Last summer’s Northeast blackout may have faded from the public’s memory, but the power industry remains steadfast in its commitment to strengthening the nation’s transmission system.
The industry is addressing the immediate problems that led to the August 14, 2003 blackout, including turning North American Electric Reliability Council (NERC) operating policies into enforceable standards, adding new audit programs, and requiring all transmission owners to annually certify their vegetation management plan.
For the long term, however, a number of issues that threaten the reliability of nation’s transmission system need further attention. Principal among these are declining investment dollars and increasing public resistance to siting transmission lines. Beyond endangering reliability, these issues also limit the economic benefits that the country can derive from the grid.
Industry action on these problems is not enough. National energy legislation is necessary to resolve them. Only through comprehensive legislation can the industry and the nation ensure that the grid is reliable enough and strong enough to meet the continually expanding needs of the country.
NERC Actions
In early April, the U.S.-Canada Power System Outage Task Force issued its Final Report on the power blackout. To sum up the findings, the grid needs clearer reliability standards with mandatory enforcement and more independent oversight to protect against blackouts of this scale from happening again.
Earlier this year, the industry-supported North American Electric Reliability Council (NERC) proposed and began implementing a wide variety of measures to address many of the recommendations detailed in the report:
Federal Legislation Needed
While EEI’s Board of Directors fully supports NERC’s interim measures and encourages FERC to provide an important oversight role to the NERC initiatives, legislative and regulatory policy action is critically needed now to bolster the grid over the years ahead.
Legislation is needed to create a national electric reliability organization (ERO). Only an ERO, with FERC oversight, can develop and enforce mandatory reliability rules and standards that are binding on all electric companies and market participants.
National reliability legislation is also needed to address another fundamental problem with the grid—a continuing decline in investment. Electric transmission infrastructure must be maintained and expanded to meet the increasing demands being placed upon it, unfortunately, investments are not keeping pace with these growing needs.
Investment Declines
In the early 1970s, the annual growth rate in lower voltage line-miles that support localized grid operations and interconnections was 1.9 percent, while the annual growth rate for high-voltage line-miles was 3. 2 percent. By the latter half of the 1990s, this relationship had reversed: the higher voltage line-miles were growing at only 0. 3 percent, while lower voltage line-miles were growing at 3. 5 percent.
Looking ahead, the Energy Information Administration predicts that consumer electricity demand is expected to increase by roughly 50 percent over the next two decades. To meet this demand, investments in transmission must increase from the current level of $3 billion annually to roughly $5. 5 billion annually over the next ten years.
Investment needs are reflected in congestion costs within and between regions as well. According to NERC, the volume of transmission transactions has increased by 400 percent in the last four years. Transactions that could not be completed because of congestion on transmission lines increased five-fold to almost 1,500 in 2002, compared with 300 uncompleted transactions in 1998.
Because of limited transmission capacity, the regional transmission operators in the PJM region, New York, and New England can transfer only about 5-10 percent of their peak loads between them, which is insufficient to support healthy regional electricity markets in the Mid-Atlantic and the Northeast.
Transmission investment is also needed to enable power buyers and sellers to take advantage of potential economics and increases in resource and pricing flexibility. According to a 2002 DOE study, competition in wholesale electricity markets, however, depend on strong transmission systems to move power to where it is needed.
Siting Difficulties
A number of factors have accounted for this drop in transmission investment. Difficulties in siting transmission lines are key among them. Individual states currently have sole jurisdiction over where to build new transmission lines. And many state siting statutes are focused on evaluating only state needs, thus preventing formal consideration of evolving regional nature of the grid and its role as a critical feature of wholesale markets.
As competitive wholesale electricity markets continue to develop, multi-state regional transmission organizations (RTOs) will operate the markets and may also gain operational control of utility transmission lines. But most state siting laws do not recognize the development of these regional wholesale markets, or the role new entities such as RTOs, regional state commissions (RSCs), and independent transmission companies (ITCs) will play in transmission planning and siting, thus making it almost impossible for the states to conduct fully informed decisionmaking.
Regional electricity markets require a siting process that has the capability to consider regional and even national needs. FERC has jurisdiction over wholesale markets and transmission service, but, unlike its authority to site natural gas pipelines, it currently does not have any authority over transmission siting. Hopefully, RSCs will provide a boost to efforts to site regional transmission lines. National energy legislation can, however, create this regional approach to siting by granting FERC a very limited backstop authority to site transmission facilities, if states cannot or will not act on a timely basis.
The federal transmission permitting process also needs streamlining. Problems here include a lack of harmony between federal agencies with potential jurisdiction and the tendency by these agencies to require multiple and duplicative environmental reviews. National legislation can streamline the federal permitting process by giving the U. S. Department of Energy lead agency authority for coordinating and setting environmental and permitting process deadlines.
FERC Incentives
Resolving these siting issues will certainly remove significant obstacles to greater investment in high-voltage transmission infrastructure. But energy legislation also is needed to provide incentives for investment. Innovative transmission pricing incentives, including performance-based rates, higher rates of return, and accelerated depreciation, are needed to make transmission investment an attractive alternative to other capital investments.
FERC has offered incentives (Docket No. PL03-1-000, January 15, 2003) to utilities who voluntarily divest their transmission assets and join RTOs, develop ITCs, and invest in the grid. Beyond improving reliability, FERC believes that independent regional grid operation and coordination will reduce wholesale transmission transaction costs, and make electric wholesale competition more effective in ways that benefit all customers.
With an action deadline of December 31st, FERC’s proposed incentive policy will reward transmission owners in the following ways:
Overall, FERC’s approach is a good start for spurring investment in the grid. One problem, though, is that by focusing on particular corporate structures, FERC has too narrowly prescribed how independent operation of transmission facilities—the ultimate policy goal—can be achieved. While the industry supports transmission incentives, it believes FERC should focus on rewarding independent behavior, not particular corporate structures, and that corporate structure decisions should be left to each company.
FERC’s approach to incentives also suffers from restrictive eligibility rules. Only companies that meet certain requirements and strict deadlines can enjoy the benefits of an increased return on equity in transmission assets. On the other hand, if all new transmission did qualify for the incentive, the cost would be minimal:To finance $4 billion in new transmission investment (the current yearly average utilities spend on transmission) with incentives under FERC’s plan, the dollar equivalent of the incentives would be $20 million, an amount that would increase the average monthly electric bill by less than a penny. By reducing transmission congestion, investments in new transmission will also enable lower cost power to reach consumers more easily.
Adequate incentives are needed to stimulate transmission construction, but how these construction costs are allocated must be addressed as well. FERC has approached cost allocation issues by seeking to distinguish between transmission facilities built to enhancereliability and facilities built to enable economic transactions.
Transmission lines built solely for reliability benefit everyone, and so there is little disagreement that these costs should be spread over all users. Lines that are built for economic reasons, on the other hand, bring more generators into the market and potentially reduce market prices, but may have little or no benefit to some utility customers. Transmission additions can also, and often do, serve both reliability and economic purposes. Arriving at an equitable cost allocation approach will be complicated, but it is essential for stimulating transmission investment.
One other issue that affects reliability and bears mentioning is the non-participation of municipal electric utilities and cooperatively-owned utilities regarding RTOs. Reliability can be improved if all market participants are subject to the same rules. Under current law and regulation, they are not required or necessarily encouraged to participate in RTOs. They are not subject to most FERC regulations, even though many of them own significant transmission assets, or are otherwise important participants in the wholesale energy market.
Failing to include municipals and cooperatives in regional planning and market operations creates operational holes within RTOs that pose substantial barriers to successful RTO implementation. This is particularly the case in the Northwest and the Southwest, where non-jurisdictional utilities have significant operations. If RTOs are to meet their charge under Order No. 2000 to ensure short-term reliability, manage transmission congestion, and provide for inter-regional coordination, it is essential that all entities within their boundaries participate.
National legislation can also improve reliability by reforming the US tax code. Currently, transmission assets receive less favorable tax treatment than other critical infrastructure and technologies. And electric companies that sell or otherwise dispose of their transmission assets into a FERC-approved RTO or interstate transmission company (ITC) may be subject to tax penalties.
As of May, the Senate had passed the Nickles and Thomas amendment that would revise the tax code to shorten depreciable lives for electric transmission assets from 20 to 15 years. No decision has been made to date by the House leadership on this or the other energy tax issues.
One area where national legislation cannot by itself spur investment in the grid is in the states. To ensure that investment in the grid is adequate to meet the demands being placed upon it, the states must support these measures as well. Twenty-plus states have, as part of retail restructuring, imposed caps, or freezes on the rates paid by retail customers. Such caps and freezes can discourage utilities from investing in transmission since there is no mechanism to recover these investment costs. In other states where restructuring has not occurred, there may not be rate mechanisms in place that will allow prompt and assured recovery of the costs of transmission incentives.
The August 2003 blackout raised many questions about what can be done to improve reliability. The immediate concerns are being addressed. Going forward, national energy legislation, coupled with effective federal and state regulatory policy action, is needed to ensure that the grid can meet the country’s growing demands for electricity. America’s power companies urge Congress to complete the task. The result will be greater reliability and more affordable power for all customers.
The industry is addressing the immediate problems that led to the August 14, 2003 blackout, including turning North American Electric Reliability Council (NERC) operating policies into enforceable standards, adding new audit programs, and requiring all transmission owners to annually certify their vegetation management plan.
For the long term, however, a number of issues that threaten the reliability of nation’s transmission system need further attention. Principal among these are declining investment dollars and increasing public resistance to siting transmission lines. Beyond endangering reliability, these issues also limit the economic benefits that the country can derive from the grid.
Industry action on these problems is not enough. National energy legislation is necessary to resolve them. Only through comprehensive legislation can the industry and the nation ensure that the grid is reliable enough and strong enough to meet the continually expanding needs of the country.
NERC Actions
In early April, the U.S.-Canada Power System Outage Task Force issued its Final Report on the power blackout. To sum up the findings, the grid needs clearer reliability standards with mandatory enforcement and more independent oversight to protect against blackouts of this scale from happening again.
Earlier this year, the industry-supported North American Electric Reliability Council (NERC) proposed and began implementing a wide variety of measures to address many of the recommendations detailed in the report:
- Standards— All existing NERC operating policies, planning standards, and compliance templates will be converted to standards by the end of 2004. In the interim, NERC has approved a package of compliance templates to enhance its audit program and facilitate reporting activities.
- Control Area Audits — By June 30, NERC staff will have conducted readiness audits of 20 of the largest control areas in North America, representing the majority of the continent’s customers. NERC auditors, assisted by staff from the Federal Energy Regulatory Commission (FERC), will assess each control area’s capability to comply with existing policies and operator requirements. Audits, which will take place on a repeating three-year cycle, include assessments of a control area’s personnel, training and certification, communications systems, and planning and modeling tools.
- Reporting — NERC’s regional reliability councils are required to report potential violations for investigation and analysis and submit readiness audit reports. Also, NERC Board requires a recommendation by December 31 that will include performance monitoring and stronger disturbance analysis functions.
- Public Disclosure — NERC has approved a set of interim guidelines for reporting and public disclosure of its audits and policy violations. Program specifics will be developed during 2004, but NERC and the industry support clear standards and greater transparency while also assuring due process and confidentiality concerns.
- Vegetation Management — NERC’s new compliance template will require all transmission owners to certify annually their vegetation management plan and that they have conducted it. NERC will also require reporting of vegetation-related line outages. It will do this while recognizing regional differences and the states’ critical role in right-of-way management. As of this writing, NERC will begin consideration of a vegetation management standard by the end of May 2004.
- Operator Training — NERC will review its operator training and certification programs, with an eye to developing standards over the next year tospecify training requirements, and require all operators to have completed five days of supplemental training by June 30, 2004 on emergency procedures.
- Grid Management — Reactive power and voltage control were two critical aspects of the blackout. NERC will also require reviews and, if necessary, replacements of relay devices on the grid. NERC will revise operating policies to clarify the roles of entities with direct operational controls of the grid.
- Modeling and Planning — During the next year NERC will undertake a review of a broad range of system design, planning, and data gathering and management. It will then make substantive recommendations to the NERC Board.
Federal Legislation Needed
While EEI’s Board of Directors fully supports NERC’s interim measures and encourages FERC to provide an important oversight role to the NERC initiatives, legislative and regulatory policy action is critically needed now to bolster the grid over the years ahead.
Legislation is needed to create a national electric reliability organization (ERO). Only an ERO, with FERC oversight, can develop and enforce mandatory reliability rules and standards that are binding on all electric companies and market participants.
National reliability legislation is also needed to address another fundamental problem with the grid—a continuing decline in investment. Electric transmission infrastructure must be maintained and expanded to meet the increasing demands being placed upon it, unfortunately, investments are not keeping pace with these growing needs.
Investment Declines
In the early 1970s, the annual growth rate in lower voltage line-miles that support localized grid operations and interconnections was 1.9 percent, while the annual growth rate for high-voltage line-miles was 3. 2 percent. By the latter half of the 1990s, this relationship had reversed: the higher voltage line-miles were growing at only 0. 3 percent, while lower voltage line-miles were growing at 3. 5 percent.
Looking ahead, the Energy Information Administration predicts that consumer electricity demand is expected to increase by roughly 50 percent over the next two decades. To meet this demand, investments in transmission must increase from the current level of $3 billion annually to roughly $5. 5 billion annually over the next ten years.
Investment needs are reflected in congestion costs within and between regions as well. According to NERC, the volume of transmission transactions has increased by 400 percent in the last four years. Transactions that could not be completed because of congestion on transmission lines increased five-fold to almost 1,500 in 2002, compared with 300 uncompleted transactions in 1998.
Because of limited transmission capacity, the regional transmission operators in the PJM region, New York, and New England can transfer only about 5-10 percent of their peak loads between them, which is insufficient to support healthy regional electricity markets in the Mid-Atlantic and the Northeast.
Transmission investment is also needed to enable power buyers and sellers to take advantage of potential economics and increases in resource and pricing flexibility. According to a 2002 DOE study, competition in wholesale electricity markets, however, depend on strong transmission systems to move power to where it is needed.
Siting Difficulties
A number of factors have accounted for this drop in transmission investment. Difficulties in siting transmission lines are key among them. Individual states currently have sole jurisdiction over where to build new transmission lines. And many state siting statutes are focused on evaluating only state needs, thus preventing formal consideration of evolving regional nature of the grid and its role as a critical feature of wholesale markets.
As competitive wholesale electricity markets continue to develop, multi-state regional transmission organizations (RTOs) will operate the markets and may also gain operational control of utility transmission lines. But most state siting laws do not recognize the development of these regional wholesale markets, or the role new entities such as RTOs, regional state commissions (RSCs), and independent transmission companies (ITCs) will play in transmission planning and siting, thus making it almost impossible for the states to conduct fully informed decisionmaking.
Regional electricity markets require a siting process that has the capability to consider regional and even national needs. FERC has jurisdiction over wholesale markets and transmission service, but, unlike its authority to site natural gas pipelines, it currently does not have any authority over transmission siting. Hopefully, RSCs will provide a boost to efforts to site regional transmission lines. National energy legislation can, however, create this regional approach to siting by granting FERC a very limited backstop authority to site transmission facilities, if states cannot or will not act on a timely basis.
The federal transmission permitting process also needs streamlining. Problems here include a lack of harmony between federal agencies with potential jurisdiction and the tendency by these agencies to require multiple and duplicative environmental reviews. National legislation can streamline the federal permitting process by giving the U. S. Department of Energy lead agency authority for coordinating and setting environmental and permitting process deadlines.
FERC Incentives
Resolving these siting issues will certainly remove significant obstacles to greater investment in high-voltage transmission infrastructure. But energy legislation also is needed to provide incentives for investment. Innovative transmission pricing incentives, including performance-based rates, higher rates of return, and accelerated depreciation, are needed to make transmission investment an attractive alternative to other capital investments.
FERC has offered incentives (Docket No. PL03-1-000, January 15, 2003) to utilities who voluntarily divest their transmission assets and join RTOs, develop ITCs, and invest in the grid. Beyond improving reliability, FERC believes that independent regional grid operation and coordination will reduce wholesale transmission transaction costs, and make electric wholesale competition more effective in ways that benefit all customers.
With an action deadline of December 31st, FERC’s proposed incentive policy will reward transmission owners in the following ways:
- 50 basis points to the owner’s return on equity (ROE) for transferring transmission control to RTOs
- 100 basis points for investment in new transmission
- 150 basis points for transmission facilities operated within an ITC
Overall, FERC’s approach is a good start for spurring investment in the grid. One problem, though, is that by focusing on particular corporate structures, FERC has too narrowly prescribed how independent operation of transmission facilities—the ultimate policy goal—can be achieved. While the industry supports transmission incentives, it believes FERC should focus on rewarding independent behavior, not particular corporate structures, and that corporate structure decisions should be left to each company.
FERC’s approach to incentives also suffers from restrictive eligibility rules. Only companies that meet certain requirements and strict deadlines can enjoy the benefits of an increased return on equity in transmission assets. On the other hand, if all new transmission did qualify for the incentive, the cost would be minimal:To finance $4 billion in new transmission investment (the current yearly average utilities spend on transmission) with incentives under FERC’s plan, the dollar equivalent of the incentives would be $20 million, an amount that would increase the average monthly electric bill by less than a penny. By reducing transmission congestion, investments in new transmission will also enable lower cost power to reach consumers more easily.
Adequate incentives are needed to stimulate transmission construction, but how these construction costs are allocated must be addressed as well. FERC has approached cost allocation issues by seeking to distinguish between transmission facilities built to enhancereliability and facilities built to enable economic transactions.
Transmission lines built solely for reliability benefit everyone, and so there is little disagreement that these costs should be spread over all users. Lines that are built for economic reasons, on the other hand, bring more generators into the market and potentially reduce market prices, but may have little or no benefit to some utility customers. Transmission additions can also, and often do, serve both reliability and economic purposes. Arriving at an equitable cost allocation approach will be complicated, but it is essential for stimulating transmission investment.
One other issue that affects reliability and bears mentioning is the non-participation of municipal electric utilities and cooperatively-owned utilities regarding RTOs. Reliability can be improved if all market participants are subject to the same rules. Under current law and regulation, they are not required or necessarily encouraged to participate in RTOs. They are not subject to most FERC regulations, even though many of them own significant transmission assets, or are otherwise important participants in the wholesale energy market.
Failing to include municipals and cooperatives in regional planning and market operations creates operational holes within RTOs that pose substantial barriers to successful RTO implementation. This is particularly the case in the Northwest and the Southwest, where non-jurisdictional utilities have significant operations. If RTOs are to meet their charge under Order No. 2000 to ensure short-term reliability, manage transmission congestion, and provide for inter-regional coordination, it is essential that all entities within their boundaries participate.
National legislation can also improve reliability by reforming the US tax code. Currently, transmission assets receive less favorable tax treatment than other critical infrastructure and technologies. And electric companies that sell or otherwise dispose of their transmission assets into a FERC-approved RTO or interstate transmission company (ITC) may be subject to tax penalties.
As of May, the Senate had passed the Nickles and Thomas amendment that would revise the tax code to shorten depreciable lives for electric transmission assets from 20 to 15 years. No decision has been made to date by the House leadership on this or the other energy tax issues.
One area where national legislation cannot by itself spur investment in the grid is in the states. To ensure that investment in the grid is adequate to meet the demands being placed upon it, the states must support these measures as well. Twenty-plus states have, as part of retail restructuring, imposed caps, or freezes on the rates paid by retail customers. Such caps and freezes can discourage utilities from investing in transmission since there is no mechanism to recover these investment costs. In other states where restructuring has not occurred, there may not be rate mechanisms in place that will allow prompt and assured recovery of the costs of transmission incentives.
The August 2003 blackout raised many questions about what can be done to improve reliability. The immediate concerns are being addressed. Going forward, national energy legislation, coupled with effective federal and state regulatory policy action, is needed to ensure that the grid can meet the country’s growing demands for electricity. America’s power companies urge Congress to complete the task. The result will be greater reliability and more affordable power for all customers.
