[Federal Register Volume 66, Number 177 (Wednesday, September 12, 2001)]
[Notices]
[Pages 47460-47462]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 01-22841]


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DEPARTMENT OF ENERGY


National Transmission Grid Study 2001

AGENCY: Department of Energy.

ACTION: Notice of public workshops.

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SUMMARY: This notice announces the National Transmission Grid Study, a 
set of public workshops, and request comments. President George W. Bush 
unveiled his National Energy Policy (NEP) on May 17, 2001. Included in 
the NEP were 105 recommendations to produce more reliable, affordable 
and environmentally clean energy. One of the recommendations directed 
the Secretary of Energy to examine the benefits of establishing a 
national electrical grid, identifying major transmission bottlenecks 
and remedies to remove them. This National Transmission Grid Study 2001 
(NTGS 2001) will identify the major transmission bottlenecks across the 
U.S. It will examine both the technical and economic issues resulting 
from these transmission constraints and provide innovative solutions to 
reverse these trends. A 21st century transmission super highway that 
utilizes new technology to ensure reliability will be the driver that 
serves the growing needs of our economy. A vibrant and reliable 
transmission system is essential to lowering the cost of electricity 
for customers all across the country. The NTGS 2001 will recommend 
regulatory and market based approaches that will stimulate new 
investment in our interstate bulk power transmission systems. The NTGS 
2001 team will work with our nation's Governors to ensure that state's 
views are heard in the process of developing this study.

DATES: DOE will host public workshops at the following dates, times and 
locations. The agenda and subject matter will be the same for each 
workshop. Those planning to attend the workshops should register at 
www.ntgs.doe.gov

--September 24th/9 a.m.--4 p.m./Detroit, Michigan.
    Detroit Marriott Romulus, Metro Airport, 30559 Flynn Drive, 
Romulus, MI 48174.
--September 26th/9:00 a.m.--4:00 p.m./Atlanta, GA.
    Hyatt Regency, 265 Peachtree Street NE, Atlanta, GA 30303.
--September 28th/9:00 a.m.--4:00 p.m./Phoenix, Arizona.
    Phoenix Airport Marriott, 1101 North 44th Street, Phoenix, AZ 
85008.

    Public Participation: The workshops are open to the public. If you 
would like to submit written comments, they can be submitted at a 
workshop or to either

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address below on or before October 10, 2001. E-mailed comments are 
recommended.

ADDRESSES: Send comments to: www.ntgs.doe.gov or Paul Carrier, Office 
of Policy and International Affairs (PI-22), US Department of Energy, 
1000 Independence Avenue, SW, Washington, DC 20585.

FOR FURTHER INFORMATION CONTACT: NTGS 2001's web site at 
www.ntgs.doe.gov or contact Paul Carrier, NTGS 2001 DOE Program Office 
of Policy and International Affairs (202) 586-5659. Vincent DeVito, 
NTGS 2001 Counsel (202) 586-8660.

SUPPLEMENTARY INFORMATION: The purpose of the workshops is to address 
and solicit comments on the NTGS 2001 and, in particular, on the 
following issues identified by the study team to facilitate discussion.

Transmission Planning and the Need for New Capacity

    The character of transmission planning is changing dramatically as 
the structure of the U.S. electricity industry shifts from one 
dominated by vertically integrated utilities to one in which new and 
evolving regional transmission organizations will be primarily 
responsible for these plans. In addition, the emergence of wholesale 
electricity markets changes the details of transmission planning in 
many ways, most of which are still in flux. These changes in industry 
structure raise important issues about transmission planning and the 
need for new transmission capacity, including: (1) The need for clear 
transmission-planning criteria, which includes appropriate measures and 
consideration of reliability and commerce as well as siting and other 
environmental effects; (2) the integration of planning for 
transmission, generation, and demand-side management programs 
(including consideration of nontransmission alternatives that can meet 
reliability requirements and commercial needs); (3) the role of new 
technologies that might reduce the need to build large transmission 
facilities; (4) the need for high-quality data and projections on the 
types, timing, size and locations of new generating units and on the 
magnitudes and shapes of customer loads; (5) the need for advanced 
planning methods that can deal with a multiplicity of alternative 
futures; (6) the role of merchant (unregulated, for-profit) 
transmission projects; (7) the possible effects of new transmission 
facilities on the ability of some generators to artificially raise 
market prices for energy; and (8) the potential benefits of proactive 
transmission plans that can guide future investments in, and the 
locations, of generation and demand-management programs.

Transmission Siting and Permitting

    In recent years, two conflicting trends have caught the attention 
of energy policy officials and the electricity industry. One is that 
across the nation the need for electricity transmission system 
improvements is growing; in fact, it has already become urgent in some 
areas. The other is that it has become increasingly difficult to obtain 
approvals from pertinent state and federal agencies for the siting and 
construction of proposed major additions or upgrades of the nation's 
electric transmission grids. Further, although bulk power markets now 
span large multistate regions, the existing regime for siting and 
permitting of transmission facilities remains fundamentally state 
based. This regime may not be well adapted to reviewing proposed new 
transmission facilities from a regional perspective. The policy options 
for addressing transmission siting and permitting in a restructured 
electricity industry fall into three major categories: (1) Options to 
establish regional or federal siting institutions with authority to 
obtain rights-of-way for new transmission projects; (2) options to 
improve the existing state-based regime for transmission siting; and 
(3) options that could improve siting practices by government agencies 
and the electricity industry under any governance structure.

Business Models for Transmission Investment and Operation

    A common theme in restructured electricity systems around the world 
is the unbundling of generation, transmission, and distribution and the 
creation of independent transmission entities that link competitive 
generation to regulated distribution. The restructured transmission 
entities can encompass three business functions: system operation, 
market operation, and grid ownership. To a large extent, current 
transmission sector business models are based on the previous grid 
ownership structure and on political expediency. In the U.S. where a 
large portion of the electricity grid is owned by investor-owned 
utilities, formation of non-profit Independent System Operators (ISOs) 
to control but not own deregulated transmission assets was a convenient 
approach that enabled restructuring to move forward without requiring 
utilities to divest their transmission assets. By contrast, in 
countries such as the U.K. or Spain where the government or private 
entities previously owned the transmission assets, restructuring 
entailed formation of for-profit independent transmission companies 
(ITCs). Both the ISO and ITC business models have strengths, 
weaknesses, and multiple variants. Federal Energy Regulatory Commission 
(FERC) order 2000 and subsequent orders concerning the formation of 
Regional Transmission Organizations (RTOs) do not identify a preferred 
business model for transmission functions. The need to evaluate 
alternative business models for transmission enterprises is prompted by 
the moves toward large RTOs, current experiences with the ISO structure 
and the development of RTO proposals that advocate formation of for-
profit ITCs. Key issues related to the choice of business model for 
RTOs include the political feasibility of different models as well as 
their effects on: (1) market efficiency; (2) system reliability; (3) 
operational efficiency; (4) transmission access and interconnection 
policies; (5) transmission system investment and innovation; and (6) 
governance and regulatory oversight.

Operation of Interconnected Transmission Systems

    Electric power systems were originally interconnected for two 
purposes: reliability and economy. Operation protocols evolved for the 
interconnected system that permitted maintenance of system frequency, 
monitoring of trades between regions, and the prevention of major power 
outages as the result of single contingencies such as the sudden loss 
of any system component. Interconnection also led to a variety of 
problems: loop flows, inter-regional stability concerns, and issues 
associated with management and coordination of a very large, diverse 
set of generators and loads. The advent of competitive energy markets 
has blurred the sharp distinction between reliability and economy so 
that reliable service may become a commodity. In addition, the 
voluntary cooperation by which utilities and others involved in system 
operation performed their tasks has been difficult to maintain as 
former partners become competitors. Two main approaches for dealing 
with short-term reliability issues (particularly congestion of 
components) have evolved: the first approach is a system whereby 
parties that are engaging in transactions curtail them according to 
prescribed rules whenever reliability becomes a concern. The 
transmission loading relief (TLR) protocol is the embodiments of this 
approach. The second approach is market-based in

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which spatial price patterns are created that lead market participants 
to relieve congestion through actions taken in their own self-interest. 
Locational pricing, such as nodal pricing, ``flowgate'' pricing, and to 
a lesser extent zonal pricing, are embodiments of this second approach. 
Issues of concern for operation of interconnected power systems 
include: (1) Could the entire U.S. electricity grid be operated as one 
integrated whole or a few large integrated markets? (2) How could we 
assure reliability of such an integrated or national electricity grid? 
(3) What are the merits of and appropriate relationship between 
``mandated'' approaches (e.g., reliance on TLR protocols), and 
``market-based'' approaches, such as real-time and day-ahead markets to 
ensure system reliability?

Reliability Management and Oversight

    Assuring power system reliability is both a physical and 
organizational activity. Specific activities must take place but they 
do so within a commercial and political framework. Determining who sets 
the rules for power system reliability and how may be the most 
challenging aspect of maintaining reliability in a restructured 
electricity industry. Historically, the vertically integrated utility 
industry utilized the North American Electric Reliability Council 
(NERC) a bottom-up, industry-dominated, volunteer organization to 
establish reliability rules and monitor compliance. The restructured 
industry will require a more open and inclusive process for 
establishing mandatory standards and monitoring and enforcing 
compliance. To assure reliability the following issues need to be 
addressed: (1) The physical constraints and requirements of the 
electricity system; (2) who should make decisions about reliability and 
the technical and economic bases for those decisions; (3) who takes 
what risk (communal versus individual risks); (4) how reliability costs 
are assessed; (5) how to address the inevitable disputes that will 
arise over reliability decisions; (6) what should be the scope of 
reliability decisions (regional vs. national); (7) how to assess 
alternative means of supplying reliability services (including the use 
of customer loads as reliability resources), and how technology is 
expanding these options; and (8) evaluating proposed institutional 
structures for insuring reliability.

New Transmission Technologies

    Electric industry restructuring is based in part on the assumption 
of a transmission system that is flexible, reliable, and open to all 
exchanges no matter where the suppliers and consumers of energy are 
located. However, neither the existing transmission system nor its 
management infrastructure can fully support this open exchange. Some 
desirable market transactions are quite different from those envisioned 
when the transmission system was designed, and they may stress the 
limits of safe operation. The risk posed by such transactions may not 
be recognized in time to avert major system emergencies, which may be 
difficult to manage without loss of customer load. It is also 
increasingly common for one transaction to interfere with others, 
producing ``congestion'' in the system. These problems can be remedied 
in part by direct technical reinforcements to the transmission system, 
in the form of improved hardware technology. Another need is for 
indirect reinforcements to the general infrastructure for grid 
operations and planning. Progress in both areas has, for many years, 
been hampered by electricity restructuring. This process is far from 
complete, and it has greatly weakened the essential dialog between 
technology developers and technology users. Development of new 
technology must be closely linked to its actual deployment for 
operational use. Together, both activities should reflect, serve, and 
keep pace with the evolving infrastructure needs of transmission 
organizations. This is not happening. Neither the details nor the needs 
of this infrastructure are well known, and all parties are 
understandably averse to investments that may not be promptly and 
directly beneficial to them. As a result many promising technologies 
are stuck at various points in the ``pipeline'' from concept to 
practical use. Included among them are superconducting equipment, large 
scale devices for routing power flow on the grid (HVDC and FACTS), real 
time operating tools for enhanced management of grid assets, and a new 
generation of system planning methods that are robust against 
uncertainty. A critical issue is that some enabling technologies for 
healthy and reliable electricity commerce are not attractive to 
individual commercial entities, but should be developed and deployed in 
furtherance of the public good. To summarize, key issues include: (1) 
The capability and cost of new technologies to improve operation of the 
transmission system; and (2) the requirements of and institutional 
options available to support timely development and deployment of these 
technologies through the current period of industry restructuring.

    Issued in Washington, DC, on September 6, 2001.
Margot Anderson,
Deputy Assistant Secretary, Office of Policy and International Affairs.
[FR Doc. 01-22841 Filed 9-11-01; 8:45 am]
BILLING CODE 6450-01-P