Power Flows -- Power System Analysis and Design

Successful power system operation under normal balanced three-phase steady-state conditions requires the following:

1. Generation supplies the demand (load) plus losses.

2. Bus voltage magnitudes remain close to rated values.

3. Generators operate within specified real and reactive power limits.

4. Transmission lines and transformers are not overloaded.

The power-flow computer program (sometimes called load flow) is the basic tool for investigating these requirements. This program computes the voltage magnitude and angle at each bus in a power system under balanced three-phase steady-state conditions. It also computes real and reactive power flows for all equipment interconnecting the buses, as well as equipment losses.

Both existing power systems and proposed changes including new generation and transmission to meet projected load growth are of interest.

Conventional nodal or loop analysis is not suitable for power-flow studies because the input data for loads are normally given in terms of power, not impedance. Also, generators are considered as power sources, not voltage or current sources. The power-flow problem is therefore formulated as a set of nonlinear algebraic equations suitable for computer solution.

In Sections 1-3 we review some basic methods, including direct and iterative techniques for solving algebraic equations. Then in Sections 4-6 we formulate the power-flow problem, specify computer input data, and present two solution methods, Gauss-Seidel and Newton-Raphson. Means for controlling power flows are discussed in Section 7. Sections 8 and 9 introduce sparsity techniques and a fast decoupled power-flow method, while Section 10 discusses the dc power flow, and Section 11 considers the power-flow representation of wind turbine generators.

Since balanced three-phase steady-state conditions are assumed, we use only positive-sequence networks in this section. Also, all power-flow equations and input/output data are given in per-unit.

EXAMPLE CASE:

Power-flow programs are used to analyze large transmission grids and the complex interaction between transmission grids and the power markets. Historically, these transmission grids were designed primarily by local utilities to meet the needs of their own customers. But increasingly there is a need for coordinated transmission system planning to create coordinated, continent-spanning grids. The following article details some of the issues associated with such large-scale system planning.

Future Vision: The Challenge of Effective Transmission Planning

Exceptional forces are changing the use of the transmission infrastructure in the United States. There are high expectations that the transmission system will support and enable national-level economic, renewable energy, and other emerging policy issues.

The U. S. transmission system was developed in a piece meal fashion. Originally, transmission systems connected large generation facilities in remote areas to users of the electricity they produced. Shortly thereafter, utilities started to interconnect their systems in order to realize the benefits of improved reliability that larger systems offer and to get access to lower cost energy in other systems. Subsequent transmission lines were typically added incrementally to the network, primarily driven by the needs of the local utility and without wide-area planning considerations.

Opportunistic usage of the transmission system be yond its design occurred early in the U. S. electric system.

The need for coordinated transmission planning among utilities soon followed. As early as 1925, small power pools formed to take advantage of the economies of developing larger, more cost-effective power plants that were made possible by the expanding transmission net work. By today's standards, these power pools were rather simple affairs made up of localized pockets of utilities that shared the expenses of fuel and operation and maintenance of shared units.

Today, the transmission system is increasingly being called upon to serve as the platform to enable sophisticated and complex energy and financial transactions. New market systems have been developed that allow transactions interconnection-wide. Today, a utility can purchase power without knowing the seller. These same market systems have the ability to enable transactions to be interconnection-wide and will soon accommodate the ability of load-serving entities to bid in their loads.

As the barriers to participate in electricity markets start to disappear, the U. S. electric system starts to look small from the perspective of market participants. In his book The World is Flat, author Thomas Friedman states, ''The world is flat.'' That is, the location of producers and consumers no longer matters in the world. It is the expectation of wholesale electricity market participants that they can soon claim, ''The transmission system is flat.'' That is, the transmission system is such that the location of power producers and power purchasers does not matter in terms of participation in national electricity markets.

Unfortunately, the vast majority of transmission infra structure was not designed for this purpose. The existing transmission infrastructure is aging, and new transmission investment hasn't kept pace with other development. This article discusses these challenges and then presents a vision for the future where effective planning can address the transmission expectations of today.

BENEFITS OF TRANSMISSION

The primary function of transmission is to transport bulk power from sources of desirable generation to bulk power delivery points. Benefits have traditionally included lower electricity costs, access to renewable energy such as wind and hydro, locating power plants away from large population centers, and access to alternative generation sources when primary sources are not available.

Historically, transmission planning has been done by individual utilities with a focus on local benefits. However, proponents of nationwide transmission policies now view the transmission system as an ''enabler'' of energy policy objectives at even the national level. This is an understandable expectation since a well-planned transmission grid has the potential to enable the following:

• Efficient bulk power markets. Bulk power purchasers should almost always be able to purchase from the lowest cost generation. Today, purchasers are often forced to buy higher-cost electricity to avoid violating transmission loading constraints. The difference between the actual price of electricity at the point of consumption and the lowest price on the grid is called the ''congestion'' cost.
• Hedge against generation outages. The transmission system should typically allow access to alternative economic energy sources to replace lost resources. This is especially critical when long-term, unplanned outages of large generation units occur.
• Hedge against fuel price changes. The transmission system should allow purchasers to economically access generation from diversified fuel resources as a hedge against fuel disruptions that may occur from strikes, natural disasters, rail interruptions, or natural fuel price variation.
• Low-cost access to renewable energy. Many areas suitable for producing electricity from renew able resources are not near transmission with spare capacity. The transmission system should usually allow developers to build renewable sources of energy without the need for expensive transmission upgrades (ill. 1).
• Operational flexibility. The transmission system should allow for the economic scheduling of maintenance outages and for the economic reconfiguration of the grid when unforeseen events occur.

Many of these benefits are available on a local level, since transmission systems have been planned by the local utility with these objectives in mind. However, these benefits are not fully realized on a regional or national level, since planning has traditionally been focused on providing these benefits at the local level.

AGING TRANSMISSION SYSTEM

Even at a local level, transmission benefits are in jeopardy.

For the past 20 years, the growth of electricity demand has far outpaced the growth of transmission capacity.

With limited new transmission capacity available, the loading of existing transmission lines has dramatically in creased (ill. 2). North American Reliability Corporation (NERC) reliability criteria have still been maintained for the most part, but the transmission system is far more vulnerable to multiple contingencies and cascading events.

A large percentage of transmission equipment was in stalled in the postwar period between the mid-1950s and the mid-1970s, with limited construction in the past 20 years. The equipment installed in the postwar period is now between 30 and 50 years old and is at the end of its expected life (ill. 3). Having a large amount of old and aging equipment typically results in higher probabilities of failure, higher maintenance costs, and higher replacement costs. Aging equipment will eventually have to be replaced, and this replacement should be planned and coordinated with capacity additions.

According to Fitch Ratings, 70% of transmission lines and power transformers in the United States are 25 years old or older. Their report also states that 60% of high-voltage circuit breakers are 30 years old or older. It is this aging infrastructure that's being asked to bear the burden of increased market activity and to support policy developments such as massive wind farm deployment.

ill. 1 Potential sources of renewable energy concentrations (U.S. Department of Energy, National Electric Transmission Congestion Study, 2006)

ill. 2 Transmission capacity normalized over MW demand ( E. Hurst, U.S. Transmission Capacity: Present Status and Future Prospects, prepared for EEI and DOE, Aug. 2004)

ill. 3 The age distribution of wood transmission poles for a Midwestern utility. Most of these structures are over 30 years old

Today, the industry is beginning to spend more money on new transmission lines and on upgrading existing transmission lines. It is critical that this new transmission construction be planned well, so that the existing grid can be systematically transformed into a desired future state rather than becoming a patchwork of incremental decisions and uncoordinated projects.

PLANNING CHALLENGES

As the transmission system becomes flatter, the processes to analyze and achieve objectives on a regional or interconnection-wide basis have lagged. Current planning processes simply don't have the perspective necessary to keep pace with the scope of the economic and policy objectives being faced today. While the planners of transmission owners often recognize these needs, ad dressing these needs exceeds the scope of their position.

Regional transmission organizations exist today, but these organizations don't have the ability to effectively plan for interconnect-wide objectives.

PLANNING BEFORE OPEN ACCESS

Before access to the electric system was required by the Federal Energy Regulatory Commission (FERC) in 1996, a vertically integrated utility would plan for generation and transmission needs within its franchise territory. This allowed for a high degree of certainty because the decisions regarding the timing and location of new generation and transmission were controlled by the utility. These projects were developed to satisfy the utility's reliability and economic needs.

Transmission interconnections to neighboring utilities for the purposes of importing and exporting bulk power and the development of transmission projects that spanned multiple utilities were also the responsibility of the vertically integrated utility. They were negotiated projects that often took years of effort to en sure that ownership shares and cost allocations were acceptable to each party and that no undue burden was placed on the affected systems.

Planning coordination eventually emerged, facilitated through the regional reliability councils (RRCs). Committees were formed that performed aggregate steady-state and dynamic analysis on the total set of transmission owner (TO) plans. These studies were performed under the direction of committee members, facilitated by RRC staff, to ensure that NERC planning policies (the predecessor to today's NERC standards) and regional planning guide lines were satisfied. Insights from these studies were used by planners to adjust their projects if necessary. Some regions still follow this process for their coordinated planning activities.

PLANNING AFTER OPEN ACCESS

The Open Access Tariff of 1996 (created through FERC Order 888) requires functional separation of generation and transmission within a vertically integrated utility. A generation queue process is now required to ensure that generation interconnection requests are processed in a nondiscriminatory fashion and in a first-come, first-served order. FERC Order 889, the companion to Order 888, establishes the OASIS (Open Access Same-time Information System) process that requires transmission service requests, both external and internal, to be publicly posted and processed in the order in which they arc entered.

Order 889 requires each utility to ensure non-preferential treatment of its own generation plan. Effectively, generation and transmission planning, even within the same utility, are not allowed to be coordinated and integrated.

This has been done to protect nondiscriminatory, open access to the electric system for all parties.

These landmark orders have removed barriers to market participation by entities such as independent power producers (IPPs) and power marketers. They force utilities to follow standardized protocols to address their needs and allow, for the most part, market forces to drive the addition of new generation capacity.

ill. 4 Regional transmission organizations in the United Stated and Canada

These orders also complicated the planning process, since information flow within planning departments be comes one-directional. Transmission planners know all the details of proposed generation planners through the queue process, but not vice versa. A good transmission plan is now supposed to address the economic objectives of all users of the transmission grid by designing plans to accommodate generation entered into the generation queue and to ensure the viability of long-term firm transmission service requests entered through OASIS. However, utility transmission planners continue to design their transmission systems largely to satisfy their own company's reliability objectives.

These planning processes designed the electric system in the Eastern United States and Canada that existed on 13 August 2003. The blackout that occurred that day which interrupted more the 50 million customers made it clear what planners were beginning to suspect-that the margins within the system were becoming dangerously small. The comprehensive report performed by the U. S.-Canada Power System Outage Task Force summarizes the situation as follows:

A smaller transmission margin for reliability makes the preservation of system reliability a harder job than it used to be. The system is being operated closer to the edge of reliability than it was just a few years ago.

PLANNING IN THE ERA OF THE RTO

Well before the 2003 blackout, FERC realized that better coordination among transmission owners is required for efficient national electricity markets. FERC Order 2000 issued in December 1999 established the concept of the regional transmission operator (RTO) and requires transmission operators to make provisions to form and participate in these organizations.

In this order, FERC establishes the authority of an RTO to perform regional planning and gives it the ultimate responsibility for planning within its region. Order 2000 allowed a 3-year phase-in to allow the RTO to develop the processes and capabilities to perform this function. For the first time in its history, the U. S. electric system has the potential for a coordinated, comprehensive regional planning process (ill. 4 shows the existing RTOs in the United States and Canada).

Despite the advance of developing planning organizations that aligned with the scope of the reliability and economic needs of a region, a significant gap was introduced between planning a system and implementing the plan. Order 2000 recognizes this gap with the following statement:

We also note that the RTO's implementation of this general standard requires addressing many specific design questions, including who decides which projects should be built and how the costs and benefits of the project should be allocated.

Determining who decides which project should be built is a difficult problem. Does the RTO decide which projects are to be built since it has planned the system? Does the TO decide which projects are to be built since it bears the project development risks such as permitting, regulatory approval, right-of-way acquisition financing, treatment of allowance for funds used during construction (AFUDC), construction, cost escalation, and prudency reviews? If the issue of project approval is not properly ad dressed, it's easy to envision a situation where planners spend significant efforts and costs to design a grid that satisfies critical economic and policy objectives. This plan ultimately languishes on the table because no TO wants to build it, no TO has the ability to build it, or no state regulator will approve it. To their credit, RTOs and their member transmission owners recognize this gap and have begun to take steps to resolve it.

TECHNICAL CHALLENGES

The main technical criteria that should drive transmission planning are reliability and congestion. Reliability relates to unexpected transmission contingencies (such as faults) and the ability of the system to respond to these contingencies without interrupting load. Congestion occurs when transmission reliability limitations result in the need to use higher-cost generation than would be the case without any reliability constraints. Both reliability and congestion are of critical importance and present difficult technical challenges.

Transmission reliability is tracked and managed by NERC, which as of 20 July 2006 now serves as the federal electric reliability organization (ERO) under the jurisdiction of FERC. For decades, the primary reliability consideration used by NERC for transmission planning has been ''N-1.'' For a system consisting of N major components, the N-1 criterion is satisfied if the system can perform properly with only N-1 components in service. An N-1 analysis consists of a steady-state and a dynamic component.

The steady-state analysis checks to see if the transmission system can withstand the loss of any single major piece of equipment (such as a transmission line or a transformer) without violating voltage or equipment loading limits. The dynamic analysis checks to see if the system can retain synchronism after all potential faults.

N-1 has served the industry well but has several challenges when applied to transmission planning today. The first is its deterministic nature; all contingencies are treated equal regardless of how likely they are to occur or the severity of consequences. The second, and more insidious, is the inability of N-1 (and N-2) to account for the increased risk associated with a more heavily interconnected system and a more heavily loaded system.

When a system is able to withstand any single major contingency, it's termed ''N-1 secure.'' For a moderately loaded N-1 secure system, most single contingencies can be handled even if the system response to the contingency is not perfect. When many components of a transmission system are operated close to their thermal or stability limits, a single contingency can significantly stress the system and can lead to problems unless all protection systems and remedial actions operate perfectly. In this sense, moderately loaded systems are ''resilient'' and can often absorb multiple contingencies and /or cascading events. Heavily loaded systems are brittle and run the risk of widespread outages if an initiating event is followed by a protection system failure or a mistake in remedial actions. Since blackouts invariably involve multiple contingencies and /or cascading events, N-1 and N-2 are not able to effectively plan for wide-area events.

N-1 secure systems are, by design, not able to withstand certain multiple contingencies. When equipment failure rates are low, this is a minor problem. When equipment failure rates increase due to aging and higher loading, this problem becomes salient. Consider the likelihood of two pieces of equipment experiencing outages that overlap.

If the outages are independent, the probability of overlap increases with the square of outage rate. Similarly, the probability of three outages overlapping (exceeding N-2) increases with the cube of outage rate. Blackouts typically result from three or more simultaneous contingencies. If transmission failure rates double due to aging and higher loading, the likelihood of a third-order event in creases by a factor of eight or more. Today's transmission systems may remain N-1 or N-2 secure, but the risk of wide-area events is much higher than a decade ago.

Computationally it's difficult to plan for wide-area events. This is due to large system models, a high number of potential contingencies, and convergence difficulties.

Consider the eastern interconnected system, which would require over 150,000 major components in a power flow model. This size exceeds the useful capabilities of present planning software, even when exploring only a few cases.

To plan for all triple contingencies, more than 3 sextillion (thousand trillion) cases must be considered. Even if only one out of every million of cases is considered, more than 3 billion simulations must be performed. Each simulation is also at risk for non-convergence, since a system under multiple contingencies will often have a solution very different from the base case.

In addition to reliability planning, it's becoming increasingly important to plan for congestion (the 2006 Department of Energy congestion study reports that two constraints alone in TWO-STATE Interconnection resulted in congestion costs totaling US$1. 2 billion in 2005). Basic congestion planning tools work as follows. First, hourly loads for an entire year are assigned to each bulk power delivery point. Second, a load flow is performed for each hour (accounting for scheduled generation and transmission maintenance). If transmission reliability criteria are violated, remedial actions such as generation re-dispatch is performed until the constraints are relieved. The additional energy costs resulting from these remedial actions is assigned to congestion cost (sophisticated tools will also incorporate generation bidding strategies and customer demand curves). Each case examined in a congestion study is computationally intensive.

There are many ways to address existing congestion problems, but it difficult from a technical perspective to combine congestion planning with reliability planning.

Imagine a tool with the capability to compute both the reliability and congestion characteristics of a system. A congestion simulation is still required, but unplanned contingencies must now be considered. To do this, each transmission component is checked in each hour of the simulation to see if a random failure occurs. If so, this component is removed from the system until it's re paired, potentially resulting in increased congestion costs.

Since each simulated year will only consider a few random transmission failures, many years must be simulated (typically 1,000 or more) for each case under consideration. These types of tools are useful when only the existing transmission system is of interest, such as for energy traders or for dealing with existing congestion problems. For transmission planners that need to consider many scenarios and many project alternatives, these types of tools are insufficient at this time.

The last major technical challenge facing transmission planning is the application of new technologies such as phasor measurements units, real-time conductor ratings, and power electronic devices. Proper application of these devices to address a specific problem already requires a specialist familiar with the technology. Considering each new technology as part of an overall proactive planning process would require new tools, new processes, and transmission planners familiar with the application of all new technologies.

Perhaps the biggest technical challenge to transmission planning is overcoming the traditional mindset of planners. Traditionally a utility transmission planner was primarily concerned with the transport of bulk generation to load centers without violation of local constraints.

In today's environment, effective transmission planning requires a wide-area perspective, aging infrastructure awareness, a willingness to coordination extensively, an economic mindset, and an ability to effectively integrate new technologies with traditional approaches.

INFRASTRUCTURE DEVELOPMENT CHALLENGES

Developing transmission projects has been a daunting affair in recent years, and significant roadblocks still exist.

A partial list of these roadblocks includes:

• NIMBY mentality (Not In My Back Yard)
• organized public opposition
• environmental concerns
• lack of institutional knowledge
• regulatory risk
• uncontrolled cost increases
• political pressures
• financing risks.

Perhaps the biggest impediment to transmission infra structure development is the risk of cost recovery.

AFUDC rate treatment is the present norm for transmission project financing. This allows the accrued cost of financing for development of a utility project to be included in rates for cost recovery. Recovery is typically only allowed after a project is completed and after state regulatory prudency review on the project. The effect is a substantial risk of cost non-recovery that discourages transmission investment. If a project fails during development or is judged to be imprudent, AFUDC recovery may not be allowed and the shareholders then bear the financial risk. Without assurances for cost recovery, it will be very difficult to build substantial amounts of new transmission. Minimizing development risks becomes of paramount importance when developing the types of projects necessary for regional and national purposes.

VISION FOR THE FUTURE

The challenges facing effective transmission planning are daunting, but pragmatic steps can be taken today to help the industry move toward a future vision capable of meeting these challenges. The following are suggestions that address the emerging economic and policy issues of today and can help to plan for a flexible transmission sys tem that can effectively serve a variety of different future scenarios.

DEVELOP AN ALIGNEDPLANNING PROCESS

Effective planning requires processes and methodologies that align well with the specific objectives being ad dressed. A good process should ''de-clutter'' a planning problem and align planning activity with the geographic scope of the goals. The process should push down the planning problem to the lowest possible level to reduce analytical requirements and organizational burden to a manageable size.

If the planning goal is to satisfy the reliability needs for communities in a tight geographic area, planning efforts should be led by the associated TO. This type of planning can be considered ''bottom up'' planning since it starts with the specific needs of specific customers. If the planning goal is to address regional market issues, planning efforts should be led by the associated RTO. This type of planning can be considered ''top down'' since it addresses the general requirements of the transmission system itself (in this case the ability to be an efficient market maker).

Typically, RTOs have drawn a demarcation line at an arbitrary voltage level (100 kV is typical). Below this line, TOs are responsible for the transmission plan. Above the line, RTOs are responsible for the transmission plan. This criterion can run counter to the ''de-cluttering'' principle.

Very often, local planning requires solutions that go above 100 kV, and regional solutions may require the need to reach below 100 kV.

TOs and RTOs can effectively address planning issues corresponding to local and regional areas, respectively, but what about issues of national scope? Consider the current issue of renewable energy. E.g., many states in the Northeast are beginning to set renewable energy portfolio targets that will require access to renewable energy concentrations in other parts of the country. Access to these resources will require crossing multiple RTO boundaries and /or transmission systems currently without RTO oversight.

Individual RTOs and TOs don't have the geographic perspective necessary to effectively address these types of broader issues. Who then should play this national role? RTOs working together could potentially be effective if the process is perceived as fair and equitable for all regions. However, if it's perceived that one region's objectives are beginning to take precedence over others, then a new national organization may be required.

If such a national step were taken, the role of the RTO must shift toward integrating member TO plans necessary to meet local load serving needs, integrating the EHV plan to address the national policy, and creating the regional plan that necessarily results to accommodate the regional objectives. The role would implement the strategic national plan and enables the tactical at the regional and local levels.

ADDRESSING THE REGULATORY NEED

The gap between planning a system and getting it developed needs to be closed. Planners should recognize that regulators are the ultimate decision makers. They decide whether or not a project is developed, not the planner.

Therefore, planners must perform their work in a way that maximizes the probability of regulatory approval for their projects.

The regulatory oversight role is to ensure that transmission investment is prudent. It also ensures that public impacts are minimized. Planners need to recognize these roles and address these concerns early in and throughout the planning processes.

To address the prudency question, transmission planning processes should be open to stakeholder participation and permit stakeholders to have influence on a project. This ensures that a broadly vetted set of goals and objectives are being addressed by the process.

The objectives of an open planning process are:

• Transparency: the ability of affected stakeholders to observe and influence the planning processes and decisions
• Traceable: the ability for all parties to track the flow of planning effort throughout the life cycle of a project or overall plan
• Defendable: the appropriateness and completeness of the process from the perspective of key decision makers such as RTO management, TOs, and regulators
• Dynamic: the ability to adjust the process for good reasons.

For planning at the regional or national levels, regulators expect that plans balance the benefits across the footprint and that stakeholder needs are addressed in an unbiased way. By design, RTOs don't own the facilities they plan and operate. By de-coupling the financial benefit of the transmission plan from the RTO, FERC hoped to ensure that plans were forwarded only driven by the needs of the stakeholders and designed in such a way as to minimize the overall cost regardless of the ownership boundaries. This independence is used by regulators to help make the prudency assessment since a project will, at least theoretically, only be approved for the ''right'' reasons.

To address the impacts on the public, planning processes need to encourage public involvement preferably early on in the process. Use of techniques such as press releases, community meetings, public planning meetings, open houses, and interactions with community development groups, economic development commissions, and regional planning commissions are extremely effective in addressing the public concerns in a meaningful way.

The effect is significant. First, the feedback provided can significantly aid in route selection and allow the planner and ultimate developer to better predict the costs of a project. Second, and equally important, if the public feels it has been heard and has had a meaningful chance to influence the results, the opposition is significantly muted.

If not, the opposition is empowered and is able to recruit support from a much wider audience. The public tends to fear the unknown more than the known.

Many TOs know that these efforts are critical to the success of their projects, and some have successfully incorporated this outreach into their planning and infra structure development efforts.

However, RTOs seem less aware of the importance of the public outreach step. A search of RTO Web sites shows significant efforts expended to bring certain stakeholders into their processes (highly commendable and necessary) but little efforts to bring in the public.

There is a need for the public to be appropriately involved in the process. If regional and national transmission projects are to be planned in a way that maximizes the likelihood of approval, then the public input must be meaningfully provided. While difficult, creative thought needs to be applied to determine how to meaningfully bring the public into the regional and national forums.

ADDRESSING THE NEEDS OF THE DEVELOPER

At the RTO level, the regulatory need for an independent plan makes it more difficult to incorporate the needs of developers. The perception of independence needs to be protected to ensure the RTO appropriately plays its FERC-appointed role.

However, by bringing the stakeholders and the public into the planning process, developers have greater assurance that a project will be approved, that costs have been more accurately estimated, and that opposition has been minimized. Meaningfully addressing these issues in the RTO process are significant steps in encouraging developers to come forward.

ENHANCED PROJECT JUSTIFICATION

ill. 5 Examples of locational marginal price (LMP) information

The advent of electricity markets illustrates the need for a richer understanding of the economic benefits of transmission projects. New facilities can have significant energy price impacts and , therefore, affect the underlying value of financial transmission rights. The evolving electricity markets are creating new winners and losers. As a result, it has become more critical to understand the economic benefits of transmission projects, especially at regional and national levels.

Project justification during the planning process needs to incorporate the pricing information available from these developing markets. Energy price history is now available to calibrate the analysis (ill. 5). Analysis tools that merge production cost analysis with transmission system constraints now exist to aid the planning in getting insights into the economic value of projects. As discussed above, these tools are difficult to use when considering myriads of alternative projects. However, they can be extremely effective in selecting between a narrowed-down set of alternatives.

For planning on a regional or national level, probabilistic methods show promise in managing the scope of studies necessary to perform N-2 or higher contingency analysis. At the regional or national level, de-cluttering still results in a network of significant scope.

At the national level, the dynamics of an interconnect wide system are poorly understood by any one planning entity.

Two things are certain; the United States needs to build more transmission capacity and it needs to begin to deal with aging transmission infrastructure. There are many challenges, but better transmission planning is needed to effectively address these issues in an integrated and cost-effective manner.

Note: To prepeare this article, we used: PowerWorld Simulator: an interactive power systems simulation package designed to simulate high voltage power systems operation on a time frame ranging from several minutes to several days. The software contains a highly effective power flow analysis package capable of efficiently solving systems with up to 100,000 buses.