CWG/9316P Rev 7 8-26-11 1

The Direction Forward – Achieving Innovation in Electric Transmission

Highlights of a Workshop Held June 7, 8 and 9, 2011 in London, England

Clark W. Gellings Fellow

Electric Power Research Institute

Background Transmission owners and operators have done an admirable job in maintaining reliability and moderating cost while managing substantive changes in power systems over the last few decades. However, there is a growing recognition among them that today’s transmission system, based on conventional technology, will require the application of increasingly innovative devices and systems in order to be able to monitor, protect and automatically optimize the operation of an increasing array of interconnected elements – from central and distributed generation through the high-voltage network and the distribution system to industrial users and building automation systems to energy storage installations, and to end-use consumers and their thermostats, electric vehicles, appliances, and other household devices (EPRI 102235). In response to their concerns, in 2010, EPRI and its members established a clear vision for the transmission system of the future. That vision highlighted that transmission plays an absolutely essential role in making the grid more robust and more interactive and thereby smarter. However, there is uncertainty as to the state of technology readiness of the necessary innovations and a lack of shared knowledge of experience in their initial adoption. These issues need to be resolved and innovation made more actionable before the evolution can begin.

The Imperative: Modernize Today’s Transmission System A critically important imperative is to engage in modernizing today’s transmission system in order to enable the use of renewable resources, integrate increasing amounts of energy storage (both transmission-connected and distributed), facilitate fully functional power markets, and enable demand response while sustaining or increasing reliability at a reasonable cost. This will include establishing the concept of flexibility as a resource that can be valued and managed as part of the overall resource mix.

There has recently been a great deal of discourse about building a “Smart Grid.” However, to date, most all of the dialogue and discussion – and the resources – have primarily been focused on the distribution and consumer portion of the power delivery system. This is somewhat warranted, since the opportunity for overlaying communications and enabling Information Technology is attractive, visible and compelling when directed at portions of the system closest to the consumer. However, there are profound changes occurring in the electricity ecosystem, both in electric power generation and with regard to consumers themselves. Today’s power system is largely comprised of central-station generation connected by a high voltage transmission system or Grid to local electric distribution systems which, in turn, serve homes, business and industry. In today’s power system, electricity flows predominantly in one direction using mechanical controls.

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Tomorrow’s power system will still depend on the support of large central-station generation, but it will also include the integration of substantial renewable energy generation facilities, both at the bulk power system level and throughout local distribution systems. The flexibility to deal with this variable and intermittent generation as a growing portion of the resource mix will require new resources like energy storage and demand response and these resources must be integrated with the overall operation and planning of the grid. A robust and modern transmission system will enable widespread use of renewable resources: both in terms of directly integrating large scale Renewables and by offering the flexibility of balancing resources between control areas. This flexibility, coupled with intelligence will allow optimal use of the system in the face of increased volatility of power flow from these disparate renewable resources. Equal, but nearly invisible, partners in tomorrow’s grid will be fully functional wholesale markets and advanced grid operating systems needed to enable storage, demand response and other distributed resources. In addition, tomorrow’s power system will have greatly enhanced sensory and control capability configured to accommodate these distributed resources as well as electric vehicles, direct consumer participation in energy management and efficient communicating appliances. In addition, tomorrow’s power system will be hardened against cyber security while assuring long-term operations of an extremely complex system of millions of nodes. This point is often masked in today’s euphoria about the smart distribution and consumer portions of the Smart Grid!

The Purpose of the London Workshop The purpose of the London workshop was to calibrate EPRI’s vision with the international community and to develop a strong, actionable framework for enabling the world to make definitive progress in deriving the benefits from the adoption of innovative technologies which will modernize today’s transmission system. This paper describes that framework and the steps necessary to implement it. It is a summary of a critical dialogue facilitated by EPRI and hosted by National Grid and ENTSO-E1 to engage utilities from the U.S., Europe, South Africa, New Zealand and Australia in a discussion as to how the electric industry could apply innovative technologies in order to continue to meet consumer demand in a reliable, economical and sustainable way through a strong and fully functional transmission system.

Why Has Transmission Modernization Not Accelerated? The state of advanced transmission technology can be characterized in four stages as illustrated below. Transmission owners and operators (so-called “utilities”) must regard engagement in these steps cautiously so as to assure that the result will add value. Each successful technology must move through each step until wide-scale adoption can be effectively realized.

1 The European Network of Transmission System Operators for Electricity (ENTSO-E) represents 40 transmission system operators (TSOs) from 34 European countries, representing 532 million customers with 880 GW of generation capacity and 305,000 km of transmission lines.

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Figure 1 Development Stages of Advanced Transmission Technologies

While there is a wide array of advanced transmission technologies on the horizon, there is considerable uncertainty as to which development stage they are in and their potential value to the individual utility. In addition, there is limited visibility as to the progress being made in their adoption by the wide range of individual utilities around the world.

In short, the transmission industry and its participants cannot easily accelerate global deployment of advanced transmission technologies without the ability to assess the current state of technology development and deployment so as to identify opportunities and gaps which need to be filled in order to leverage maximum value. In addition, a forum is needed wherein participants can assess best practices and share in implementation experiences.

The Industry Needs a Transmission Technology Adoption Report Card To define the way forward, workshop participants urged EPRI to engage with them and other industry practitioners in the development of a transmission technology adoption report card. The transmission technology adoption report card (TARC) would enable the industry to understand the state of development of each technology and the extent that others are in the process of researching, testing, demonstrating or deploying these technologies and the results they have achieved. In short, it would help determine where the industry is now with regard to technology so it can move forward. This would allow the industry to define which technologies need further development and deployment and what technologies are simply missing. The costs and complexity of these technologies will require wide-scale international industry collaboration. The TARC will facilitate that collaboration. A secondary benefit of the TARC would be to share best practices in transmission technology applications from around the world.

Research & Discovery

Innovation & Development

Demonstration

Commercialization & Diffusion

(wide-scale adoption)

• Basic Development• Proof of Concept

• System and Components Validated

• Early- and Late-Scale Demonstration

• Early- and Later-Stage Commercial Deployment (technology available commercially)

Research & Discovery

Innovation & Development

Demonstration

Commercialization & Diffusion

(wide-scale adoption)

• Basic Development• Proof of Concept

• System and Components Validated

• Early- and Late-Scale Demonstration

• Early- and Later-Stage Commercial Deployment (technology available commercially)

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Transmission Technology Adoption Report Card EPRI’s Transmission Technology Adoption Report Card (TARC) will be developed by a collaborative effort from across the industry worldwide. EPRI will begin by outlining the TARC for review and deliberation by the Transmission Forum participants and other advisors. Forum participants will subsequently further refine the TARC by conducting self-assessments of transmission assets, technology deployment, and operations. A key feature of this approach will be the opportunity to capture “best practices” of methods to demonstrate, adopt and deploy technologies. This information will be shared with all participants. By assessing the state of technology readiness and implementation, these utilities will drive modernization forward. Figure 2 illustrates one example of collaboration across utilities involved in researching transmission efficiency.

Figure 2 An Example of Collaboration Across Demonstrations in Transmission Efficiency

Preliminary discussions during the workshop suggested that the TARC contain four levels of assessment:

1. The Technology Readiness Level (TRL) of individual technologies.

2. The degree of implementation of technologies at the individual utility itself.

3. Attributes reflecting the ease of implementation.

4. The performance of technologies during demonstration or implementation and after commissioning.

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Technology Readiness Levels Technology Readiness Levels (TRLs) are a convenient means to describe the stage of technology development of transmission technologies. TRLs are systematic metric and measurement systems that support assessments of the maturity of a particular technology and the consistent comparison of maturity between different types of technologies. The TRL approach was originally developed by the National Aeronautic and Space Administration (NASA) as a means to manage NASA’s space-related R&.

TRL levels include (a) basic (blue sky) research in new technologies and concepts (targeted identified goals, but not necessarily specific systems); (b) focused technology development addressing specific technologies for one or more potential applications; (c) technology development and demonstration for each application; (d) system development; and (e) commercialization.

Nine TRL levels are used to describe the readiness of a transmission technology. Those definitions are as follows:

TRL 1 – Exploratory research transitioning basic science into laboratory application.

TRL 2 – Technology concepts and/or application formulated for transmission systems.

TRL 3 – Proof of concept validation.

TRL 4 – Subsystem or component validation in high-voltage laboratory environment to simulate service conditions.

TRL 5 – Early system validation demonstrated in high-voltage laboratory or limited field application on real transmission system.

TRL 6 – Early field demonstration and system refinements completed.

TRL 7 – Complete system demonstration in an operational environment on a loaded transmission line.

TRL 8 – Early commercial deployment (Serial Nos. 1, 2, etc.); technology can be purchased from electrical apparatus manufacturers.

TRL 9 – Wide-scale commercial deployment of the technology.

Figure 3 illustrates Technology Readiness Levels grouped by the broader categories illustrated in Figure 1.

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Figure 3 Technology Readiness Levels

Degree of Implementation The degree of implementation for any transmission utility ranges from early assessment to wide-scale deployment. Implementation may range through several stages as illustrated in Figure 4.

Figure 4 Implementation and Performance

A framework for assessing implementation and performance will be developed by EPRI. All elements of the TARC will be further refined.

Discovery Assessment Testing Demonstration Pilots Wide-Scale Deployment

• Aware of the technology

• Developing preliminary information as to its applicability

• Evaluation of possible value

• Assessment of potential integration

• Identify implementation steps

• Laboratory testing by utilities or third parties

• Initial demonstration of 1 to N units as needed to ascertain actual field performance

• Deployment of N+ units to validate wide-scale deployment

Discovery Assessment Testing Demonstration Pilots Wide-Scale Deployment

• Aware of the technology

• Developing preliminary information as to its applicability

• Evaluation of possible value

• Assessment of potential integration

• Identify implementation steps

• Laboratory testing by utilities or third parties

• Initial demonstration of 1 to N units as needed to ascertain actual field performance

• Deployment of N+ units to validate wide-scale deployment

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Technologies in the TARC Early in 2011, EPRI identified three technology pillars which will facilitate the transformation to a smarter transmission grid (see Figure 5): Grid Development and Operation, Asset Life-Cycle Management, and Information and Communication Technologies (EPRI 1022305). These technologies will form an essential part of the TARC assessment.

Figure 5 Technology Pillars for a Smarter Transmission Grid (Source: EPRI 1022305)

Grid Development and Operation Although the existing grid operations, planning processes, and technologies may be adequate to meet today’s needs, new processes and technologies are needed to address the challenges faced by grid planners and operators in a new era of power transmission. Unprecedented levels of variable generation and the integration of emerging supply- and demand-side technologies will challenge electric utilities as they continue to rely on and maintain an aging infrastructure to ensure reliability. The increased number of players and transactions in the electricity market and the ever-growing footprint of the vast electrical grid will significantly increase the complexity of grid operations. Figure 6 illustrates the challenges that variable generation from wind present to power systems, especially when wind power ramps do not correlate with demand variations or when they are not forecasted correctly.

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Figure 6 An Example of Wind Energy Variations that may or may not correlate with demand profile characteristics (NERC Special Report – Accomodating High Levels of Variable Generation, 2009)

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Asset Life-Cycle Management (LCM) Asset life-cycle management optimizes the use of existing transmission assets, builds new and efficient (high-capacity) transmission infrastructures, and develops and deploys a new generation of equipment. The ultimate goal of LCM efforts is to ensure and enhance the safety, reliability, security, cost-effectiveness, and power quality of the transmission grid.

Information and Communications Technology (ICT) As new technologies are deployed to enable a smarter transmission grid, the information and communication technology infrastructure will take on an increasingly critical role. Modern transmission technologies will demand more analytical horsepower and data-handling capabilities. These data will be large in volume and scattered through the interconnected network. The data sources will be diverse, including equipment health sensors, phasor measurement units (PMUs), intelligent electronic devices (IEDs), and weather sensors, among many other types. Some of these data will be harvested in real time, while others will be stored in a historian database. The challenge will be to ensure that the data and the associated information are made available to end users and end-user applications with the desired levels of accuracy, security, and speed.

Technologies Needed To accomplish the current vision of a modern transmission grid, deploying advanced technologies is essential. Such technologies include integrated communication across the grid; advanced methods of control; devices that sense, meter, and measure the parameters of electric power; and software and hardware that enable people to make better decisions. The next generation of the electrical grid will take full advantage of innovative materials, nanotechnologies, advanced power electronics devices and topologies, superconducting technologies, advanced computing, parallel processes, and fast simulation.

At the heart of the emerging Smart Grid is a network of communication devices that more precisely monitor grid parameters and provide a path toward an “aware” network that leads us toward the Holy Grail of the industry – “self-diagnostics.” Getting to this point requires carefully planned and coordinated steps that safely, reliably and securely move the industry toward the goal.

Managing the path toward a smarter transmission grid is complex and cumbersome due to the inter-relationships and dependencies between all the elements presented here. However, prudent planning along with technology roadmaps can play a key role in assuring the implementation sequence, and selections build upon one another effectively and reduce the likelihood of stranded investments, unreliable operations, and other missteps along the way. The time is now – to work collaboratively in transitioning to a smarter transmission grid in order to meet the future needs and expectations of the bulk power system.

Examples of Promising Applications for a Smarter Transmission Grid 1. Situational Awareness with “Look-Ahead” Capability – A set of situational-awareness

tools for control centers will be available to display present state (conditions) within and

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around the system of interest and to provide an indication of system conditions anticipated throughout the day.

2. Simulation Tools and Modeling – Grid planners and operators will have the ability to seamlessly transfer real-time EMS data to off-line simulation study tools for conducting off-line studies and to transfer results of off-line simulation studies to an energy management system (EMS) environment for display.

3. On-Line System Restoration – Decision-support tools will be available to system operators to restore their systems following a major blackout.

4. State Measurement (Evolving from State Estimation) – Currently, control centers use supervisory control and data acquisition (SCADA) technology, in which data from transmission substation remote terminal units (RTUs) are fed into a state-estimation (SE) engine, which calculates the state of the power system once every few minutes. In the future, PMUs will be installed at many of these substations, and an engine will instantly derive the state of the entire system.

5. Model Validation – Automated processes will be available for grid planners and operators to continuously validate the model(s) they use in real time and off-line power system studies.

6. Reactive Power Management – Grid operators will have the ability to identify in real time the potential areas of voltage instability and the corresponding dynamic and static reactive power requirements in these areas to avoid instability by deploying generator automatic voltage regulators (AVRs), capacitors, shunt reactors, static VAR controllers (SVCs), the flexible AC transmission devices (FACTS) devices, and power system stabilizers (PSSs).

7. On-Line Assessment of Voltage Security Performance – For each potential voltage-security or collapse scenario identified from off-line studies, PMU data will be used to calculate MW or MVAR margin available in real time before a voltage collapse could occur.

8. Automated Event Analysis – Automated tools will be available to replicate a system event using power flow and system dynamics simulation programs.

9. Electricity Storage for Transmission – Large-scale bulk-storage options will be available for deployment to address transmission needs.

10. Asset Health Center – Health sensors will be installed to remotely collect data from all major pieces of equipment across the system.

11. Increased Utilization of Right of Way – A set of tools, techniques, and technologies will be available to asset managers, grid planners and operators to enable (a) increased power flows on new and existing transmission lines, (b) reduced transmission line losses; and (c) safe and efficient use of right of way by multiple entities.

12. Advanced Grid Components – A set of advanced components will be available for their incorporation into the existing and new transmission infrastructures.

13. Substation IED Data Utilities – Data from protection and control (P&C) IEDs at substations will be transformed automatically into information by specialized techniques/utilities developed for this purpose.

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14. Advanced Computing Techniques and Communication Technologies – A robust and secure information and communication platform/infrastructure will be in place to meet the users’ needs; namely, the collection, analysis, processing, transmittal, storage, retrieval, and display of asset, system performance, and situational-awareness data, and the associated information derived from the data.

Figure 7 An Illustration of Communications for Condition Monitoring (Source: National Grid)

15. Substation Automation – Transmission substations will become data hubs, where data from within the substation as well as nearby transmission line structures will be collected.

16. Advanced Controls and Control Strategies – Advanced controls, such as adaptive relays and protection and control devices, will be available.

The specific technologies associated with each pathway are at various stages of development. However, common to all is the need to for sustained, substantial RD&D to accelerate commercial deployment and to enable technology performance and deployment than possible with existing technologies.

Next Steps: The Direction Forward Workshop participants universally agreed that it is “time to make progress.” Use of the EPRI transmission technology adoption report card would enable the industry at large to measure where it is now and how advancements in modernizing the transmission system can best be achieved.

Key to this achievement is the issue of defining the Smart Grid’s and transmission’s role in enabling it, as well as embracing the phenomenally complex elements of the overall grid and understanding its many barriers.

Switch in transformer cabinet on CORP LAN

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substation on corporate LAN

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Many smart applications have been identified. A number of them have been applied, some tested thoroughly, others not. Each transmission owner and/or operator has a different view of where technologies are in the development pipeline. Figure 8 is an example of how collaboration may identify opportunities to evolve technologies. In this example, the readiness level associated with SynchroPhasor applications is displayed.

Figure 8 SynchroPhasor Applications (Source: PJM)

In order to accelerate the development of transmission in the world, EPRI will convene a transmission forum in conjunction with ENTSO-E which will outline the performance measures and establish a framework (the TARC) to measure progress toward achieving a functional and strong(er) transmission system. It is proposed that each transmission owner and operator use the framework for a self-assessment. The forum will reconvene every nine to twelve months to measure progress overall and share best practices.

The Value of a Modernized Transmission System Power systems have begun to change over the last ten years, and numerous benefits have now been identified which would result from the widespread use of sensors, communications, and computational ability coupled with other advanced technologies. This overall modernization of transmission and distribution integrated with consumer energy management is typically called the “Smart Grid.” Most of the benefits of a Smart Grid cannot be realized without a fully functional and robust transmission system.

Today’s transmission system was not designed to meet the needs of a restructured electricity marketplace, the increasing demands of a digital society, or the increased use of renewable

Voltage Stability Monitoring

1-2 years 2-5 years >5 years

Disturbance Analysis

Determination of Accurate Operating Limits

Angle & Frequency Monitoring

Real-time Control of wide-area network

System Restoration

Improve State Estimation

Wide-area monitoring

Model Derivation & Validation

Detection of imminent Cascading

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TodayVoltage Stability Monitoring

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Determination of Accurate Operating Limits

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Detection of imminent Cascading

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1-2 years 2-5 years >5 years

Disturbance Analysis

Determination of Accurate Operating Limits

Angle & Frequency Monitoring

Real-time Control of wide-area network

System Restoration

Improve State Estimation

Wide-area monitoring

Model Derivation & Validation

Detection of imminent Cascading

Real-time control of corridors

Dep

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Ready to deployNeeds moderate development

Requires more research

Inter-area Oscillation Detection & Analysis

Today

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power production. In addition, investments in expansion and maintenance are constantly being challenged, and the existing infrastructure has become vulnerable to various security threats.

Achieving the vision of a modern transmission system will require careful policy formulation, accelerated infrastructure investment, and greater commitment to public/private research, development, and demonstration (RD&D) to overcome barriers and vulnerabilities.

Table 1 shows that the estimated net investment needed to realize the envisioned power delivery system (PDS) of the future for the U.S. is between $338 and $476 billion. The total value estimated range is between $1,294 and $2,028 billion, and when compared to the future PDS cost estimate results in a benefit-to-cost ratio range of 2.8 to 6.0 (EPRI 1022519).

Table 1 Summary of Estimated Cost and Benefits of the Smart Grid

20-Year Total ($ billions)

Net Investment Required 338 – 476

Net Benefit 1,294 – 2,028

Benefit-to-Cost Ratio 2.8 – 6.0

The benefits of a smarter transmission system are numerous and stem from a variety of functional elements which include cost reduction, enhanced reliability, improved power quality, increased national productivity, and enhanced electricity service, among others. Table 2 summarized these benefits for the U.S.

Table 2 Estimated Benefits of a Smarter Transmission System (EPRI 1022519)

Attribute New Present Worth

(2010 $ billions)

Low High

Productivity 1 1

Safety 13 13

Environment 102 390

Capacity 299 393

Cost 330 475

Quality 42 86

Quality of Life 74 74

Even though the cost of transmission ownership, operation and maintenance is typically only 7% to 10% of a consumer’s electricity bill, these Smart Grid benefits cannot be realized without

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resilient transmission networks. In order to access the benefits highlighted in Table 2, the attributes of tomorrow’s transmission system must be enhanced to:

• Accommodate all generation and storage options

• Enable new products, services and markets

• Provide power quality for the digital economy

• Optimize asset utilization and operational efficiency

• Anticipate and respond to system disturbances (self-heals)

• Operate resiliently against attack and natural disaster

Adequate Transmission is also needed Modernization – by itself – is not sufficient to realize the benefits tomorrow’s power system can bring to fruition. Without adequate and reliable transmission capacity, the applications described in this paper will not be fully realized.

However, transmission upgrades and expansion do bring forward opportunities to embrace advanced technologies – ones which are interoperable with the existing and planned adoption of other advanced components. These technologies can be adopted along with necessary upgrades and expansion and reduce marginal cost.

There will be intra- and inter-regional differences in how upgrades and expansion will evolve. Some of these differences may result in supergrids with regional high-voltage overlays, perhaps with on-and-off ramps of high-voltage DC and/or high-voltage AC. There are several examples where these concepts of upgrades and expansion have been analyzed.

European Supergrid – One option for the future transmission system being debated in Europe is the European Supergrid. This is one approach to expanding interconnection so as to facilitate a truly cross-European wholesale market. Several options are being debated which would define a European Supergrid: (1) enhance the interconnections between countries/systems across Europe; (2) enhance the interconnections between synchronous zones within Europe and Europe’s neighbors; (3) creating and overlaying another Supergrid on current European networks; or to create an offshore North Sea grid by either reinforcing interconnections and/or including wind farms feed into interconnections.

The European Supergrid’s development is being driven by three elements:

• Assist creation of a single European electricity market

• Integrate renewable energy supplies (provide flexibility through better interconnection across balancing authorities)

• Enhance security of supply

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Figure 9 Illustration of European Supergrid

The U.S. Department of Energy commissioned the U.S. National Renewable Energy Laboratory (NREL) to conduct a study highlighting the potential for 20% of U.S. electric energy supply to be accommodated by wind energy by the year 2030 (NREL, 2008). This study concluded that “a new transmission superhighway would be required” if the U.S. were to enable 20% of its electricity production supplied from wind. NREL concluded that it is more efficient to site wind projects in higher-quality wind resource areas that are remote from load and require transmission. NREL projected that it would be cost-effective to build more than 12,000 miles of additional transmission at a cost of approximately $20 billion. Much of that capacity would be required in later years after an initial period in which generation is able to use the limited remaining capacity available on the existing transmission grid (http://www.nrel.gov/wind/systemsintegration/pdfs/2008/20_percent_wind.pdf).

The U.S. Midwest ISO recently studied the costs of developing 16,000 MW of wind within its system, along with 5,000 miles of new 765 kV transmission lines to deliver the wind from the Dakotas to New York State. Although the overall costs reached an estimated investment of $13 billion, the project produced annual savings of $600 million over its costs. These saving are in the form of lower wholesale power costs and prices in the eastern part of the Midwest ISO footprint, resulting from greater access to lower-cost generation in western states such as Iowa and the Dakotas (https://www.midwestiso.org/Library/Repository/Study/JCSP/JCSP_Report_Volume_1.pdf).

Figure 10 illustrates various U.S. transmission system upgrade scenarios for connecting areas with high wind resource potential to major load centers.

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Figure 10 Transmission system upgrade scenarios. New 765-kV lines are shown in green and new interties in black, complementing the existing 765-kV system shown in red, to facilitate deployment of up to 400 GW of additional wind capacity. (Sources: AEP 2007; DOE 2008)

American Electric Power (AEP), a large utility and transmission owner/operator, conducted a similar study as to what it would take to integrate 20% electricity from wind. AEP concluded that 19,000 miles of new 765 kV transmission line at a discounted or net present value cost of $26 billion would be required (AEP, 2007).

ERCOT, the independent transmission operator for most of Texas, evaluated 12 options to build transmission for additions of 1,000 MW to 4,600 MW of wind energy. ERCOT found that the transmission addition would cost between $15 million and $1.5 billion, depending on the distance required (http://www.ercot.com/news/presentations/2006/ATTCH_A_CREZ_Analysis_Report.pdf).

The United Kingdom’s (UK) transmission networks will need to undergo an extensive expansion and upgrading (National Electricity Transmission System Seven Year Statement, May 2011 available at www.nationalgrid.com). This will be driven by:

• Radical change in generation mix which will reverse critical power flows and the location of generation sources. By 2020, the UK will shut down 25% of existing coal, oil and nuclear plants.

• Integration of substantial offshore wind.

• Electrification from conversion of building heating systems from fossil fuels to electric heat pumps and the adoption of electric vehicles.

• The need for stronger ties with neighboring countries.

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Figure 11 Illustration of the United Kingdom’s Transmission Challenge (Source: National Grid)

Figure 12 Accommodating Increased Volume of Renewables from Scotland with Onshore and Offshore Solutions

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Australia’s National Electricity Market (NEM) comprises 90% of Australia’s electricity usage. Western Australia and the Northern Territories have isolated power systems and are not part of the NEM due to their remoteness. Sparse networks and weak interconnections limit Australia’s ability to generate electricity from remote energy sources (Energy Transmission Network Planning, Infrastructure Australia, 2010).

Australia’s peak demand is growing very fast. For example, peak demand in Queensland is projected to be approximately 28% from 2010/11 to 201/16.

Australia’s electricity industry’s opportunities are complicated by three elements:

1. Explosive growth of a new coal seam methane LNG export industry.

2. A new Renewable Energy Climate Change Policy (RECCP) which contains a Mandatory Renewable Energy Trading Scheme (MRET).

3. A Carbon Emission Climate Change Policy. The federal government attempted to introduce a Carbon Pollution Reduction Scheme (CPRS) so that polluter would have to pay for CO2 emissions.

Australia has abundant renewable energy resources located thousands of kilometers from the main grid. There is wind power along the south coast, solar in the center and north, and geothermal in central Australia. Stronger interconnections and an inland supergrid will be required to develop these renewable resources.

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Figure 13 Increased Need for Transmission in Australia to Bring Renewables to Population Centers (Geothermal Energy in Australia, Geodynamics Annual Report, 2007)

Conclusion There is a worldwide imperative to modernize and enhance the power delivery system. Tomorrow’s transmission system is envisioned to provide the enhancements to ensure high levels of security, quality, reliability, and availability (SQRA) of electric power; to improve economic productivity and quality of life; and to minimize environmental impact while maximizing safety and sustainability. Tomorrow’s transmission system must be capable of accommodating pervasively collaborative distributed intelligence, including flexible wide band gap communications, dynamic sharing of all intelligent electronic devices and distributed command and control.

EPRI and the forum participants have defined a Way Forward. They have committed to establish a framework, including a Transmission Technology Application Report Card (TARC), under which the industry could embrace the development of a transmission system around the world which is able to broadly meet tomorrow’s needs. EPRI has committed to draft the TARC. Transmission owners and operators from around the world have expressed interest in using the TARC to conduct a self-assessment.

Those self-assessments will then be used to form a collective repository to accelerate modernization of transmission systems. The forum will reconvene at 9- to 12-month cycles to measure progress and to share best practices.

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References European Smart Grid Technology Platform: Vision and Strategy for Europe’s Electricity Networks of the Future, European Commission, publications.eu.int, 2006.

ENTSO-E Strategic Plan, European Network of Transmission System Operators for Electricity, ENTSO-E, December 16, 2009.

Offshore Grid Development in the North Seas – ENTSO-E Views, European Network of Transmission System Operators for Electricity, ENTSO-E, February 2011.

The Challenges Facing AC Offshore Substations for Wind Farms, CIGRẾ WB B3.26, ELECTRA, CIGRẾ, Paris, France, December 2010.

Factsheet 2011, ENTSO-E, European Network of Transmission System Operators for Electricity, ENTSO-E, Brussels, Belgium, February 2011.

Technology Roadmaps: Smart Grids, International Energy Agency (IEA), Paris, France, 2011.

Power Deliver & Utilization International Council Meeting Briefing Book, K. Forsten, EPRI, Knoxville, TN, USA, June 2011.

The NETL Modern Grid Initiative: A Systems View of the Modern Grid, National Energy Technology Laboratory, U.S. Department of Energy, Office of Electricity Delivery and Energy Reliability, January 2007.

Estimating the Costs and Benefits of the Smart Grid: A Preliminary Estimate of the Investment Requirements and the Resultant Benefits of a Fully Functioning Smart Grid, EPRI, Palo Alto, CA: January 2011, 1022519.

20% Wind Energy by 2030: Increasing Wind Energy’s Contribution to U.S. Electricity Supply, U.S. Department of Energy, National Renewable Energy Laboratory (NREL), July 2008.

2010 Long-Term Reliability Assessment, North American Electric Reliability Corporation, October 2010.

The Power to Reduce CO2 Emissions: Transmission Efficiency, EPRI, Palo Alto, CA: May 2010, ___________.

A Smarter Transmission Grid, EPRI, Palo Alto, CA: January 2011, 1022305.

Final Report on the August 14, 2003 Blackout in the United States and Canada, North American Electric Reliability Corporation, 2004.

Wind Power: Issues and Opportunities for Advancing Technology, Expanding Renewable Generation and Reducing Emissions, EPRI, Palo Alto, CA: January 2011, 1023455.

Renewable Energy: Solar Power Continues to Push Its Way into New Markets, Despite Recession, Umar Irfan, E&E Reporter, July 25, 2011.

Interstate Transmission Vision for Wind Integration, American Electric Power, White Paper available at 222.aep.com, 2007.

20% by 2030: Increasing Wind Energy’s Contribution to U.S. Electricity Supply, U.S. Department of Energy, Report #DOE/GO-102008-2567, Oak Ridge, TN, 2008.

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International Energy Outlook 2010, U.S. EIA, Report #DOE/EIA-0484, Washington, DC, 2010.

Needed: A Grid Operating System to Facilitate Grid Transformation, EPRI, July 2011, 1023223.

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Appendix

Opportunities Which a Modernized Transmission System Will Address There is a substantial opportunity for a modernized transmission system to be more resilient to natural or man-made disasters and to be better able to operate reliably under complex and variable flows which will result from the widespread diffusion of variable generation coupled with increasingly complex market dynamics. The following are examples of opportunities which can be addressed through such modernization.

Renewable portfolio standards have been established in 30 of the 50 U.S. states plus the District of Columbia stimulating rapid expansion of renewable technology and accelerating the need for Smart Grid technology for grid integration. EPRI’s analysis anticipates 135 GW of renewables In the U.S. by 2030 (EPRI 1020389). A number of states have also enacted policies to address specific environmental concerns. In Europe, the European Union has adopted a goal to achieve 20% of power generation from renewable resources (principally wind and solar) by 2020.

Wind power generation meets an increasing share of electricity demand in the world. And with rising regulatory and legislative pressure, little or no fuel requirements, a low CO2 “footprint” and huge regional resources, wind power is expected to play a significant role in future electricity production. In the next 20 to 25 years, central station wind is expected to increase the renewable component of generation more than tenfold. Increases to 20% or 30% of total generation are a real possibility by 2030. Already, some areas in Europe, New Mexico, and California see wind penetration levels as high as 10% to 15% of capacity. Even higher penetrations have occurred in European grids.

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Figure 14 European 2020 Wind Figures (Source: NREAP)

Figure A-2 Even relatively conservative projections forecast substantial growth in U.S. and global wind capacity, particularly across the next decade. Duplicating what occurred from 2000 to 2010, another 10-fold increase in capacity is expected through 2050. (Source: EIA, 2010)

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Photovoltaic future costs are continuing to decline, implying increased penetration in the near future even without government incentives. Some manufacturers are citing $1.40/watt costs for panels with a 10% drop in price per year for the foreseeable future. This is down from $5.25/watt just three years ago, largely by Chinese firms collapsing the supply chain, vertically integrating and squeezing out costs. Some industry experts see panel costs reaching $1.20/watt by the end of the year, possibly $0.70/watt by the end of 2012 and $0.15/watt by the end of 2014.

Efficiency of transmission systems can be enhanced resulting in substantial reductions in energy needs and transmission-related CO2 reductions. There are two principal avenues to accomplish this. The first is through transmission energy savings. The second is through enhanced utilization of transmission to enable integration of higher levels of efficient generation. Together these two approaches can increase transmission efficiency by 20% and, for example, reduce U.S. electric sector CO2 emissions by 1.4% relative to projected 2030 levels. The efficiency gains represent an annual savings of 28.6 TWh in the U.S. by 2030, enough to power 2.5 million homes. The annual CO2 emissions savings amount to approximately 41 million tons per year by 2030. If wholesale electricity is valued at 6.5 cents per kWh2, and CO2 is valued at $65 per ton3 in 2030, annual savings will be approximately $4.5 billion (EPRI_________).

Figure A-3 Transmission Loss Potential from Aggressive Modernization to Improve Efficiency (EPRI _________)

Demand response programs are accelerating. The U.S. Federal Energy Regulatory Commission’s (FERC’s) 2008 Demand Response (DR) and Automated Metering Infrastructure (AMI) Survey indicated that advanced metering penetration reached 4.7% of total meters, up from less than 1% in 2006, and that 8% of U.S. customers were currently involved in DR programs. DR continues to gain ground through state legislative initiatives and utility regulation.

2 EIA – Electricity Supply, Disposition, Prices, and Emissions, Reference case. Generation prices (2008 cents/kWh). 3 EIA report “Energy Market and Economic Impacts H.R. 2454, the American Clean Energy and Security Act of 2009 (ACESA).” GHC allowance prices projection corresponding to the ACESA Base Case.

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FERC’s “A National Assessment of Demand Response Potential – Staff Report” in June 2009 and FERC’s staff report “National Action Plan on Demand Response” in June 2010 highlight the potential (FERC, 2009 and 2010). Several European utilities are now embracing demand response programs to help manage demand. Many more are planning to do so.

Outage prevention becomes increasingly important in an information-service-based economy. There have been a number of major blackouts in the last 40 years, three of which occurred in the last decade. The societal cost of a massive blackout is estimated to be in the order of $10 billion per event (NERC, 2004). Power quality and reliability problems are estimated to cost the U.S. $119 to $188 billion per year (EPRI 1006274).

Carbon reduction has become an international imperative. A modern transmission system is capable of providing a significant contribution to the goals of energy and carbon savings, as documented in two recent reports:

• One report by EPRI states that the emissions reduction impact of a Smart Grid is estimated at 60 to 211 million metric tons of CO2 per year in 2030 (EPRI ___________).

• Another report by Pacific Northwest National Laboratory (PNNL) states that full implementation of Smart Grid technologies is expected to achieve a 12% reduction in electricity consumption and CO2 emissions in 2030 (PNNL ___________).

And in another report, EPRI estimated that an enhanced U.S. transmission system, combined with a portfolio of generation and end-use options, could reduce 2030 annual CO2 emissions from the electric sector by 58% relative to 2005 emissions (EPRI 100389).

System stability and frequency is deteriorating. System stability is a synchronized power system’s ability to regain a state of operating equilibrium after being subjected to an electrical disturbance. Frequency response is a measure of an interconnected power system’s ability to stabilize its frequency immediately following a sudden loss of generation or rapid change in load. There is a concern that frequency response is declining.

The decline in frequency response primarily stems from changes in the way fossil- and nuclear-powered units are being operated to meet environmental and business goals along with reduced response from motor-driven loads and the installation of photovoltaics (PV) and wind generation which has limited frequency response. For example, at present there are approximately 20 gigawatts of rooftop photovoltaics in Germany. They are set to disconnect at 50.2 Hz on the European 50 Hz system. As the otherwise uncontrolled PV generation causes the frequency to rise above 50.2 Hz – all 20 gigawatts can disconnect simultaneously.

In its 2010 Long-Term Reliability Assessment (NERC, 2010), NERC reported that the North American electric industry has prepared adequate plans for the 2010 to 2019 period to provide reliable electric service. However, NERC highlighted the fact that many issues may affect the implementation of these plans. Key among them was:

• An unprecedented, continuing change in the generation fuel mix is expected during the next ten years, which includes significant increases in new gas-fired, wind, solar, and nuclear generation.

• Vital bulk power transmission development begins to take shape, strengthening the bulk power system as well as integrating the high levels of projected variable generation.

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Aging assets will plague the electricity sector in developed countries in the decades ahead. For example, in the U.S., the average date of commissioning power plants is 1960, as are the transmission corridors which connect them. In addition, the average age of substation transformers is 42 years, while their design life is 40 years. As such, the existing transmission system in many countries will need to embrace more aggressive asset management strategies, undertake replacements and upgrades, and consider modernization as modifications are made to ensure adequate reliability, meet growth and enable integration of renewables.

What is the Vision for Tomorrow’s Transmission System? Global transmission initiatives have become a major driving force towards building a new and efficient transmission infrastructure, improving the operating efficiency of the existing infrastructure, and deploying advanced technologies. This will enhance the capacity, safety, reliability, security, efficiency, and economic operation of the interconnected power systems to meet the ever-changing and sophisticated needs of consumers in the 21st century.

Today’s transmission grid already employs some intelligent technologies so that asset managers as well as grid planners, designers, and operators can meet today’s needs. For example, transmission control centers employ system data-acquisition and situational-awareness tools that can help operators identify potential adverse operating conditions across the power system. However, these technologies will not meet future needs (EPRI 1022305).

Because the electricity infrastructure is aging, the electric utility industry must charter more vigorous efforts to diagnose the health of assets and to apply innovative life-extension and replacement strategies. Additionally, concerns over cyber security are mounting because the industry is relying more on the Internet, as well as networks and applications based on Internet protocol. Compliance with reliability, security, and safety criteria and standards has become a paramount goal for the industry. Additionally, environmental issues such as CO2 emissions constraints and greenhouse gas emissions reductions need to be addressed.

Tomorrow’s transmission systems must be strong and resilient to allow the integration of technologies to enable the following functionality (NETL 2007):

• Self-healing.

• Resist both physical and cyber attacks.

• Enable the ability for distribution systems to motivate consumers to participate in saving energy; these functions require integration with the transmission system.

• Provide a high level of power quality for 21st century needs.

• Accommodate all generation and storage options.

• Enable wholesale and retail electricity markets to mature and flourish, optimizing assets and enabling efficient operation.

The International Energy Agency’s (IEA) Technology Roadmap – Smart Grid envisions a Smart Grid focused on similar elements (IEA 2011). The IEA Roadmap highlights eight key technologies which are essential to the development of the Smart Grid:

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Technology Area Hardware

Wide-area monitoring and control Phasor measurement units (PMU) and other sensor equipment

Information and communication technology integration

Communication equipment (power line carrier, WIMAX, LTE, RF mesh network, cellular), routers, relays, switches, gateway, computers (servers)

Renewable and distributed generation integration

Power conditioning equipment for bulk power and grid support, communication and control hardware for generation and enabling storage technology

Transmission enhancement Superconductors, FACTS, HVDC

Distribution grid management Automated re-closers, switches and capacitors, remote-controlled distributed generation and storage, transformer sensors, wire and cable sensors.

Advanced metering infrastructure Smart meter, in-home displays, servers, relays

Electric vehicle charging infrastructure Charging infrastructure, batteries, inverters

Customer-side systems Smart appliances, routers, in-home display, building automation systems, thermal accumulators, smart thermostat

The European Union’s (EU) European Smart Grids Technology Platform offers a similar vision and strategy as it defines Europe’s Electricity Networks of the Future. The vision is about a bold program of research, development and demonstration that charts a course towards an electricity supply network that meets the needs of Europe’s future. The EU envisions that Europe’s electricity networks must be:

• Flexible: fulfilling customers’ needs while responding to the changes and challenges ahead.

• Accessible: granting connection access to all network users, particularly for renewable power sources and high-efficiency local generation with zero or low carbon emissions.

• Reliable: assuring and improving security and quality of supply, consistent with the demands of the digital age with resilience to hazards and uncertainties.

• Economic: providing best value through innovation, efficient energy management, and “level playing field” competition and regulation.

ENTSO-E has established a ten-year network development plan (TYNDP) for Europe. The plan is intended to respond to the European Union’s energy policy goals by addressing three elements:

• Sustainability/GHG:

− More renewables, further from the loads

− More heating and mobility with electricity

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• Competitiveness/market integration: − More long-distance flows

• Security of supply

− More optimal resources sharing

Security of supply, market, and renewable energy integration are evolving priorities based upon EU policies which call for massive development of transmission grids, both between and within countries. Seamless integration of electricity highways into the 400 kV grids demands that European transmission system operators (TSOs) take ownership and secure operations. However, permitting and public acceptance is the key issue; without radical changes, policy objectives will not be met.

European transmission capacities depend on lines within countries and cross-border, and as much on the existing 400 kV grids as on post-2020 innovative higher voltages. Whatever the option, “smart grids, electricity highway, offshore grids…” ENTSO-E believes that seamless integration with the existing networks (design and operation) equal prerequisite for reliability (ENTSO-E _____________).

The TYNDP represents approximately 14% of existing lines or 42,000 km. This includes 9600 km of new DC lines, 2900 km of AC lines less than 300 kV (17% of which are upgrades) and 29,600 km of AC lines greater than 300 kV (22% of which are upgrades).

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Figure A-4 Possible Projects of EU Significance

Technologies Highlighted by Workshop Participants During the workshop, participants highlighted a number of specific technologies that they believe should receive priority in development. These are highlighted in Table A-1.

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Table A-1 Technologies Highlighted by Workshop Participants

Information & Communications

Grid Development & Operations

Asset Life-Cycle Management

• Intelligent Electronic Devices

• Sensors • Condition Monitoring • Cyber Security • Communications

• Forecasting • System Planning &

Operations Tools • Dynamic Modeling • Cycling Generation • Demand-Response

Technologies • Visualization • Data Mining • Grid Management • Microgrids • Load Response • Synchrophasors • Scheduling Tools • Economic Modeling

• Undergrounding • High-Voltage DC

Technologies • Electric Energy Storage • Power Electronics • Consumer Acceptance &

Response • Cable & Conductors • Non-Destructive

Evaluation • Smart Phone Apps for

Power Systems • Energy-Efficient

Technologies

Workshop participants stressed that regardless of which advanced technology is under consideration, there are a number of overarching issues which must be considered. These include the following:

• Technologies should be broadly compatible and interoperable with the existing power system and allow the flexibility to expand as needed.

• Where possible, technologies which are fungible to the extent they can be part of “products” which can be offered by TSOs/ISOs/RTOs in the wholesale market.

• The industry at large needs to understand the policy implications of all technologies, and it must be prepared to inform both the public at large and policymakers of the consequences of various policy actions regarding technology deployment.

• Interconnection standards will continue to drive the adoption of certain technologies.

• The industry needs to understand how the adoption of various technologies impacts the interaction between fuels.

• The technology which will be part of a modern transmission system will necessitate a workforce with different skills. Techniques to capture the knowledge embedded in today’s workforce and training the workforce of the future must be part of an overall grid modernization program.

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Acknowledgements

Name Company Title

Robbie Aherne EirGrid Operations Engineer

Santiago López Barba Red Eléctrica de España, S.A.U. Network Security Manager

Simon Bartlett Powerlink Chief Operating Officer

Colin Bayfield ScottishPower Energy Networks Network Development Manager

Sanjay Bose Consolidated Edison of New York, Inc.

Vice President, Substation Ops.

Terry Boston PJM Interconnection President & CEO

Karima Boukir EDF UK R&D Coordination, Management of Intermittent Renewable Energies

Jenny Cooper National Grid-UK R&D Specialist

Kevin East Electric Power Research Institute (EPRI)

International Director, Technical Advisory Services

Nigel Edwards EDF Energy plc Project Director, European Liaison

Angelo Ferrante Terna Head of International Regulation

Damian Flynn Electricity Research Centre (ERC) at University College Dublin

Deputy Director

Karen Forsten Electric Power Research Institute (EPRI)

Director, Power Delivery & Utilization

Clark Gellings Electric Power Research Institute (EPRI)

Fellow

Doug Goodwin Transpower New Zealand Ltd. System Operator Development Manager

Mike Heyeck American Electric Power Sr. Vice President, Transmission

Sue Higgins National Grid-UK Olympics Project Manager

Steven Holiday National Grid-UK Chief Executive Officer

Paul Hollinshead Department of Energy & Climate Change (DECC)

Director of Science & Innovation

Chavdar Ivanov European Network of Transmission System Operators for Electricity (ENTSO-E)

Research & Development Advisor

Carl Johnstone National Grid-UK Condition Monitoring Lead Engineer

CWG/9316P Rev 7 8-26-11 32

Name Company Title

Jussi Jyrinsalo Fingrid Oyj Sr. Vice President, System Development

Diyar Kadar ScottishPower Energy Networks Technology Manager

Hubert Lemmens Elia Group Head of Innovation & Knowledge Management

Rob Manning Tennessee Valley Authority Executive Vice President, Power System Operations

Arshad Mansoor Electric Power Research Institute (EPRI)

Sr. Vice President, Research & Development

Joseph McClelland Federal Energy Regulatory Commission (FERC)

Director, Office of Electric Reliability

Mark McGranaghan Electric Power Research Institute (EPRI)

Vice President, Power Deliver & Utilization

Sikelela Mkhabela Eskom Regional Engineering Manager

Rana Mukerji New York Independent System Operator

Sr. Vice President, Market Structures

Mongezi Ntsokolo Eskom Divisional Executive, Transmission

Rónán O’Hogartaigh ESB Networks Operations Manager, Asset Manager

Terry Oliver Bonneville Power Administration Chief Technology Innovation Officer

Mark Osborne National Grid-UK Asset Policy Engineer

Peter Sebola Eskom Regional General Manager

Seya Shayi Eskom Executive Assistant

Richard Smith National Grid-UK Future Networks Manager

Konstantin Staschus European Network of Transmission System Operators for Electricity (ENTSO-E)

Secretary General

Jim Sutherland ScottishPower Energy Networks Network Development Director

Ian Welch National Grid-UK R&D Strategy Manager, Asset Management

Nick Winser National Grid-UK Executive Director Transmission

Didier Wiot Elia Engineering SA Head of Technical Governance & eXpertise (TGX)