same technology can be used to manage gas and water distribution networks, as well as to enable consumers to monitor and control their own electricity usage.

    “This technology provides utilities with a more intelligent, real-time and secure power grid that should help conserve energy, reduce electricity disruptions and protect critical infrastructure,” said Alex Urquhart, president and CEO of GE Energy Financial Services.

    Approximately $270 billion is spent annually in the United States for electricity, with demand expected to grow 40 percent by 2020. A smart grid can reduce energy demand and the need for more power plants, while improving reliability. The Electric Power Research Institute projects that smart grid-enabled distribution could reduce electrical energy consumption by 5 percent to 10 percent, carbon dioxide emissions by 13 percent to 25 percent, and the costs of power-related disturbances to business by 87 percent.

    In Texas, Current is deploying a BPL-enabled smart grid with TXU Electric Delivery, a subsidiary of TXU Corp. A range of “smart” equipment and applications, including automated meters, 24/7 power quality monitoring and remote security cameras, will be installed on the electric distribution network to provide TXU Electric Delivery with real-time information about power consumption, availability and quality, while enhancing security monitoring.

    The same communications network will also deliver broadband service to consumers, High-performance Internet, voice, and video service will be available to residential and business subscribers simply by plugging into an ordinary electric outlet.

    ComEd Adds Hybrid Bucket Truck to Fleet

    Consumers aren’t the only ones feeling the fuel pinch. It hits businesses, including utility companies, in the pocketbook as well. In an attempt to counter rising fuel costs Commonwealth Edison (ComEd) is now testing a first-of-its-kind hybrid bucket truck to meet the challenge of higher fuel costs.

    The average price of diesel fuel has already topped $3 a gallon this year in the Chicago area, compared to about $2.50 a year ago, according to Chicago AAA. ComEd’s fleet managers adjusted their fuel budget upward in January and anticipate additional budget increases in the near future to keep up with rising fuel costs.

    ComEd’s hybrid bucket truck is manufactured by Warrenville, Ill.-based International Truck and Engine Corp. and Cleveland, Ohio-based Eaton Corp. The combination diesel and electric powered trucks are expected to improve fuel economy up to 60 percent compared to diesel-only fueled trucks.

    When field personnel operate a diesel-powered bucket truck, the engine must remain on when employees use the bucket. The new hybrid truck allows the operator to shut off the diesel engine and operate the bucket on an electric motor for up to two hours before the engine has to come back on briefly to charge the battery.

    “As a result, considerably less fuel is burned and greenhouses gas and noise are reduced,” said Pat Pineau, ComEd fleet manager. “About two-thirds of the fuel savings will result from the engine being shut off at the work site.”

    ComEd also is benefiting financially from its use of biodiesel. ComEd has saved an average of four cents a gallon by using biodiesel, compared to the cost of using conventional diesel. The utility operates all of its diesel- powered vehicles with biodiesel and is one of the nation’s largest consumers of the alternative fuel.

    ComEd Buys GIS as Part of $200M Reliability Project

    Commonwealth Edison (ComEd) has awarded a contract to Siemens Power Transmission & Distribution’s high-voltage division to supply a 345-kV gas insulated switchgear (GIS) for the West Loop Substation Project. This GIS installation consists of an indoor substation with four 345-kV breaker bays and a potential future extension to 10 bays. The contract includes the engineering, supply, installation supervision, and commissioning of a 345-kV switchgear.

    The switchgear installation is part of a more than $200 million reliability reinforcement project to increase ComEd’s capacity to deliver power to Chicago, particularly in the northern portion of the central business district, where consumption continues to grow. ComEd plans a 345-kV transmission line project to connect high-voltage arteries of power between three separate electrical substations. It is the second 345-kV GIS installation in ComEd’s system.

    “Siemens switchgear will serve as the backbone of the West Loop Project, helping provide critical redundancy needed to assure reliable power to some 3.7 million people,” said Gerd Ottehenning, Siemens vice president and general manager of the high-voltage division.

    Elster Goes Citywide

    Elster Electricity has announced its first EnergyAxis System deployment in the Lone Star State’s City of Fredericksburg, Texas. This is Elster’s first commitment for a complete system-wide deployment of both electric and water meter automation in the United States. The EnergyAxis System is an advanced metering infrastructure (AMI) system for residential, commercial, and industrial electric and water metering applications. Deployment will take place in stages over a three-year period encompassing approximately 5,290 electric meters and 5,071 water meters installed at residential and commercial locations. The city expects to improve billing efficiencies with more accurate and timely bills.

    The city selected the EnergyAxis System for its controlled mesh network technology, its user friendly features and its minimal number of system components. The system meets the city’s requirement for remotely accessing meter data from both electric and water meters. Having a limited staff with increasing responsibilities, the city wanted to implement a state-of-the-art advanced meter reading system that did not require extensive planning, infrastructure, administration or resources to deploy. Another main deciding factor was the system’s ability to read water meters in service areas where the city does not manage the electricity service.

    Elster’s EnergyAxis Metering Automation Server (MAS) allows the city to perform on-demand meter reads. In the future, the city plans to implement the remote service connect and disconnect feature. The automated functionality of MAS helps save time and improves time management efficiency for system operators. The city expects to improve customer service with the system’s capability to perform daily reads and to retrieve meter data from past months.

    Bangor Hydro to Build N.E. Reliability Interconnect

    InfraSource Services Inc., a specialty contractor servicing utility transmission and distribution infrastructure in the United States, and Bangor Hydro-Electric Co., an electric utility wholly owned by Emera Inc., announced that Bangor Hydro and InfraSource Transmission Services Co. had executed a contract to construct an 85-mile-long, 345-kV electric transmission line, known as the Northeast Reliability Interconnect (NRI), that will extend from Orrington, Maine, to the St. Croix River near Baileyville, Maine.

    The scope of the contract includes procurement, construction and environmental management activities. Once completed, the line will connect with a complementary new transmission line to be built in New Brunswick, Canada, linking the electrical systems of Maine and the Canadian Maritimes.

    The NRI is designed to improve electric system reliability, stability and efficiency in the region, in addition to expanding competition and electric energy exchanges between New England and the Maritimes. The Maine section of the line will be owned and operated by Bangor Hydro; the New Brunswick section will be owned and operated by New Brunswick Power.

    “The NRI will provide a number of benefits directly to the Bangor Hydro customer base, the region, the state of Maine and the Maritimes,” said Rob Bennett, president of Bangor Hydro. Bennett added: “The NRI will bolster the reliability and stability of the power grid in the northeast U.S. and Maritime Canada, while expanding two-way electric energy transport capabilities between New England and New Brunswick.”

    OPPD to Deploy 326,000 Solid-state AMR Meters

    Itron Inc. announced a contract with Omaha Public Power District (OPPD) to install more than 326,000 CENTRON solid-state electricity meters equipped with Itron’s AMR technology, within two years, throughout Omaha and parts of southeast Nebraska.

    OPPD officials said their goal is a better and more efficient method of collecting accurate customer usage information. The vehicle-based mobile AMR system will replace an older generation Itron handheld computer system that OPPD has used for many years. In addition, safety concerns for both customers and OPPD staff have been a top priority for OPPD, and using Itron’s AMR technology eliminates the need to access private property to read meters.

    “The main driver for a complete meter change-out was economics-Itron’s solutions were not only the most economical, they provided other features that will help direct where we go in the future to enhance customer service,” said Larry Ciecior, division manager for OPPD’s customer service operations. “After replacing all our current residential and C&I meters with Itron technology, we are planning to migrate to Itron’s Fixed Network technology within three years by installing network infrastructure over our meter population.”

    OPPD uses a third-party meter reading company to cover its service territory, in addition to employing 35 of its own meter readers. Using Itron’s AMR technology, OPPD will not need to contract with a third party and will reduce its meter reading force to 10 employees. The new technology also allows OPPD to work with the water and gas utilities in Omaha for possible joint meter reading opportunities because those utilities are also Itron customers.

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The Clarion Energy Content Team is made up of editors from various publications, including POWERGRID International, Power Engineering, Renewable Energy World, Hydro Review, Smart Energy International, and Power Engineering International. Contact the content lead for this publication at Jennifer.Runyon@ClarionEvents.com.

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