Electric Power Transmission: Background and Policy Issues
Released: 2009-04-14T00:00:00

Introduction and Organization

This report discusses electric power transmission and related policy issues. Transmission is a prominent federal issue because of a perceived need to improve reliability and reduce costs, transmission's role in meeting national energy goals (such as increased use of renewable electricity), and the potential efficiency advantages of "smart grid" modernization. Proposals before the 111 th Congress for changing federal transmission law and regulations to meet these and other objectives include S. 539 , the Clean Renewable Energy and Economic Development Act, introduced on March 5, 2009; and the March 9, 2009, majority staff transmission siting draft of the Senate Energy and Natural Resources Committee (the "Senate Energy Majority Draft").

Transmission development and regulation are complex and sometimes contentious policy areas. In addition to an overview of the electric power system, this report reviews six major transmission policy topics:

Transmission planning. Transmission permitting. Financing and cost allocation. System modernization and the smart grid. Transmission system reliability.

A concluding section summarizes the policy issues identified in the report.

Overview of the Electric Power System

This section discusses the physical and technical characteristics of the nation's power system, and then regulation of electric power transmission.

Physical and Technical Features of the Power System

Figure 1 illustrates the major components of the electric power system. In brief:

Generating plants produce electricity, using either combustible fuels such as coal, natural gas, and biomass; or non-combustible energy sources such as wind, solar energy, and nuclear fuel. Transmission lines carry electricity from the power plant to demand centers. The higher the voltage of a transmission line the more power it can carry. Current policy discussions focus on the high voltage network (230 kilovolts (kV) rating and greater) used to move large amounts of power long distances. Near customers a step-down transformer reduces voltage so the power can use distribution lines for final delivery.

The vast majority of the transmission system in the United States is an alternating current (AC) system. This is largely because the voltage of AC power can be stepped up and down with relative ease. A small portion of the system runs on high voltage direct current (DC) lines. This technology is very efficient but requires expensive converter stations to connect with the AC system.

The transmission grid was not built in conformance with a plan like the interstate highway system. The grid is a patchwork of systems originally built by individual utilities as isolated transmission islands to meet local needs. These small networks were unsystematically linked when utilities decided to jointly own power plants or to connect to neighboring companies to facilitate power sales. The grid eventually evolved into three major "interconnections," Eastern, Western, and the Electric Reliability Council of Texas (ERCOT, which covers most but not all of the state) ( Figure 2 ). Within each interconnection the AC grid must be precisely synchronized so that all generators rotate at 60 cycles per second (synchronization failure can cause damage to utility and consumer equipment, and cause blackouts). There are only eight low capacity links (called "DC ties") between the Eastern, Western, and ERCOT Interconnections. In effect, the 48 contiguous states have three separate grids with limited connections.

Within the three interconnections, the grid is operated by a total of about 130 balancing authorities. These are usually the utilities that own transmission systems, but in some cases (such as ERCOT) a single authority supervises an entire regional grid. The balancing authorities operate control centers which monitor the grid and take actions to prevent failures like blackouts.

The transmission grid is owned by several hundred private and public entities. Table 1 shows the miles of high voltage transmission line in the 48 contiguous states by region and type of owner. The table also shows the data expressed as ownership percentages (values in brackets).

The table illustrates how ownership patterns vary greatly across the country. In the West and Upper Plains regions, public power owns more than 40% of the high voltage grid. In the other regions about 80% of the grid is owned by investor owned utilities.

Figure 3 (below) shows the eight North American Electric Reliability Corp. (NERC) regions. As discussed later in the report, NERC and its regions play important roles in maintaining the reliability of the power system. Like the interconnections, some of these NERC regions extend into Canada or Mexico. However, this report is concerned only with the U.S. transmission grid.

Regulatory Framework

Electric power regulation is divided among federal, state, and regional authorities. The scope of federal authority is different for rates and reliability. The following discussion reviews:

State regulation and self-governing public power. Federal regulation of the transmission system and the reliability of the bulk power system.

State Regulation and Self-Governing Public Power

State regulation of the electric power industry is usually centered in a public utility commission (PUC). The authority of the commissions is often limited to investor-owned utilities (IOU; i.e., private corporations, usually with publicly traded stock). The PUCs set retail rates, review utility operations, and, most importantly for the purposes of this report, issue siting approvals (permits) for new transmission lines.

Publicly-owned utilities (POUs) are owned by municipal, state, and federal governments. The term is also sometimes applied to customer-owned rural electric cooperatives. POUs are typically small and operate only distribution systems, but some have large transmission and generation systems, such as the Tennessee Valley Authority. POUs are self-regulated by their governing boards, are generally not subject to state or federal economic regulation, and make their own decisions on adding new generating capacity and building transmission lines.

Federal Regulation of Electric Power Transmission and Power System Reliability

This part of the report first discusses federal regulation of transmission, and then federal regulation of the reliability of the power system.

Federal Transmission Regulation

Federal regulation of the power industry is exercised by the Federal Energy Regulatory Commission (FERC), an independent agency administratively housed within the Department of Energy. FERC regulates wholesale electricity rates, approves transmission line projects, and sets transmission rates. However, FERC's authority is limited in important respects:

For the most part FERC's rate-making and transmission authorization authority is limited to IOUs in the 48 contiguous states outside of ERCOT. While FERC must approve transmission projects proposed by jurisdictional utilities and establishes rates, a project also needs a siting permit from every state the line will traverse.

Critics have argued that multi-state permitting of transmission lines has delayed the construction of needed transmission lines. In the Energy Policy Act of 2005 (EPACT05), Congress gave FERC "backstop" siting authority. This authority operates as follows:

The Department of Energy (DOE) is to conduct a triennial study of transmission system congestion. Based on this study, DOE may designate as National Interest Electric Transmission Corridors (NIETC) areas with severe transmission congestion. A special permitting rule applies to transmission projects proposed for a NIETC. If a state has not acted on the permit application for a NIETC project within a year, the developer can bypass the state and bring its application to FERC for approval.

DOE completed its first congestion study in 2006 and in 2007 designated two NIETCs, one in southern California–Arizona, and a second covering a large part of the Northeast. As of early 2009 no use had been made by transmission developers of the backstop process. Moreover, in February 2009, the Fourth Circuit Court of Appeals ruled that FERC had overstepped its authority in implementing the backstop process. FERC had interpreted the law to mean that the backstop process could be used if a state has not acted within a year or if the state has affirmatively decided to reject the project . However, the court ruled that a state's decision to reject a project could not be appealed to FERC. On April 2, 2009, FERC asked the Fourth Circuit to reconsider its decision.

Another aspect of FERC regulation is its efforts to encourage competition in the electric power market. In 1996, FERC mandated "open access" to the transmission system. Open access requires transmission owners to make available, at cost-based or market-based fees, available transmission capacity to any generator or power buyer that is or can be connected to the system. The objective is to prevent transmission owners from using their control of the power system from stifling competition. To further facilitate open access, in 1999 a FERC order encouraged the creation of regional transmission organizations (RTO; see Figure 4 ). RTOs take over operation of the transmission network in a region or large state, although utilities continue to own their systems. RTO's ensure open access to the grid, coordinate transmission planning, and establish mechanisms to pay for new transmission lines.

Federal Regulation of Bulk Power System Reliability

The one sphere in which FERC's authority covers all entities in the 48 contiguous states is oversight of the reliability of the "bulk power system," including transmission. Before EPACT05, transmission system reliability was subject to voluntary power industry self-regulation, exercised through the North American Electric Reliability Council (NERC). As a voluntary organization NERC could not enforce reliability rules. In reaction to the northeastern blackout of 2003, EPACT05 ordered FERC to designate an official Electric Reliability Organization (ERO) to design and enforce new mandatory reliability standards. In 2006, FERC designated NERC – now reorganized as the North American Electric Reliability Corporation – as the ERO, giving NERC the legal enforcement authority it had lacked. All reliability standards and enforcement actions proposed by NERC must be approved by FERC. NERC has delegated some of its reliability functions to its eight regions ( Figure 3 ).

Transmission Planning

Background

Many analysts have identified a need to expand the national transmission system. For example, the official report on the 2003 northeastern blackout concluded that:

As evidenced by the absence of major transmission projects undertaken in North America over the past 10 to 15 years, utilities have found ways to increase the utilization of their existing facilities to meet increasing demands without adding significant high-voltage equipment. Without intervention, this trend is likely to continue. Pushing the system harder will undoubtedly increase reliability challenges…. Special protection schemes may be relied on more to deal with particular challenges, but the system still will be less able to withstand unexpected contingencies. 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.

Assuming more transmission capacity is needed, some of the next questions are what types of lines should be built, where should they be constructed, and on what schedule. S. 539 , the Senate Energy Majority Draft," and other transmission policy proposals generally include a federally sponsored planning process, conducted at a regional or interconnection-wide scale and subject to FERC oversight, that would answer these questions. The planning process would include utilities, states, power developers, government agencies, and community representatives. The process would go far beyond current efforts by FERC to encourage transmission planning.

In these proposals a primary object of the planning process is typically to identify high priority transmission projects that would be eligible for preferential permitting and financing. "High priority" is usually defined as meeting one or both of two goals:

Expanding the grid to reach areas where renewable electricity plants can be built. Resolving grid congestion and reliability problems.

The next two parts of the report discuss the following transmission planning issues:

The objectives of the planning process. Planning authority.

Objectives of the Planning Process

This discussion looks at the objectives of federal transmission planning from three perspectives: renewable energy development; congestion relief and reliability; and alternatives to transmission.

Expansion for Renewable Energy

Currently the most important source for new renewable electricity generation is wind power, but many of the best wind production areas are in thinly populated areas in the Midwest and northern plains that have limited access to transmission lines. The best region for solar development is the isolated desert southwest. Some planning process proposals, including S. 539 , are explicitly focused on expanding the grid to serve these remote renewable resource areas. In the S. 539 process, the purpose of the plan is to develop transmission lines to serve "National Renewable Energy Zones," and 75% of the generating capacity connected to the lines must be renewable (e.g., wind and solar energy). Other objectives, such as congestion relief, are included in the legislation but are not the primary aims of the bill.

There are two basic concepts for expanding the transmission grid to reach remote renewable energy regions. One concept is to plan and construct a continent-spanning ultra-high voltage "overlay" system of AC or DC transmission lines that would be the electrical equivalent of the interstate highway system. This system of "transmission superhighways" would be designed to move large amounts of renewable electricity to customers across the country. No firm plans exist for such a system, but conceptual layouts have been proposed. The second, less ambitious, concept relies on interconnection-wide or regional plans for identifying discrete transmission projects to connect renewable energy zones to load centers.

Renewable energy-focused transmission planning could accelerate the development of renewable power. However, some critics argue that such a renewable-centric approach to transmission planning would produce costly facilities. This is because a transmission line built for peak renewable power output would be underutilized much of the time (since the output of wind and solar power vary with the weather and time-of-day). Critics also claim that a renewable-centric planning approach might not adequately meet congestion relief and reliability objectives.

Expansion for Congestion Relief and Reliability

Transmission congestion occurs when use of a power line is restricted (for example, to prevent overloading and failure of the line). Utilities and RTOs can work around transmission congestion by using alternative transmission paths or by changing power plant operations, but these steps (which often involve running expensive power plants that would otherwise be less-utilized or idle) can be costly. Studies suggest that the annual costs of transmission congestion range from the hundreds of millions to billions of dollars. The solution for congestion costs is not necessarily massive transmission construction. For example, DOE found that in the Eastern Interconnection "a relatively small portion of constrained transmission capacity causes the bulk of the congestion cost that is passed through to consumers. This means that a relatively small number of selective additions to transmission capacity could lead to major economic benefits for many consumers."

Transmission system reliability is defined by NERC has having two aspects: whether a transmission system has enough capacity to continuously meet customer needs, and whether the system has the resiliency to withstand major failures, such as the loss of a key transmission line. As with congestion relief, the solutions to reliability problems do not necessarily involve building new transmission lines. For example, sometimes reliability can be enhanced by building new or expanded substations or by installing certain types of specialized equipment that helps maintain system voltage levels.

When new transmission lines are needed for congestion relief or to improve reliability they can be expensive, multi-year projects. An example of a large transmission project for reliability is the 210 mile Trans-Allegheny Interstate Line (TrAIL) from southwestern Pennsylvania through West Virginia to Northern Virginia. This $820 million project involves construction of 210 miles of new transmission lines and substations. According to NERC, the project is needed to "relieve anticipated overloads and voltage problems in the Washington, DC area, including anticipated overloads expected in 2011." If the project stays on schedule, it will take five years from the start of planning to operation.

Planning and Alternatives to Transmission

One perspective on renewable development, reliability, and other power system goals is that new transmission is central to meeting these objectives. This point of view is illustrated by FERC testimony to Congress in early 2009:

We need a National policy commitment to develop the extra-high voltage (EHV) transmission infrastructure to bring renewable energy from remote areas where it is produced most efficiently into our large metropolitan areas where most of this Nation's power is consumed. Certainly, developing local renewable energy and distributed resources is also important as we expand our capacity to generate clean power, but that is a separate issue from, and is not a substitute for, developing the EHV transmission infrastructure….

An alternative viewpoint is that a transmission-focused planning process may, almost by definition, not give enough emphasis to non-transmission approaches to meeting energy needs. This view is illustrated by the reaction of the New York and New England RTOs to the "Joint Coordinated System Plan," which outlines massive transmission construction to bring wind power from the Dakotas to the East Coast. In the view of the northeastern RTOs, the plan was badly flawed because it did not consider other options, including eastern wind plants, demand response, and building shorter transmission lines to renewable power in Canada. Another example of this perspective is an "infrastructure vision" report of the National Governors' Association, which emphasizes decentralized and technological solutions to power system issues rather than big transmission projects.

Another option that may require less construction of interstate transmission lines is reliance on conventional coal, nuclear, and natural gas-fired generation. Unlike location constrained resources such as wind and solar power (i.e., they must be built where the energy source is found), coal, gas, and nuclear plants can be built near load centers and existing transmission networks. Transmission upgrades may still be necessary and expensive, especially for nuclear plants which tend to be very large, but these may still be less intrusive than long-distance interstate lines for moving renewable power from remote locations to customers.

This alternative perspective, which gives equal weight to non-transmission solutions to power system needs, implies that the proposed interconnection-wide transmission plans actually should be combined electricity supply and demand plans. In this case the planning process becomes much broader and possibly much more complicated than transmission planning.

Planning Authority

Many transmission planning efforts are now underway at a regional level. These exercises are voluntary and generally cover at most a few states. The states are not obligated to permit any new projects that emerge from the plans.

Proposals such as S. 539 and the Senate Energy Majority Draft would mandate unprecedented Eastern and Western Interconnection-wide transmission plans. These and other proposals would also establish new, federally authorized planning authorities that would be responsible for coordinating development of the plans and submitting the plans to FERC for review and approval. The proposals envision the interconnection-wide planning processes making use of the regional efforts, but it seems inevitable that the regional plans would lose influence in comparison to the federally-mandated interconnection-wide plans.

The proposed planning authorities and their interconnection-wide plans would differ from the regional initiatives in two critical respects:

First is the assumption that optimal planning for new high voltage transmission lines should be based on a view of an entire interconnection, not a narrower regional focus. In essence the existing "bottom-up" and voluntary planning approach would be replaced with an arguably more "top-down," integrated, and binding approach. Second, new transmission projects included in the interconnection-wide plans would include preferential permitting and financing. In particular, the projects would have a federal permitting option that would bypass state regulation.

Proponents of interconnection-wide planning believe that it makes no more sense to plan the grid piecemeal than it would have been to build the interstate highway system without a national plan. However, centralized transmission planning under the aegis of FERC may be objectionable to the states, which would lose influence over power system planning.

Transmission Planning: Summary of Policy Issues

In summary, transmission planning issues for Congress include:

What should be the objectives of the planning process ? For example, planning could be focused on renewable power development or on broader objectives, such as congestion relief and reliability enhancement. What should be the scope of authority of the planning entities ? Federal transmission planning could be run by interconnection-wide centralized authorities (the top-down approach) or be conducted primarily at a regional level (the bottom-up approach), or as a hybrid. What is the appropriate scope of the planning process ? Should the planning process extend beyond transmission planning narrowly defined to a include a broader array of solutions to power system issues, such as demand response, distributed power, or conventional power plant construction. Could preferential treatment tied to the planning process distort transmission investment ? The planning proposals typically make available certain benefits, such as a federal permitting option, to projects included in the plan. These benefits could lead developers to add unnecessary features and costs to qualify proposals to meet plan criteria (e.g., proposing only high voltage lines if the plans have a minimum voltage threshold). Avoiding these distortions will require careful oversight or, arguably, limiting the benefits associated with the plan (for example, putting all new power lines or none, whether or not they are in the plan, under federal government permitting authority). Is the scheme for managing and financing the planning process realistic? The planning process will need realistic schedules and budgets, both to develop the plans and for executive branch review. A concern is that a prolonged and contentious interconnection-wide planning process could delay transmission projects that would otherwise evolve out of smaller scale planning efforts.

Transmission Permitting

Background and Discussion

As discussed above, interstate transmission projects require siting permits from every state the line will traverse. If any state disapproves a project, it will at best be delayed for rerouting or at worst canceled. A contrast is often drawn between multi-state transmission permitting and FERC's sole permitting authority for natural gas transmission lines and liquefied natural gas terminals.

Some observers believe that multi-state permitting has inhibited the development of new long distance transmission lines. According to FERC, between 2000 and mid-2007 only 14 interstate high voltage transmission lines, with a total length of 668 miles, have been built. This compares with current proposals to build many thousands of miles of new long-distance transmission.

FERC's backstop siting authority (discussed above) was enacted to help expedite permitting. But this authority applies only in limited circumstances and areas, and in practice has never been used. Proposals for transmission reform, such as S. 539 and the Senate Energy Majority Draft, would expand FERC's siting authority. For example, S. 539 would still require a developer to initially pursue state permitting, but if a project "has failed to make reasonable progress in siting the facility based on timelines in the plan" the developer can take the project to FERC. The Senate Energy Majority Draft allows "National High Priority Transmission Projects" identified through a federally-sanctioned planning process to go directly to FERC for approval.

A common element in these and some other proposals is that projects eligible for FERC permitting must be included in an interconnection-wide plan. Other projects would remain under state purview. Another approach is to simply give FERC permitting authority over all transmission projects, or at least all high voltage transmission projects.

An alternative view is that the current permitting process is not broken and at most needs tweaking. The National Association of Regulatory Utility Commissioners (NARUC), an association of state PUCs, passed a resolution in March 2009 urging "Congress and the White House to move cautiously, if at all, in expanding federal jurisdiction over siting and planning of new transmission infrastructure." According to the NARUC president, "Siting and planning transmission is one of the most difficult yet essential jobs of a State regulator, and no federal agency will have the resources or local knowledge on its own to balance all the considerations that must be taken into account."

Where FERC does have siting authority, as with natural gas pipelines and LNG terminals, it has sometimes been intensely criticized by state officials and members of Congress who believe FERC has made poor decisions. However, this may simply argue for giving an agency other than FERC any new federal transmission siting authority.

Transmission Permitting: Summary of Policy Issues

In summary, in considering how much additional transmission siting authority, if any, the federal government should assume, Congress may want to consider the following policy questions:

Should the grid be viewed from a national perspective? The grid began as local systems regulated by states. Now that the system has evolved into three separate synchronized interconnections, each spanning (other than ERCOT) many states, a question is whether a state-by-state view of the grid or a national perspective is most appropriate. The question is made pressing by proposals to make more use of the grid for long distance power transactions, such as for renewable energy. The issue does not necessarily have a single answer; for example, a state perspective may be appropriate for "routine" projects, while a national perspective could be applied to high priority interstate projects (however "routine" and "high-priority" are defined). Can transmission system reliability be separated from authority over new transmission construction? In EPACT05 Congress put the reliability of the grid under federal jurisdiction. By extension, should the federal government have control over the permitting of transmission lines aimed at enhancing system reliability (which could mean almost any new line in an interconnected power system)? As discussed in more detail later in the report, failures at one point in a synchronized system can spread widely, and these failures (in a worst case, blackouts) do not respect state lines. How important is it to accelerate the construction of new transmission lines? One criticism of current regulation is that it takes many years to permit a project. Expanding federal authority over permitting is viewed as a means of accelerating the process. The underlying assumption is that it is indeed important to build transmission lines faster. For example, if national priorities include quickly putting low carbon generating plants on line to reduce greenhouse gas emissions and to speed the introduction of electric vehicles, then a rapid permitting process may be critical. But with other assumptions about the shape of the future power market, acceleration of the permitting process may be less pressing, and therefore expanding federal permitting authority less important. (An example of such an alternative assumption would be more reliance on large nuclear or coal plants built near existing transmission networks, rather than many small wind plants in remote locations.) Management of the permitting process . Whether FERC or another agency is assigned a federal permitting role, it will need the resources to expeditiously process applications. Otherwise the whole point of giving more permitting power to the federal government would largely be obviated.

Transmission Financing and Cost Allocation

Background

Between 1977 and 1998, real dollar investment in the transmission system by investor-owned utilities generally declined, from about $4 billion annually to a trough of $2.1 billion annually by 1997 and 1998 (constant 2000 dollars; see Figure 5 , below). Although spending picked up to $4.2 billion by 2004 (constant 2000 dollars), Congress was still sufficiently concerned about transmission investment to include construction incentives in EPACT05 (in the form of more profitable rates for projects that met certain criteria).

Some critics claim that FERC has awarded incentives to projects that did not need special rates. Nonetheless and for whatever reason, transmission investment has continued to grow since 2004, reaching a 30-year high of $6.5 billion (constant 2000 dollars) in 2007.

More growth in annual investment may be needed. Estimates of the cost of expanding the transmission grid to increase renewable power delivery and other goals run into the tens of billions of dollars. For example (all figures in nominal dollars):

The estimated transmission cost of the Joint Coordinated System Plan to bring Great Plains wind power to the East Coast range from $49 to $80 billion. A DOE study of expanding the use of wind power estimated transmission expansion costs of $60 billion by 2030. A study of transmission funding requirements for all purposes for the period 2010 to 2030 estimated total costs of about $300 billion.

There are two major transmission financing policy issues: early financing for new projects, and how to allocate the costs of interstate projects to customers. Each issue is discussed below.

Early Financing

The early funding or "chicken and egg" problem particularly applies to renewable power. Renewable power plant developers may have difficulty getting funding because the transmission to bring their power output to market is not in place, while the transmission projects cannot get loans because the generation that would justify construction of the new lines has not been built. This early funding issue is exacerbated by the typical development pattern for many renewable energy projects. The projects are built in phases over several years. However, it is not economic to build a transmission line in phases; the line must be built at once for the maximum anticipated capacity even if the full load will not be developed until years after the line is first put into operation.

The FERC, RTOs, and the states have been developing regulatory solutions for the early funding problem, but there is no standard or widely used approach. The Western Governors' Association has proposed that the federal government and the federal power marketing administrations step in with direct funding and other incentives that will allow transmission developers to "supersize" planned lines to meet potential future generation, not just the renewable power expected to be built in the near term.

Note that although the early funding issue and cost allocation issue (discussed immediately below) are currently viewed as largely problems for renewable energy development, they could also apply to new coal plants with carbon capture and sequestration (CCS) equipment. This is because one option for siting coal plants with CCS is to place them in remote locations where captured CO 2 can be stored or used for enhanced oil recovery. In this scenario, a long-term build-out of new coal capacity may face transmission funding issues similar to that of renewable development in remote areas.

Cost Allocation

Perhaps the most contentious transmission financing issue is cost allocation for new interstate transmission lines – that is, deciding which customers pay how much of the cost of building and operating a new transmission line that crosses several states. DOE's Electricity Advisory Committee concluded that "cost allocation is the single largest impediment to any transmission development." The committee also noted that "cost allocation disagreements can also impact transmission siting; therefore, resolution of these two issues must be linked." This is an important point, and most current transmission proposals fold the cost allocation issue into the transmission planning process . For example, S. 539 and the Senate Energy Majority Draft both require the regional planning authorities to submit cost allocation proposals along with their transmission plans . If cost allocation proposals are not submitted or are rejected by FERC , then FERC can order its own cost-allocation scheme.

Another suggest ion is to simply allocate the costs of new projects that are part of an interconnection-wide plan to all customers in the interconnection (sometimes referred to as "socializing" costs) . For example, every ratepayer in the Eastern Interconnection would help pay for a line from Maine to New Hampshire . The idea is that in a synchronized grid all ratepayers benefit to some extent from all transmission system enhancements . A related concept is that new transmission for renewable power yields environmental benefits to all ratepayers . And whether explicit or implicit, the notion is also that interconnection-wide cost sharing makes transmission projects more palatable by minimizing the rate impact on an y one group of customer s , and accelerates project approvals by substituting a simple cost allocation rule for lengthy rate hearings.

A criticism of interconnection-wide cost allocation is that cost responsibility arguably becomes more diffuse and the incentives for cost discipline decline . A nother criticism is that especially favorable funding for transmission could bias policymakers and investors away from other solutions to electric market problems , such as demand response or local renewable power . Other cost allocation approaches are being explored across the country but no approach is standard or even widely used .

Financing and Cost Allocation: Summary of Policy Issues

Transmission financing issues for Congress include:

Should the federal government help pay for new transmission lines? Some proposals call for the federal government, possibly acting through the federal utilities, to help pay for new transmission lines, pay for expanding projects to meet future needs, or actually build new transmission. How far should the federal government go into financing the expansion of the transmission grid? Should the Congress establish a national cost allocation ru le for new transmission projects ? I n order to expedite transmission development, the federal government may need to implement standard, generally applicable cost allocation methodologies . An approach included in several proposals would require all ratepayers in an interconnection to pay for new projects anywhere in the interconnection. The notion is that in an interconnected system all customers benefit to some degree from enhancements to the grid, but a preferential cost allocation mechanism for transmission may bias investment away from other alternatives.

Transmission System Modernization and the Smart Grid

Background

Distinct from proposals for expanding the grid are proposals for modernizing the transmission system. Modernization proposals are often made under the rubric of the "smart grid," a term that encompasses technologies that range from advanced meters in homes to advanced software in transmission control centers. There is no standard definition of the smart grid. For the purposes of this report, the smart grid can be viewed as a suite of technologies that give the grid the characteristics of a computer network, in which information and control flows between and is shared by individual customers and utility control centers. The technologies will allow customers and the utility to better manage electricity demand, and will include self-monitoring and automatic protection schemes to improve the reliability of the system. Although grid technology has not been static over the years, the smart grid concept would implement capabilities well beyond any existing electric power system.

The smart grid primarily involves the development of software and small-scale technology (e.g., smart meters for homes and businesses that would interface with grid controls) rather than construction of new transmission lines. However, full implementation of the smart grid also requires new electricity rate structures, especially for residential customers, and as discussed below, this and other aspects of the smart grid may prove contentious.

The following discussion is divided into three sections:

A more detailed description of smart grid functions. A summary of current federal support for the smart grid. Smart grid cost and rate issues.

Smart Grid Functions

Because the smart grid involves integrated operation of the power system from the home to the power plant, this discussion will go beyond the transmission system to cover the distribution network. Within this integrated system the smart grid has two scopes. One scope is transmission monitoring and reliability , and includes the following capabilities:

Real-time monitoring of grid conditions; Improved automated diagnosis of grid disturbances, and better aids for the operators who must respond to grid problems; Automated responses to grid failures that will isolate disturbed zones and prevent or limit cascading blackouts that can spread over wide areas. "Plug and play" ability to connect new generating plants to the grid, reducing the need for time consuming interconnection studies and physical upgrades to the grid. Enhanced ability to manage large amounts of wind and solar power. Some (though not all) analysts believe deployment of the smart grid is essential to the large scale use of wind and solar energy.

The second scope is consumer energy management . An essential part of this scope is the installation of smart meters (also referred to as advanced metering infrastructure or AMI). These meters and other technology would implement the following capabilities:

At a minimum, the ability to signal homeowners and businesses that power is expensive and/or in tight supply. This can be done, for instance, via special indicators or displayed through web browsers or other personal computer software. The expectation is that the customer will respond by reducing its power demand. The next level of implementation would allow the utility to automatically reduce the customer's electricity consumption when power is expensive or scarce. This would be managed through links between the smart meter and the customer's equipment or appliances. The smart grid system would automatically detect distribution line failures, identity the specific failed equipment, and help determine the optimal plan for dispatching repair crews to restore service. The smart grid would automatically attempt to isolate failures and prevent local blackouts from spreading. The smart grid would make it easier to install distributed generation, such as rooftop solar panels, and to implement "net metering," a ratemaking approach that allows operators of distributed generators to sell surplus power to utilities. The smart grid would also manage the connection of millions of plug-in hybrid electric vehicles into the power system.

The transmission and customer energy management scopes described above are integrated in the full smart grid concept. For example, if the transmission system becomes overloaded, the smart grid could respond at the distribution system level by automatically reducing customer demand.

Federal Support for the Smart Grid

The Energy Independence and Security Act of 2007 (EISA) articulated a national policy to modernize the power system with smart grid technology, and authorized research and development programs, funding for demonstration projects, and matching funds for investments in smart grid technologies. These and related programs received $4.5 billion in funding in the 2009 stimulus bill. In addition, the Emergency Economic Stabilization Act of 2008 shortens the depreciation period for smart meters and other smart grid equipment from 20 years to 10 years (which increases each year's depreciation tax deduction for the equipment). The value of this tax change to the power industry is reportedly $915 million over 10 years.

EISA assigned to the National Institute of Standards and Technology (NIST), a unit of the Department of Commerce, the lead in developing interoperability standards for smart grid equipment. This is a critical role, because it is essential that the smart grid technologies installed by one utility be able to communicate with those of another and with control centers. This work has been lagging. DOE, FERC, and NIST have reportedly begun interagency efforts to accelerate development of the standards, and NIST has created and filled a new National Coordinator on Smart Grid Interoperability to push the effort forward.

Pursuant to EISA, once NIST's work is sufficiently advanced FERC is to establish, through a rulemaking, national smart grid interoperability standards. On March 19, 2009, FERC published for comment a proposed smart grid policy statement and action plan, intended "to articulate its policies and near-term priorities to help achieve the modernization of the Nation's electric transmission system, one aspect of which is 'Smart Grid' development." According to FERC, the statement focuses on "Prioritizing the development of key standards for interoperability of Smart Grid devices and systems; [and] a proposed rate policy for the interim before the standards are developed." Comments are due back to FERC in May 2009.

Smart Grid Cost and Rate Issues

Advocates believe the potential benefits from the smart grid are enormous. For example, the Electric Power Research Institute, a research arm of the power industry, estimated that implementation of the smart grid and related technologies could increase annual gross domestic product by 10% annually by 2020. The Galvin Institute, a proponent of grid modernization, claims that among other benefits a modernized grid would "reduce the need for massive [electric power] infrastructure investments by between $46 and $117 billion over the next 20 years."

Nonetheless, because the smart grid concept and technology are still evolving and there are no operational systems to evaluate, the benefits and costs are uncertain. According to Xcel Energy, which is developing a large smart grid demonstration in Boulder, Colorado:

Everybody says they have technology that can be applied to this project. How much really exists and how much of it still needs to be developed? Right now we think 60 percent of the data architecture is already there, while the other 40 percent will probably need tweaking. Then we will determine what is or isn't scalable [to larger installations]…. As an industry we haven't really demonstrated the benefit of combining all these technologies. Until we do, there will be skepticism. That's the real value of this project.

It does seem likely that costs of rolling out the smart grid will be high. Just installing the metering equipment is expensive. Pacific Gas and Electric, a large utility in California, plans to install 10.3 million smart meters by 2012 at a cost of $1.7 billion. Estimates of installing smart meters nationwide are in the $40 billion to $50 billion range. Some utilities are incurring costs to replace smart meters installed just a few years ago with newer models, indicating both the rapidity with which the technology is changing and the absence of firm standards.

Some consumer advocacy groups have expressed concern that utilities and regulators are pressing ahead with smart grid investments, especially the installation of smart meters, without knowing whether the benefits will justify the costs. A claim from critics is that some utilities are enthusiastic about immediate spending on smart grid technology because once the investment is reflected in the company's rate base it will result in higher profits.

Another consumer advocate concern relates to the change in utility rate structures that will likely accompany implementation of the smart grid. As discussed above, one function of the smart grid is to signal consumers when electricity is expensive or in short supply. The question is whether the consumer will act on this information by reducing power usage. In typical utility rate structures, consumers pay a rate for power that reflects annual average costs. The consumer's rate does not vary from day to day or hour to hour. But if the consumer's rates do not reflect real-time power costs, then the consumer has no immediate economic incentive to respond to utility price signals. For this reason, the smart grid concept is accompanied by new rate structures, such as "dynamic" pricing in which charges to consumers reflect actual market prices (or marginal production costs) for electricity. As put by the President of NARUC, "You can't have a smart grid and dumb rates. We have been used to – for over 100 years – rates that are the same all day, every day. That's not the way electricity is produced."

Dynamic rates mean that the price of power would be much higher in the afternoon of a hot summer day when demand peaks and the most expensive generating plants are on-line, than in evening of the same day or on the weekend. With dynamic rates, consumers would have an incentive to respond to utility price signals by reducing demand by turning down the air conditioner or delaying the laundry. If the capability exists, the consumer might sign-up for direct utility control of appliances.

In theory, this demand response scenario has consumer benefits in the short-term (less use of expensive fuels and inefficient peaking power plants) and long-term (less need for new power plants to meet growth in peak load and reduced air emissions). However, in the view of critics these benefits are much more nebulous than the certainty that under dynamic rates consumers will face higher power costs. The critics also argue that lower income people may not have the schedule flexibility to shift cooking and laundry to less expensive hours of the day; however, there is some evidence that lower income people will actually be more responsive to price signals than higher-income households. Another argument is that the elderly or ill may face the choice of paying higher power bills or risking their health by turning down the air conditioning or electric heat.

It is also unclear how much smart grid technology and cost needs to be incurred to get most of the available demand response benefits. For example, a dynamic pricing pilot program in Chicago used minimal technology (e.g., price notifications by phone) but still produced substantial reductions in peak demand. Some studies suggest that the more sophisticated the technology used in a demand response pilot program the greater the savings, but the optimal balance between technology cost and benefits is still unclear. Industrial customers will reportedly recommend adding a cost-benefit test for smart grid investments to FERC's final policy.

Modernization and Smart Grid: Summary of Policy Issues

Congress has already put in place federal programs to help develop the smart grid. Continuing policy issues for Congress include:

Program oversight . The American Recovery and Reinvestment Act provided funding for previously authorized smart grid programs, including one key effort – development of interoperability standards by the National Institute for Standards and Technology – that has been lagging. Congress may want to monitor how these programs progress. Smart grid cost/benefit oversight . The balance of costs and benefits that the smart grid will produce for customers has been hotly debated. Many smart grid investment decisions will be made by state utility commissions. However, other investments and rate decisions will involve transmission systems and RTOs under FERC jurisdiction, or will relate to bulk power system reliability standards that are under federal jurisdiction throughout the 48 contiguous states. (This federal role will be even larger if an interconnection-wide planning process under federal supervision is made into law, because these plans will inevitably have to deal with grid modernization.) These responsibilities create ample room for Congressional oversight of the actual costs, benefits, and performance of smart grid investments.

Transmission System Reliability

This section of the report will discuss the reliability of the transmission system from three perspectives:

Problems in evaluating the current reliability condition of the grid; Modernization and reliability; Reliability and changes in the energy market.

Problems in Evaluating the Current Reliability Condition of the Grid

As discussed earlier, power system reliability has two dimensions: adequate capacity to consistently meet customer demands, and the ability to withstand disturbances such as failed transmission lines or power plants. It is currently impossible to judge the reliability of the national transmission system by either criteria because the data does not exist to make an assessment. According to the Energy Information Administration, "The Government does not have the [analytical tools] and data necessary to verify that existing and planned transmission capability is adequate to keep the lights on."

This is not to say that transmission risks cannot be evaluated for specific parts of the transmission grid. These studies are performed routinely. What is missing is uniform, nationwide data on the frequency and causes of transmission outages that can be used to determine whether the overall performance of the system is improving or deteriorating, and what factors are driving these changes.

A contrast can be drawn between the data available on generating plant reliability and operations versus that for the transmission system. For decades NERC has managed a highly detailed collection of data on the reliability of power plants, and other relevant data are available from EIA and the Environmental Protection Agency (EPA). In contrast to the wealth of information on power plant operations, minimal data has been collected by government or industry on transmission system reliability. The most significant existing source is information on major transmission outages collected on DOE's Form OE-417, which is compiled by EIA and NERC. A recent Carnegie Mellon University study of this data was able to conclude "that the frequency of large blackouts in the United States has not decreased over time," but could not determine why this is because of the lack of detailed information.

This information gap leaves policy makers without a full understanding of transmission reliability risks or able to determine the best steps for improving reliability. To help fill this gap, NERC has launched a new Transmission Availability Data System (TADS) to provide the data "needed to support decisions with respect to improving reliability and performance." TADS reporting, which began in 2008, is mandatory for all high voltage transmission owners in the 48 contiguous states. NERC is still developing metrics to display and analyze the data in a meaningful way, and believes it may take up to five years before the data can be used to analyze trends."

It may also take several years to judge whether TADS is collecting all the necessary data or if it needs to be revised or expanded. Pursuant to EPACT05, NERC and FERC have been promulgating and enforcing new, mandatory, power system reliability standards. Until a useful data collection and analysis system are in place, it will be difficult to judge whether these standards and other actions are actually improving the reliability of the transmission system.

Reliability and Grid Modernization

The transmission grid is sometimes portrayed as a decrepit victim of underinvestment; one recent press report described the grid as "frayed" like grandmother's quilt. There is, in fact, no clear evidence that the transmission grid is physically deteriorating. But this does not mean that the grid is universally well managed or is as up-to-date as it should be. The grid probably needs to be modernized to improve reliability. This is not necessarily the same as installing the full smart grid discussed above. The smart grid is an ambitious concept for integrated operation of the power system. The full smart grid is not needed to use a subset of "intelligent" technologies to improve the reliability of the transmission system.

The need for modernization is illustrated by the causes of the August 14, 2003 northeastern blackout. The blackout, which interrupted service to 50 million people in the United States and Canada for up to a week, started with transmission line trips (automatic shutdowns) and resulting overloads on the FirstEnergy utility system in Ohio. The blackout was not the result of insufficient transmission capacity or deteriorated equipment. As identified by the joint United States – Canada investigating task force, the blackout was caused by factors such as the following:

FirstEnergy and the NERC reliability region within which it operated did not understand the strengths and weaknesses of the FE system. FirstEnergy consequently operated its system at dangerously low voltages. FirstEnergy's system operators lacked the "situational awareness" that would have revealed the blackout risk as lines began to trip. The operators were blinded by monitoring and computer system breakdowns, combined with training and procedural deficiencies which led to those failures going undetected until it was too late. FirstEnergy did not adequately trim the trees under its transmission lines. As a result, three key transmission lines tripped when they sagged (as the lines are designed to do as they heat up with use) and came in contact with trees. The Midwest Independent System Operator (MISO), the RTO that manages the grid in FirstEnergy's service area, did not have the real-time information necessary to assess the situation on FirstEnergy system and provide direction to the utility.

Once the FirstEnergy system collapsed, overloads and power swings spread out across the Northeast, causing a cascading series of transmission line and power plant trips that left tens of millions of people without electricity. One reason the outage spread over such a wide area was because many power plants were equipped with unnecessarily sensitive automatic protection mechanisms that tripped the units prematurely. The speed of the cascade allowed almost no time for manual intervention. The elapsed time from the start of the cascade (i.e., when failures began to radiate out from the collapsed FirstEnergy grid) to its full extent was about seven minutes.

In summary, as discussed in the official blackout report and other analyses, the 2003 blackout was not caused by a utility having built too few transmission lines, or because power line towers and substations were falling apart. The blackout was apparently due to such factors as malfunctioning if not obsolete computer and monitoring systems, human errors that compounded the equipment failures, mis-calibrated automatic protection systems on power plants, and FirstEnergy's failure to adequately trim trees.

One part of a strategy for preventing repetitions of the 2003 blackout is to modernize the grid from a reliability standpoint. This will not always entail building more power lines. One analysis written shortly after the 2003 blackout concluded that "The common contributing factor to the recent blackout, based on investigations to date, is confusion-communication breakdowns both technical and human….[W]e maintain that much can be solved by updating technology and by changing procedures followed within the operating companies. This fix is cheaper and much more immediate than huge investment in new power lines."

Modernization involves installing new technology into the existing system so that:

Operators have accurate real time data on the status of the power network. Operators also have advanced simulation tools to assist them in evaluating incipient problems and formulating responses. The grid can automatically respond to certain types of problems. This is sometimes referred to as the "self-healing" grid.

Some of these technologies are being implemented. An example is two new control centers installed by the Western Electricity Coordinating Council (WECC), the NERC reliability region covering the western states. According to WECC:

These centers have a view of the entire Western Interconnection. They can see every tower, line, and transmission element over 100 kV. They will be able to see the entire Western bulk system, identify its status, and respond to outages…. they have the tools now to see and head off problems as they develop and they have the authority to contact grid operators and direct them to take certain actions to protect the interconnection as a whole.

On the other hand, the control centers will not be able to remotely actuate equipment such as transmission line circuit breakers. As is typically the case, a crew will still need to be sent to manually reset the equipment, so the control system is still several steps away from automated, "self-healing" responses to grid problems.

In summary, depending on the case, building new transmission lines is not the only or best approach to enhancing power system reliability. In some instances investments in new monitoring and control technology may be the better solution.

Reliability and Changes in the Energy Market

The transmission grid was built for a specific business and technical model: power plants would use transmission lines to move electricity to distribution networks for delivery to customers. The power plants were large "central station" facilities using fossil, nuclear, or hydroelectric energy sources, and were designed to run as-needed, when-needed. The power flow was one-way, from the power plant to the customer.

This model is already changing:

Variable Renewable Generation : One factor is the introduction of large amounts of wind power onto the grid. Unlike conventional power plants, the output of wind plants varies with the weather. Power systems were not designed to handle this kind of power supply variability and uncertainty. Total wind capacity is now large enough in some parts of the country, such as the ERCOT Interconnection (covering most of Texas), to be an important influence on how the power system is operated. The variable output of wind plants can be dealt with in a variety of ways, including improved wind forecasting, adding electricity storage and/or quick start natural gas-fired peaking plants to the grid, and drawing wind power from a wide geographic area to smooth out local changes in wind speed. However, these capabilities will have to be added rapidly to the grid if, as some expect, the use of wind power grows quickly. Demand Response : Another factor is the increasing use of demand response programs, in which large commercial and industrial customers agree to interruptible power service in return for lower rates. For example, in the Florida and northeastern NERC reliability regions, significant parts of peak demand (respectively, 6% and 4%) can now be met by customers reducing output rather than by operating power plants. Demand response reverses the conventional power system operating model: instead of changing power plant output to match demand, demand is reduced to match the available supply of electricity. An issue is how much real time information and control (also referred to as "visibility") system operators will have over industrial and commercial facilities that have signed on to demand response programs. Another issue is whether industrial and commercial loads will become less willing to participate in demand response programs if cycling of their operations becomes routine rather than a rarity. These issue are clearly not insuperable, given the success to date with these programs, but they may have to be dealt with on a much larger scale in the future. Distributed Generation : A third factor is the use of distributed generation (local power generation controlled by the customer), which can vary from rooftop solar units to large industrial cogeneration facilities. A distributed generation facility will sometimes take power off the grid. Other times it will have excess power to sell to the utility, reversing the normal flow of electricity. Buying power from customers is inconsistent with standard utility technology, accounting, and rates. This is especially true when the generation is hooked up to the distribution system, which was designed to make final delivery of power to customers, not receive power from the customer. Distributed generation poses control and visibility issues similar to demand response. Wide use of distributed generation will also pose institutional issues. One is that generation connected to the distribution system (in contrast to the transmission system) is not covered by NERC reliability standards. Second, realizing the full potential of distributed generation may require the states to implement net metering laws that allow owners to sell surplus power back to the grid. As with demand response, these issues are neither new or insuperable, although the scale may increase greatly. On the other hand, plug-in hybrid electric vehicles would pose a truly unique challenge, since their batteries would be a load on the power system at times and a source of stored electricity at other times. System operators would have to be able to decide on a daily or hourly basis how much they can rely on electricity storage scattered over thousands or millions of batteries, none of which are owned by the utility.

Integrating non-traditional resources into the grid will be a reliability challenge. This is not because these resources are new. For example, distributed generation in the form of industrial cogeneration has been increasingly common since Congress passed the Public Utility Regulatory Policies Act ( P.L. 95-617 ) in 1978. The issue is integration of much larger amounts of these resources into a power system primarily designed around a different model. For example, NERC has concluded that "Demand response will become a critical resource for maintaining system reliability over the next ten years." In 2008 NERC reported proposals to connect 145,000 MW of new wind capacity to the transmission grid by 2017, equivalent to about 14% of current total generating capacity in the United States. Even if all of the proposed wind capacity is not built, many more wind plants will probably be connected to the grid. The most recent EIA long-term forecast, which assumes no changes to current laws, estimates that wind generation will increase by 300% by 2030.

A characteristic that variable renewable generation, demand response, and distributed generation have in common is potentially less predictability (in respect to availability and level of service) than traditional resources. Improved real time monitoring, analysis, and control of the grid could help compensate for this issue. Another system-wide response may be to collapse the 130 balancing authorities that currently operate the transmission system into a smaller number that could call on a wider range of resources for managing electricity supply and demand.

Transmission Reliability: Summary of Policy Issues

In response to the 2003 northeastern blackout, Congress gave FERC authority over the reliability of the bulk power system in the 48 contiguous states. Continuing policy issues include:

Transmission system information gap . There is currently no good source of data that measures the reliability of the transmission grid or allows trend analysis. NERC is developing a new process for collecting and analyzing transmission reliability data. The progress of this effort may be of interest to Congress, because without good data it will be difficult to judge whether FERC's new reliability standards and other actions are actually improving the reliability of the transmission system. Modernization and reliability . The implementation of modernized technology and management may be an alternative, or necessary supplement, to building new transmission lines to improve the reliability of the grid. In considering new spending and planning approaches for the transmission system, Congress may wish to ensure that the right balance is struck between modernization and new construction. Reliability and the changing power market. The power system is changing from a model based on central station power plants to a more diverse range of resources, including variable renewable power, demand response, and distributed generation. Congress may want to exercise oversight to ensure that FERC and NERC are developing reliability standards for a changing grid. Also, certain kinds of distributed generation are not covered by federal reliability authority, a situation Congress may want to revisit in the future.

Summary of Transmission Policy Issues

This concluding section summarizes policy issues of potential interest to Congress.

Federal Transmission Planning

S. 539 and other proposals call for a much larger federal role in transmission planning, and suggest that planning should be conducted on a larger geographic scope than in the past. Policy issues include:

What should be the objectives of the planning process ? For example, planning could be focused on renewable power development or on broader objectives, such as congestion relief and reliability enhancement. What should be the scope of a uthority of the planning entities . Federal transmission planning could be run by interconnection-wide centralized authorities (the top-down approach) or be conducted primarily at a regional level (the bottom-up approach), or as a hybrid. What is the appropriate scope of the planning process ? Should the planning process extend beyond transmission planning narrowly defined to a include a broader array of solutions to power system issues, such as demand response, distributed power, or conventional power plant construction. Could preferential treatment tied to the planning process distort transmission investment? The planning proposals typically make available certain benefits, such as a federal permitting option, to projects included in the plan. These benefits could lead developers to add unnecessary features and costs to qualify proposals to meet plan criteria. Avoiding these distortions will require careful oversight or, arguably, limiting the benefits associated with the plan (for example, putting all new power lines or none, whether or not they are in the plan, under federal government permitting authority). Is the scheme for managing and financing t he planning process realistic? An effective planning process will need realistic schedules and sufficient resources to timely develop and update transmission plans.

Permitting of Transmission Lines

Transmission line permitting is primarily under the control of the states. Current proposals would extend federal authority, perhaps by completing displacing the state role. Issues include:

Should the grid be viewed from a national perspective? The grid evolved as local systems serving limited utility service areas. Now that the system has evolved into three separate synchronized interconnections, each spanning (other than ERCOT) many states. The question is whether a state-by-state or national view of the grid is most appropriate. The issue does not necessarily have a single answer; for example, a state perspective may be appropriate for "routine" projects, while a national perspective could be applied to "national interest" projects. Can transmission s ystem reliability be separated from authority over new transmission construction? In EPACT05 Congress put the reliability of the grid under federal jurisdiction. By extension, should the federal government have control over the permitting of transmission lines aimed at enhancing system reliability (which could mean almost any new line in an interconnected power systems)? How important is it to accelerate the construction of new transmission lines? One criticism of the current regulatory regime is that it takes many years to move a transmission project through the permitting steps. Expanding federal authority over permitting is viewed as a means of accelerating the process. The question is how important is it to quickly build transmission lines to meet reliability, environmental, and other objectives. Management of the permitting process . If FERC or some other agency is assigned a federal permitting role, it will need the resources to expeditiously process applications. Otherwise the whole point of giving more permitting power to the federal government would largely be obviated.

Transmission Line Funding and Cost Allocation

Building new transmission lines could cost billions of dollars. Even more contentious than how to fund these projects is the question of how the costs of interstate transmission lines should be allocated to utility customers. Issues include:

Should the federal government help pay for new transmission lines? Some proposals call for the federal government, possibly acting through the federal utilities, to help pay for new transmission lines, pay for expanding projects to meet future needs, or actually build new transmission. How far should the federal government go into financing the expansion of the transmission grid? Should the Congress establish a national cost allocation rule for new transmission projects ? An approach included in several proposals would require all ratepayers in an interconnection to pay for new projects anywhere in the interconnection. The notion is that in a interconnected grid all customers benefit to some degree from enhancements to the system, but a preferential cost allocation mechanism for transmission may bias investment away from other alternatives.

Transmission Modernization and the Smart Grid

The smart grid is a concept for modernizing the grid with information technology and intelligent features. Congress has already established and funded programs for encouraging development of the smart grid. Policy issues include:

Program oversight . The American Recovery and Reinvestment Act provided funding for previously authorized smart grid programs, including one key effort – development of interoperability standards by the National Institute for Standards and Technology – that has been lagging. Congress may want to monitor how these programs progress. Smart grid cost/benefit oversight . The balance of costs and benefits that the smart grid will produce for customers has been hotly debated. Many smart grid investment decisions will be made by state utility commissions. However, other investments and rate decisions will be under FERC jurisdiction, so there is ample room for Congressional oversight of the actual costs, benefits, and performance of smart grid investments.

Transmission System Reliability

In response to the 2003 northeastern blackout, Congress gave FERC authority over the reliability of the bulk power system in the 48 contiguous states. Continuing policy issues include:

Transmission system information gap . There is no good source of data that measures the reliability of the transmission grid or allows trend analysis. NERC is developing a new process for collecting and analyzing transmission reliability data. The progress of this effort may be of interest to Congress, because without good data it will be difficult to judge whether FERC's new reliability standards and other actions are actually improving the reliability of the transmission system. Modernization and reliability . The implementation of modernized technology and management may be an alternative, or necessary supplement, to building new transmission lines to improve the reliability of the grid. In considering new spending and planning approaches for the transmission system, Congress may wish to ensure that the right balance is struck between modernization and new construction. Reliability and the changing power market. The power system is changing from a model based on central station power plants to a more diverse range of resources, including variable renewable power, demand response, and distributed generation. Congress may wish to exercise oversight to ensure that FERC and NERC are developing reliability standards for a changing grid. Also, certain kinds of distributed generation are not covered by federal reliability authority, a situation Congress may want to revisit in the future.