The past year has seen the power industry launch an aggressive campaign to install safeguards against another massive grid failure. As of this writing in late June, the North American Electric Reliability Council (NERC), with electric utility industry support, was on target to complete readiness audits of more than 20 of the largest control areas in North America by June 30, adopt guidelines for the disclosure and reporting of reliability violations and audit results, and transform NERC operating policies into reliability standards by the end of 2004.

But some caution flags are still out. To ensure that the grid can continue to meet customer demands in the future, the power industry remains a vocal proponent for national legislation to encourage transmission investment and ease siting difficulties. And, as onsite power generation systemsówhether fuel cells, microturbines, or solar, wind, or related technologiesóbecome more common, the industry is recommending a number of interconnection procedures and agreements to enable these distributed energy (DE) systems to increase the benefits they offer customers, while ensuring that electricity delivery networks operate safely and reliably.

NERC Actions

In early April, the US‚Canada Power System Outage Task Force issued its report on the power blackout: "Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations" (http://www.nerc.com/~filez/blackout.html). 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, NERC proposed and began implementing a wide variety of measures to address many of the recommendations detailed in the report:

Standards: Virtually all existing NERC operating policies, planning standards, and compliance templates will be converted to standards by the end of 2004, with adoption by the NERC board planned in February 2005. 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 more than 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 compliance audit reports. Also, the NERC board has requested a recommendation by December 31 that will include performance monitoring and stronger disturbance analysis functions.

Public Disclosure: NERC has approved a set of guidelines for reporting and public disclosure of its audits and policy violations. Program specifics are being developed during 2004. NERC and the industry support clear standards and greater transparency, while assuring that violations are disclosed in context and that due process and confidentiality concerns are fully addressed.

Vegetation Management: All transmission owners must make vegetation management procedures and documentation of work completed available for review and verification. NERC's new compliance template will require all transmission owners to annually certify that procedures have been carried out. NERC will require reporting of vegetation-related line outages. Also, NERC has begun development of a vegetation management standard.

Operator Training: NERC will review its operator training and certification programs, with an eye to developing standards over the next year to specify training requirements. All operators will 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.

Transmission Congestion Increases

Adopting these reliability measures will improve the reliability of the grid. But another issue, transmission capacity, must be addressed to ensure that the grid can meet the demands placed upon it in the future.

The nation's transmission system was built primarily to ensure reliable, local electric service. It was not built to support the developing regional wholesale markets that require moving large quantities of power across long distances. It is not a superhighway. According to NERC, the volume of transmission transactions nationwide has increased by 400% in the past 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 Pennsylvania–New Jersey‚Maryland region, New York, and New England can transfer only aout 5%‚10% of their peak loads between them, which is insufficient to support healthy regional electricity markets in the Mid-Atlantic and the Northeast.

Adequate transmission capacity 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 US Department of Energy study, competition in wholesale electricity markets, however, depends on strong transmission systems to move power to where it is needed.

What has led to the increasing congestion on the grid is a lack of investment. Billions of dollars are being spent annually on transmission facilities. But the bulk of the new transmission being built is to serve local demand and to connect new generation to the grid, instead of the long-distance, high-voltage wires needed to strengthen regional electricity markets.

For example, in the early 1970s, the annual growth rate in lower voltage line-miles that support localized grid operations and interconnections was 1.9%, while the annual growth rate for high-voltage line-miles was 3.2%. By the latter half of the 1990s, this relationship had reversed: the higher-voltage line-miles were growing at only 0.3% per year, while lower-voltage line-miles were growing at 3.5% per year.

Looking forward, investments in transmission must increase from the current level of $3 billion annually to roughly $5.5 billion annually over the next 10 years. But a number of factors are discouraging this needed investment in long-distance transmission lines, including:

• Local opposition to siting new facilities
• Inability to recover planning and related costs when facilities are delayed or ultimately rejected by siting authorities
• State retail rate caps that may prevent utilities from recovering their investments in transmission
• Uncertainty over transmission ownership and control policies
• Uncertainty as to whether beneficiaries will pay for new transmission

Another problem that has discouraged transmission investment is the emerging regional nature of electricity markets. Individual states currently have sole jurisdiction over where to build new transmission lines. Also, many state siting statutes are focused on evaluating only state needs, thus preventing formal consideration of the evolving regional nature of the grid and its role as a critical feature of wholesale markets.

As competitive wholesale electricity markets continue to develop, multistate regional transmission organizations (RTOs) will operate the markets and may 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, and independent transmission companies (ITCs) will play in transmission planning and siting, thus making it almost impossible for the states to conduct fully informed decision making.

Federal Legislation Needed

National reliability legislation is needed to address this continuing decline in transmission investment. National energy legislation can create the regional approach needed for 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 US Department of Energy lead agency authority for coordinating and setting environmental and permitting process deadlines. 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.

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 direct incentives for investment. Innovative transmission pricing incentives are needed. These include performance-based rates, which reward certain performance levels; higher rates of return, which are need to spur investment; and accelerated depreciation, which put transmission assets on par with other capital equipment. These are all needed to make transmission investment an attractive alternative to other investment options.

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 an ITC may be subject to tax penalties.

As of May, the US 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 US House leadership on this or the other energy tax issues.

Distributed Energy Issues

The August 2003 blackout has also raised the profile of DE systems and the role they can play in improving the grid's reliability. The interconnection of DE systems is an important issue with implications for both electric utilities and their customers.

A month prior to the blackout, FERC issued a long-anticipated final rule on interconnection standards for generators larger than 20 megawatts. At the same time, the commission released an advance notice of proposed rulemaking (ANPR) for interconnection of generators 20 megawatts and smaller.

A number of states, notably California, Texas, and New York, already have rules in place for the small generators. These regulations address a wide array of issues, including ownership and control of DE, interconnection standards, environmental issues, metering and billing, distribution tariffs, backup and standby rates, net metering, and stranded costs. How the commission's proposed rule could affect the state rules remains to be seen.

If adopted, the proposed rule [Docket No. RM02-12-000] would provide the commission with jurisdiction over DE interconnection, if the generator were connected to a high-voltage transmission line used in interstate commerce or to a low-voltage circuit that is already used under an open-access transmission tariff. Where DE systems are connected to a system beyond this jurisdiction, state regulators could use the final rule as a guideline.

FERC's small-generator interconnection agreement would establish legal rights and obligations of each party, address cost responsibility, lay out milestones for completing projects, and set forth a process for dispute resolution. The proposed rule would apply to any interconnection that may be used to transmit energy in interstate commerce or is subject to an approved open-access transmission tariff, and to an interconnection request where a utility's distribution facilities are to be used to transmit energy in interstate commerce.

The proposed rule is controversial because FERC jurisdiction over small-scale distributed generation is not solidly defined. FERC has stated that the proposed rule is meant to expedite the interconnection of small generators, including wind and solar systems. It offers simplified procedures for pre-certified generators of 2 megawatts or less, connecting to low-voltage systems of less than 69 kilovolts. It also outlines separate procedures for generators of 2 to 10 megawatts and of more than 10 megawatts, connecting to low- and high-voltage systems. Relatively large distributed generators, up to 20 megawatts, may benefit under the proposed rule, because it is simpler and less costly to follow than the newly released interconnection rule for larger generators. FERC has stated that it intends this rule to encourage the use of DE systems of all kinds.

In its comments to the commission about the ANPR, Edison Electric Institute (EEI) stated that it supports standardization because properly constructed standardized processes can provide customers with significant benefits, and ensure that electricity delivery networks can operate safely and reliably.

EEI the offered a set of principles to assist FERC in the development of interconnection rules and procedures for DE systems:

• All utility customers should be treated in a non-discriminatory manner;
• DE interconnection rules must ensure that all electric consumers continue to receive safe, adequate, and reliable service;
• There should be no ratepayer or shareholder subsidies to small generators;
• Interconnection procedures and agreements should only apply to interconnection, not delivery, or other services;
• Any DE interconnection policy must accommodate variations in local and regional operating requirements and system designs;
• Availability of sensitive and confidential information must not compromise national security or the commercial interests of third parties.

EEI further argued that the commission should leave the regulation of distribution-level interconnection to the states. By doing so, the commission would maintain its clear authorities under the Federal Power Act, and ensure that the interconnection of small generators correctly takes into account state and local requirements, as well as regional operational and reliability standards.

Commission entry into distribution-level interconnection raises complex jurisdictional and cost-recovery issues. Commission procedures could impose costs on utilities, although the commission has no authority to grant recovery of these costs through retail rates, an authority that resides with the states.

If the commission does end up regulating distribution-level interconnections, it should create a single set of documents for generators up to 10 megawatts, or for a size that regional transmission operators or independent system operators deem appropriate for their respective region. Such a set of documents would include a single, uniform set of procedures; an agreement; and an application.

With considerable experience interconnecting non-utility generators into the transmission grid, electric utilities recognize that even small DE poses new challenges. Conditions on different parts of the distribution grid, even within a single utility's network, can be so variable that it complicates attempts to generalize about DE's grid impacts.

Complicating the picture further is wide variation in the DE units themselves, including the manner of the connection, the generation technology used, the plant's impact on power quality, the manner in which the plant is operated, the amount of fault currently injected onto the grid, and the amount of energy being exported from the facility to the grid. Because of these uncertainties, each DE interconnection must be studied individuallyóa somewhat costly endeavor. To help streamline equipment certification, EEI supports the development of equipment testing procedures by the National Renewable Energy Laboratories.

A number of other factors complicate the interconnection of DE systems. These include:

• Uncertainty over the installer's intended use. Many end-users seek DE as backup during utility outages. Utilities are concerned that DE operation will cause backfeed onto the grid during emergencies, energizing lines thought to be dead and resulting in possible injuries or fatalities to utility workers as they repair downed lines. The same holds true in non-emergencies, when line workers are trying to upgrade facilities.
• The potential for electric utility customer and shareholder subsidies to small generators. These situations could occur if small generators did not have to pay the actual cost the utility incurs to study the interconnection request, or if small generators do not contribute to the cost of grid upgrades, to the extent that large generators would have to contribute.
• Complications for grid safety and reliability, which impose more costs to study the grid impacts of the proposed generator. A DE interconnection might also require the connecting utility to make localized grid upgrades that, but for the DE interconnection, would not be necessary. Utilities favor requiring the installer of DE to pay these costs.
• The cost of insurance. If small generators do not have to provide adequate insurance, utilities and their other customers will be exposed to the damages that a small generator could cause. In effect, the utility would be providing insurance by fiat, without compensation. The commission should require small generators to provide their own insurance.

EEI stressed to FERC that its final ruling on interconnection standards for small generators must also ensure safe, reliable, and high-quality electric service. Electricity transmission and distribution owners should have adequate time and resources to study system impacts and take necessary steps to interconnect small generators safely and reliably. Small distribution utilities lack many of the resources of large utilities with which the commission is most familiar. But the commission should assume that small generators will have some system impactóimpacts that could benefit small generators at expense of safety, reliability, and quality of service.

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 will be needed to ensure that the grid can continue to meet the country's growing demands for electricity. The interconnection of small DE systems, another element in today's increasingly complex electricity grid, will also need to be properly structured to enable these systems to fulfill their potential, while furthering the nation's goal of a reliable and affordable electricity supply.

JAMES FAMA is executive director of EEI's Energy Delivery Group in Washington, DC.

DE - September/October 2004