An Editor’s Note on T&D Resolutions

To celebrate 2008, Utility Automation & Engineering T&D invited experts from all over the country to predict the future. We wanted to know what different parts of the country are doing and planning: how they are spending their T&D cash, how the public will interact in the process, how little–or how much–is in the works for the upcoming year. And we got an avalanche of responses from Alaska to New York City. Each little tidbit is unique to the utility and written personally by one of their own, in their own voices. You can find those resolution snippets beginning on page 22.

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We also asked Frank Hoss of GE Energy to sit down and picture the perfect grid of the future–how he would make it all work together if he were elected T&D czar. You can read his article starting on page 18. He leads off our section of 2008 T&D resolutions. Enjoy.

– Kathleen Davis, associate editor

Perfect Grid, or the Perfect Storm?

By Frank Hoss, GE Energy

Editor’s note: We challenged grid expert Frank Hoss to paint us a picture of “The Perfect Grid.” He mulled it over and wrote up the following in answer to our challenge.

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Perfect: the state of being flawless, ideal, complete or just the right thing. Just like the old adage “beauty is in the eye of the beholder,” the use of the term “perfect” requires some understanding regarding the intent of its use. Looking at the electric utility industry’s present state, and what the future likely holds, can help shape the definition of “perfect.”

Some key facts to consider:

  • U.S. electricity usage is projected to grow more than twice as fast as committed resources over the next 10 years (50,000 MW by 2014 and 258,000 MW by 2030).
  • Peak demand for electricity in the U.S. is forecasted to increase by about 18 percent (135,000 MW) in the next 10 years.
  • Committed resources to meet demand, including demand response programs, are projected to increase by only about 8.5 percent (77,000 MW).
  • Counting uncommitted resources, total resources would increase only by about 12.7 percent (123,000 MW).
  • Many states/regions could fall below their target capacity margins within two to three years if additional supply/demand-side resources are not brought into service.
  • 28 U.S. states currently have, or will shortly have, renewable portfolio standards (RPS) in place, anywhere from 3 percent to 33 percent of total generation.
  • While several transmission projects were completed in 2007, and a number have been accelerated, projected transmission additions still lag demand growth and new generation additions in most areas. Financial pricing, cost allocation, siting and permitting transmission lines remains difficult.
  • While the number of proposed nuclear plants sounds promising, because of their large size, the grid will also require expansion and strengthening to provide for reliable integration.
  • Power companies have announced more than 140 new conventional coal-fired plants between now and 2025; however, more than 20 of these have been denied permits/cancelled in the last few months. At least six Federal CO2 legislative initiatives are pending. Regulation at the Federal level is almost certain within the next five to six years. CO2/greenhouse gas (GHG) emissions are becoming a driving factor in power sector decision-making.
  • A number of U.S. regions continue to be highly dependent on natural gas as a fuel for electricity generation. Canadian imports have started to decline, and while overseas markets can provide a new supply, it requires construction of liquefied natural gas (LNG) terminals. This increases the grid’s exposure to global economic and political risk.
  • Electric grid physical and cyber-security is a primary concern. The electric grid is vital to the U.S. and world economy. This infrastructure must be protected from any acts of terrorism and vandalism/theft.
  • Energy customers expect to be provided with choices in their consumption of electricity. Electric prices and consumers’ appetite for electricity continue to grow, and the combination no longer makes it an “out of mind” decision.

Summarized, it’s not realistic to think we can build enough coal-fired plants or install enough renewable generation to keep up with surging U.S. electrical demand and the rising opposition to global warming. EPRI’s Intelligrid Project gives an overall, good concise summary of future power delivery system characteristics needed to meet these challenges. This provides a good basis for defining the “Perfect Grid.” I believe that three of the seven identified future power delivery characteristics are core to this definition. These are:

  • Interactive with consumers and markets,
  • Accommodates a variety of generation options, and
  • Self-awareness of grid/network operations.

Interactive with Consumers and Markets

Consumers and markets will interact with the electric grid primarily through demand response (DR) programs and dynamic pricing models (real-time pricing, TOU, etc.). These programs have a direct positive impact on GHG emissions reduction resulting from the delayed/cancelled construction of new fossil-fueled generation, can be commissioned within a few years, and offer consumers more choices. Florida Power and Light (FP&L) estimates that customer participation in its conservation and energy management programs has helped prevent the need to build 11 power plants over the past quarter-century.

DR is the proactive management of electric utility loads to more efficiently and reliably market, produce, transmit and deliver energy. Demand response applications can be as simple as the utility interrupting load in response to severe grid transients or supply shortages (direct load control or active demand-side management), or as complex as millions of customers voluntarily reducing their consumption/load in response to price signals (passive demand-side management). Large commercial and industrial customer DR programs are not new. They have been in place for 20-plus years. This is primarily because the individual loads are larger, requiring fewer controls and automation, in achieving the desired load reduction/shedding. However, as demand has continued to grow, there has been a noticeable shift in the overall makeup and magnitude of the energy demand peak. Residential consumers now make up about 60 percent of the peak, with unprecedented growth occurring, such as 17 percent growth in the last three years in the U.S. Mid-Atlantic states. Additional DR will have to come from residential consumers. There currently are successful residential DR programs–FP&L has about 750,000 residential customers enrolled with the capability to shed approximately 1,000 MW of load and the ability to obtain almost 2,000 MW, if needed. With the exception of having to address emergencies, DR is generally used to flatten demand peaks.

How much DR is needed to meet growing demand, and, thus, accelerated interaction with consumers, will primarily depend on accepted/legislated GHG emissions targets and the availability of specific new technologies. The Electric Power Research Institute (EPRI) recently completed a study “The Power to Reduce CO2 Emissions,” showing that the aggressive development and deployment of several advanced technologies could reduce U.S. electricity sector CO2 emissions by roughly 45 percent by 2030, relative to estimates in the EIA 2007 Annual Energy Outlook base case. Most importantly, the analysis indicates that the rising trend in CO2 emissions from the U.S. electricity sector can be slowed, stopped and ultimately turned around. Efficiency (DR programs) is shown to have a significant impact on CO2 emissions reduction, with the technology being available today. The amount of DR needed will be highly dependent on the availability and amount of new technology deployed. In addition to technology choices, the issues of program design, rate structure and customer impact will also have a tremendous influence on DR’s success or failure.

For demand response programs and dynamic pricing to work, the utility must have a communications gateway to either directly control the consumer’s loads or provide a pricing signal to allow consumers to manage their consumption directly by making the decision when to use appliances/equipment or as input to a home/premise energy management panel which automates these decisions based on initial consumer input/settings. Successful DR to achieve the needed demand reductions will require a combination of active load control by the utilities and voluntary energy management by the consumer. Advanced metering infrastructure (AMI) projects, currently being deployed, are providing the two-way communications infrastructure needed to support these programs.

Accommodates a Variety of Generation Options

Utilities presently generate about 40 percent of the CO2 in the U.S. With recent legislative, regulatory, and societal focus on environmental consciousness (e.g., carbon constraints, GHG emissions, global warming), new coal-fired plants are being turned down/denied approval at an unprecedented rate. This leaves the utility with few choices to meet this substantial demand growth and the environmental constraints. Nuclear generation likely won’t be available until 2020. Natural gas generation, which can be built within a few years, will be used to meet some of this growing energy demand; however, fuel price volatility and supply susceptibility to global economic and political risk makes it a less favorable fuel choice.

Also, there are currently 11 states with GHG emission targets, 27 with climate action plans, and 28 with renewable portfolio standards. Large investments are being made in wind and solar generation, at both transmission and distribution levels; however, until sufficient energy storage devices are available, utilities will have to address the problems of intermittency. For example, a recent California energy market study of the deployment of 33 percent RPS will require an additional 1,700 MW of quick-start generation, 40 additional transformers/substations, 1,860 megavolt amperes reactive (reactive power) in voltage support and day-ahead forecast errors upwards of 100 percent greater. Cal-ISO will also need 6,000 MWh of additional flexibility (up from the present 4,300 MWh). It’s worth noting that many wind farm sites will require transmission infrastructure investments to get the power from wind-rich, remote locations to the load centers. A number of the new coal-fired power plants that have recently been turned down had transmission infrastructure investments included, resulting in this no longer being available for co-located wind projects. Residential consumers will have to support a portion of this through DR, which is the only capacity resource with a positive environmental impact and yet acts like a gas peaking plant to the utility.

Self-Awareness of Grid/Network Operations

The electric utility transmission grid, distribution network, and load serving entities (LSE)/retail customers have operated largely independently, both externally across, and internally within, their respective organizations. Looking ahead, as the operating environment becomes more dynamic, reliably generating, transmitting, delivering and consuming electricity will require these entities to work much closer together, i.e., have a “self-awareness” internally as well as externally to conditions that are critical to grid/network operations, protection and control. This self-awareness will provide for the automated operation, protection and control of the grid/network, and data/information to utility personnel to make decisions. Embedded communications/sensors will provide the capability for these utility environments to efficiently work alone and together, as required, for normal operations and in response to abnormal or emergency conditions. This will facilitate substation and distribution automation, provide for predictive rather than reactive response to emergencies or abnormal conditions, and in some cases even be self-healing. Under normal operations, this will facilitate the best use of resources and equipment (e.g., more granular availability of voltages and loads across the network could be used to control cap banks, load tap changers, VARs, etc.).

“The Perfect Grid,” as defined here, looked at the environment that electric utilities are likely facing. Predicted demands are far out-pacing committed supplies, environmental concerns are driving business decisions, and consumers must become much more involved.

However, maybe “perfection” should be viewed as a journey, not an end state. Perfection will not be achieved overnight, in the next year, or perhaps the next decade. It is an absolute, however, that the future electric environment will be much more dynamic and interdependent, and utilities must develop a roadmap based on the plausible scenarios likely to be encountered. Their success depends upon it, or the “Perfect Grid” may become, the “Perfect Storm.”

Hoss is GE Energy’s regional T&D marketing development manager for the Americas, focused primarily on the development of advanced metering and distribution “intelligent grid” solutions. In this capacity, he evaluates potential regulatory, legislative, environmental and societal influences on utility operations, and assists utilities in developing a comprehensive roadmap to successfully meet these challenges.

Utility New Year’s Resolutions


AEP’s Eye on 2008

By Carl English, President, AEP Utilities

Like many electric utilities, American Electric Power is taking a comprehensive look at how we deliver energy and manage our distribution assets in the face of environmental concerns, higher prices and a growing consumer awareness of climate change issues in 2008.

AEP Utilities President Carl English (left) talks with Gary Cannon, distribution system supervisor for AEP affiliate Public Service Company of Oklahoma, in Tulsa, Okla.Click here to enlarge image

AEP, with 5.1 million customers in 11 states, is one of the largest electric utilities in the nation. Because of our size, we have a large footprint in almost every aspect of the business, but none more so than environmental. We take great pride in our leadership on issues such as clean-coal development, carbon capture and greenhouse gas emissions, but realized that one element was missing from many of these efforts–and that’s distribution.

So Mike Morris, our chairman, president and chief executive officer, gave us a challenge: Develop new ways to conserve energy, improve our environmental performance and provide customers with greater reliability and control over their own energy future. Hence the creation of “gridSMART.”

gridSMART is a comprehensive effort by AEP to transform customer service, energy efficiency and distribution operations by employing distribution automation and smart meters. But gridSMART is more than new automation–it’s also about making us think about our own energy usage. This ranges from the amount of fuel we use to run our vehicle fleet to internal transmission and distribution line losses to how we can upgrade our buildings with the same systems we encourage our customers to use. It’s also about understanding how automation will allow us to work more efficiently, thus reducing our own energy consumption.

Because of our size and the number of jurisdictions we serve, deploying gridSMART will be a multi-year project. We have an industry-first partnership with GE Energy to develop advanced meters and technology platforms to facilitate gridSMART features. We plan to install advanced meters in two midsized cities of approximately 100,000 customers each to test the technology and gauge customer response in 2008. Those pilots also will allow us to see how the new technology will affect internal processes such as outage response, call center interaction with customers, crew management, order processing and related tasks.

The gridSMART project also anticipates the use of distributed resources, such as sodium sulfur batteries, which we have begun to deploy. We expect to add 6 MW of NAS battery capacity in 2008 to enhance system reliability. We have a goal of 25 MW in place by 2010.

We expect to have all of our customers on smart meters by 2015, pending regulatory approval.

On the transmission front, our hands are already full. We expect to begin extending our 2,100-mile-plus 765-kV system to create an interstate transmission grid for the United States. With our partner, Allegheny Energy, we will begin siting the Potomac Appalachian Transmission Highline LLC (PATH), a 250-mile 765-kV transmission line in West Virginia.

In September AEP and ITC Holdings Corp. completed a study for 700 miles of 765-kV transmission in Ohio and Michigan that would connect to the existing 765 system in Ohio. The proposals require PJM and MISO approval.

We are also considering substantial transmission development with our partner, MidAmerican Energy Holdings Co., for Electric Transmission Texas, LLC, in the Electric Reliability Council of Texas (ERCOT), and with Electric Transmission America, LLC, elsewhere in the United States. Development of a robust interstate transmission grid will benefit U.S. consumers by improving market efficiency, removing barriers to access for renewable power and newer technology generation, and improving network reliability to a level the U.S. economy deserves.

B.C. Hydro Gives a Quick Glimpse at the Year

By Craig Befus, Distribution Standards

BC Hydro has started work on a few major initiatives in distribution and substations. In substations, we have an active project to replace electro-mechanical relays with new smart relays that include metering. On the distribution side, we have begun efforts toward building our smart grid and smart metering infrastructure (SMI).

One objective is to find a common wide-area communications infrastructure that can support both smart grid and SMI–even though the communication requirements differ significantly. As part of the smart grid push, we are looking at extending SCADA to line reclosers, switches, regulators and capacitor banks as well as looking to automate operation of these devices in certain areas.

We have a Volt VAR optimization project underway that will improve system efficiency and lower consumption at peak load periods. We are also looking at communications to remote faulted circuit indicators. The SMI project scope presently includes extensive feeder telemetry, customer metering, and time-of-use rates to account for all energy and provide incentive to our customers to conserve energy.

AP&T’s “Strategic Vis-olusion Initiatives” for 2008

By Mark McCready, Director of Marketing

I must admit, the invitation to submit a bit of discourse regarding Alaska Power & Telephone’s plans for 2008 in terms of “resolutions” struck an odd chord. Most of us utility types tend to mold our tall tales around phrases such as “strategic planning, initiatives or ” corporate vision.” Hence the headline incorporating corporate-speak and the magazine’s New Year’s request to share with our peers who we are and what we’re up to in 2008.

Mark in the field at Kasidaya Creek Falls near Skagway, Alaska.Click here to enlarge image

AP&T is an employee-owned energy, communications and data services provider serving Alaskans since 1957. One hundred forty-four employees serve more than 30 communities stretching from the Arctic Circle to the southernmost tip of southeast Alaska. The demographic alone presents its own unique challenges. Distances are vast, costs to provide services to very remote communities are high and weather provides the third piece of a trifecta that is a wild-card unto itself.

End of commercial, on to the facts: The energy side of the house has taken a leadership role in the development of renewable resource opportunities in Alaska. AP&T will continue that focus in 2008 with the completion of our fourth small hydro facility just south of Skagway, known as Kasidaya Creek Hydro. The company has shifted its energy production carbon footprint in the last 12 years from 99 percent fossil fuel, to over 70 percent renewable-base energy production. A Denali Commission grant funded Hydro-Kinetic river-turbine project is in the works for the Yukon River at Eagle even as test towers gather wind data near Delta for a potential wind farm venture at that location.

Not to be outdone, the communications and data segment will focus resources toward the build-out of mountain-top network facilities enabling enhanced delivery of high-speed broadband data services to several southeast Alaskan communities. Progress on this network in 2008 will be a keystone in AP&T’s broader plans for the southeast.

And, just like many of our personal resolutions, what T&D resolution would be complete without the resolve to get some of those pesky line maintenance items behind us in the New Year. With that thought, I’ll end by sending safe and health-filled wishes to our peers in 2008.

Con Edison Builds for New York’s Future

By Mary Ellen Conlin, General Manager, Environmental Engineering

When you’re running the largest underground electrical system in the United States that serves Times Square and the media, financial and fashion capital of the world, plus world headquarters for Pepsi Cola and IBM, reliability is paramount–and Con Edison’s reliability is No. 1 in the nation.

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To maintain that reliability and plan for the future, Consolidated Edison Company of New York Inc. (Con Edison) filed a three-year rate proposal with the New York State Public Service Commission (PSC) seeking support for continued significant investments in its electric-delivery infrastructure, as well as demand-reduction and energy-efficiency initiatives. The filing began a nearly year-long public review process with the PSC and interested parties that will wrap up in the spring of 2008.

These pictures illustrate the work Con Edison is doing to upgrade and reinforce the system for the 9 million New Yorkers the company serves.Click here to enlarge image

Con Edison has been a part of the economic engine of the New York metropolitan area since the late 1880s when Thomas Edison threw a switch on Pearl Street in the shadow of Wall Street. One of the oldest electric utility systems in the United States, Con Ed operates 94,000 miles of underground transmission and distribution lines and more than 36,000 miles of overhead transmission and distribution lines. The company distributes electricity to more than 3.2 million customers in New York City and Westchester County, serving more than 9 million people and meeting the energy needs of 44 million visitors a year. Con Edison’s service territory, while relatively small geographically, represents approximately 40 percent of New York State’s peak electricity demand.

Electric demand in Con Edison’s service territory is growing at approximately 1.5 percent per year. Construction is booming in every neighborhood throughout the region. In New York City and Westchester County, significant economic development projects are under way or being planned from the new rail link at Howland Hook on Staten Island to the Freedom Tower rising in Lower Manhattan to the new Yankees and Mets stadiums in Bronx and Queens, to the development of the Atlantic Yards in Brooklyn, to the new homes going up and businesses opening in Westchester County.

As New York begins to face the challenges of the 21st Century, the company’s rate proposal seeks the necessary revenue critical not only for addressing short-term conditions, but also for providing long-term solutions to support the energy strategies proposed by the governor and the mayor.

Significant infrastructure investments will include replacing or installing more than 10,000 miles of cable; 4,500 transformers; 3,000 composite covers, along with equipment modernization such as upgraded remote-monitoring systems on over 12,000 underground transformers. Over the term of the three-year rate proposal, the company’s investments would include:

  • $918 million to construct new substations and to upgrade and replace existing substations;
  • $683 million to strengthen the electric distribution infrastructure;
  • $340 million to install advanced metering infrastructure and automated meters; and
  • $154 million to improve storm response and coastal storm mitigation efforts.

Our filing expands the energy-efficiency incentive programs available to both residents and business owners. Con Edison will continue working with customers to install energy-efficient lighting, refrigeration, motors, programmable thermostats for air conditioners, and clean distributed generation. The company is also continuing demand-response programs that pay businesses to reduce electric use during peak summer days.

Among the other initiatives that Con Edison has requested in the new rate proposal are:

  • The continued development and demonstration of new fault-current limiters to facilitate the connection of renewable and distributed generation;
  • Installation of advanced sensors and communications technologies to better monitor and control the secondary system; and
  • Further development of the “3 G System of the Future,” a new design for the city’s underground infrastructure that would reduce congestion under the streets and maintain reliability through asset-sharing technologies.

Renewable Energy, Network Planning Top Hawaiian Electric’s List of Resolutions

By Ken Morikami, Engineering Manager

Ken Morikami, Engineering Manager of Hawaiian Electric Company, gave UAE the details of the utility’s plans for this year.Click here to enlarge image

In 2008, Hawaiian Electric Company (HECO) will continue to demonstrate leadership in the areas of renewable energy and network planning and maintenance. Recently, we sought approval from our regulators for a proposed program to expand our transmission and distribution system to areas of known renewable energy resources. This will help to facilitate the development of renewable energy projects as HECO is supporting the State of Hawaii’s goal of reducing fossil fuel dependency. By providing these needed transmission and distribution interconnections and other operations-related equipment, more renewable projects can become commercially viable and can be integrated into our grid in a way that maintains system reliability.

But HECO’s plans for T&D expansion don’t stop there. Unlike other utilities across the country, HECO’s electrical system is isolated and not connected to other grids. Therefore, the company must be completely self-reliant in all areas, including generation, transmission and distribution. This means keeping our existing assets in peak condition and planning for future expansion.

Keeping these guiding principles in mind, the company’s T&D projects focus on three areas: accommodating new growth on the island of Oahu; managing existing aging assets; and responding to requests from customers.

The western part of Oahu has seen rapid development in recent years, and that trend will continue for the foreseeable future. The University of Hawaii plans to break ground in 2008 on a new West Oahu campus. The area is also expected to see new major shopping centers with big-box retailers such as Target, Costco and Wal-Mart setting up shop within a few years. This area will also be the future home to the first Disney hotel and resort complex not associated with a theme park.

The development in West Oahu is not limited to commercial projects. In 2008, another 1,000 residential units will be added to the area. By 2012, this will jump to 8,000 units. Much of this land was historically used for agriculture or was not developed and therefore does not have much utility infrastructure in place. So, beginning in 2008, HECO plans to design and construct new substations, along with associated 46-kV sub-transmission lines and 12-kV distribution lines, to serve the projected increase in load in the area.

Like many utilities across the country, Hawaiian Electric is committed to the challenge of managing its existing aging T&D assets to extend their useful life. In 2008, the company has prioritized continued replacement of 10-MVA transformers at distribution substations. This program will continue on into the foreseeable future, as worldwide there is currently a lengthy lead time to procure new transformers.

Hawaiian Electric also works closely with various government entities and other customers who request T&D facilities be relocated to accommodate construction and development plans. The company has always strived to maintain a close relationship with its customers, a practice which will carry on in 2008 and beyond. HECO is also looking at new technologies to better serve our customers. We are currently in the midst of an expanded advanced metering infrastructure pilot program that runs through early 2008. These “smart” meters could potentially offer customers a variety of pricing options and could enhance energy conservation efforts.

Wisconsin Public Service Reveals 2008 Plans

By Otto Marquardt, Manager-Electric Distribution Engineering, and Greg LeGrave, Director-Electric Distribution Planning

Wisconsin Public Service Corp., a subsidiary of Integrys Energy Group, serves about 420,000 electric customers and is based in Green Bay, Wis. The company, generally known as one that is intent on providing the latest proven technologies in providing reliable service for customers, expects a wide range of transmission and distribution projects to be in varying stages of completion in 2008.

Perhaps most significantly, the company will see the complete energizing of the 220-mile 345-kV Arrowhead (near Duluth, Minn.) to Weston (Central Wisconsin) transmission line. Work on the line began in 2002 following a three-year approval process. Siting for the line proved contentious, as many individuals and a few governmental organizations opposed the project. The line will ease serious constraints of the electric grid in Wisconsin.

The company will also begin operating the 500-MW coal-fired Weston 4 Power Plant and associated substations.

WPS is nearing completion of a major system-wide voltage conversion to 25 kV. The company began the conversion in the 1960s–well ahead of most other utilities.

With the rapid rise of renewable energy requirements, Wisconsin will see several wind farms being completed in the state. In preparation, WPS is making modifications to its Wesmark substation near Denmark, Wis., to accept a connection from a nearby 20-MW wind facility.

Also on the renewable front, the Ringle Landfill near Wausau, Wis., will begin producing about 2.5 MWs of electricity. WPS is preparing to connect the capacity to its system east of Wausau.

In addition, the company is planning to implement additional distribution automation switches that will automatically open and close to help customers with service restoration following unexpected electric outages.

In its Green Bay division, WPS plans to undergo a pilot project to control capacitors from a central location using remote communications.

The Next “Big Build” is on the Horizon for Idaho Power

By Lynette Berriochoa, Corporate Communications Specialist

On some days, particularly hot summer afternoons, Idaho Power’s transmission lines are full. Like a busy California freeway during rush hour, we can’t get one more car–or one more electron–on the lines.

Lynette Berriochoa goes behind the scenes at Idaho Power.Click here to enlarge image

This requires action. Planners knew this time was coming. Company leaders anticipated a big investment. Project leaders are gearing up for some extraordinary 500-kV transmission projects that connect Oregon, Idaho and Wyoming.

“We are seeing continued growth and increasing demand. We can’t maintain the pace we’re at right now without making some big changes. We can’t eke any more magic out of the system,” said Lisa Grow, vice president of Delivery Engineering and Operations.

That magic is something customers don’t see but expect to happen each time they flip a light switch. And Idaho Power’s employees often work magic on those hot summer afternoons, trying to keep the electrical supply and demand in balance.

“Based upon the current trends, we know new generation resources must be built; we just don’t know yet where or when,” Grow said. “Knowing where the transmission will be helps to remove uncertainty for the generators. Because it takes longer to build transmission than it does to build a generator, it makes sense to have transmission built first.

“And building new infrastructure is something we’re good at,” she added. “That’s one of our core competencies and this will be an exciting and challenging opportunity for many employees. We have a rich tradition of vision and of doing things well. We say “Ëœfair-priced, reliable energy today and tomorrow’; this is the “Ëœtomorrow’ part of that statement.”

Idaho is a key place in the interconnection, and Idaho Power is acting quickly through partnerships, like the one with PacifiCorp on the joint Gateway West Transmission Project. Grow said it’s an economy of scale. Working together, utilities can build fewer projects to meet their needs, rather than each building individual projects. It’s more responsible and more cost-effective, she said.

In 2008, Idaho Power and PacifiCorp will continue to define and refine the project specifics for Gateway West, a transmission project spanning southern Idaho and central Wyoming. The proposed line is about 650 miles long.

The preliminary work–rating, permitting and right-of-way acquisition–will dominate the next couple of years. Idaho Power will be pursuing similar steps for the Hemingway-to-the-Northwest project, a proposed 260-mile, 500-kV line into Oregon. The company is working through the regional planning entities and the states to ensure an open, public process.

As Idaho Power begins the steps for the Gateway West project, others in the region are working within the same philosophy and developing other projects.

“The regional projects that are currently under discussion have great synergy with the Gateway West Project,” Grow said. “These new lines will allow flexibility and will create some dynamic trading points in the Western Interconnection that today is highly constrained. In the end it helps ensure the lowest-cost resource for our customers.”

KCP&L Looks Ahead

By William Menge, Manager, Distribution Reliability, Asset Management and Automation

In 2008, KCP&L will be in the third year of implementing our award-winning Comprehensive Energy Plan (CEP). The CEP is an innovative five-year strategic plan that was created in collaboration with a wide array of stakeholders. KCP&L engaged regulators, government officials, customers, employees, labor representatives, suppliers and environmentalists in a truly collaborative effort to shape the way we generate, deliver and use energy in our region.

The CEP addresses 5 categories key to KCP&L’s business and our region:

  • Environmental Improvements,
  • New Wind Generation,
  • New Coal-Fired Generation,
  • Infrastructure Improvements, and
  • Affordability, Efficiency and Demand Response Programs.

The balanced portfolio and collaborative approach employed in gaining acceptance for the CEP were the main reasons KCP&L won EEI’s coveted Edison Award in 2007.

Environmental Improvements

Environmental upgrades will continue at two coal-fired plants to continue reducing emissions to meet or exceed existing and anticipated federal air quality standards.

New Wind Generation

Plans will progress for the installation of the next 100 MW of wind generation in addition to the 100 MW commissioned in 2006.

New Coal-Fired Generation

Construction will continue on a new 850-MW low-emission, coal-fired generation plant in Missouri.

T&D Infrastructure Improvements

To maintain KCP&L’s high reliability and customer satisfaction levels, the CEP provides for accelerated investments in T&D infrastructure in three arenas: distribution asset management, transmission asset management, and distribution automation with the following components:

  • Distribution Asset Management: Distribution system inventory and condition assessment, proactive URD cable replacement, URD cable injection, and programs to address poor performing pocket areas.
  • Transmission Asset Management: T&D circuit breaker replacement, RTU replacement, wood pole and structural replacements, transmission disconnect switch replacement, and shield wire replacement.
  • Distribution Automation: Faulted circuit indicators, underground network automation, relay automation, dynamic voltage control, 34-kV automated switching, and rural power quality. (See “KCP&L Plan Energizes Distribution Automation” in the September 2007 issue.)

Affordability, Efficiency and Demand Response

This component provides for affordability programs for low-income families, weatherization programs, high-efficiency lighting and appliances, online energy analysis tools, and energy training for customers. Putting more control over energy management in the hands of customers has potential to reduce overall demand.

Additional Initiatives for High Reliability and Customer Satisfaction

In October, KCP&L was named winner of the 2007 ReliabilityOne National Reliability Excellence Award by PA Consulting. KCP&L also achieved top tier performance in J.D. Power and Associates’ Customer Satisfaction survey in 2007. In order to continue performing at these high levels, KCP&L will continue with a variety of additional T&D programs that fall outside the CEP. A sampling of these additional initiatives includes: assertive URD cable maintenance and replacement; worst-performing circuit improvements; capacity additions matched with regional growth; installation of a new energy management system; growth of our mobile computing platform; and smart grid research to name just a few.

Merger with Aquila in Missouri

Lastly, KCP&L plans to complete a merger in 2008 with Aquila in the state of Missouri. Significant effort and resources will be focused on completing a successful integration of Aquila’s Missouri Electric assets and customers into KCP&L in 2008.

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