25838 Federal Register / Vol. 72, No. 87 / Monday, May 7, 2007 / Notices 

1This notice uses the terms ‘‘Secretary’’ and 

‘‘Department’’ interchangeably. 

2Electric transmission congestion (congestion) is 

the condition that occurs when transmission 

capacity is not sufficient to enable safe delivery of 

all scheduled or desired wholesale electricity 

transfers simultaneously. Congestion results from a 

transmission capacity constraint (constraint). See 

Section II.A of this notice for further discussion of 

these terms. 

DEPARTMENT OF ENERGY 

Office of Electricity Delivery and 

Energy Reliability; Draft National 

Interest Electric Transmission Corridor 

Designations 

[Docket No. 2007–OE–01, Draft Mid–Atlantic 

Area National Corridor; Docket No. 2007– 

OE–02, Draft Southwest Area National 

Corridor] 

AGENCY: Department of Energy. 

ACTION: Notice and opportunity for 

written and oral comment. 

SUMMARY: Having issued the first 

National Electric Transmission 

Congestion Study under section 216 of 

the Federal Power Act (FPA), and 

having evaluated public comments on 

the Study, the Department of Energy 

(Department or DOE) today begins two 

proceedings that may lead to one or 

more orders designating one or more 

national interest electric transmission 

corridors (National Corridors). The 

Department believes that, although the 

FPA does not require it, allowing an 

opportunity for comment on draft 

National Corridor designations prior to 

the Department issuing its FPA section 

216(a) report will aid both the public 

and the Department. Interested persons 

may file written comments in one or 

both of these proceedings in the manner 

indicated in the ADDRESSES portion of 

this notice. Only those persons who file 

such comments by the date listed in the 

DATES portion of this notice will become 

parties to the proceedings and, thus, 

eligible to file a request for rehearing 

under FPA section 313 of any final 

order issued in these proceedings. 

DATES: Written comments on the draft 

National Corridors must be received on 

or before July 6, 2007. 

The Department has scheduled public 

meetings on Docket No. 2007–OE–01 

(the draft Mid-Atlantic Area National 

Corridor) for the following dates: 

May 15, 2007, 10 a.m. to 3:30 p.m., 

Arlington, VA; and 

May 23, 2007, 10 a.m. to 3:30 p.m., 

New York, NY. 

The Department has scheduled a 

public meeting on Docket No. 2007–OE– 

02 (the draft Southwest Area National 

Corridor) for May 17, 2007, 10 a.m. to 

3:30 p.m., San Diego, CA. 

ADDRESSES: Color versions of the figures 

included in today’s notice as well as 

other supporting documents are 

available at http://nietc.anl.gov. 

You may submit written comments on 

one or both of the draft National 

Corridors electronically at http:// 

nietc.anl.gov, or by mail to the Office of 

Electricity Delivery and Energy 

Reliability, OE–20, U.S. Department of 

Energy, 1000 Independence Avenue 

SW., Washington, DC 20585. If you are 

commenting on Docket No. 2007–OE–01 

(the draft Mid-Atlantic Area National 

Corridor), your comments must be 

marked ‘‘Attn: Docket No. 2007–OE– 

01.’’ If you are commenting on Docket 

No. 2007–OE–02 (the draft Southwest 

Area National Corridor), your comments 

must be marked ‘‘Attn: Docket No. 

2007–OE–02.’’ The following electronic 

file formats are acceptable: Microsoft 

Word (.doc), Microsoft Works (.wps), 

Corel Word Perfect (.wpd), Adobe 

Acrobat (.pdf), Rich Text Format (.rtf), 

plain text (.txt), Microsoft Excel (.xls), 

and Microsoft PowerPoint (.ppt). If you 

submit information that you believe to 

be exempt by law from public 

disclosure, you may only submit your 

comments by mail, and you must 

submit one complete copy, as well as 

one copy from which the information 

claimed to be exempt by law from 

public disclosure has been deleted. DOE 

is responsible for the final 

determination concerning disclosure or 

nondisclosure of the information and for 

treating it in accordance with the DOE’s 

Freedom of Information regulations (10 

CFR 1004.11). 

Note: Delivery of U.S. Postal Service mail 

to DOE continues to be delayed by several 

weeks due to security screening. DOE 

therefore encourages commenters to submit 

comments electronically by e-mail. If 

comments are submitted by mail, the 

Department requests that they be 

accompanied by a CD or diskette containing 

the electronic files of the submission. 

The locations for the public meetings 

are: 

Arlington—Doubletree Hotel Crystal 

City—National Airport, 300 Army 

Navy Drive, Arlington, VA 22202– 

2891; 

New York—Park Central New York 

Hotel, 870 Seventh Avenue at 56th 

Street, New York, NY 10019–4038; 

and 

San Diego—Manchester Grand Hyatt 

San Diego Hotel, One Market Place, 

San Diego, CA 92101. 

If you are interested in speaking at 

one of these meetings, please sign up at 

http://www.energetics.com/ 

NIETCpublicmeetings or call 410–953– 

6250. 

FOR FURTHER INFORMATION CONTACT: For 

technical information, David Meyer, 

DOE Office of Electricity Delivery and 

Energy Reliability, (202) 586–1411. 

david.meyer@hq.doe.gov. For legal 

information, Mary Morton, DOE Office 

of the General Counsel, (202) 586–1221, 

mary.morton@hq.doe.gov. 

SUPPLEMENTARY INFORMATION: 

I. Background 

A. Statutory Framework 

Section 1221(a) of the Energy Policy 

Act of 2005 (Pub. L. 109–58) (EPAct) 

added a new section 216 to the Federal 

Power Act (16 U.S.C. 824p) (FPA). New 

FPA section 216(a) requires the 

Secretary of Energy (Secretary) 1 to 

conduct a nationwide study of electric 

transmission congestion 2 within one 

year from the date of enactment of 

EPAct and every three years thereafter. 

FPA section 216(a)(1) requires the 

Secretary to consult with ‘‘affected 

States’’ when conducting the study. 16 

U.S.C. 824p(a)(1). FPA section 216(a)(2) 

provides ‘‘interested parties’’ with an 

opportunity to offer ‘‘alternatives and 

recommendations.’’ 16 U.S.C. 

824p(a)(2). Following consideration of 

such alternatives and recommendations, 

the Secretary is required to issue a 

report on the study ‘‘which may 

designate any geographic area 

experiencing electric energy 

transmission capacity constraints or 

congestion that adversely affects 

consumers as a national interest electric 

transmission corridor.’’ 16 U.S.C. 

824p(a)(2). FPA section 216(a)(4) states 

that in determining whether to 

designate a corridor, the Secretary may 

consider whether: 

(A) the economic vitality and development 

of the corridor, or the end markets served by 

the corridor, may be constrained by lack of 

adequate or reasonably priced electricity; 

(B)(i) economic growth in the corridor, or 

the end markets served by the corridor, may 

be jeopardized by reliance on limited sources 

of energy; and (ii) a diversification of supply 

is warranted; 

(C) the energy independence of the United 

States would be served by the designation; 

(D) the designation would be in the interest 

of national energy policy; and 

(E) the designation would enhance national 

defense and homeland security. 

16 U.S.C. 824p(a)(4). 

The effect of a National Corridor 

designation is to delineate geographic 

areas within which, under certain 

circumstances, the Federal Energy 

Regulatory Commission (FERC) may 

authorize ‘‘the construction or 

modification of electric transmission 

facilities.’’ FPA section 216(b); 16 U.S.C. 

824p(b). The statute imposes several 

conditions on the exercise of FERC’s 


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Federal Register / Vol. 72, No. 87 / Monday, May 7, 2007 / Notices 25839 

3See also Regulations for Filing Applications for 

Permits to Site Interstate Electric Transmission 

Facilities, Order No. 689, 71 FR 69,440, 69,468 

(Dec. 1, 2006), 117 FERC ¶ 61,202 at pp. 128–29 

(2006) (to be codified at 18 CFR parts 50 and 380), 

reh’g pending (FERC Order No. 689) (§ 50.6(e) 

requires applicants to demonstrate that the 

conditions of FPA sec. 216(b)(1) are met). 

4See also id. (§ 50.6(f) requires applicants to 

demonstrate that the conditions of FPA sec. 

216(b)(2)–(6) are met). 

5See id. 71 FR 69,440, 69,446, 117 FERC ¶ 61,202 

at PP 41–42 (‘‘The Commission will conduct an 

independent environmental analysis of the project 

and determine if there is no significant impact as 

required by [the National Environmental Policy 

Act]. It will look at alternatives, including, as 

appropriate, alternatives other than transmission 

lines. * * * It will review the alternatives for their 

respective impacts on the environment and will 

determine mitigation measures to lessen the adverse 

impacts. * * * The Commission will also consider 

the adverse effects the proposed facilities will have 

on land owners and local communities.’’); and 71 

FR 69,440, 69,470, 117 FERC ¶ 61,202 at p. 142–43 

(§§ 380.5(b)(14) and 380.6(a)(5) require either an 

environmental assessment or an environmental 

impact statement for projects seeking permits under 

sec. 216(b)). 

6RTOs and ISOs are Federally regulated entities 

charged with operating a regional transmission 

system in a manner that is non-discriminatory and 

ensures safety and reliability. The existing RTOs 

and ISOs do not own any transmission or 

generation and are run by independent boards of 

directors. 

permitting authority within a National 

Corridor. 

Under FPA section 216(b)(1), FERC 

jurisdiction is triggered only when 

either: the State does not have authority 

to site the project; the State lacks the 

authority to consider the interstate 

benefits of the project; the applicant 

does not qualify for a State permit 

because it does not serve end-use 

customers in the State; the State has 

withheld approval for more than one 

year; or the State has conditioned its 

approval in such a manner that the 

project will not significantly reduce 

congestion or is not economically 

feasible. 16 U.S.C. 824p(b)(1).3 Further, 

FPA section 216(g) states, ‘‘Nothing in 

this section precludes any person from 

constructing or modifying any 

transmission facility in accordance with 

State law.’’ 16 U.S.C. 824p(g). 

Under FPA section 216(b)(2)–(6), 

FERC may issue a permit only if all of 

the following conditions are met: the 

facilities will be used for the 

transmission of electric energy in 

interstate commerce; the project is 

consistent with the public interest; the 

project will significantly reduce 

congestion and protect or benefit 

consumers; the project is consistent 

with national energy policy and will 

enhance energy independence; and the 

project maximizes, to the extent 

reasonable and economical, the 

transmission capabilities of existing 

towers or structures. 16 U.S.C. 

824p(b)(2)–(6).4

Accordingly, a National Corridor 

designation itself does not preempt 

State authority or any State actions. A 

National Corridor designation is not a 

determination that transmission must, 

or even should, be built; it is not a 

proposal to build a transmission facility 

and it does not direct anyone to make 

a proposal. Transmission expansion is 

but one possible solution to a 

congestion or constraint problem; 

increased demand response, improved 

energy efficiency, and conservation, as 

well as siting of additional generation 

close to load centers are also potential 

solutions. Whether a particular 

transmission project, some other 

transmission project, or a nontransmission project is an appropriate 

solution to a congestion or constraint 

problem identified by a National 

Corridor designation is a matter that 

market participants, applicable regional 

planning entities, and State authorities, 

among others, will consider and decide 

before any project is built. In the event 

that FERC jurisdiction under FPA 

section 216(b) is triggered, the 

designation of a National Corridor by 

the Secretary does not control FERC’s 

substantive decision on the merits as to 

whether to grant or deny a permit 

application, specifically where any 

facilities covered by a permit should be 

located, or what conditions should be 

placed on a permit. 

A National Corridor designation is not 

a siting decision; it does not dictate the 

route of any transmission project. If a 

transmission project is proposed in a 

National Corridor, it will be the State 

siting authorities, and potentially FERC 

if certain conditions are met, that will 

determine the specific route of that 

project.5

Thus, FPA section 216(a) does not 

shift to the Department any of the 

traditional roles of transmission 

planners and siting authorities in 

evaluating solutions to congestion and 

constraint problems and designing 

routes for transmission facilities. 

Instead, FPA section 216(a) assigns to 

the Department the role of identifying 

transmission congestion and constraint 

problems, and the geographic areas in 

which these problems exist. 

B. Congestion Study 

On August 8, 2006, DOE issued its 

initial congestion study (the Congestion 

Study) for comment by interested 

members of the public and affected 

States (71 FR 45,047 (Aug. 8, 2006)). 

The Congestion Study gathered 

historical congestion data obtained from 

existing studies prepared by the regional 

reliability councils, regional 

transmission organizations (RTOs) and 

independent system operators (ISOs),6

and regional planning groups. The 

Congestion Study also modeled future 

congestion: the years 2008 and 2011 for 

the Eastern Interconnection; and the 

years 2008 and 2015 for the Western 

Interconnection. The modeling focused 

on five metrics: binding hours (the 

number of hours per year that a path is 

loaded to its limit and, thus, unable to 

accommodate all desired power 

transactions), U90 (the number of hours 

per year that a path is loaded above 90 

percent of its limit), all-hours shadow 

price (the marginal cost of generation 

redispatch required to accommodate a 

given constraint averaged across all 

hours in the year), binding hours 

shadow price (average shadow price 

over only those hours during which the 

constraint is binding), and congestion 

rent (shadow price multiplied by flow, 

summed over all hours the constraint is 

binding). 

Based on the historical data and the 

modeling results, the Congestion Study 

classified the most significant 

congestion areas in the country. Two 

‘‘Critical Congestion Areas’’ (i.e. areas 

where the current and/or projected 

effects of congestion are especially 

broad and severe) were identified: the 

Atlantic coastal area from metropolitan 

New York through northern Virginia 

(the Mid-Atlantic Critical Congestion 

Area); and southern California (the 

Southern California Critical Congestion 

Area). Four ‘‘Congestion Areas of 

Concern’’ (i.e. areas where a large-scale 

congestion problem exists or may be 

emerging but more information and 

analysis appear to be needed to 

determine the magnitude of the 

problem) were identified: New England; 

the Phoenix-Tucson area; the San 

Francisco Bay area; and the SeattlePortland area. Also, a number of 

‘‘Conditional Congestion Areas’’ (i.e. 

areas where future congestion would 

result if large amounts of new 

generation were to be developed 

without simultaneous development of 

associated transmission capacity) were 

identified, such as: Montana-Wyoming; 

Dakotas-Minnesota; Kansas-Oklahoma; 

Illinois, Indiana and upper Appalachia; 

and the Southeast. 

DOE has received over 400 comments 

on the Congestion Study. DOE has made 

all of these comments available at 

http://nietc.anl.gov. The Department is 

no longer accepting comments on the 

Congestion Study. All comments filed 

in response to today’s notice should be 

limited to the draft National Corridors 

set forth in this notice. 


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25840 Federal Register / Vol. 72, No. 87 / Monday, May 7, 2007 / Notices 

7A detailed explanation of the location of these 

draft National Corridors is provided in Sections 

VIII.D and IX.D of this notice. 

C. Purpose of Today’s Notice 

This notice summarizes and responds 

to the comments received in response to 

the Congestion Study that are relevant 

to the designation of National Corridors. 

This notice also issues and solicits 

comment on draft National Corridor 

designations for the two Critical 

Congestion Areas identified in the 

Congestion Study: the draft MidAtlantic Area National Corridor; and the 

draft Southwest Area National Corridor. 

See Figure I–1 for the location of these 

draft National Corridors.7 Further, the 

Department has scheduled three public 

meetings to discuss these draft National 

Corridor designations. If, after 

consideration of all comments on these 

draft designations, the Secretary decides 

that one or more National Corridor 

designations are appropriate, he will 

issue one or more orders making such 

designations. 

BILLING CODE 6450–01–P 


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Federal Register / Vol. 72, No. 87 / Monday, May 7, 2007 / Notices 25841 

This notice is also intended to notify 

interested persons how to obtain party 

status for the proceeding in Docket No. 

2007–OE–01 or the proceeding in 

Docket No. 2007–OE–02. Review of any 

final order designating a National 

Corridor in one of these proceedings 

will be governed by section 313 of the 

FPA (16 U.S.C. 8251). Thus, only those 


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25842 Federal Register / Vol. 72, No. 87 / Monday, May 7, 2007 / Notices 

8See also comments of BP Alternative Energy 

North America Inc. 9TLR is a procedure used in the Eastern 

Interconnection, usually outside of organized 

markets, to deal with situations when a 

transmission path has reach its operating limit. 

persons who have obtained party status 

in the proceeding may file a request for 

rehearing of a final order with the 

Department. Further, to the extent that 

any person has standing to obtain 

judicial review, the filing of a rehearing 

request within 30 days of issuance of 

the final order is a prerequisite to such 

potential judicial review. In order to 

become a party to one or both of these 

proceedings, you must file comments in 

response to this notice in the manner 

indicated in the ADDRESSES portion of 

this notice by the deadline date 

identified in the DATES portion of this 

notice. 

The proceedings being started today 

focus on the two geographic areas of the 

Nation experiencing the most acute and 

urgent electric transmission congestion 

problems. This notice takes no action 

with regard to the other geographic 

areas discussed in the Congestion 

Study. Thus, today’s notice does not 

address comments received on the 

Congestion Study that relate solely to 

areas outside the two Critical 

Congestion Areas. Also, today’s notice 

does not address those comments that 

relate to the conduct of future 

congestion studies. The Department will 

address the subject of how it intends to 

conduct future congestion studies in a 

later notice. 

II. Deciding When a National Corridor 

Designation Is Warranted 

The Congestion Study solicited 

comment on the criteria the Secretary 

should use when determining when a 

National Corridor designation is 

warranted. In this section, the 

Department summarizes and responds 

to these comments. 

A. General Scope of the Secretary’s 

Authority 

Summary of Comments 

The Department received numerous 

comments that relate to the general 

scope of the Secretary’s authority to 

designate National Corridors, including 

comments on the meaning of key terms 

used in FPA section 216(a). The 

Department received a few comments 

on the appropriate definition of 

‘‘congestion’’ and ‘‘constraint.’’

FirstEnergy Service Company 

(FirstEnergy) supported the definition of 

‘‘congestion’’ used in the Congestion 

Study. National Grid USA (National 

Grid) argued that the Congestion Study’s 

definition of ‘‘constraint’’ should be 

expanded to include not just limitations 

due to a piece of equipment, but also 

due to the absence of equipment 

between two or more nodes. Similarly, 

the California Energy Commission (CEC) 

argued that the focus of the Congestion 

Study is too narrow to accommodate 

State laws and policies on renewable 

portfolio standards. The CEC stated that 

the Department’s criteria for identifying 

congestion should incorporate 

consideration of constraints that pose 

obstacles to reasonably priced power, 

diversity of supply, and energy 

independence, regardless of whether 

those constraints currently produce 

congestion.8 Upper Great Plains 

Transmission Coalition argued that the 

lack of evidence of curtailments and 

congestion costs does not necessarily 

mean that a critical constraint is absent; 

for example, sophisticated management 

tools in place in the upper Great Plains 

have avoided the need for transmission 

loading relief (TLR) actions,9

nevertheless, export capacity is 

constrained. 

The Department received comments 

on the level of adverse effects on 

consumers needed to justify a National 

Corridor designation. The Pennsylvania 

Public Utility Commission (PAPUC) 

argued that National Corridors should 

be designated only where it is 

demonstrated that there is chronic 

physical congestion that has potential 

for substantially impairing existing or 

future grid reliability. The Attorney 

General for the State of Connecticut 

(Connecticut Attorney General) argued 

that the Department has no authority to 

designate a corridor in an area that the 

Congestion Study acknowledges does 

not rise to the level of a Critical 

Congestion Area. The Connecticut 

Attorney General argued that the statute 

was not intended to empower the 

Department to ‘‘act as a sort of roving 

commission that oversees transmission 

planning and construction nationwide,’’

and thus designations should be limited 

to ‘‘those limited and extraordinary 

circumstances in which transmission 

constraints so severely impact the 

national interest that Federal 

intervention’’ may be warranted. 

On the other hand, LS Power 

Development, LLC (LS Power) argued 

that the statutory standard for 

designating a corridor ‘‘appears to be 

relatively low’’ and that this is 

understandable given the limited 

purpose of a National Corridor 

designation. LS Power further argued 

that the Department should apply the 

standard for designation liberally, 

instead of ranking different areas of 

congestion and only addressing some of 

those areas. LS Power asserted that if an 

area is congested, consumers are 

therefore adversely affected by higher 

costs, and consumers should be afforded 

the potential relief available through a 

National Corridor designation. 

Similarly, the Edison Electric Institute 

(EEI) argued that the Department should 

not wait until a major problem emerges 

before designating a National Corridor, 

given the long-term, capital-intensive 

nature of electricity infrastructure 

development. EEI urged the Department 

to maintain a high-level view and not 

dwell on the unachievable goal of 

technical precision in the congestion 

study process before making 

designations. The Electric Power Supply 

Association (EPSA) argued that National 

Corridor designation is warranted 

wherever the grid is constrained to the 

point of only being available to 

accommodate power flows of incumbent 

utilities to serve their native load, 

because in all such circumstances 

consumers are adversely affected by the 

existence of a barrier to entry of 

potentially lower-cost competitors. 

The Department received comments 

on the use of projections of future 

congestion to support a National 

Corridor designation. The Organization 

of MISO States (OMS) argued that the 

statute makes clear that designations 

may only be made for areas actually 

experiencing congestion adversely 

affecting consumers, and does not 

provide for designations in areas that 

may experience congestion in the future 

or under certain circumstances. 

Therefore, OMS was not persuaded that 

National Corridor designation is 

warranted in the Congestion Areas of 

Concern or the Conditional Congestion 

Areas. OMS stated that rather than 

attempting to forecast the need for 

future National Corridors, designations 

should be in response to existing, 

persistent, and well-documented 

problems. Some Western commenters, 

including Northern Wasco County 

Peoples Utility District (NWPUD) and 

Seattle City Light (SCL), argued there is 

a need to examine historical data and 

not rely solely on simulated congestion 

metrics. Public Service Electric and Gas 

Company, PSEG Power LLC, and PSEG 

Energy Resources and Trade LLC 

(collectively PSEG) argued that forecasts 

of future congestion, driven by longrange projections of fuel costs, are 

inherently questionable. ABB, on the 

other hand, said National Corridor 

designation should not be based solely 

on analysis of historic congestion but 

rather should be made after a 

comprehensive analysis of future 

resource mix and resource adequacy. 


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10Midwest ISO is the RTO serving all or parts of 

Illinois, Indiana, Iowa, Kentucky, Michigan, 

Minnesota, Missouri, Montana, Nebraska, North 

Dakota, Ohio, Pennsylvania, South Dakota, and 

Wisconsin. 

11Other sources use similar definitions. See, e.g., 

California Independent System Operator, 

Conformed Simplified and Reorganized Tariff, App. 

A, Master Definitions Supplement (April 6, 2007) 

(‘‘Congestion—A condition that occurs when there 

is insufficient Available Transfer Capacity to 

implement all Preferred Schedules simultaneously 

or, in real time, to serve all Generation and 

Demand.’’); and Southwest Power Pool, Glossary 

and Acronyms, http://www.spp.org/ 

glossary.asp?letter=C (‘‘Congestion is a condition 

that occurs when insufficient transfer capacity is 

available to implement all of the preferred 

schedules for electricity transmission 

simultaneously.’’). 

12One aspect of the constraint-related definitions 

used in the Congestion Study did generate debate 

among commenters, which is addressed later in this 

section. 

13 In general terms, an LMP-based congestion 

management system entails an RTO or ISO 

operating a bid-based energy market in which those 

generators and loads who have not fully committed 

themselves through bilateral power contracts can 

participate. As the operator of the transmission 

system, the RTO or ISO also analyzes whether 

transmission of all the desired energy transactions 

is simultaneously feasible. When there are no 

binding constraints, the energy market clears at a 

single price throughout the system. When a 

constraint is binding, separate prices result on 

either side of the constraint. Market participants 

can then see and respond to these different LMPs. 

Those customers who choose to have power 

transmitted over the binding constraint are assessed 

a transactional congestion charge based on the 

difference between the LMPs on either side of the 

constraint. 

The American Wind Energy 

Association, Wind on the Wires, 

Interwest Energy Alliance, the Wind 

Coalition, and the Renewable Northwest 

Project (collectively Wind Associations) 

expressed concern that the Department 

may approach Conditional Congestion 

Areas in a manner that ‘‘continues the 

‘chicken and egg’ problem of wind 

development, in which no generators 

are constructed until transmission 

capacity is built, but no transmission 

capacity is expanded until there are 

generators requesting service.’’ Thus, 

the Wind Associations sought 

clarification that National Corridors can 

be designated in a Conditional 

Congestion Area before all the expected 

generation has been developed in that 

area. 

Some commenters called for 

clarification of the criteria the 

Department would use in deciding 

whether to designate a National 

Corridor and made recommendations 

about criteria they considered most 

important. For example, the Committee 

on Regional Electric Power Cooperation 

(CREPC) stated that the Department 

should develop metrics for the criteria 

used to designate National Corridors 

and document how it has applied the 

criteria. CREPC argued that priority 

should be given to designating National 

Corridors that enable the achievement of 

State energy policy objectives or that 

address location-constrained generation 

resource areas; low priority should be 

given to areas with contractual 

congestion but little physical 

congestion, or areas where findings of 

congestion are based on studies with a 

high level of uncertainty. The American 

Public Power Association (APPA) 

suggested that the Department focus on 

the effect that a designation will have on 

the plans of load-serving entities to meet 

their long-term service obligations to 

their retail customers; in particular, the 

effect on deliverability of new base-load 

and renewable resources to the loadserving entities that intend to purchase 

power from those resources. The 

Midwest Independent Transmission 

System Operator, Inc. (Midwest ISO) 10

supported the reduction in electricity 

supply costs as a criterion for National 

Corridor designation; however, only if 

there is sufficient evidence that such 

cost reductions would occur and that 

the amount of the reductions would be 

significant enough to warrant national 

attention. 

DOE Response 

FPA section 216(a)(2) gives the 

Secretary the discretion to designate as 

a National Corridor ‘‘any geographic 

area experiencing electric energy 

transmission capacity constraints or 

congestion that adversely affects 

consumers.’’ The statute does not define 

any of the terms in this phrase. 

The Congestion Study defined 

‘‘congestion’’ as the condition that 

occurs when transmission capacity is 

not sufficient to enable safe delivery of 

all scheduled or desired wholesale 

electricity transfers simultaneously. 

This definition generated little debate 

among commenters.11 The Congestion 

Study defined ‘‘transmission constraint’’

as a limitation on one or more 

transmission elements that may be 

reached during normal or contingency 

system operations. The Congestion 

Study also defined ‘‘constrained 

facility’’ as a transmission facility (line, 

transformer, breaker, etc.) that is 

approaching, at, or beyond a System 

Operating Limit or Interconnection 

Reliability Operating Limit.12

‘‘Congestion,’’ then, refers to the denial 

of desired transmission service over a 

transmission path, while ‘‘constraint’’

refers to the chokepoint on the 

transmission system that causes such 

denial of desired transmission service. 

In contrast, there is no generally 

accepted understanding of what 

constitutes ‘‘constraints or congestion 

that adversely affects consumers,’’ as the 

debate among the commenters amply 

demonstrates. The term is ambiguous, 

and the statute attaches no modifiers to 

the term to specify the particular type or 

magnitude of adverse effect intended. 

While the Congestion Study identified 

and applied various metrics ‘‘related to 

the magnitude and impact of 

congestion,’’ the Congestion Study did 

not attempt to define when constraints 

or congestion ‘‘adversely affects 

consumers.’’ In the following 

discussion, the Department will first 

address congestion that adversely affects 

consumers and then constraints that 

adversely affect consumers. 

With regard to congestion that 

adversely affects consumers, the 

Department notes that any congestion, 

by definition, thwarts customer choice, 

because it prevents users of the 

transmission grid from completing their 

preferred power transactions. These 

users include wholesale industrial 

consumers of power as well as loadserving entities buying power on behalf 

of retail consumers, all of whom are 

prevented by congestion from obtaining 

delivery of desired quantities of 

electricity from desired sources. In other 

words, any congestion on a line 

necessarily interferes with the choices 

of those who wish to use that line on 

their own or their customers’ behalf. 

Whenever there is congestion on a 

transmission path, there simply is not 

enough transmission capacity to 

accommodate all the desired power 

transactions, and some sort of rationing 

of available capacity is needed. In areas 

with organized electricity markets, this 

rationing generally occurs through a 

pre-established economic mechanism, 

such as a congestion management 

system based on locational marginal 

prices (LMPs),13 which is designed to 

allocate the limited capacity to the users 

who value it the most. In areas of the 

country without organized markets, the 

rationing may involve the transmission 

provider denying requests for 

transmission service, adjusting 

schedules, or in some cases making pro 

rata curtailments in real time. 

Regardless of how the rationing is 

resolved, however, one thing remains 

true: congestion results in some users of 

the transmission system being denied 

the benefit of their preferred 

transactions. 

Moreover, electricity buyers generally 

seek power from the most economic 

source. Arranging for delivery of power 

from less preferred sources is referred to 

as ‘‘redispatching’’ power. When 

congestion occurs, resulting in the need 


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25844 Federal Register / Vol. 72, No. 87 / Monday, May 7, 2007 / Notices 

14A node is the physical location on the 

transmission system where energy is, or will be, 

injected by generators or withdrawn by loads. 

15As the Department is not issuing any draft 

National Corridors today based on the existence of 

constraints in the absence of persistent congestion, 

it is unnecessary in this notice to reach the question 

of the type of information that would be required 

to demonstrate that a constraint is hindering the 

development or delivery of a generation source that 

is in the public interest. However, the Department 

notes that the considerations identified in FPA 

section 216(a)(4) provide some examples of 

generation sources the development of which 

would be in the public interest, including sources 

that are needed to ensure adequate or reasonably 

priced electricity, sources that are needed for 

diversification of supply, sources that would 

promote energy independence, sources that would 

further national energy policy, or sources that 

would enhance national defense and homeland 

security. There may, however, be other generation 

sources the development of which would be in the 

public interest. 

16Because the Department is not issuing any draft 

National Corridor designations based solely on 

projections of future congestion (without any 

showing of a constraint that adversely affects 

consumers), it is not necessary to determine now 

the extent of its authority to do so. 

17See, e.g., EPAct sec. 1241 (requiring FERC to 

establish rules to promote capital investment in 

transmission); EPAct sec. 1233 (requiring FERC to 

exercise its authority in a manner that facilitates 

planning and expansion of transmission to meet the 

needs of load-serving entities); EPAct sec. 368 

(requiring the designation of energy right-of-way 

corridors across Federal lands for electric 

transmission and other energy projects); FPA sec. 

216(h) (establishing procedures to ensure timely 

and efficient review of proposed transmission 

projects by Federal agencies); and EPAct sec. 1222 

(giving additional authority for Western Area Power 

Administration and Southwestern Power 

Administration to participate with other entities in 

the development of transmission). 

for buyers to accept power from lesspreferred generating sources in order to 

meet their power needs, redispatch is 

required and typically results in the use 

of more expensive power. Congestion 

also usually reduces competition and 

diversity, by limiting the range of 

generators from which buyers can 

obtain power. Finally, congestion means 

that parts of the transmission system are 

so heavily loaded that grid operators 

have fewer options for dealing with 

adverse circumstances or unanticipated 

events, thus increasing the risk of 

blackouts, forced interruptions of 

service, or other grid-related 

disruptions. 

Therefore, any congestion can 

adversely affect at least some 

consumers. Nevertheless, congestion 

remedies are not free; therefore, not all 

congestion is worth fixing. Under 

certain circumstances, congestion can 

arise on any transmission path. But the 

appearance of isolated or transient 

instances of congestion usually does not 

warrant consideration of transmission 

expansion. While the Department is not 

attempting in this notice to define the 

complete scope of the term ‘‘congestion 

that adversely affects consumers’’ as 

used in FPA section 216(a)(2), the 

Department concludes that the term 

includes congestion that is persistent. 

Thus, the Department believes that FPA 

section 216(a) gives the Secretary the 

discretion to designate a National 

Corridor upon a showing of the 

existence of persistent congestion, 

without any additional demonstration of 

adverse effects on consumers. However, 

as discussed below, whether the 

Secretary should exercise his discretion 

to designate a National Corridor in a 

given instance of congestion is a 

separate question. 

With regard to constraints that 

adversely affect consumers, one way in 

which a constraint can adversely affect 

consumers is by causing persistent 

congestion that in turn, as discussed 

above, adversely affects consumers. 

However, the Department agrees with 

those commenters who argue that the 

Secretary’s authority is not limited to 

areas where congestion presently exists. 

If Congress had intended to limit the 

Secretary’s designation authority over 

constraints to cases where constraints 

are currently causing congestion, then 

there would have been no need for the 

statutory language to refer to ‘‘any 

geographic area experiencing electric 

energy transmission constraints or 

congestion that adversely affects 

consumers.’’ See 16 U.S.C. 824p(a)(2) 

(emphasis added). Further, the 

Department agrees with those 

commenters who argued that the total 

absence of a line connecting two nodes 

can be just as, if not more, limiting to 

consumers than the presence of a line 

that is operating at capacity and, 

therefore, constraints include the 

absence of transmission equipment 

between two or more nodes.14

Constraints limit access to power 

sources. Further, the existence of a 

constraint can hinder the development 

of new power sources, since project 

sponsors may not be able to obtain the 

financing they need if there is 

uncertainty over the degree to which 

their electricity could be delivered to 

consumers. Again, the Department is 

not attempting in this notice to define 

the complete scope of the term 

‘‘constraints that adversely affect 

consumers’’ as used in FPA section 

216(a)(2). However, the Department 

concludes that the term includes not 

only constraints that cause persistent 

congestion, but also constraints that 

hinder the development or delivery of a 

generation source that is in the public 

interest. Thus, the Department believes 

that FPA section 216(a) gives the 

Secretary the discretion to designate a 

National Corridor upon a showing of the 

existence of a constraint, including the 

total absence of a transmission line, that 

is hindering the development or 

delivery of one or more generation 

sources that is in the public interest, 

regardless of whether there is 

congestion and without the need for any 

additional demonstration of adverse 

effects on consumers.15 This 

interpretation of the term ‘‘constraints 

or congestion that adversely affects 

consumers,’’ which allows for a 

National Corridor designation when 

there is a constraint that adversely 

affects consumers even though there is 

no present congestion, is appropriate 

because it gives meaning to all of the 

terms used in the statutory provision. 

Additionally, this interpretation of the 

statute answers the concerns of those 

commenters who question whether the 

statute authorizes designation of 

National Corridors in the Conditional 

Areas of Concern based solely on 

projections of future congestion. The 

Congestion Study identified several 

Conditional Areas of Concern ‘‘where 

future congestion would result if large 

amounts of new generation were to be 

developed without simultaneous 

development of associated transmission 

capacity.’’ The Secretary is taking no 

action with respect to those areas at this 

time. Nevertheless, were the Secretary 

to designate a National Corridor for one 

of those areas, the Secretary would need 

only to demonstrate the existence of a 

constraint that was hindering the 

development or delivery of a generation 

source that is in the public interest, and 

would not need to rely on 

demonstrations of future, or even 

present, congestion.16

The Department’s interpretation of the 

scope of the Secretary’s authority is 

consistent with the objective and 

structure of the statute. FPA section 

216(a), as well as other provisions of 

EPAct,17 evince concern about the need 

to strengthen transmission 

infrastructure throughout the Nation. 

The Department concludes that a broad 

interpretation of the Secretary’s 

discretion to designate National 

Corridors is consistent with that 

concern, particularly given the effect of 

a National Corridor designation, as 

discussed in Section I.A above. Given 

the statutory limitations on the exercise 

of FERC’s permitting authority, there is 

no need to interpret narrowly the 

Secretary’s National Corridor 

designation authority. 

While the Department concludes that 

the Secretary has broad authority to 

designate National Corridors, FPA 


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18See also comments of EPSA, Northern Indiana 

Public Service Company, Old Dominion Electric 

Cooperative (ODEC), OMS, Piedmont 

Environmental Council (PEC), PSEG, The 

Wilderness Society (Wilderness), and many 

individuals. 

19NYISO is the ISO serving New York State. 

20See, e.g., comments of FirstEnergy, National 

Grid, and National Rural Electric Cooperative 

Association (NRECA). 

section 216(a) does not require the 

Secretary, under any circumstances, to 

make a National Corridor designation. 

Rather, in recognition of the 

Department’s expertise, the statute 

leaves to the Secretary’s judgment 

which geographic areas experiencing 

constraints or congestion adversely 

affecting consumers to designate as 

National Corridors. The Department 

recognizes that FPA section 216(a) 

adopted a novel approach to addressing 

the need for new transmission 

infrastructure, an approach that poses 

challenges to all stakeholders as we 

collectively work to address this 

problem. Therefore, the Secretary 

intends to proceed carefully in the 

exercise of his discretion to designate 

National Corridors. As evidenced by the 

specific draft designations set forth 

below, the Department is not starting 

the process of designating National 

Corridors at the outer limits of its 

authority. The Congestion Study 

identified two Critical Congestion 

Areas, and today’s notice issues two 

draft National Corridors to address 

them. These draft National Corridors are 

based on the existence of well-known, 

persistent congestion that adversely 

affects large numbers of consumers. 

Finally, the Department does not 

believe it is necessary to develop a 

specific and finite set of criteria to guide 

the exercise of the Secretary’s 

discretion. Instead, the most reasonable 

interpretation of FPA section 216 is that 

the Secretary may make National 

Corridor designations based on the 

totality of the information developed, 

taking into account relevant 

considerations, including the 

considerations identified in FPA section 

216(a)(4), as appropriate. 

B. Analysis of Potential Solutions 

Summary of Comments 

The Department received comments 

on whether a National Corridor 

designation should be based on an 

analysis of potential solutions to an 

identified congestion problem. Many 

commenters, including the National 

Association of Regulatory Utility 

Commissioners (NARUC), the New York 

Public Service Commission (NYPSC), 

and the New Jersey Board of Public 

Utilities (NJBPU), argued that the 

Department should conduct a cost/ 

benefit analysis of transmission 

solutions as well as non-transmission 

solutions to relieving congestion before 

designating a National Corridor; 

otherwise, they contend, the designation 

would unfairly skew the playing field in 

favor of transmission solutions.18 For 

example, the NJBPU and PSEG argued 

that without such an analysis, National 

Corridor designation may lead to 

preemptive siting of long-haul ratebased transmission projects intended to 

move power from remote generating 

sources to load centers, and thus distort 

or destroy market signals for local 

developers of generation, demand 

response resources, and improvements 

to local distribution systems. NYPSC 

and the New York Independent System 

Operator (NYISO)19 urged the 

Department to analyze the potential 

market impact of a National Corridor 

designation, because the very act of 

designating a National Corridor could 

cause downstream project developers to 

abandon already-planned facilities. 

Consolidated Edison Company of New 

York, Inc., and Orange and Rockland 

Utilities, Inc. (collectively ConEd) and 

NJBPU expressed concern about 

whether a National Corridor would 

disadvantage local generation to the 

detriment of reliability, noting that 

remote generation cannot provide the 

same level of voltage support and other 

ancillary services that local generation 

can. Numerous individuals who 

commented in opposition to specific 

transmission projects asserted that the 

Department has an obligation under 

FPA section 216 to consider alternatives 

to building new transmission lines. 

On the other hand, numerous 

commenters argued that the Department 

should not engage in analysis of 

possible solutions to congestion. These 

commenters noted that the Department’s 

role is to identify areas where 

congestion and constraints exist, 

whereas other entities, including State 

siting authorities, regional planning 

entities, market participants, and under 

some circumstances FERC will consider 

the relevant solutions. These 

commenters cautioned that any such 

analysis by the Department would 

unnecessarily delay the designation 

process.20

DOE Response 

The Department disagrees with those 

commenters who argue that a National 

Corridor designation is warranted only 

if the Department has demonstrated that 

transmission is the best, or at least a 

cost-effective, solution to an identified 

congestion problem. Nothing in FPA 

section 216 requires or envisions that 

the Department make such a 

demonstration. In fact, the preparation 

of a transmission cost-benefit analysis 

by the Department would be 

inconsistent with the very role that the 

statute assigns to the Department. As 

discussed in Section I.A above, the 

Department’s role under FPA section 

216 is to identify constraint or 

congestion problems and their 

geographic locations; the statute does 

not call for the Department to analyze 

and decide upon solutions. While FPA 

section 216(a)(2) does call for the 

Secretary to consider ‘‘alternatives and 

recommendations from interested 

parties’’ before making a National 

Corridor designation, the reference to 

‘‘alternatives and recommendations 

from interested parties’’ in this 

provision is ambiguous. In light of the 

statutory framework, the Department 

concludes that the term ‘‘alternatives 

and recommendations from interested 

parties’’ is intended to refer to 

comments suggesting National Corridor 

designations for different congestion or 

constraint problems, comments 

suggesting alternative boundaries for 

specific National Corridors, as well as 

comments suggesting that the 

Department refrain from designating a 

National Corridor. 

The Department acknowledges that 

transmission expansion is but one 

possible solution to a congestion or 

constraint problem; increased demand 

response, improved energy efficiency, 

and conservation, as well as siting of 

additional generation close to load 

centers are also potential solutions. 

However, given the effect of a National 

Corridor designation and the existing 

obligations of State and Federal siting 

authorities as discussed in Section I.A 

above, there is no need for the 

Department to undertake an analysis of 

transmission solutions and nontransmission solutions or to speculate 

about any theoretical indirect effects a 

National Corridor designation would 

have on the market. Indeed, the 

Department believes that expanding its 

role to include making findings on the 

optimal remedy for congestion could 

supplant or otherwise duplicate the 

traditional roles of States and other 

entities. 

C. Cost Allocation 

Summary of Comments 

The Congestion Study solicited 

comment on how the costs of proposed 

transmission should be allocated. A few 

commenters argued that the Department 


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21See comments of PSEG, ODEC, and J. Hayden. 22See, e.g., comments of Allegheny Power, 

American Electric Power (AEP), Arizona Public 

Service Company (APS), ConEd, Duke Energy 

Corporation (Duke), EEI, FirstEnergy, LS Power, 

National Commission on Energy Policy (NCEP), 

National Grid, and OMS. 

should consider cost allocation when 

deciding whether to make a National 

Corridor designation, and offered 

recommendations on specific cost 

allocation structures.21 For example, 

Montana-Dakota Utilities Co. argued 

that the Department should only 

designate National Corridors where the 

resulting transmission facilities would 

be paid for on a beneficiary-pays, rather 

than a postage-stamp, basis. NRECA 

supported rolled-in rate treatment for 

projects that serve native load network 

customers. However, the majority of 

those who provided comment on cost 

allocation issues urged against the 

Department considering those issues in 

the FPA section 216(a) process.22 These 

commenters noted that FERC, rather 

than the Department, has jurisdiction 

over cost allocation for transmission 

projects, and argued that cost allocation 

was not relevant to National Corridor 

designation. 

DOE Response 

The Department agrees with those 

commenters who argue that the analysis 

of whether to designate a National 

Corridor should not include 

consideration of how the costs for new 

transmission facilities will be allocated. 

While cost allocation issues can be 

critically important to determining 

whether, when, and where specific 

transmission projects are developed, 

those issues are not relevant to the 

Secretary’s role under FPA section 

216(a) of identifying geographic areas 

where congestion or constraints are 

adversely affecting consumers. 

D. Regional Planning and Local Siting 

Summary of Comments 

The Department received comments 

on the relevance of regional planning 

processes to National Corridor 

designation. FirstEnergy argued that in 

general, in RTO regions, National 

Corridors should be designated when a 

transmission facility would relieve 

congestion in an identified congestion 

area and the facility has been recognized 

as needed for reliability in an RTO’s 

transmission planning and expansion 

process. The Midwest ISO argued that 

the Department should wait to designate 

a National Corridor until a suitable 

planning solution is proposed within an 

identified congestion area. NARUC 

argued that the Department should grant 

deference to the results of adequate 

regional planning processes. Other 

commenters, for example NYPSC, also 

recommended that the Department 

should coordinate its designations with 

regional planning processes. 

On the other hand, some commenters 

expressed concern about the 

Department relying too much on RTO 

input regarding designation of National 

Corridors. For example, ODEC argued 

that while RTOs provide a forum within 

which public and well-vetted 

transmission planning could occur, at 

this time they lack procedures needed to 

ensure that such planning would 

actually occur. ABB expressed concern 

about the fragmented nature of the 

studies performed by RTOs. 

OMS argued that any designation 

must be based on the existence of siting 

barriers. For example, OMS asserted 

that if needed transmission is not being 

constructed due to cost recovery or 

other non-siting uncertainties, then a 

designation is inappropriate. According 

to OMS, designation is only appropriate 

when a National Corridor is truly 

necessary to solve a congestion problem 

of national significance, when the 

congestion problem is persistent, and 

when the prior failure to develop a 

solution is the result of siting problems. 

The Public Utilities Commission of the 

State of California (CPUC) argued that 

designation is unwarranted unless there 

is evidence that State and regional 

processes are not addressing the 

problem in a timely manner. CPUC 

argued that it is, first of all, up to the 

States and the regions to solve their 

transmission planning and siting 

problems, and Federal agencies should 

not intervene unless and until there is 

a demonstrated need for them to do so. 

CPUC further asserted that designation 

of a National Corridor in connection 

with any large multi-state project is 

likely to delay project siting, because of 

litigation and conflict it would produce. 

CEC commented that Federal back-stop 

siting would be beneficial where the 

State has been unable to make progress 

in approving vital transmission projects. 

PAPUC argued that the Department 

should not make any designation that 

does not clearly identify the national 

interests requiring protection and 

without making findings of fact that 

those interests are better served by a 

National Corridor designation than by 

another approach that would be less 

intrusive of State laws and policies. 

NYISO urged the Department to 

designate National Corridors with care 

so as not to usurp arbitrarily State siting 

authority. On the other hand, the 

Midwest ISO argued that the 

Department should not wait until local 

siting has become problematic, given 

the effect of a National Corridor 

designation. 

DOE Response 

The Department disagrees with those 

commenters who suggest that the 

Department defer making a National 

Corridor designation either until siting 

problems have already manifested 

themselves or until a regional planning 

process proposes a solution to the 

congestion or constraint problem. 

Nothing in FPA section 216 requires or 

envisions that the Department adopt a 

wait-and-see approach to National 

Corridor designation. FPA section 216 

empowers the Department to make 

designations when it finds constraints 

or congestion adversely affecting 

consumers, a finding that is not 

dependent on actions that others (e.g., 

transmission owners, regional planners, 

or States) may take to remedy those 

constraints or congestion. The 

Department fully supports such entities 

taking aggressive action to remedy 

congestion and nothing in a National 

Corridor designation conflicts with their 

ability to do so. Moreover, acting in 

parallel with the efforts of other entities 

is consistent with Congressional intent 

in enacting EPAct, which emphasizes 

the immediate need for new investment 

in transmission. Delaying action by the 

Department until action by all others is 

exhausted would not be consistent with 

this intent, nor with the Nation’s 

pressing need for new transmission. 

Moreover, the statute provides a 

specific mechanism by which States can 

insulate themselves from the FERC 

permitting provisions of FPA section 

216(b). FPA section 216(i)(1) provides 

that three or more contiguous States 

may enter into interstate compacts 

establishing regional transmission siting 

agencies. 16 U.S.C. 824p(i)(1). Such 

regional transmission siting agencies 

would then have authority to site 

transmission facilities in National 

Corridors. FPA section 216(i)(3); 16 

U.S.C. 824p(i)(3). Further, FERC would 

have no authority to issue a 

transmission permit within a State that 

is party to such a compact unless the 

members of the compact were in 

disagreement and the Secretary, after 

notice and opportunity for hearing, 

made a finding that the conditions of 

FPA section 216(b)(1)(C) were met. FPA 

section 216(i)(4); 16 U.S.C. 824p(i)(4). In 

light of this mechanism, as well as the 

other statutory limitations on FERC’s 

permitting authority discussed in 

Section I.A above, the Department 

concludes it would be inappropriate for 

it to limit itself to designating National 

Corridors where States have either 


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23See, e.g., comments of APS, Wyoming 

Infrastructure Authority, and Great Northern 

Properties, L.P. and Great Northern Power 

Development, L.P. 24See, e.g., comments of PAPUC, OMS, and 

National Grid. 

25See, e.g., comments of CEC, National Parks 

Conservation Association, National Park Service, 

Wilderness, Upper Delaware Council, and 

numerous individuals. 

26See 2006 Cal. Adv. Legis. Serv. 638 (Deering) 

(to be codified at Cal. Pub. Res. Code §§ 25330–

341). 

27See, e.g., comments of PG&E, ConEd, LS Power, 

National Grid, and Western Business Roundtable. 

failed to act or have already developed 

a preferred solution. 

The Department supports and 

encourages regional planning efforts. A 

National Corridor designation neither 

dictates nor bars any solution that might 

be considered in a regional planning 

process. The Department intends to 

draw the boundaries of any National 

Corridor so as to encompass a range of 

potential transmission solutions. In the 

event that a regional planning process 

concludes that a modification to an 

existing National Corridor designation is 

needed, the Department will consider 

such a request. 

III. Defining National Corridor 

Boundaries 

Summary of Comments 

In the Congestion Study, the 

Department solicited comment on how, 

where, and on what basis to establish 

the boundaries of a National Corridor. 

One approach identified in the 

Congestion Study would use specific 

transmission projects to define National 

Corridor boundaries. Under this 

approach, a proponent of a National 

Corridor would identify a specific 

project that could serve as a solution to 

the underlying congestion or constraint 

problem, an approximate centerline for 

the project would be identified, and the 

National Corridor boundary would be 

banded around that centerline. A 

number of commenters, including EEI, 

AEP, and Allegheny Power (Allegheny), 

supported this approach. 

Some commenters supported a 

project-based approach provided that 

there was some sort of independent 

review of the project. For example, 

ODEC argued that an open stakeholder 

process should first identify and vet 

conceptual projects and then make 

National Corridor boundary 

recommendations to the Department for 

those projects. Southern California 

Edison Company (SCE) argued that 

National Corridor boundaries should be 

tailored to aid in the construction of 

specific viable transmission projects 

approved through a regional planning 

process. CREPC stated that the 

delineation of National Corridor 

boundaries should be informed by a 

detailed analysis of congestion 

mitigation options. 

Several commenters raised the 

possibility of an incremental process for 

setting National Corridor boundaries, 

under which the Secretary would first 

make a designation of a broad area, and 

then as specific transmission proposals 

are developed and presented for review 

by appropriate authorities, the Secretary 

would narrow the boundaries.23

Commenters who supported a projectbased approach emphasized that 

National Corridor boundaries drawn in 

such manner should not dictate a 

particular line route, but rather should 

be drawn broadly enough to allow for 

consideration of alternative alignments 

during the siting process. 

On the other hand, some commenters 

opposed the project-centerline approach 

to developing National Corridor 

boundaries. For example, PAPUC 

argued that such an approach would 

involve the Secretary in siting decisions 

of the sort that Congress did not intend 

and for which the Department lacks 

expertise. OMS opposed National 

Corridor designation for particular 

projects. A number of commenters 

supported use of a non-project-based 

approach either instead of or in addition 

to a project-based approach. FirstEnergy 

suggested that in the absence of a 

specific project, a National Corridor 

could be drawn by means of a radius 

around the congested area. However, 

most commenters who supported a nonproject-based approach recommended 

that the Department use a source-andsink approach to setting National 

Corridor boundaries, in which the 

Department would identify a sink (the 

congested or constrained load area) and 

a source (an area of potential supply), 

and then draw a National Corridor 

connecting these two areas.24 AEP’s 

version of a source-and-sink approach 

looks at three factors: the area of 

potential generation resources, the 

critically congested load area, and the 

transmission deficiencies between the 

two areas. 

Several commenters supported the 

specification of precise boundaries for 

National Corridors. For example, 

Allegheny argued that specific 

boundaries are needed so that the 

project sponsor would know whether its 

project is encompassed within a 

National Corridor, FERC could readily 

determine the geographic scope of its 

potential jurisdiction, and land owners 

would know whether their property 

may be subject to the Federal exercise 

of eminent domain. However, OMS 

argued that instead of setting specific 

perimeter boundaries, the Department 

should identify source and sink areas, 

define the goal of the National Corridor, 

and then limit the National Corridor 

designation to those projects that further 

that goal. OMS expressed concern that 

delineation of specific boundaries could 

have the effect of establishing Federal 

transmission line corridors within 

States, and notes that just because a 

proposed project is located within a 

National Corridor it should not be 

assumed to address the concerns that 

lead to the designation of the National 

Corridor. 

With regard to drawing the specific 

perimeters of a National Corridor, 

Allegheny argued for using existing or 

proposed originating, intermediate, and 

terminating substations for proposed 

lines identified by planning studies. 

Numerous commenters argued that the 

Secretary should draw National 

Corridor boundaries to exclude parks 

and other environmentally protected 

areas.25 Some commenters, including 

CEC, Imperial Irrigation District (IID) 

and the Appalachian Trail Conservancy, 

recommended that the Department take 

into consideration existing rights of way 

when drawing boundaries. CEC argued 

that DOE should ensure that any 

National Corridors in California are 

delineated in a manner consistent with 

recent legislation concerning State 

designation of electric transmission 

corridors.26 NCEP noted that congestion 

occurs within an electrical system of 

flowgates rather than within a specific 

geographic framework, and expresses 

concern that arbitrary geographic 

boundaries may foreclose the most costeffective option for remedying 

congestion. Thus, NCEP argued that 

Balancing Authorities, which have the 

job of managing congestion, should be 

used to define National Corridor 

boundaries. 

Several commenters emphasized the 

need to make the area covered by a 

National Corridor broad, to ensure 

adequate flexibility of transmission 

planners and siting authorities to 

consider alternatives.27 The 

Appalachian Trail Conservancy argued 

that National Corridors should be 75 to 

100 miles wide in order to allow 

flexibility to align projects to avoid 

environmentally sensitive areas. 

Northwestern Energy argued for broad 

National Corridors so that one group of 

developers is not put at an unfair 

advantage. ABB argued that the 

boundaries of a National Corridor 

should include adjacent contiguous 

areas physically affected by large 


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28See Section II.A above. 

transmission upgrades since it is likely 

that additional reinforcements will be 

needed in those outlying areas. EEI 

argued in favor of a two-track process 

for drawing boundaries. Under EEI’s 

process, where there is a specific 

transmission project that could address 

the congestion or constraint problem, 

the boundaries would be as narrow as 

several miles wide; where no specific 

projects have been proposed, the 

boundaries would be wider, up to 200 

miles, to allow for a range of possible 

solutions. 

On the other hand, some commenters 

acknowledged the need for flexibility to 

consider alternatives but cautioned 

against drawing the National Corridor 

boundaries too broadly. For example, 

the City of New York stated that an 

overbroad interpretation of ‘‘corridor’’ is 

both inconsistent with the plain 

meaning of the word and may be too 

amorphous to provide adequate 

guidance for beneficial transmission 

planning. The PAPUC argued that 

National Corridors should be set so as 

to minimize the intrusion into State 

siting jurisdiction and to guarantee that 

any transmission projects claiming the 

benefits of the National Corridor 

designation will actually address the 

problem Congress intended to address. 

PAPUC further argued that the 

Department should require a project 

claiming the benefits of the National 

Corridor designation to show that its 

project would substantially alleviate the 

specific directional congestion on which 

the National Corridor was based and 

that the project would not conflict with 

any other transmission solutions being 

planned in the applicable regional 

planning process. Long Island Power 

Authority (LIPA) argued that an 

overbroad National Corridor would 

dilute the effectiveness of FPA section 

216 and would discourage nontransmission solutions. 

DOE Response 

The statute provides little direction 

on how the Department should draw the 

boundaries of a National Corridor. FPA 

section 216(a) uses the term ‘‘geographic 

area’’ and lists several considerations 

the Secretary may take into account 

when making a National Corridor 

designation. However, the statute does 

not define the term ‘‘corridor.’’ While 

this term is commonly understood to 

refer generally to some sort of path 

between different areas, the specific 

meaning of the term in this context is 

ambiguous. After careful consideration 

of the overall purpose and effect of this 

statutory provision, as well as the 

comments received, the Department has 

concluded that, while there may be 

circumstances where a project-based 

approach would be appropriate, in 

general the Department will use a 

source-and-sink approach to defining 

National Corridor boundaries. 

As discussed in Section I.A above, the 

National Corridor designation process is 

intended as a process to identify 

congestion and constraint problems, and 

the geographic areas in which these 

problems exist, rather than as a process 

to identify solutions to those problems. 

Just as the determination of whether to 

designate a National Corridor need not 

await or rely on the existence or 

analysis of specific transmission 

proposals, neither does the 

determination of the boundaries of that 

National Corridor. Setting National 

Corridor boundaries through a sourceand-sink approach is consistent with the 

problem-identification purpose of 

National Corridor designations under 

FPA section 216(a), because it is not 

focused on any particular transmission 

projects, or set of transmission projects. 

The Department recognizes that when 

it designates a National Corridor, there 

may be specific projects that have 

already been proposed within the 

boundaries of that National Corridor. 

Such is the case with the draft National 

Corridors designations in this notice. 

This result is not surprising, because 

these draft National Corridors 

encompass well-known constraints that 

have adverse effects on millions of 

consumers. However, the Department 

emphasizes that it is neither endorsing 

nor recommending any specific projects 

when it designates a National Corridor 

based on a source-and-sink analysis. 

There was broad consensus among the 

commenters that if a project-based 

approach were not used to set National 

Corridor boundaries, then a source-andsink approach should be used. Such an 

approach is consistent with the common 

usage of ‘‘corridor’’ as an area linking 

two other areas. Such an approach also 

is consistent with the physical 

properties of the electrical grid, because 

a transmission line into a congested or 

constrained load area will not benefit 

that load unless the line connects with 

a source of power that could help to 

serve the load. 

While the comments support the use 

of a source-and-sink approach to setting 

National Corridor boundaries, they 

provide little clarification about how 

such an approach should actually be 

implemented. The details of how the 

Department will draw the boundaries of 

a National Corridor will depend on the 

specific circumstances. However, in 

general terms, the geographic extent of 

the sink area in a National Corridor is 

determined by the geographic 

distribution of the consumers adversely 

affected by the congestion or 

constraints—in other words, the 

location of load downstream of the 

limiting transmission constraints. 

With regard to the source area, where 

the decision to designate a National 

Corridor is based on the existence of a 

constraint that is hindering the 

development or delivery of a particular 

generation source that is in the public 

interest,28 the identification of the 

appropriate source area would be 

relatively straightforward: the source 

area would be the geographic area 

within which that particular source of 

supply is, or is likely to be, located. In 

contrast, where the decision to 

designate a National Corridor is based 

on the existence of persistent 

congestion, the identification of an 

appropriate source area may require the 

consideration of a range of potential 

source areas. The selection of a source 

area or source areas in those situations 

will necessarily involve discretion and 

is not suited to a formulaic approach. 

Given the long lead time involved in 

planning, obtaining regulatory 

approvals for, and constructing 

transmission projects, areas without a 

current surplus of generation could well 

develop additional power sources by the 

time a transmission project is 

completed. Therefore, depending on the 

circumstances, the Department may 

consider as potential source areas not 

only those areas with existing surplus 

generation, but also areas with projected 

surplus generation, or areas with 

available fuel supply for additional 

generation. 

Once the Department has identified 

the range of potential source areas, it 

must then decide which of those 

potential source areas it will use to set 

the boundaries of a National Corridor. 

The Department observes that the 

considerations identified in FPA section 

216(a)(4) provide guidance on some of 

the possible bases for making this 

decision. FPA section 216(a)(4)(A)–(E) 

authorizes the Secretary when making a 

National Corridor designation to 

consider lack of adequate or reasonably 

priced electricity, diversification of 

supply, energy independence, national 

energy policy, and national defense and 

homeland security. Each of these 

considerations potentially has relevance 

to the selection of source areas. For 

example, certain potential source areas 

may provide greater diversity of supply 

than others, or may be more consistent 

with national energy policy. Therefore, 

when there are multiple potential 

source areas, the Secretary will use his 


rwilkins on PROD1PC63 with NOTICES2
Federal Register / Vol. 72, No. 87 / Monday, May 7, 2007 / Notices 25849 

29 Drawing National Corridor boundaries broadly 

may also help encompass transmission upgrades 

needed to address ‘‘loop flow.’’ Loop flow is a 

phenomenon of alternating current transmission 

networks in which electricity flows seek their own 

paths, sometimes in patterns unanticipated by 

system operators. Thus, a transmission 

improvement designed to correct a congestion 

problem on one part of the transmission system 

may in some cases cause loop flows elsewhere that 

must also be addressed. 

30The Department acknowledges that this 

approach to establishing boundaries for National 

Corridors under FPA section 216(a) differs from the 

approach being used for energy right-of-way 

corridors on Federal land under EPAct section 368. 

However, given the distinct purposes of FPA 

section 216 and EPAct section 368, the Department 

believes that applying different approaches to the 

two different types of corridors is appropriate. See 

Env’t Def. v. Duke Energy Corp., No. 05–848, slip 

op. at 10 (U.S. April 2, 2007) (‘‘A given term in the 

same statute may take on distinct characters from 

association with distinct statutory objects calling for 

different implementation strategies.’’) 

31See FERC Order No. 689, 71 FR 69,440, 69,446, 

117 FERC ¶ 61,202 at P 41 (‘‘The Commission will 

review the proposed project and determine if it 

reduces the transmission congestion identified in 

DOE’s study and if it will protect or benefit 

consumers.’’); and 71 FR 69,440, 69,468, 117 FERC 

¶ 61,202 at pp. 128–29 (§ 50.6(f) requires applicants 

to demonstrate that the conditions of FPA sec. 

216(b)(2)–(6) are met). 

32See comments of Upper Delaware Preservation 

Coalition, Delaware Riverkeeper Network, 

SayNo2NYRI, Upstate NY Citizens Alliance, and 

Stop NYRI, Inc. (collectively Delaware River 

Commenters), Communities Against Regional 

Interconnection (CARI) and Toll Brothers, Inc. (Toll 

Brothers). 

expert judgment to determine which of 

the potential source areas to include, 

taking into account relevant 

considerations, including the 

considerations identified in FPA section 

216(a)(4), as appropriate. 

After the Department has identified 

the sink and source areas, it must then 

delineate the specific boundaries of a 

National Corridor linking those areas. 

The Department agrees with the 

majority of commenters that National 

Corridor designations should specify 

precise geographic boundaries. Such an 

approach is not only consistent with the 

plain meaning of the statutory term 

‘‘geographic area,’’ it also provides 

greater clarity and ease of 

administration to those entities 

concerned with whether a particular 

project or land area would be 

encompassed within a National 

Corridor. 

The Department acknowledges that 

determining the exact perimeters for a 

National Corridor under a source-andsink approach is more an art than a 

science, and there will rarely be a 

dispositive reason to draw a boundary 

in one place as opposed to some number 

of miles to the left or right. The drawing 

of the boundary is ultimately a 

judgment the Secretary must make, 

based on all relevant considerations, 

including the considerations identified 

in FPA section 216(a)(4), as appropriate, 

and available, relevant data. There is no 

single boundary line that can be 

determined based solely upon analysis 

of the data. The Department notes that 

the drawing of the boundary lines of a 

National Corridor does not finally 

determine or fix the substantive rights of 

anyone. A National Corridor designation 

simply provides developers proposing 

certain projects within its boundaries an 

additional procedural option in the form 

of a potential Federal siting venue that 

is not available to transmission projects 

outside a National Corridor. 

Therefore, the Department agrees with 

those commenters who emphasize the 

need for the Department to draw 

National Corridor boundaries so that 

they could encompass a range of 

potential projects and a range of 

potential routes.29 So long as a range of 

alternatives is encompassed, further 

refinement is unnecessary. Given this 

approach, the Department concludes 

that it is not necessary to adjust the 

boundaries of a National Corridor to 

avoid parks or other environmentally 

protected areas or to align the 

boundaries with existing rights of 

way.30 Further, the Department need not 

attempt to interpret State laws on siting 

preferences. The determination of the 

best route for a specific project will be 

made by siting authorities, who are 

better positioned to make such a 

determination. As discussed in Section 

I.A above, if a project in a National 

Corridor were to satisfy the statutory 

requirements for seeking a permit from 

FERC, FERC would analyze alternative 

routes for that project, including route 

realignments necessary to avoid adverse 

effects on the environment, landowners, 

and local communities. Nothing in FPA 

section 216 alters the applicability of 

Federal environmental and cultural 

statutes and regulations. 

The Department recognizes that some 

States are concerned that specification 

of broad boundaries could result in 

unintended expansion of Federal siting 

authority to include proposed 

transmission projects that happen to be 

located within a National Corridor but 

are unrelated to the problem that 

prompted the National Corridor 

designation. Sometimes the approach 

described above could produce very 

large corridors; sometimes it could 

produce smaller corridors. The breadth 

of a corridor would be driven by the 

geographic expanse of the adversely 

affected load, the number and 

geographic dimensions of source areas, 

and the distance between the source and 

sink areas. FPA section 216(b) itself 

specifies the scope of FERC jurisdiction 

over projects proposed to be built in 

National Corridors, including a 

requirement that the project will 

‘‘significantly reduce transmission 

congestion and protects or benefits 

consumers.’’ 31 The Department believes 

that these statutory limitations 

adequately address the States’ concerns 

and do not require further clarification 

by the Department. 

Finally, in the event that an affected 

party concludes at some later stage that 

a modification to the boundaries of an 

existing National Corridor is needed, the 

Department will consider such a 

request. 

IV. Involvement of Interested Parties 

A. Public Notice 

Summary of Comments 

Some commenters argued that it 

would be premature to designate any 

National Corridors without a full 

disclosure of the data and analysis 

underlying the conclusions in the 

Congestion Study. NYPSC, the Maine 

Public Utilities Commission (Maine 

PUC), and NARUC argued that the 

Department must perform a more 

granular analysis of congestion before 

designating a National Corridor; 

according to these commenters, the 

Congestion Study alone does not 

provide an adequate record of how the 

conclusions about congestion were 

reached. PAPUC stated that while the 

Congestion Study is a good initial 

assessment of congestion at the national 

level, designation of specific National 

Corridors cannot be based on the 

preliminary analysis contained in the 

Congestion Study; according to PAPUC, 

more specific and focused regional 

studies must be conducted prior to any 

designation. A number of commenters 

argued that the Congestion Study fails to 

provide adequate notice of a National 

Corridor designation under the 

Administrative Procedure Act, 5 U.S.C. 

551.32

DOE Response 

The Department notes that as of 

September 27, 2006, it made available 

on its Web site non-proprietary data 

relied on in the Congestion Study. 

Moreover, as discussed further below, 

the Department in this notice is 

identifying the specific data on which it 

is relying to establish the existence of 

congestion or constraints adversely 

affecting consumers, to explain the 

reasons the Secretary is considering 

exercising his discretion to designate a 

National Corridor, and to explain how 


rwilkins on PROD1PC63 with NOTICES2
25850 Federal Register / Vol. 72, No. 87 / Monday, May 7, 2007 / Notices 

33See comments of Maine PUC, New England 

Conference of Public Utility Commissioners 

(NECPUC), Connecticut Attorney General, New 

England Governors’ Conference, Inc., and Maine 

Congressional Delegation. 

34See, e.g., comments of the Governor of the 

Commonwealth of Virginia, Arizona Corporation 

Commission (Arizona Commission), and American 

Transmission Company LLC. 

35National Conference of State Legislatures, 

Seattle, WA, Aug. 18, 2005; Southern States Energy 

Board, Atlanta, GA, Aug. 27, 2005; Midwest State 

Energy Office, webcast, Aug. 31, 2005; National 

Association of State Energy Officials, New York, 

NY, Sept. 12, 2005, and Washington, DC, Feb. 7, 

2006; CREPC, San Diego, CA, Sept. 20, 2005, and 

Sept. 27, 2006, and Portland, OR, April 4, 2006; 

NARUC, Palm Springs, CA, Nov. 14, 2005, 

Washington, DC, Feb. 14 and 22, 2006, San 

Francisco, CA, Aug. 1, 2006, and conference calls, 

Jan. 11, 2006, and June 16, 2006; NYPSC, Albany, 

NY, Dec. 20, 2005; OMS, conference call, May 11, 

2006; Florida Public Service Commission, 

Tallahassee, FL, June 15, 2006; Midwestern 

Legislative Conference, Chicago, IL, Aug. 20, 2006; 

Organization of PJM States, Inc., Cambridge, MD, 

Sept. 17, 2006; CPUC, conference call, Sept. 20, 

2006; CEC, conference call, Sept. 22, 2006; and 

Maine PUC, conference call, Oct. 6, 2006. 36See e.g., comments of Delaware River 

Commenters. 

37See, e.g., comments of National Trust for 

Historic Preservation and numerous individuals. 

38See, e.g., comments of PEC and Virginia 

Chapter of the Sierra Club (Sierra Club); see also 

comments of U.S. Sen. Warner and U.S. Rep. Wolf. 

39See, e.g., comments of CARI. 

40See, e.g., comments of Wilderness. 

41See, e.g., comments of Civil War Preservation 

Trust, Foundation of the State Arboretum of 

Virginia, and National Parks Conservation 

Association. 

the specific boundaries of the draft 

National Corridors were delineated. 

Commenters will have a full 

opportunity to comment on those data. 

B. State Consultation 

Summary of Comments 

A number of commenters raised 

concerns about the level of consultation 

with States. Several commenters 

asserted that the Department failed to 

consult with the States in New England 

in the preparation of the Congestion 

Study.33 NARUC commented that the 

Department failed to consult with States 

in some regions. Other commenters 

argued that the Secretary should not 

designate any National Corridors 

without further consultation with 

affected States.34

DOE Response 

FPA section 216(a)(1) requires that the 

Department conduct its congestion 

studies ‘‘in consultation with affected 

States.’’ FPA section 216(a)(2) then 

states that ‘‘[a]fter considering 

alternatives and recommendations from 

interested parties (including an 

opportunity for comment from affected 

States), the Secretary shall issue a 

report, based on the study, which may 

designate * * * [National Corridors].’’

The Department is committed to 

fulfilling its obligation to consult with 

States in this process. At the same time, 

the Department notes that there are 

practical difficulties in conducting the 

level of consultation that some may 

prefer in the context of a study of this 

magnitude, which examines congestion 

over 150,000 miles of transmission lines 

throughout 47 States and the District of 

Columbia, within statutorily mandated 

deadlines. Moreover, the statute refers 

to conducting the congestion study in 

consultation with ‘‘affected States.’’ It is 

difficult to know which States are 

‘‘affected’’ until the conclusions of the 

congestion study are known. 

The Department has provided States 

with numerous opportunities for input 

and has held meetings with officials 

representing individual States and 

groups of States. The Department 

initiated a series of conference calls in 

December 2005 and January 2006 with 

States to describe the Department’s 

study plan and request information and 

suggestions. On February 2, 2006, the 

Department published a Notice of 

Inquiry explaining the Department’s 

intended approach for the Congestion 

Study and inviting comment. On March 

29, 2006, the Department held a public 

technical conference in Chicago, Illinois 

to address the questions presented in 

the Notice of Inquiry. The Congestion 

Study itself was made available for 

comment on August 8, 2006. In 

addition, the Department held 

numerous meetings with State officials 

to discuss the Congestion Study and 

made presentations at several State 

conferences and events.35

As indicated by its outreach efforts in 

connection with the Congestion Study, 

the Department recognizes the 

importance of State consultation. The 

Department further recognizes that the 

most significant stage of the entire 

process under FPA section 216(a) is the 

National Corridor designation stage. 

Therefore, in addition to making the 

draft National Corridor designations 

described in this notice available for 

comment, the Secretary is 

simultaneously contacting the 

Governors of each State in which the 

draft National Corridors would be 

located to arrange consultation 

meetings. 

V. Environmental and Cultural 

Analyses 

Summary of Comments 

The Department received several 

comments proposing that the 

Department prepare a Programmatic 

Environmental Impact Statement (PEIS), 

pursuant to the National Environmental 

Policy Act of 1969 (42 U.S.C. 4321–

4347) (NEPA), before designating any 

National Corridors. Specifically, some 

commenters state that designating a 

National Corridor is equivalent to 

establishing a plan for routing 

transmission lines and, therefore, must 

be evaluated in a PEIS.36 Other 

commenters argue that a National 

Corridor designation is not just a plan 

for routing of transmission lines, but 

rather would amount to a de facto 

permitting of a specific, identifiable 

transmission line for which a PEIS or an 

Environmental Impact Statement must 

be prepared.37

Several commenters also asserted that 

the designation of a National Corridor 

selects a transmission-based solution to 

congestion rather than alternative 

energy solutions such as siting local 

generation or increased demand 

response. These commenters argue that 

DOE should conduct a PEIS that 

considers alternatives to transmissionbased solutions to congestion prior to 

designating a National Corridor.38

Other commenters note that the 

Council on Environmental Quality’s 

regulations implementing the 

procedural provisions of NEPA (40 CFR 

1500–1508) require that NEPA be 

applied at the earliest possible time in 

the planning process and contend that, 

therefore, DOE should prepare a PEIS 

prior to any designation of a National 

Corridor.39 Still other commenters state 

that DOE should prepare a PEIS before 

designating a National Corridor because 

a PEIS would allow DOE to examine not 

just environmental impacts from 

individual projects but also cumulative 

environmental and non-environmental 

impacts, including socioeconomic 

impacts.40

The Department also received 

comments that it should conduct other 

environmental and cultural analyses, 

such as a review under the National 

Historic Preservation Act (16 U.S.C. 

470) (NHPA), before designating 

National Corridors.41 For example, the 

Advisory Council on Historic 

Preservation states that the Department 

should conduct a ‘‘tiered’’ approach 

under the NHPA, and that the 

Department should designate National 

Corridors that are broad enough to 

ensure that feasible alternatives to 

mitigate potential adverse effects to 

historic properties may be developed 

and evaluated at a later stage. 

DOE Response 

Section 102(2)(C) of NEPA requires 

that all Federal agencies include an 

environmental impact statement in 


rwilkins on PROD1PC63 with NOTICES2
Federal Register / Vol. 72, No. 87 / Monday, May 7, 2007 / Notices 25851 

42See FERC Order No. 689 discussed in n.4. 

43PJM is the RTO serving parts or all of Delaware, 

Illinois, Indiana, Kentucky, Maryland, Michigan, 

New Jersey, North Carolina, Ohio, Pennsylvania, 

Tennessee, Virginia, West Virginia, and the District 

of Columbia. 

‘‘every recommendation or report on 

proposals for legislation and other major 

Federal actions significantly affecting 

the quality of the human environment.’’

42 U.S.C. 4332(2)(C). The designation of 

a National Corridor under FPA section 

216(a)(2) does not significantly affect 

the quality of the human environment. 

To the contrary, as described in Section 

I.A above, a National Corridor 

designation is not a determination that 

transmission must, or even should, be 

built; it is not a proposal to build a 

transmission facility and it does not 

direct anyone to make a proposal. Nor 

does the Department’s designation of a 

National Corridor result in or plan for 

any ground-breaking environmental 

impacts. Nor does National Corridor 

designation irrevocably commit any 

resources to any activity having 

foreseeable environmental impacts. 

Designation of a National Corridor does 

not control FERC’s substantive decision 

on the merits as to whether to grant or 

deny a permit application, specifically 

where any facilities covered by a permit 

should be located, or what conditions 

should be placed on a permit. Further, 

as discussed in Section III above, the 

Department has decided not to establish 

the boundaries of today’s draft National 

Corridors using a project-centerline 

approach that would give an advantage 

to a particular transmission line. As 

discussed in Section I.A above, the 

Department’s approach to National 

Corridor designation does not foreclose 

future options for addressing 

congestion, including non-transmission 

options. For these reasons, National 

Corridor designation is not a ‘‘proposal 

for a major Federal action significantly 

affecting the quality of the human 

environment’’ that falls within the 

purview of NEPA. 

While NEPA review is not required at 

this time, all proposals for Federal siting 

permits will be subject to, as 

appropriate, project-specific NEPA 

review. In addition to NEPA, proposals 

for such permits will also be subject to 

other environmental and cultural 

reviews, including, but not limited to, 

review under the NHPA.42 Nothing in 

FPA section 216 alters the applicability 

of Federal environmental and cultural 

statutes and regulations. 

VI. Duration of National Corridor 

Designations 

Summary of Comments 

The Congestion Study solicited 

comment on whether National Corridor 

designations should be permanent or 

whether the Department should set an 

expiration date. Most commenters did 

not address this question. Most of those 

who did said that DOE should not set 

a standard duration period for National 

Corridor designations. SCE, for example, 

said that relevant conditions would vary 

too much from case to case, and that 

DOE should establish a period suitable 

to a given National Corridor and then 

work with affected parties to determine 

when or if the designation should be 

terminated. APS emphasized that the 

development of transmission facilities is 

often a protracted process; that the 

initial designation should be for a 

considerable period; and that thereafter 

DOE should ensure that a designation 

does not expire in a manner that would 

disadvantage existing efforts to relieve 

congestion problems. EEI said that 

designations should not have any fixed 

duration; rather, they should simply 

remain in force until rescinded by DOE. 

EEI argued that DOE should stipulate in 

its designations that it reserves the right 

to rescind a designation if it finds that 

the designation is no longer needed, and 

that it would revisit the need for 

existing designations in its periodic 

studies and reports. EEI also 

emphasized the need for DOE to ensure 

that it did not rescind a designation 

prematurely. 

Wilderness noted that DOE is to 

update its congestion study every three 

years, and suggested that DOE should 

reassess the need for existing National 

Corridors as part of each three-year 

study. Similarly, the York County 

Planning Commission said that 

designations should be for three-year 

terms, subject to renewal or rescission 

based on the findings in the updated 

congestion analyses. 

PJM Interconnection, LLC, (PJM)43

recommended that DOE designate 

National Corridors for an initial 10-year 

term, and stipulate the Secretary’s right 

to rescind or modify the terms or 

boundaries of a National Corridor at any 

time after showing that such action was 

appropriate. 

DOE Response 

DOE appreciates the need to be 

responsive to the broad range of factors 

and considerations pertaining to the 

duration of National Corridor 

designations. It also recognizes that 

designations, once made, should be in 

place for a considerable period of years, 

with the possibility of either rescission 

or renewal for cause. Accordingly, DOE 

intends to adopt a default approach, 

under which an initial designation 

would be for a period of 12 years unless 

it finds reason in a particular case to set 

some other initial term. 

Notwithstanding this approach, the 

Department recognizes the disruptive 

effect that regulatory uncertainty can 

have on transmission investment. 

Therefore, the Department does not 

intend to terminate any National 

Corridor designations while an accepted 

permit application in that National 

Corridor is pending at FERC, or, once 

FERC has granted a permit, during the 

period in which the approved facilities 

are being constructed. The Department 

will stipulate in any National Corridor 

designation order that the designation 

may be modified, rescinded, or renewed 

for cause at any time, after a period of 

public notice and comment and 

consideration of the comments. 

VII. Technical Comments on the 

Congestion Study 

In this section, the Department 

summarizes and responds to technical 

comments it received on the Congestion 

Study that are relevant to today’s draft 

National Corridor designations. 

Specifically, the Department first 

summarizes and responds to those 

comments on the data and methodology 

used in the Congestion Study that have 

general relevance to any National 

Corridor designation. Then, the 

Department summarizes and responds 

to comments on the Congestion Study 

that have particular relevance to the 

draft National Corridor designations in 

this notice. As mentioned above, today’s 

notice does not address comments 

received on the Congestion Study that 

relate solely to areas outside the two 

Critical Congestion Areas or that relate 

to the conduct of future congestion 

studies. 

A. Comments of General Relevance 

Several commenters commended DOE 

for its efforts in completing the first 

national electric transmission 

congestion study and advancing the 

discussion on transmission congestion. 

NARUC stated, ‘‘The DOE’s successful 

development of a base case electric load 

flow model in a single year for the entire 

Eastern Interconnection is a significant 

achievement.’’ First Energy commented 

that ‘‘DOE seems to have relied on 

appropriate information to support its 

conclusions in the Congestion Study. 

DOE seems to have made reasonable 

assumptions about the electric 

infrastructure that will be in use and 

seems to have relied upon reasonable 

modeling methods with respect to 

identifying potential future transmission 

constraints.’’


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44See also comments of PSEG. 

The Midwest ISO remarked: 

The classification of congested areas into 

Critical Congestion Areas, Congestion Areas 

of Concern, or Conditional Congestion Areas 

is an appropriate means to distinguish 

between varying characteristics of these 

congested areas * * *. Overall, the method 

employed to identify congested areas is an 

appropriate combination of available 

historical data, transmission studies by 

planning organizations, and simulation of 

future congestion. 

EEI applauded the Department for the 

timely completion of the Congestion 

Study, stating, ‘‘In light of the strong 

emphasis on electric infrastructure 

made by the Congress in enacting 

EPAct, the congestion study identifies a 

broad range of critical geographic areas 

throughout the nation that face 

potentially serious challenges for 

ensuring reliable and cost-effective 

electricity delivery.’’

International Transmission Company 

stated that as a general matter, ‘‘the 

Congestion Study did a commendable 

job of identifying areas of the United 

States in which congestion represents 

an economic problem, i.e., where 

densely populated, economically 

significant regions of the country face 

limited access to economic sources of 

electricity as the result of transmission 

congestion.’’ However, the Department 

also received comments expressing 

concern about several general aspects of 

the Congestion Study, as discussed 

below. 

1. Data Sources 

Summary of Comments: ODEC stated 

that the Department should not rely 

solely on RTOs and ISOs for data, 

asserting that their processes are not 

totally open, collaborative and 

inclusive. Toll Brothers asserted that 

rather than conduct its own Congestion 

Study, the Department has relied too 

much on industry sources, such as PJM, 

Allegheny, and transmission owners 

who wheel power for low-cost providers 

into higher priced markets. 

DOE Response: The Department did 

not rely solely on data and information 

from any single source or category of 

sources. The Department contacted a 

wide range of stakeholders for publicly 

available and current data. Through the 

notice of inquiry and technical 

conference the Department opened the 

call for data to all entities. Furthermore, 

the Department performed its own 

review of the information provided. 

2. Congestion Metrics 

Summary of Comments: The 

Department received a number of 

comments on the use of congestion rents 

to measure congestion. ODEC supported 

the use of congestion rents as a 

congestion metric. However, several 

commenters complained that congestion 

rent can significantly overstate the 

economic effect of congestion because 

the figure does not account for hedging. 

NYISO argued that the proper metric to 

measure congestion is potential 

production cost savings not gross 

congestion rent, which ‘‘is merely an 

accounting protocol that does not 

recognize the offsets that exist under 

various hedging instruments and 

grandfathered contract arrangements.’’

Similarly, NYPSC argued that gross 

congestion rent is a misleading metric 

that significantly overstates the cost of 

congestion by failing to factor in the 

return of some congestion revenues to 

loads. NYPSC argued that the 

Department should measure congestion 

by analyzing the additional cost of local 

generation required to serve customers 

in a load pocket.44 Toll Brothers argued 

that under FPA section 216(a), the 

Department may only consider 

economic factors after the Department 

has demonstrated that congestion exists, 

and the demonstration of the existence 

of congestion must be based on an 

analysis of the transmission system’s 

physical capability of meeting the 

demand for electricity. According to 

Toll Brothers, if demand can be met, 

then there is no congestion, regardless 

of the relative price of the power needed 

to meet that demand. 

Other commenters argued that 

congestion rent has limited relevance 

outside of organized markets, and thus 

the Congestion Study significantly 

underestimated congestion and 

constraints in the areas of the country 

without such markets. Several 

commenters from the Southeast, for 

example the Public Works Commission 

of the City of Fayetteville, North 

Carolina, expressed concern that the 

Study had missed significant congestion 

problems and urged the Department to 

consider other types of information, 

such as lack of long-term firm 

transmission capacity. NRECA and NEC 

also argued for use of alternative 

metrics, including available transfer 

capacity. Western commenters, 

including NWPUD and SCL, noted that 

the need to look at alternative metrics, 

such as withdrawn or declined 

transmission requests, limits on 

scheduling rights, or real-time schedule 

curtailments, is particularly important 

in the Northwest, given that power there 

is obtained solely through bilateral 

markets. NWPUD and SCL assert that 

modeling congestion using production 

cost simulations may be misleading 

since most of the Western 

Interconnection uses contract path 

methods for acquiring, reserving, and 

scheduling transmission service. Duke 

noted that because areas without formal 

markets are generally served by 

vertically integrated utilities, the type of 

LMP-based congestion data typically 

provided by RTOs and ISOs are often 

not available. PSEG asserted that the 

Congestion Study is biased towards 

regions that use LMP because the Study 

is only capable of measuring congestion 

in LMP-type markets. PSEG concluded 

that this inherent bias is not properly 

recognized or addressed in the Study, as 

is evidenced by the fact that the 

Congestion Study contains no 

significant congestion findings for areas 

without organized markets. NCEP 

asserted that lack of data for the 

Southeast and parts of the West, where 

organized markets do not exist, presents 

a significant gap in the knowledge 

available to the Department to 

determine the need for National 

Corridors in those regions. NCEP further 

asserted that the fact that data from 

these areas are not available does not 

mean that congestion does not exist. 

DOE Response: The Department 

recognizes that the Congestion Study’s 

use of congestion rent as a metric has 

led to concern and confusion. The 

Department did not intend to suggest 

that congestion rents represent the 

actual monetary cost that consumers 

pay specifically as a result of 

congestion, or that congestion rents 

measure the benefits of relieving the 

congestion. The Department recognizes 

that outside of the organized markets 

that use LMP-based congestion 

management, transmission customers do 

not pay congestion rents per se. The 

Department further recognizes that 

within the organized markets that use 

LMP-based congestion management, 

financial transmission rights can 

provide load-serving entities with 

significant protection from the payment 

of congestion rents, although as the 

system becomes more constrained the 

availability of those rights may not be 

able to protect consumers from the full 

effects of congestion. Also, the 

Department recognizes that congestion 

rents are not the same as the cost of 

redispatch, a cost that some 

combination of transmission customers 

actually pay specifically as a result of 

congestion. 

Nevertheless, congestion rents are an 

indicator of the existence of congestion, 

since if there is no congestion, there are 

no rents, and whenever there is 

congestion, congestion rents can be 

calculated. The Congestion Study 

modeled congestion rents for areas with 


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organized markets in the same way it 

modeled congestion rents for areas 

without organized markets. For both 

types of areas, the models determined 

congestion rent for a particular 

constraint by calculating a shadow price 

for that constraint and multiplying the 

shadow price by the megawatt (MW) 

flow on the constraint. For each 

constraint, models compute hourly 

shadow prices as marginal costs of 

redispatch required to relieve 

congestion (if any) on that constraint in 

each hour, taking into account the 

differences in production costs among 

the appropriate generators. 

Nevertheless, in most organized 

markets, RTOs and ISOs calculate LMPs 

and make them publicly available; 

whereas in areas without organized 

markets, there is less transparency with 

regard to the actual marginal cost of 

redispatch. Thus, the Congestion 

Study’s modeling of congestion rents for 

areas with organized markets is easier to 

validate than for areas without 

organized markets. 

With regard to the recommendation 

that the Department use changes in bid 

production cost instead of congestion 

rent to measure congestion, the 

Department concludes that use of bid 

production cost in the context of FPA 

section 216(a) congestion studies is not 

required. Bid production cost analysis 

compares a base case against different 

scenarios in which action is taken to 

alleviate congestion or constraints. By 

contrast, the Department is specifically 

not seeking to assess the benefits of 

different fixes to a congestion or 

constraint problem. Rather, the 

Department is simply identifying 

congestion or constraint problems, and 

the geographic areas in which these 

problems exist. 

While the Department believes that 

congestion rent, when correctly 

understood, is a useful indicator of the 

persistence and pervasiveness of 

congestion within a transmission 

system, congestion rent was only one of 

the metrics used in the Congestion 

Study. Further, as discussed in Section 

II.A above, while FPA section 216(a) 

requires a National Corridor designation 

to be based on the existence of 

constraints or congestion that adversely 

affects consumers, once the Department 

has demonstrated the existence of 

persistent congestion, no additional 

demonstration, let alone monetization, 

of the adverse effects on consumers is 

required. Thus, in the draft National 

Corridor designations detailed below, 

the Department relies on historical 

binding hours and a range of other 

indicators to support its conclusion that 

the areas are experiencing persistent 

congestion and that National Corridor 

designation is appropriate. For the 

purposes of future congestion studies, 

the Department is considering whether 

other metrics, in addition to or instead 

of congestion rents, are appropriate, 

particularly in those areas without 

organized markets. 

3. Direct Current Versus Alternating 

Current Modeling 

Summary of comments: Some 

commenters, including NARUC, 

NYPSC, and PAPUC, asserted that the 

direct current (DC) model used by the 

Department for the Eastern 

Interconnection is oversimplified, does 

not adequately reflect the system, may 

understate congestion, cannot take into 

account voltage-related constraints, and 

therefore will not include any 

congestion caused by such constraints. 

According to these commenters, the 

impact of voltage-related constraints can 

be significant and should not be 

overlooked in the Congestion Study. 

These commenters argued that 

alternating current (AC) modeling 

(including thermal, voltage, and 

stability analyses under both normal 

and contingency conditions) should be 

used on a sub-regional basis to provide 

more detailed analysis of the areas 

identified as problematic through the 

DC modeling. 

DOE response: For the Eastern 

Interconnection, modeling was 

performed using GE–MAPS, a 

commercially available simulation tool. 

GE–MAPS uses a DC representation of 

the load flow, which does not model 

reactive power requirements directly. 

Use of indirect approaches to account 

for reactive power is not unusual in 

electric analysis. For example, many 

well-known operational constraints in 

PJM, such as the Eastern, Central, and 

Western interfaces are proxies for 

reactive power limitations downstream. 

PJM specifies the MW limit (real power) 

to ensure that the capacity of local units 

to provide sufficient reactive power is 

not exceeded. It is not possible to 

conduct a full-scale AC power flow 

modeling exercise (with forwardlooking unit commitment and hourly 

chronological dispatch) of the Eastern 

Interconnection using today’s 

computational resources. While subregional analyses using AC modeling 

may be feasible, the Department does 

not believe that such analyses are 

necessary, given the purpose of the 

Congestion Study and the effect of any 

National Corridor designation, as 

discussed in Section I.A above. 

4. Marginal Versus Average Losses 

Summary of comments: Commenters, 

including NJBPU, asserted that using 

average costs for transmission losses 

(instead of marginal costs) for the entire 

Eastern Interconnection understates the 

congestion in certain areas. Specifically 

commenters pointed out that the PJM 

plan to adopt marginal losses as of June 

2007 is not included and although the 

Florida Reliability Coordination Council 

sub-region uses marginal losses, the 

Congestion Study modeled that subregion using average losses. In the West, 

the Western Electricity Coordinating 

Council (WECC) noted that its results 

showed that improvements are needed 

to address this issue. 

DOE response: It is true that the 

Congestion Study modeled average 

losses for all regions. Although in some 

regions transmission losses are charged 

based on average cost and in others they 

are charged based on marginal cost, the 

models used in the Congestion Study 

require the use of either average or 

marginal losses for the entire model 

footprint. In future congestion studies, it 

may be more appropriate to model 

marginal losses in all regions. 

5. Aggregation of Nodes 

Summary of comments: Some 

commenters expressed concern that the 

Congestion Study’s aggregation of the 

Eastern Interconnection’s load and 

generation pockets into 253 nodes and 

analysis of the load flow patterns among 

them resulted in many local areas of 

congestion and localized transmission 

constraints not being identified or 

described. For example, Northern 

Indiana Public Service Company 

pointed out that not all congestion is on 

major transmission facilities and claims 

that flow on some major lines is limited 

by the potential of contingency 

overloads on secondary transmission 

lines contained within a node. 

Similarly, First Energy and SCL noted 

that the level of analysis does not 

present enough detail on their 

respective areas. ODEC claimed that the 

Department’s node analysis should be 

made in conjunction with a more 

localized analysis of all nodes within a 

congested area. Otherwise, ODEC 

asserted that an aggregated approach is 

likely to result in congestion being 

understated because the implicit netting 

of adjacent buses may inadvertently 

offset one against another. 

DOE response: In the modeling of the 

Eastern Interconnection for the 

Congestion Study, congestion was 

calculated at all constraints known to 

have been previously identified for 

monitoring by regional reliability 


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45Seams are interregional differences in market 

design that result in market inefficiencies. 

councils, RTOs, ISOs, and transmission 

owners. This calculation was wholly 

separate from the aggregation of the 

Interconnection into the 253 nodes, 

which was done later in the analytic 

process to identify broad patterns of 

power flows from sources to sinks and 

determine the principal transmission 

elements involved. Accordingly, all 

congestion at the identified locations 

was estimated and reported in the 

model’s outputs. Any failure to flag realworld congestion through this approach 

should be traceable to either of two 

problems, or some combination of them: 

(1) a failure to identify a real-world 

constraint as appropriate for monitoring 

in the model; or (2) a disparity between 

the modeled results and real-world 

experience. The Department intends to 

explore this issue further in future 

congestion studies, and looks forward to 

working on it with interested entities. 

6. Fuel Prices 

Summary of comments: Commenters 

such as ODEC, ConEd, and Toll Brothers 

cautioned the Department against 

reliance on fuel scenarios. ODEC argued 

that evaluating different fuel price 

scenarios implies that fuel price is a 

driver in transmission congestion, when 

in fact it is the lack of sufficient 

transmission capacity that is the 

principal driver of transmission 

congestion. ConEd and PEC stated that 

the Department’s assumption of an 

increasing price difference between 

coal-fired generation and natural-gasand oil-fired generation is unrealistic. 

EPSA cautioned that the extreme 

weather conditions such as were 

experienced during 2005 and the related 

natural gas price impacts associated 

with hurricanes Katrina and Rita should 

not inflate assessments of the duration 

of congestion over the lifetime of a 

transmission asset. 

DOE response: The Department did 

not intend to suggest in the Congestion 

Study that fuel price is the only factor 

creating congestion. In fact, congestion 

can exist in the complete absence of fuel 

price differences when generation 

capacity in a load pocket combined with 

transmission capacity to import energy 

is insufficient to meet demand. Further, 

in the absence of such a reliability 

problem, fuel price differences between 

locations on the grid will not result in 

congestion if transmission capacity is 

adequate to accommodate the demand 

for the cheaper power. The modeling 

performed in the Congestion Study 

resulted in similar locational patterns of 

congestion under each fuel price 

scenario, but with different congestion 

costs. The cost differences reflect the 

marginal generation costs, but the 

locations reflect the underlying 

transmission system topology. 

Moreover, the constraints that were 

identified generally are well-known 

constraints that have been long 

observed. 

Contrary to the assertion of ConEd 

and PEC, natural gas and oil prices were 

assumed to drop in the base case of the 

Congestion Study over the time period 

of 2006 through 2015, thus narrowing 

the price spread between coal-fired 

generation and natural-gas- and oil-fired 

generation. What is more important is 

that the analysis considered three 

distinct fuel price scenarios which offer 

dramatically different relationships 

between the prices of natural gas and 

coal. At the same time, transmission 

problems identified in the Congestion 

Study as persistent are those that appear 

under all fuel price scenarios. 

7. Seams 

Summary of comments: ConEd 

expressed concern that the Congestion 

Study did not effectively take into 

account congestion caused by seams. 

ConEd asserted that, given the 

differences in market design between 

PJM and NYISO, market inefficiencies 

may produce congestion costs while in 

fact the lines are underutilized. 

DOE response: The Department 

acknowledges that seams are an 

important issue in the analysis of 

congestion.45 In the modeling 

conducted for the Eastern 

Interconnection in the Congestion 

Study, seams were reflected by means of 

the hurdle rates used for commitment 

and dispatch and the use of a 

‘‘commitment by pool’’ modeling logic. 

It may be appropriate in future 

congestion studies to consider 

additional analysis of the effects that 

seams are having on congestion. 

However, the Department does not 

believe that the congestion that has led 

to today’s draft National Corridors is 

primarily a result of interregional 

differences in market design. 

8. Line Outages 

Summary of comments: NWPUD and 

SCL question whether the Congestion 

Study adequately accounted for lengthy 

maintenance outages on transmission 

lines in the Western Interconnection. 

DOE response: In the Western 

Interconnection, the transmission 

system is assumed intact when rating 

studies are conducted to determine the 

maximum capability, or Total Transfer 

Capability (TTC) of a path. In addition, 

seasonal Operating Transfer Capability 

(OTC) ratings are conducted for critical 

paths in the Interconnection. These 

studies assume system conditions 

expected to occur in the near term, such 

as long-term transmission or resource 

outages. The western studies used in the 

Congestion Study did de-rate some 

paths below their maximum path 

capability to account for the fact that 

operationally, they are often held below 

the maximum limits. The Pacific AC 

and DC Interties and the tie between 

Alberta and British Columbia are three 

examples that were de-rated in the 

studies to account for issues like those 

raised by SCL and Northern Wasco. The 

Department will consider additional 

approaches to handling the effects of 

line outages in future congestion 

studies. 

B. Comments Specific to the MidAtlantic Critical Congestion Area 

Summary of Comments 

PEC noted differences between the 

load data used in the Congestion Study 

and the PJM Load Forecast Report 2006 

and suggested that a detailed review and 

validation of the data is warranted. PEC, 

ConEd, and LIPA argued that the 

Department should revise the 

Congestion Study to reflect the data in 

NYISO’s final 2006 Comprehensive 

Reliability Plan. 

DOE Response 

When preparing the Congestion 

Study, the Department made every effort 

to include the most current and best 

available data. The specific reports cited 

above were not available at that time, 

and the Department therefore relied on 

2005 data. Nevertheless, the Department 

has reviewed the information cited by 

commenters and concludes that it does 

not alter the analysis set forth below 

concerning the draft designation of 

National Corridors. 

Summary of Comments 

National Grid suggested that the 

geographic area from Albany and Utica 

to New York City should be included 

within the Mid-Atlantic Critical 

Congestion Area. 

DOE Response 

The Department agrees that it is 

appropriate to include this area within 

the Mid-Atlantic Critical Congestion 

Area, and as discussed below, the 

Department has included this area in 

the draft Mid-Atlantic Area National 

Corridor. 

Summary of Comments 

PSEG believed that the Mid-Atlantic 

Critical Congestion Area identified by 

the Congestion Study is too broad. PSEG 


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claimed that the Department’s broad 

designation essentially means that each 

region and each city within this area 

suffers from the same type and degree 

of congestion problem. Given the 

unique transmission topology of the 

sub-regions, PSEG claimed that it is 

unlikely that each sub-region is 

experiencing the same degree of 

congestion. 

DOE Response 

DOE agrees that this broad area is not 

homogeneous and that congestion is not 

uniformly distributed. Nevertheless, as 

the entire region is downstream of 

significant constraints, congestion 

occurs to one degree or another across 

the entire area. 

Summary of Comments 

PSEG noted that the Congestion Study 

says (p. 41) that transmission congestion 

problems are worsening in southeastern 

New York, in New York State as a 

whole, in New Jersey, and in the 

Delaware River Path. PSEG added that 

the Study does not provide data 

applicable to PJM to support these 

assertions. Further, PSEG cited PJM’s 

2005 State of the Market Report as 

showing that although total gross 

congestion was rising in the PJM 

footprint over the 6-year period between 

1999 and 2005, this was occurring as the 

geographic size of PJM’s market was 

growing, and the level of gross 

congestion, as a percentage of total PJM 

billings, remained relatively consistent 

at about 8 percent (plus or minus 2 

percent) per year. 

DOE Response 

DOE believes that the information it 

cites on pp. 42–43 of the Congestion 

Study strongly supports the assertions 

made on p. 41. Concerning congestion 

and PJM’s expansion, DOE notes that 

from 1999 through 2005, PJM was 

expanding into relatively uncongested 

areas, while congestion was rising 

sharply in PJM’s original, ‘‘classic,’’

footprint. Thus, although total 

congestion for PJM’s footprint remained 

relatively consistent as a percentage of 

total PJM billing is true, that is not 

particularly relevant. The rapid increase 

in congestion in the eastern portion of 

PJM’s footprint can be demonstrated in 

two ways. One way is to compare total 

annual congestion costs in the PJM 

footprint with total transmission 

revenue requirements (adjusting the 

latter figure as appropriate to take PJM’s 

broadening footprint into account). As 

shown in Table VII–1, congestion costs 

rose from 7.4 percent of transmission 

revenue requirements in 1999 to 107.9 

percent of these requirements in 2005. 

These figures suggest that the demands 

on the transmission system in PJM’s 

footprint were increasingly intensive 

over this period. 

BILLING CODE 6450–01–P 


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Another way to see that congestion 

was growing rapidly in the eastern 

portion of PJM’s footprint during this 

period is to compare historical changes 

in LMPs for the utilities in ‘‘classic 

PJM.’’ As shown in Figure VII–1, the 

LMPs for the eastern utilities in ‘‘classic 

PJM’’ were generally increasing between 

2002 and 2005 or 2006, as compared to 

the LMP for Penelec, which is in 

‘‘classic PJM’’ but located west of most 

of PJM’s major constraints. 


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46NYISO operates both a day-ahead LMP energy 

market and a real-time LMP energy market. NYISO 

uses the terminology ‘‘location-based marginal 

prices’’ or LBMP instead of LMP. 

Summary of Comments 

NYPSC and NYISO expressed concern 

about the accuracy of the data 

underlying the Congestion Study, noting 

that the modeling results indicated, 

contrary to NYISO’s 2005 State of the 

Market Report, that the amount of 

congestion in upstate New York is 

relatively high compared to the amount 

of congestion in southeastern New York. 

DOE Response 

NYISO market data on congestion are 

not directly comparable to the 

Congestion Study’s simulation results 

for several reasons. First, NYISO’s 2005 

State of the Market Report relies on realtime congestion data. The Congestion 

Study simulations reflect forwardlooking unit commitment in response to 

predictable loads and therefore should 

be compared to day-ahead data.46

Analysis of historical day-ahead LBMP 

prices indicates that price differences in 

upstate New York (Zone A [West] to 

Zone G [Hudson Valley], and Zone G to 

Zone I [Dunwoodie]) are becoming 

increasingly more significant compared 

to price differentials in downstate New 

York (Zone I to Zone J [New York City]) 

as shown in Table VII–2. This indicates 

that transmission limitations of the 

upstate system in NYISO are becoming 

at least as influential as downstate 

limitations. 

Second, the Congestion Study 

simulations reflect ‘‘planning’’ interface 

definitions and limits published by 

NYISO whereas NYISO’s 2005 State of 

the Market Report is based on 

operational interface limits. Table VII–3 

presents a comparison of planning 

limits and operating limits. For the 

upstate system, the planning limits are 

more stringent than the operating limits. 

For example, the planning limit 

reported by NYISO for Moses South 

used in the Congestion Study ranges 

between 1300 MW and 1700 MW. 

However, the operating limit for that 

interface used in NYISO operations 

ranges between 2550 MW and 2875 

MW. On the other hand, for the 

downstate system, the planning limits 

are less stringent than the operating 

limits. For example, the planning limit 

reported by NYISO for UPNY-ConEd 

used in the Congestion Study ranges 

between 4850 MW and 5750 MW, 

whereas the operating limit for that 

interface used in NYISO operations 

ranges between 3300 MW and 3950 

MW. The combination of looser upstate 

operational limits and tighter downstate 

operational limits compared with the 

planning limits employed in the 

Congestion Study results in a shift in 

congestion in the Congestion Study’s 

modeling from downstate to upstate 

New York. 


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47 ISO–NE is the RTO serving Maine, Vermont, 

New Hampshire, Massachusetts, Connecticut, and 

Rhode Island. 

48FERC conditionally approved a settlement on 

RPM. 117 FERC ¶ 61, 331 (2006), reh’g pending. 

Since the issuance of that order, some parties that 

had provisionally agreed to support RPM have 

withdrawn their support. 

49 70 FR 25,162 (May 12, 2005) (Environmental 

Protection Agency regulation of sulfur dioxide and 

nitrogen oxides). 

Third, NYISO monitors only open 

interfaces (except for Total East). The 

Congestion Study simulations followed 

NYISO planning documents and 

modeled both open and closed 

interfaces. 

Finally, historical congestion data 

referenced in NYISO’s 2005 State of the 

Market Report do not reflect 1000 MW 

of new generation capacity added in 

Zone J in 2006. The Congestion Study 

simulations reflect these and other 

future capacity additions. 

Summary of Comments 

NYPSC claimed that Appendix I and 

Section 12B of the memorandum 

entitled ‘‘GE–MAPS Input Assumptions: 

Eastern Interconnect’’ (GE–MAPS 

Assumptions Memo) appear to 

misrepresent NYISO’s 118 percent 

installed capacity (ICAP) requirement 

by applying that requirement only to 

upstate load instead of to State-wide 

load. 

DOE Response 

This is a reporting error and the 

capacity balance for NYISO as a whole 

provided in the referenced 

memorandum is incorrect. Nonetheless, 

ICAP requirements do not explicitly 

affect system simulations; they affect the 

timing of the need for new capacity 

additions. The NYISO system as 

modeled in the Congestion System is 

balanced. Thus, this reporting error did 

not affect the analysis and findings of 

the Congestion Study. 

Summary of Comments 

NYPSC commented that Section 7 

(Capacity Additions and Retirements) of 

the GE–MAPS Assumptions Memo 

employs a $65/kW-year cost for gas 

turbines, which appears to be very low. 

DOE Response 

The Department agrees that this 

estimate seems low, especially in light 

of a recent increase in costs. However, 

$65/kW-yr was used as a generic 

carrying charge for new peaking 

capacity. With $10/kW-yr fixed 

operating and maintenance cost, this 

would make the cost of new entry equal 

to $75/kW-yr (in real 2005 dollars, or 

$81.2/kW-yr in 2008 dollars). This is 

only moderately lower than the cost of 

new entry used in the NYISO ICAP 

manual for the New York Control Area 

demand curve for the 2007/2008 

capability period ($87.6/kW-yr). Thus, 

the Department does not believe that 

increasing the cost of new entry would 

alter the conclusions in the Congestion 

Study. 

Summary of Comments 

NYPSC commented that Section 10 

(External Region Supply) in the GE–

MAPS Assumptions Memo ‘‘scheduled’’

flows from Hydro Quebec to New York, 

New England, and Ontario on 12 

months of historical data that might not 

be typical. 

DOE Response 

The Department will work with 

NYPSC to develop more representative 

data for use in future congestion studies. 

However, the Department does not 

believe that changing these data would 

alter the conclusions in the Congestion 

Study. 

Summary of Comments 

NYPSC commented that Section 12C 

(Market Model Assumptions—ISO 

Boundaries) of the GE–MAPS 

Assumptions Memo cites high hurdle 

rates between NYISO and ISO New 

England (ISO–NE) 47 even though 

wheeling charges between the two areas 

were eliminated. 

DOE Response 

The Department recognizes the 

absence of wheeling charges between 

NYISO and ISO–NE. The Congestion 

Study used hurdle rates to reflect other 

inefficiencies in conducting transactions 

across market boundaries resulting from 

differences in market design. 

Summary of Comments 

NYPSC commented that Section 12D 

(Market Model Assumptions—Operating 

Reserves) of the GE–MAPS Assumptions 

Memo misstates how New York 

determines operating reserves. 

DOE Response 

The Congestion Study based operating 

reserve assumptions on the actual 

requirements instituted by each 

reliability region. 

Summary of Comments 

NJBPU argued that the Congestion 

Study fails to take into account 

reliability upgrades that PJM has already 

required in its existing Regional 

Transmission Expansion Program 

(RTEP) process and new upgrades 

continually being formulated as that 

process progresses. According to PSEG 

and PEC, the Department did not take 

sufficient account of PJM’s proposed 

Reliability Pricing Model (RPM) or the 

effects of mandatory reliability-driven 

transmission reinforcements and 

upgrades, since such upgrades like the 

Neptune Project would reduce 

congestion. PSEG asserted that the 

Congestion Study’s claim that ‘‘addition 

of * * * generation capacity * * * will 

create additional congestion unless new 

transmission is also developed’’ is 

erroneous and presumes the siting of 

remote generation that is far from load 

and located on the wrong side of the 

constraint. Additionally, PEC contended 

that RPM may spur the addition of new 

generation close to load centers that is 

not accounted for in the Congestion 

Study. 

DOE Response 

The model included planned capacity 

that is scheduled to come on line over 

the next several years. In addition, the 

model assumes that when additional 

capacity is needed, new capacity will be 

added at locations that have high 

locational prices, which are usually 

close to load. This tends to reduce 

modeled congestion. The PJM RPM 

process, if and when it is implemented, 

should have a similar result.48 All 

transmission projects that are far enough 

along in the siting and construction 

process to be considered firm in the 

load flow, including the Neptune 

Project and any such projects approved 

in the RTEP process, are included. 

PEC questioned why the re-powering 

of the Potomac River and Benning 

plants is considered uneconomical. 

DOE Response 

No assumptions were made in the 

Congestion Study with regard to these 

plants. 

Summary of Comments 

Toll Brothers claimed that the 

Congestion Study fails to take into 

account two assumptions that will 

reduce the need for increased 

transmission capacity from west to east 

in the PJM footprint: (1) the likely 

retirement of some generation facilities 

between the Midwest and the District of 

Columbia; and (2) increased restrictions 

on traditional air pollution emissions 

from coal-fired plants and the future 

regulation of greenhouse gas emissions, 

both of which would increase the cost 

of electricity generated by such plants. 

NYPSC asked if modeling accounted for 

compliance with the Clean Air Interstate 

Rule.49


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50See also comments of National Grid, Potomac 

Holdings, Inc., and HQ Energy Services (US). 

51NERC is the Electric Reliability Organization 

responsible for proposing and enforcing reliability 

standards for the bulk-power system throughout the 

United States subject to FERC approval under FPA 

section 215. 

52See also comments of U.S. Rep. Hinchey 

(Recommending National Corridor between PJM 

and New York City as an alternative to National 

Corridor recommended by NYRI). 

DOE Response 

The Congestion Study analysis 

included only planned retirements. Any 

attempt to forecast other retirements 

would be inappropriately speculative. 

Similarly, in the Eastern analysis, each 

unit in the model is assumed to comply 

with all promulgated air regulations, 

including the Clean Air Interstate Rule, 

and the Department did not speculate 

about potential future regulation. 

C. Comments Specific to the Southern 

California Critical Congestion Area 

Summary of Comments 

CPUC argued that the Congestion 

Study exaggerated the significance of 

congestion into southern California, 

relying heavily on simulations instead 

of historical data and on information 

from project proponents. CPUC noted 

that one of the studies provided to DOE 

concluded, based on physical flow data 

from 1999 through 2005, that Arizonato-southern California was not among 

the areas found to be experiencing 

heavy path usage. CPUC noted that the 

year 2008 simulations cited in the 

Congestion Study as indicating high 

economic significance of congestion 

from Arizona into southern Nevada and 

southern California actually show that 

the highest simulated congestion costs 

occur on lines from Arizona into 

southern Nevada. 

DOE Response 

The Department’s identification of 

southern California as a Critical 

Congestion Area was based on a 

combination of factors, including the 

existence of historical congestion, 

projections that this historical 

congestion will worsen in the absence of 

remedial measures, as well as the 

economic and strategic significance of 

southern California to the Nation as a 

whole. Thus, while other areas in the 

Western Interconnection may have 

experienced higher levels of historical 

congestion, the Department believes that 

the totality of circumstances in southern 

California warrant its identification as a 

Critical Congestion Area and, as 

explained further in Section IX below, 

the draft designation of a National 

Corridor. 

VIII. Draft Mid-Atlantic Area National 

Corridor 

A. Alternatives and Recommendations 

In the Congestion Study, the 

Department solicited alternatives and 

recommendations for National Corridor 

designations. The Department received 

a number of such alternatives and 

recommendations for the Mid-Atlantic 

Critical Congestion Area. Some 

commenters, including EEI and Exelon 

Corporation, recommended National 

Corridor designations in eastern New 

York and eastern PJM, citing the need to 

remedy the existing and growing 

congestion problems in the Mid-Atlantic 

Critical Congestion Area, but they did 

not specify specific boundaries.50

Based on its regional transmission 

planning studies, PJM recommended 

three specific National Corridors in the 

Mid-Atlantic area. According to PJM, a 

National Corridor is needed in a 

contiguous area of southeastern 

Pennsylvania, northern West Virginia, 

western Maryland, and northern 

Virginia, because in the absence of 

construction of a new high-voltage 

transmission circuit within this area, 

PJM and North American Electric 

Reliability Corporation (NERC) 51

reliability planning criteria will be 

violated by 2011. The other two 

National Corridors recommended by 

PJM are: (1) a contiguous area of eastern 

Ohio, much of Pennsylvania, and part of 

northern New Jersey; and (2) a 

contiguous area of eastern Maryland, all 

of Delaware, and parts of eastern 

Pennsylvania and southern New Jersey. 

These two National Corridors are 

needed, according to PJM, to ensure that 

planning and development of required 

transmission solutions can be 

completed in time to prevent violations 

of PJM and NERC reliability planning 

criteria that would otherwise occur by 

2014. 

AEP recommended a National 

Corridor to encompass the general 

anticipated route of a transmission line 

it is proposing to build between West 

Virginia and Maryland. Allegheny 

recommended a National Corridor to 

encompass the general anticipated route 

of a transmission line that it and 

Dominion Virginia Power (Dominion) 

are proposing to build between 

southwestern Pennsylvania and 

northern Virginia. 

The Governor of the State of West 

Virginia commented that development 

of transmission to supply regions north 

and east of West Virginia with lowpriced clean-coal generation and 

renewable generation from within, as 

well as south and west of, his State 

would result in economic and reliability 

benefits for all involved regions. Thus, 

noting the time it can take to site a 

transmission line and the urgency of 

addressing the transmission problems, 

the Governor recommended designation 

of a National Corridor that would 

encompass the AEP project as well as 

the Allegheny-Dominion project. 

New York Regional Interconnect Inc. 

(NYRI) recommended a National 

Corridor to encompass the general 

anticipated route of a transmission line 

it has proposed to build from Marcy, 

New York to New Windsor, New York. 

The City of New York argued that 

growing energy demand, national 

security concerns, the unique nature of 

electricity dependence in the Nation’s 

financial and commercial capital, and 

fuel diversity and stability factors all 

warrant the designation of one or more 

National Corridors for New York City. 

Specifically, the City of New York 

recommended a National Corridor 

between the New Jersey segment of PJM 

and New York City.52 The City of New 

York also recommended a National 

Corridor north and northwest of New 

York City within New York State. The 

City of New York further cited a 

recently enacted New York State statute 

that would deny the use of eminent 

domain powers to NYRI even if its 

proposed transmission project were to 

obtain a State permit as illustrative of 

the type of parochial concerns that may 

impede needed energy infrastructure 

improvements and that FPA section 216 

was designed to address. 

NYISO commented that the 

Congestion Study correctly included 

metropolitan New York within the 

Critical Congestion Area, and correctly 

identified the general location and 

direction of congestion in New York. 

NYISO explained that it conducts a 

Comprehensive Reliability Planning 

Process to assess reliability needs and 

that while its analysis indicates a 

reliability need for additional resources 

in southeast New York starting in 2008, 

sufficient market-based generation 

solutions have been submitted so that 

reliability criteria will be met through 

2014. Thus, according to NYISO there is 

no need for a National Corridor from a 

reliability standpoint. However, NYISO 

also noted that ‘‘New York’s 

comprehensive and effective generation 

siting law expired in December 2002 

and has not been re-enacted.’’ NYISO 

further noted that while it provides upto-date data to assist stakeholders in 

evaluating investments to address the 

economic effects of congestion, ‘‘by 

design, the NYISO leaves the decision 

making on economic solutions for the 

Market Participants.’’


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53See DOE response, Section IV.B. above. 54See DOE response, Section II.A, II.D, and IV.A 

above. 55See DOE response, Sections II.B, II.D, IV.A, 

VII.A, and VII.B above. 

56See, e.g., comments of Citizens for Fauquier 

County, Clarke County Board of Supervisors, 

Fauquier County Architectural Review Board, 

Fauquier County Board of Supervisors, Fauquier 

County Historical Society, Foundation of the State 

Arboretum, Goose Creek Association, Historic Long 

Branch, Route 50 Corridor Coalition, Shenandoah 

Valley Network, Unison Preservation Society, 

Valley Conservation Council, Sierra Club, Virginia 

Local and Regional Organizations, Virginia 

Outdoors Federation, U.S. Rep. Wolf, VA Sen. 

Herring, Toll Brothers, and many individuals. 

57See, e.g., comments of ConEd, U.S. Rep. 

Hinchey, NY Sen. Bonacic, Delaware River 

Commenters, Upper Delaware Council, CARI, and 

many individuals. 

58See DOE response, Sections II.B, III, and V 

above. 

Numerous commenters recommended 

against one or more National Corridor 

designations for the Mid-Atlantic 

Critical Congestion Area. The Governor 

of the Commonwealth of Virginia 

commented that no National Corridor 

designations should be made before 

there had been adequate consultation 

with States.53 PAPUC commented that 

while the preliminary data show that 

there is chronic congestion in some 

portions of the Mid-Atlantic region that 

deserves close attention by Federal and 

State regulators, additional analysis in 

consultation with States is needed 

before any National Corridor 

designation is made.54 NYPSC and 

NJBPU opposed National Corridor 

designations, raising concerns about the 

data and methodology used in the 

Congestion Study and arguing that 

further analysis was needed.55

Many commenters recommended 

against designation of the National 

Corridor proposed by Allegheny,56 and 

many commenters recommended 

against designation of the National 

Corridor proposed by NYRI.57 These 

commenters raised concerns about the 

environmental and landowner effects of 

the particular projects proposed by 

Allegheny and Dominion and by NYRI 

and argued for consideration of nontransmission solutions to congestion.58

After reviewing the alternatives and 

recommendations provided, the 

Department believes that designation of 

a National Corridor for the Mid-Atlantic 

Critical Congestion Area may be 

warranted. In the following sections, the 

Department will detail its factual 

finding of the existence of constraints or 

congestion that adversely affects 

consumers in the Mid-Atlantic Critical 

Congestion Area and explain the 

considerations that it believes warrant 

designation of a National Corridor for 

this area. Finally, the Department will 

delineate and explain the specific 

boundaries of the draft National 

Corridor. 

B. Finding of Constraints or Congestion 

That Adversely Affects Consumers 

The Congestion Study identified the 

Atlantic coastal area from metropolitan 

New York southward through northern 

Virginia as a Critical Congestion Area 

based on evidence of historical, 

persistent congestion caused by 

numerous well-known constraints that 

are projected to continue and worsen 

unless addressed through remedial 

measures. In conducting the Congestion 

Study, the Department identified these 

well-known constraints based on a 

review of extant transmission studies 

and expansion plans available prior to 

the publication of the Study. These 

constraints are listed in Table VIII–1, in 

no particular order, and their 

approximate locations are shown in 

Figures VIII–1 and VIII–2. 

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Many of these constraints were 

binding, and thus produced congestion 

in years 2004, 2005, and 2006. (See 

Tables VIII–2 and VIII–3 for summaries 

of hourly data reported by PJM and 

NYISO.) Further, from 2004 through 


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59Like NYISO, PFM operates both a day-ahead 

LMP-based energy market and a real-time LMPbased energy market. 

2005 in the PJM footprint, a total of 19 

constraints were binding more than 5 

percent of the time (438 hours/year) in 

the day-ahead market, and six 

constraints were binding more than 5 

percent of the time in the real-time 

market.59 (See Table VIII–4.) In New 

York over the same period, 18 

constraints were binding in the dayahead market more than 5 percent of the 

time, and 62 constraints were binding 

more than 5 percent of the time in the 

real-time market. (See Table VIII–5.) 


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The modeling directed by DOE for the 

Congestion Study projected that some of 

these constraints will continue to be 

problems in 2008, along with other 

additional constraints. DOE found that 

looking across the several Congestion 

Study scenarios, 12 constraints were of 

particular interest in the PJM footprint 

and 21 in New York. These constraints 

are listed in Tables VIII–6 and VIII–7 

respectively. DOE’s analysis indicates 

that five of the ten most problematic 

constraints in the Eastern 

Interconnection are in New York, and 

the other five are in the PJM footprint. 


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60Regulations governing the mix of generation 

supplied by load-serving entities to consumers, 

such as State renewable portfolio standards, could also affect the capacity factors for higher cost 

generation, but do not appear relevant here. 

The existence of constraints causing 

persistent congestion is further 

evidenced by regional differences in 

generation capacity factors within the 

PJM and NYISO footprints. In a 

regional-scale electricity market, 

generators producing electricity at lower 

costs will typically be used at higher 

capacity factors than generators with 

higher production costs, except when 

such efficient use of resources is not 

feasible due to transmission limitations 

and the need to operate some generation 

capacity close to load centers to ensure 

voltage stability in those areas.60

Accordingly, the Department undertook 

an analysis to identify areas within or 

near the PJM footprint and New York 

State with underutilized lower cost 

generation, and to identify the 

constraints that limit flows of lowerpriced electricity from generation-rich 

areas to generation-short areas with 

higher prices. 

PJM data for 2004, 2005, and 2006 

show that the utilization rate (or 

capacity factor) for large generators 

(>200MW) in the $30–40/MWh cost 

category in the western portion of PJM’s 

footprint was 63, 61, and 67 percent on 

average respectively (Table VIII–8); DOE 

projections show a slightly higher figure 

for 2008 (also Table VIII–8). By 

comparison, the average capacity factor 

for generation in the same cost class in 

the eastern portion of PJM’s footprint 

was 74, 79, and 77 percent in 2004, 

2005, and 2006 respectively and is 

projected by DOE at over 79 percent for 

2008. (See Table VIII–9.) In DOE’s 

projections for 2008, similar 

differentials in capacity factor are seen 

between the western and eastern 

portions of PJM’s footprint for higher 

cost groups of generators (i.e., $40–50/ 

MWh, $50–60/MWh, $60–80/MWh, and 

$80–90/MWh). The western portion of 

PJM’s footprint has no operating units 

above $100/MWh; the eastern portion 

does, and they are used when needed. 

(See Figure VIII–3.) 

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These historical data and projections 

confirm that there are differences in 

capacity factors between the eastern and 

western portions of PJM’s footprint, and 

that the eastern portion consistently 

relies on a more-expensive-to-run mix of 


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generation sources than the western 

portion. This is a direct result of 

transmission constraints that prevent 

lower-priced electricity from the 

western portion of the PJM footprint 

from reaching load centers in the 

eastern portion during the hours the 

constraints are binding. 

DOE also examined the data from its 

projections for 2008 to identify the 

transmission constraints that most 

limited flows from the western portion 

of PJM’s footprint (and from the eastern 

portion of the Midwest ISO’s footprint) 

to serve loads in the eastern portion of 

PJM’s footprint. The constrained 

facilities are listed in Table VIII–10, and 

the approximate locations of those 

constraints are shown in Figure VIII–4. 


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A somewhat similar situation exists in 

New York State. For purposes of this 

analysis, DOE divided the State into 

three geographic areas: Upstate West 

(NYISO zones A through E), Upstate 

East (NYISO Zones F through I), and 


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Downstate (NYISO Zones J and K). (See 

Figure VIII–5.) Downstate has almost no 

thermal capacity below $60/MW, 

whereas Upstate West has about 5750 

MW and Upstate East has about 2600 

MW at $60/MW or lower. (See Figure 

VIII–6.) In DOE’s projections for 2008, 

however, the below-$60/MW thermal 

units are shown as operating at very 

high capacity factors already. (See 

Figure VIII–7.) The effects of 

transmission congestion start to become 

apparent in the $60–70/MW class, 

where lower-cost capacity in Upstate 

East is available but its output is not 

always deliverable to Downstate. 

Downstate has more than 14,250 MW of 

capacity with production costs of $70/ 

MW or higher (up to more than $200/ 

MW), whereas Upstate East and Upstate 

West combined have only about 5100 

MW at $70/MW or higher. Further, 

according to both historical data and 

DOE’s projections for 2008, the units in 

Downstate in all classes with 

production costs above $70/MW almost 

always operate at higher capacity factors 

than in the other two areas. (See Table 

VIII–11.) 


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DOE reviewed both historical data 

and its projections for 2008 to identify 

the constraints that appear most critical 

in limiting the use of generation in 

upstate New York, Ontario, and 

Pennsylvania to serve downstate New 

York loads. The constraints thus 

identified are listed in Table VIII–12, 

and their approximate locations are 

shown in Figures VIII–8A and VIII–8B. 


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61Whenever a constraint is binding in real time, 

PJM assesses a transactional congestion charge to 

those customers whose power is transmitted over 

the constraint. The charge is the difference in LMP 

on either side of the constraint multiplied times the 

amount of power transmitted. 

62 In this analysis, the eastern portion of PJM’s 

footprint includes the service areas of Pepco, 

Baltimore Gas & Electric Company, Dominion, 

Atlantic City Electric, PSEG, Rockland Electric Co., 

Delmarva Power, Jersey Central Power & Light, MetEd, PECO, and PPL Electric Utilities. The western 

portion of PJM’s footprint includes the service areas 

of AEP, Commonwealth Edison (ComEd), The 

Dayton Power & Light Company (DP&L), and 

Duquesne Light Company (Duquesne). 

Further, PJM notes in its comments 

that total congestion costs in its growing 

footprint rose from $65 million in 1999 

to more than $2.09 billion in 2005.61

(See Table VIII–13.) These figures are 

similar to the results from the 

Department’s modeling for 2008, which 

show that the top constraints in this 

region account for $1.57 billion (20 

percent) of the $8 billion of total 

congestion rent for the entire Eastern 

Interconnection. The Department’s 

projections for 2008 show that the top 

constraints in New York account for 

$0.98 billion (12 percent) of the $8 

billion of total congestion rent for the 

entire Eastern Interconnection. As 

discussed in Section VII.A.2 above, 

while financial transmission rights 

protect load-serving entities in PJM and 

NYISO from paying congestion costs or 

congestion rents, congestion costs and 

congestion rents are nonetheless useful 

indicators of the persistence and 

pervasiveness of congestion within a 

transmission system. 

BILLING CODE 6450–01–P 

Thus, the Department has 

documented the existence of persistent 

congestion into and within the MidAtlantic Critical Congestion Area, as 

well as the constraints causing that 

persistent congestion. As discussed in 

Section II.A above, whenever there is 

persistent congestion, buyers must rely 

on power from less-preferred generating 

sources, a smaller range of generators is 

able to serve load, and grid operators 

have fewer options for dealing with 

adverse circumstances or unanticipated 

events, all of which adversely affects 

consumers. Therefore, the Department 

finds under FPA section 216(a)(2) that 

there are ‘‘constraints or congestion that 

adversely affects consumers’’ in the 

Mid-Atlantic Critical Congestion Area. 

C. Determination That Designation of a 

Mid-Atlantic Area National Corridor 

Would Be Warranted 

Given the presence of constraints or 

congestion that adversely affects 

consumers in the Mid-Atlantic Critical 

Congestion Area, the Secretary has the 

discretion to consider designation of a 

National Corridor. As discussed above 

in Section II.A, the Secretary will 

determine whether to exercise his 

discretion based on the totality of the 

information developed, taking into 

account relevant considerations, 

including the considerations identified 

in FPA section 216(a)(4), as appropriate. 

In this section, the Department 

discusses the considerations that it 

believes warrant designation of the MidAtlantic Area National Corridor. 

1. Economic Development 

Considerations 

Data from January 2004 through 

December 2006 confirm that despite the 

fact that PJM has been operating as a 

single market, transmission constraints 

result in major and persistent disparities 

in wholesale electricity prices within 

the market. (See Figure VIII–9.) As a 

result of these fundamental price 

disparities, electricity consumers in the 

eastern portion of PJM’s footprint 

consistently end up paying higher 

electricity bills than consumers in the 

western portion.62


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63Note that the incomplete price data shown in 

Figure VIII–10 in 2004 and 2005 are the result of 

new members joining the PJM market: ComEd 

joined in May 2004; AEP and DP&L joined in 

October 2004; Duquesne joined in January 2005; 

and Dominion joined in May 2005. 

64According to a staff report published by the 

Maryland Public Service Commission (MPSC): 

Maryland offers a first-hand look at the pricing 

impacts of congestion. Frederick County is a key 

congestion point on the west-to-east transmission 

import path. Three years ago, locational marginal 

prices (LMPs) for electricity in Maryland west of 

that point averaged $2.90 per megawatt-hour 

(MWh) less than prices in Maryland east of that 

point. By 2006, that gap had risen to $9.43 per 

MWh. The gap is likely to continue to increase until 

additional generation becomes available to serve 

central and southern Maryland and the Eastern 

Shore, or additional transmission capacity becomes 

available to import electricity into those regions. 

MPSC Staff Report, Electric Supply Adequacy 

Report of 2007, p. 3 (Jan. 2007) (MPSC Report). The 

report continues ‘‘Maryland is directly affected by 

transmission congestion, particularly since it and 

neighboring states (including the District of 

Columbia) have to import a large proportion of their 

energy needs. * * * LMPs in Maryland are among 

the very highest in PJM.’’ Id., p. 11. 

65See Appendix A for additional detail. 

Appendix A is available at http://nietc.anl.gov. 

As shown in Figure VIII–10 63, the 

price disparity in monthly average dayahead LMPs between the Pepco and 

Duquesne zones was as much as $45/ 

MWh from August 2005 through 

October 2005 and again in August 2006. 

More generally, consistently higher 

prices were experienced in the zones of 

eastern PJM that serve Washington, DC, 

Baltimore,64 Philadelphia, and northern 

New Jersey. Further, the basic price 

disparity between the eastern and 

western parts of PJM’s footprint 

occurred regardless of the time of day. 

A similar pattern was observed when 

the data were divided into on-peak and 

off-peak periods, and when data from 

PJM’s real-time market for the same 

period were examined.65 As one might 

expect, the price disparity widened 

considerably when the electricity 

supply system was working close to its 

physical limits, as on hot summer days. 

Figure VIII–11 shows hourly day-ahead 

LMPs for August 8, 2005, when the 

differential reached its maximum ($270/ 

MWh) for that calendar year. 


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For the area served by NYISO, 

historical electricity price data from 

2004 through 2006 show a persistent 

pattern of substantially lower wholesale 

electricity prices in the day-ahead 

market for the western and upstate 


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zones than in New York City and Long 

Island. (See Figure VIII–12.) As a result 

of this persistent disparity, electricity 

consumers in the area north of New 

York City, the City itself, and on Long 

Island end up paying higher electricity 

bills than consumers in the rest of the 

State of New York. 


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As shown in Figure VIII–12, the 

difference in monthly average wholesale 

day-ahead prices between the highest 

and lowest zones was as much as $44/ 

MWh. A similar pattern is seen if one 

looks only at the day-ahead on-peak 


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66See id. 

hours and only at the day-ahead offpeak hours, sometimes with a reordering of the zones with intermediate 

prices. Similar price patterns are also 

seen in the real-time data.66 As one 

might expect, the price disparity 

widened considerably when the 

electricity supply system was working 

close to its physical limits, as on hot 

summer days. Figure VIII–13 shows 

hourly day-ahead LBMPs for August 5, 

2005, when the differential reached its 

maximum ($325/MWh) for that calendar 

year. 


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In addition, the constraints in New 

York result in consumers in downstate 

New York paying disproportionate 

generation capacity costs. If local loadserving entities were to contract for their electricity supply needs across New 


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67 DOE does not mean to imply that large load 

centers, such as New York City, Long Island, or the 

major cities in the eastern portion of PJM’s footprint 

could rely entirely on distant generation if 

sufficient transmission capacity were available. 

DOE recognizes that some level of local generation 

is needed to maintain voltage support and stability. 

York without regard to the location of 

the generation capacity, reliability could 

be imperiled because there would be no 

assurance that all of the electricity 

required could actually be delivered to 

the load centers when needed. To avoid 

such situations, the New York State 

Reliability Council has established 

locational ICAP requirements, according 

to which generation capacity must be 

located within New York City sufficient 

to meet 80 percent of the City’s forecast 

annual peak load. Similarly, 99 percent 

of Long Island’s forecast annual peak 

load must be located on the Island. 

Load-serving entities are free to buy 

their electricity supplies from distant 

sources when those sources are 

accessible, but the load-serving entities 

must also ensure that they have 

adequate local capacity available at all 

times. The locational ICAP system 

enables reliability requirements to be 

met, but at additional cost to consumers. 

To ensure that the locational ICAP 

requirements are met, NYISO operates 

an ICAP market. The ICAP market 

involves the sale of generation capacity, 

unlike NYISO’s day-ahead and real-time 

markets, which involve the sale of 

energy. Load-serving entities that have 

not met their full ICAP requirements 

through contracts with local generators 

must participate in NYISO’s ICAP 

market. The ICAP market consists of 

periodic auctions for three areas: New 

York City, Long Island, and the New 

York Control Area (which is all of 

NYISO). 

The amount of capacity that a 

generator is qualified to provide through 

the ICAP market is determined by an 

Unforced Capacity (UCAP) 

methodology, which accounts for the 

possibility of forced outages, thus the 

prices set in the ICAP market are 

referred to as UCAP prices. As shown in 

Figure VIII–14, UCAP prices for New 

York City and Long Island were 

consistently higher than UCAP prices 

for the entire New York Control Area 

over the 26-month period from 

September 2004 to October 2006, 

sometimes dramatically so. The 

substantial differentials between the 

State-wide UCAP prices and UCAP 

prices in New York City and Long 

Island represent a premium the loadserving entities in the City and on Long 

Island (and their retail customers) must 

pay to ensure reliability by maintaining 

local generation capacity instead of 

improving the transmission system 

sufficiently to be able to rely more 

extensively on distant generation 

sources. This premium is in addition to 

the higher costs the load-serving entities 

and their customers pay for electric 

energy because they are relying to a 

greater extent on generation sources 

with higher production costs.67

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The data detailed above indicate that 

consumers in the Mid-Atlantic Critical 

Congestion Area now pay high 

electricity prices because their 

electricity suppliers are unable to access 

low-cost supplies due to insufficient 


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68Comments of PJM, p. 28. 

69 Id., p. 30. In Maryland, recently enacted 

environmental legislation will cause: Owners of at 

least two Maryland coal-fired power plants to 

consider whether it is possible, or worthwhile, to 

install the necessary [control] equipment. Any 

existing Maryland coal plants that may have to be 

retired will exacerbate the existing reliability 

challenges and increase the possibility of supplies 

during peak periods not being able to meet the 

demand for electricity. The consequences could 

include periods of voltage reductions and/or rolling 

outages during peak periods to keep the system 

from collapsing. 

MPSC Report, p. 23. 

70Comments of PJM, p. 32. 

71 Id., p. 38. 

72PJM says that: 

[F]or purposes of long-term planning for total 

system adequacy, substituting [demand response] 

for incremental transmission capability would 

require, at best, several times the equivalent amount 

of new generation that would be needed to offset 

the new transmission capacity. [Demand response] 

does not produce a steady stream of MW equivalent 

output because it is normally cycled over a given 

time period (i.e., load would be switched off and 

on to ensure minimal impact to the [demand 

response] provider, rather than switched off for the 

entire duration of the system need). Also, [demand 

response] is produced in a variety of diverse 

programs, which also result in divergent 

measurements. Within PJM, [demand response] 

participants may be price responsive, contractually 

obligated, or directly controlled. Each category of 

[demand response] results in a variation of the 

expected amount, or ‘‘output,’’ of [demand 

response] that is provided when called upon, 

thereby further complicating the difficulty of 

determining, for long-term planning purposes, the 

transmission or generation MW that are equivalent 

to a stated amount of [demand response]. 

Id., pp. 38–40. 

73 Id., pp. 5–6. 

74See NYISO, Comprehensive Reliability 

Planning Process 2007 Reliability Needs 

Assessment (March 16, 2007). 

75 Id., p. 10. 

76 Id., p. 7. 

77 Id., p. 10. 

transmission capacity. Reasonably 

priced electricity supplies are vital to 

the economic and social well-being of 

any metropolitan area. High electricity 

prices add to the cost of living or doing 

business in the area, and retard the 

area’s economic growth and 

competitiveness. Further, one of the 

considerations identified in FPA section 

216(a)(4) is whether ‘‘the economic 

vitality and development of the 

corridor, or the end markets served by 

the corridor, may be constrained by lack 

of adequate or reasonably priced 

electricity.’’ FPA section 216(a)(4)(A); 16 

U.S.C. 824p(a)(4)(A) (emphasis added). 

Therefore, the Department believes 

that economic development 

considerations warrant designation of a 

National Corridor for the Mid-Atlantic 

Critical Congestion Area. 

2. Reliability Considerations 

The constraints limiting delivery of 

electricity to the eastern portion of 

PJM’s footprint pose a threat to 

reliability given the steady growth in 

electricity demand in that area, the 

area’s aging generation fleet with recent 

retirements of significant amounts of 

capacity, the slow pace of development 

of new local generation capacity in that 

area, and the uncertainties associated 

with increasing demand response. 

Weather-normalized summer peak 

load for the PJM footprint as a whole is 

projected to grow at an average rate of 

1.6 percent per year for the period 2006 

through 2016. However, projected 

annual growth varies widely among the 

utilities in PJM’s footprint, ranging from 

0.7 percent to 2.4 percent, and much of 

the most rapid growth is concentrated in 

the eastern portion, and particularly in 

the Baltimore-Washington-Northern 

Virginia area.68

Between 2003 and 2006, a total of 582 

MW of generating capacity in the 

Baltimore-Washington-northern Virginia 

area was retired or put on a restricteduse status for environmental reasons.69

About 200 MW has been added in the 

area since 2000, and about 20 MW is 

now under construction. An additional 

5600 MW is now proposed for the area, 

but only 14 MW of it would go into 

service before 2009, and about 5000 MW 

is associated with three new nuclear 

units that would not become available 

before 2015 or 2016.70 PJM estimates 

that 2500 MW of net new generation 

would need to be installed east of its 

Loudon substation in northern Virginia 

to avoid the need for additional 

transmission in the western portion of 

its footprint.71

Further, while efforts are being made 

to increase the participation of demandside resources in the PJM wholesale 

electricity markets, it does not appear 

that such efforts are capable of 

producing near-term results on the scale 

needed to forestall the need for 

additional transmission.72

Thus, PJM asserts: 

additional transmission capability is 

essential in [the western portion of PJM’s 

footprint] to maintain reliable and economic 

service to the Baltimore-WashingtonNorthern Virginia urban load center. Unless 

a major new, high-voltage transmission 

circuit is constructed * * * by 2011, existing 

500 kV transmission facilities serving this 

critical load center will become overloaded, 

in violation of NERC and PJM reliability and 

planning criteria * * * Additional 

transmission capability [in the eastern 

portion of PJM’s footprint] will be needed, in 

this instance by 2014, to avoid numerous 

projected violations of NERC and PJM 

reliability and planning criteria in northern 

New Jersey.73

With regard to New York, since its 

submission of comments on the 

Congestion Study, NYISO has published 

a new Reliability Needs Assessment 

(2007 RNA) as part of its 

Comprehensive Reliability Planning 

Process.74 The 2007 RNA indicates that 

the constraints limiting delivery of 

electricity to southeast New York pose 

a threat to reliability by 2011, given the 

growth in electricity demand and the 

projected retirement of generating units. 

NYISO notes that load in southeast 

New York has been growing by over two 

percent per year.75 NYISO estimates that 

between 2007 and 2009, 1,674.8 MW of 

generating capacity in New York will be 

retired, and only 1,203.9 MW of 

capacity will be added.76 NYISO 

describes the effects of these factors on 

the already constrained transmission 

system as follows: 

By 2011, the NYCA load forecast estimates 

that approximately two thirds of the NYCA 

load will be located in load Zones G through 

K which is downstream of the UPNY–SENY 

[Upstate New York-Southeast New York] 

transmission interface. In addition, 

approximately 52% of the NYCA load will be 

located in load Zones J and K, downstream 

of the Dunwoodie-South transmission 

interface, which is a slight increase from 

current load levels. 

The demands that are increasingly being 

placed on the transmission system in 

conjunction with other system changes, 

consisting primarily of generating units 

retirements * * *, load growth, neighboring 

system changes and the lack of new capacity 

or transmission resources downstream of the 

UPNY–SENY interface, have and will 

continue to result in voltage criteria 

violations at much lower transfer levels than 

have previously occurred. The result is that 

over time, transfers into and through SENY 

will increasingly be limited by voltage 

constraints rather than thermal constraints. 

This reduced capability of the bulk power 

system to make power transfers into SENY 

due to these voltage constraints, coupled 

with continuing load growth in SENY results 

in a resource adequacy criterion violation by 

2011.77

The data detailed above indicate that 

consumers in the Mid-Atlantic Critical 

Congestion Area face threats to 

reliability if existing congestion 

problems are not addressed. Reliable 

electricity supplies are vital to the 

economic and social well-being of any 

metropolitan area. Electricity supply 

disruptions may come in many forms, 

ranging from brief disturbances in 

power quality and localized outages to 

large-scale, cascading blackouts. The 

exact cost of electric supply disruptions 

is difficult to quantify and varies 

depending upon the specific 

circumstances. However, such 

disruptions can impose enormous costs 

on consumers and may also, under 


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78U.S.-Canada Power System Outage Task Force, 

Final Report on the August 14, 2003 Blackout in the 

United States and Canada: Causes and 

Recommendations, p. 1 (April 2004). 

79Comments of PJM, p. 51. 

80 Id., pp. 52 and 78. 

81NYISO presentation prepared for Sept. 11, 

2006, meeting with DOE. 

82U.S. Census Bureau, Population Estimates 

Program, http://factfinder.census.gov/ 

83See Bureau of Economic Analysis, National 

Economic Accounts, http://www.bea.gov/bea/dn/ 

home/gdp.htm. 

certain circumstances, pose dangers to 

public health and safety. 

For example, estimates of the total 

cost of the eastern blackout of August 

14, 2003 range between $4 billion and 

$10 billion (U.S. $) for the United 

States; in Canada, the same event led to 

a reduction in gross domestic product of 

0.7 percent in August, a net loss of 18.9 

million work hours, and manufacturing 

shipments in Ontario were down $2.3 

billion (Canadian $).78

Further, one of the considerations 

identified in FPA section 216(a)(4) is 

whether ‘‘the economic vitality and 

development of the corridor, or the end 

markets served by the corridor, may be 

constrained by lack of adequate or 

reasonably priced electricity.’’ FPA 

section 216(a)(4)(A); 16 U.S.C. 

824p(a)(4)(A) (emphasis added). 

Therefore, the Department believes 

that reliability considerations warrant 

designation of a National Corridor for 

the Mid-Atlantic Critical Congestion 

Area. 

3. Supply Diversity and Energy 

Independence Considerations 

Much of the existing generation fleet 

in the eastern portion of PJM’s footprint 

is fueled by oil or natural gas. For 

example, about 28 percent of the 

installed generation capacity in 

Maryland and the District of Columbia 

is either solely oil-fired or capable of 

using both oil and natural gas as fuels, 

as is 35 percent of the installed capacity 

in Delaware. Further, more than 75 

percent of the generation capacity that 

has been added in recent years in 

Delmarva, Maryland, the District of 

Columbia, and New Jersey has been 

fueled by natural gas.79 By contrast, the 

overall generation mix in PJM’s 

footprint is 41 percent coal and 9 

percent oil; coal provides more than 56 

percent of total output from PJM units. 

Further, 

More than 6000 MW of additional coalfired generation, some utilizing clean-coal 

technology, is currently under construction 

or active in PJM’s interconnection queue. All 

of this capacity is or will be located far from 

the Baltimore-Washington-Northern Virginia 

load centers. Moreover, approximately 

12,000–15,000 MW of additional windpowered generation is either under 

construction or under active study in PJM’s 

interconnection queue. With the exception of 

one plant under construction on the New 

Jersey coast, all of these facilities are or will 

be located west of the [eastern] load 

centers.80

Accordingly, one of the consequences 

of transmission congestion in the 

eastern portion of PJM’s footprint is that 

it prolongs and exacerbates the area’s 

existing use of oil and natural gas as 

generation fuels. 

Most of the existing generation fleet in 

the downstate portion of New York is 

fueled by oil or natural gas. On a Statewide basis, about 39 percent of the 

electricity used in New York in 2005 

came from oil or gas units, and 32 

percent came from coal or hydroelectric 

capacity.81 The absence of transmission 

facilities that would enable more hydro- 

, wind-, or coal-based electricity to 

reach the downstate load centers 

prolongs the area’s current relatively 

high dependence on oil and natural gas 

as fuel sources. 

Oil and natural gas are relatively high 

in price and must be purchased in 

markets that are highly volatile and 

subject to unanticipated international 

trends and adverse events. Inadequate 

transmission capacity leaves consumers 

in the Mid-Atlantic Critical Congestion 

Area exposed, perhaps increasingly, to 

the higher prices and higher price 

volatility associated with these 

generation fuels, with a resulting impact 

on business certainty, especially for 

industrial consumers. Lack of adequate 

transmission capacity also limits the 

Mid-Atlantic Critical Congestion Area’s 

access to generation fueled by domestic 

sources that could displace generation 

fueled by foreign sources. Thus, 

economic growth may be jeopardized 

and energy independence is 

compromised. Further, one of the 

considerations identified in FPA section 

216(a)(4) is whether ‘‘(i) economic 

growth in the corridor, or the end 

markets served by the corridor, may be 

jeopardized by reliance on limited 

sources of energy; and (ii) a 

diversification of supply is warranted.’’

FPA section 216(a)(4)(B); 16 U.S.C. 

824p(a)(4)(B). Another consideration 

identified in that statute is whether ‘‘the 

energy independence of the United 

States would be served by the 

designation.’’ FPA section 216(a)(4)(C); 

16 U.S.C. 824p(a)(4)(C). 

Therefore, the Department believes 

that supply diversity and energy 

independence considerations warrant 

designation of a National Corridor for 

the Mid-Atlantic Critical Congestion 

Area. 

4. National Defense and Homeland 

Security Considerations 

The Mid-Atlantic Critical Congestion 

Area is home to 55 million people (19 

percent of the Nation’s 2005 

population)82 and is responsible for $2.3 

trillion of gross state product (18 

percent of the 2005 gross national 

product).83 Given the large number of 

military and other facilities in the MidAtlantic Critical Congestion Area that 

are extremely important to the national 

defense and homeland security, as well 

as the vital importance of this populous 

area to the Nation as an economic 

center, any deterioration of the electric 

reliability or economic health of this 

area would constitute a serious risk to 

the well-being of the Nation. Further 

one of the considerations identified in 

FPA section 216(a)(4) is whether ‘‘the 

designation would enhance national 

defense and homeland security.’’ FPA 

section 216(a)(4)(E); 16 U.S.C. 

824p(a)(4)(E). 

Therefore, the Department believes 

that national defense and homeland 

security considerations warrant 

designation of a National Corridor for 

the Mid-Atlantic Critical Congestion 

Area. 

D. Boundaries of the Draft Mid-Atlantic 

Area National Corridor 

In this section, the Department first 

explains how it determined the general 

extent of the draft Mid-Atlantic Area 

National Corridor using a source-andsink approach. Then the Department 

explains how it delineated specific 

boundaries for the draft Mid-Atlantic 

Area National Corridor. 

1. General Extent of the Draft MidAtlantic Area National Corridor 

In order to set the boundaries of the 

draft Mid-Atlantic Area National 

Corridor, DOE used the general sourceand-sink approach described in Section 

III above. The sink areas are the 

locations of the consumers adversely 

affected by the persistent congestion 

documented in Section VIII.B above. 

Specifically, the sink areas are the areas 

downstream of the constraints identified 

in Section VIII.B above, from 

metropolitan New York City south along 

the Atlantic coast to northern Virginia. 


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84See FPA sec. 216(a)(4)(A). 

85See FPA sec. 216(a)(4)(B). 

86See FPA sec. 216(a)(4)(C). 

87The existing, under-used economic generation 

capacity used to establish the source areas was 

identified through the analysis summarized in 

Appendix A (available at http://nietc.anl.gov). The 

potential wind generation capacity used to establish 

the source areas was identified through State-level 

maps of potential wind resources. Those maps are 

provided in Appendix B, which is available at 

http://nietc.anl.gov. 

With regard to selecting source areas, 

as discussed in Section III above, the 

Department was guided by the 

considerations identified in FPA section 

216(a)(4). In particular, the Department 

focused on the considerations of 

ensuring adequate supplies of 

reasonably priced power,84 diversifying 

supply,85 and furthering energy 

independence.86 Applying those 

considerations, DOE selected as source 

areas locations of substantial amounts of 

existing, under-used economic 

generation capacity, as well as locations 

with the potential for substantial 

development of wind generation 

capacity. The existing under-used 

economic generation capacity could 

readily ensure adequate supplies of 

reasonably priced power if additional 

transmission capacity were made 

available. In addition, increased access 

to this under-used economic generation 

capacity, which is predominantly coalfired, as well as to the wind generation 

capacity would help diversify supply 

and increase energy independence for 

the Mid-Atlantic Critical Congestion 

Area. Figure VIII–15 indicates the 

locations of the source areas in upstate 

New York, western New York, western 

Pennsylvania, western Maryland, West 

Virginia, Ohio, Indiana, and 

Kentucky.87


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Having identified the source and sink 

areas, DOE next sought to determine 

which transmission constraints most 

limit the delivery of electricity from the 

source areas to the sink areas. The 

results of this inquiry are shown in 

Figure VIII–16. 

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In the PJM footprint, the major 

obstacles to increased west-to-east flows 

are three groups of heavily loaded large 

high-voltage transmission lines. One 

group extends from northern West 

Virginia and western Maryland into 


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88Figures VIII–15 and -16 present results of 

additional analysis, using outputs from the 

simulation of 2008 generation and power flows 

prepared for the Congestion Study. For additional 

detail, see Appendix A (available at http:// 

nietc.anl.gov). 

89These constraints also happen to limit access 

to additional generation capacity located outside 

New York State, in Quebec, Ontario, and Michigan. 

90See Appendix A (available at http:// 

nietc.anl.gov) for additional detail. 

northern Virginia and central Maryland; 

a second group extends from western 

Pennsylvania into central Pennsylvania; 

and the third is a cluster of lines located 

mostly in eastern Pennsylvania but also 

extending into northeastern Maryland, 

northern Delaware, and northern New 

Jersey. The net effect of these 

constraints is to prevent the delivery of 

increased amounts of electricity in bulk 

from the source areas in the Midwest to 

the load centers in the BaltimoreWashington-Northern Virginia area, 

Philadelphia, Wilmington, the Delmarva 

peninsula, and the urban centers in 

central and northern New Jersey.88

Somewhat similarly, providers of 

electricity to consumers in the New 

York City area have limited access to the 

source areas in upstate New York and in 

the western part of the State, due to 

several clusters of transmission 

constraints within New York State.89

Conceivably, New York City’s needs 

might be satisfied to some degree 

through increased transmission access 

to PJM, but that could exacerbate the 

existing and projected congestion 

problems in the PJM footprint—unless it 

were done as part of some larger, wellcoordinated plan between PJM and 

NYISO and their respective members. 

The constraints of particular interest in 

New York State are: a group between 

New York City and the existing 

substations at Marcy and Edic (near the 

city of Utica); a group to the south and 

east of the city of Massena; and a group 

in the western part of the State, between 

the cities of Buffalo and Syracuse.90

Thus, within PJM’s footprint, the draft 

National Corridor encompasses the 

problematic existing west-to-east 

transmission lines; further, the draft 

National Corridor is broad enough, 

north-to-south, to encompass a range of 

potential projects and a range of 

potential routes to facilitate additional 

west-to-east flows. In addition, the draft 

National Corridor includes the sink 

areas as well, because it is frequently 

the case that the full potential benefits 

associated with a major new line will 

not be gained unless key improvements 

are made in the area to which the 

electricity is to be delivered. Somewhat 

similarly, the draft National Corridor 

extends far enough into the source areas 

to encompass a number of possible 

strong points on the transmission 

network that serves those areas. 

In New York, the draft National 

Corridor extends northward from the 

area immediately north of New York 

City to the vicinity of Utica; then it 

divides into two legs, one to the 

Massena area and one to the Buffalo 

area. As with the section in the PJM 

footprint, this section of the draft 

National Corridor is broad enough to 

encompass a range of potential projects 

and a range of potential routes, and it 

includes the sink areas as well to 

encompass appropriate upgrades there. 

Further, as shown in Figure VIII–17, 

there are several important transmission 

constraints between New York City and 

Long Island. As a result, no solutions to 

New York City’s congestion problems 

should be planned without considering 

Long Island, and thus the draft National 

Corridor includes Long Island. 


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Finally, although for ease of 

presentation the discussion thus far has 

focused on a draft National Corridor in 

the PJM footprint and a draft National 

Corridor in New York, the two areas are 

contiguous along a part of the shared 

border between the PJM and NYISO 

footprints. Accordingly, the draft 

National Corridor for the Mid-Atlantic 

Critical Congestion Area is a single 

Corridor—the draft Mid-Atlantic Area 

National Corridor—covering part of the 


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PJM footprint and part of New York, 

partly because some of the transmission 

planning that is needed should involve 

both PJM and NYISO, and also because 

transmission projects may be proposed 

that would cross their common 

boundary. 

2. Specific Boundaries of the Draft MidAtlantic Area National Corridor 

Having identified the sink and source 

areas on which to base the draft MidAtlantic Area National Corridor, as well 

as the constraints that must be 

encompassed in the National Corridor, 

DOE then delineated the specific 

boundaries of the draft Mid-Atlantic 

Area National Corridor. Again, for ease 

of presentation, the Department will 

discuss the draft Mid-Atlantic Area 

National Corridor in terms of a section 

within the PJM footprint and a section 

in New York; however, the Department 

notes that it is a single draft MidAtlantic Area National Corridor that is 

under consideration. 

For the section within the PJM 

footprint, DOE first identified some 

general boundary points, and then 

linked certain of these points by means 

of straight lines to form a polygon. It 

would be impractical, however, to treat 

the polygon as this section of the draft 

Mid-Atlantic Area National Corridor, 

because that would not enable precise, 

easily identified boundaries in all areas. 

Accordingly, if the polygon includes 

some part of a county (or a city not 

included within a county), the 

Department has included all of that 

county or city in the draft National 

Corridor. This approach enlarges the 

draft Mid-Atlantic Area National 

Corridor but, in addition to establishing 

readily identifiable boundaries, helps 

ensure that the draft National Corridor 

encompasses a range of potential 

projects and a range of potential routes, 

as discussed in Section III above. 

The western margin of the section of 

the polygon within the PJM footprint, in 

functional terms, is the eastern edge of 

the existing 765 kV transmission 

network in the Midwest, beginning with 

the South Canton substation, located 

near Canton, Ohio, continuing on to 

other substations to the south located on 

one side or the other of the Ohio River 

(which forms the boundary between 

Ohio and West Virginia), and ending 

with the John Amos substation near 

Charleston, West Virginia. Tapping into 

this network with new west-to-east 

transmission lines would enable access 

to generation capacity throughout the 

source areas. 

The eastern margin of the section of 

the polygon within the PJM footprint is 

a straight line from the Calvert Cliffs 

substation in southern Maryland due 

east to the Atlantic shoreline, and then 

generally northward following the 

Atlantic shoreline and then up the 

Hudson River to the northeastern corner 

of New Jersey. The area around the 

Calvert Cliffs substation is of interest 

because if additional nuclear generating 

capacity is developed at the Calvert 

Cliffs nuclear plant or at nearby Virginia 

plants, additional transmission capacity 

would be needed to enable the 

electricity output to be moved from the 

Calvert Cliffs substation (or other 

relevant substations within the polygon) 

to the load centers in the sink area. If 

the nuclear capacity is not developed, 

the sink area could still benefit from 

development of additional west-to-east 

transmission capacity across the PJM 

footprint. 

The Department has extended the 

draft National Corridor to the actual 

shoreline not because major new 

transmission lines are likely to be sited 

in such areas, but rather because these 

areas are sink areas, and transmission 

upgrades in some locations within these 

areas may be needed to gain the full 

benefit of improving their access to the 

source areas. 

The southern margin of the section of 

the polygon within the PJM footprint is 

a straight line between the John Amos 

substation and the Calvert Cliffs 

substation. 

The northern margin of the section of 

the polygon within the PJM footprint is: 

a straight line between the South Canton 

substation and the Susquehanna 

substation (which is the northernmost 

500 kV substation in eastern PJM); a 

straight line from the Susquehanna 

substation due north to the 

Pennsylvania-New York border; the 

Pennsylvania-New York border east and 

southeast to the border between 

Pennsylvania and New Jersey; and then 

the border between New York and New 

Jersey southeast to the northeast corner 

of New Jersey. 

Connecting the points described 

above produces the polygon shown in 

Figure VIII–18. Defining the draft 

National Corridor boundaries as 

including all of the partially enclosed 

cities or counties, as shown in Figure 

VIII–19, establishes the portion of the 

draft Mid-Atlantic Area National 

Corridor within the PJM footprint. 


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For the section of the draft MidAtlantic Area National Corridor within New York, DOE has adopted a 

somewhat simpler approach based more 

directly on county boundaries. DOE has 

identified four areas within New York 


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for inclusion in the draft Mid-Atlantic 

Area National Corridor. 

The first area is New York City and 

Long Island. This area is included 

because it is a sink area. 

Second is a central upstate area, 

extending from New York City 

northward to include an area around the 

city of Saratoga Springs, and westward 

to include an area around the city of 

Utica. This central upstate area 

encompasses a number of the existing 

constraints that limit the delivery of 

additional electricity in bulk from the 

source areas to the sink areas. Although 

easing the constraints in this area could 

provide benefits in the sink areas, these 

benefits could be limited unless some of 

the key constraints further to the north 

and to the west were also addressed. 

Therefore, the Department has included 

the following two additional areas in the 

draft National Corridor. 

The draft National Corridor includes 

an area to the south and east of the city 

of Massena, New York. This area 

encompasses several transmission 

constraints that may frequently prevent 

electricity flows from the source areas to 

the sink areas. 

Finally, the draft National Corridor 

includes an area between the city of 

Buffalo and the city of Syracuse. This 

area is a major electricity pathway that 

is frequently constrained, preventing 

electricity flows from the source areas to 

the sink areas. 

The resulting New York section of the 

draft Mid-Atlantic Area National 

Corridor, based on the boundaries of the 

affected counties, is shown in Figure 

VIII–20. The entire draft Mid-Atlantic 

Area National Corridor is shown in 

Figure VIII–21. 

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91CAISO is the ISO serving most of California. 

92See DOE response, Section II.A above. 

93See DOE response, Section III above. 

The list of the counties and cities that 

comprise the draft Mid-Atlantic Area 

National Corridor is as follows: 

Delaware 

Counties: All are included—Kent, 

New Castle, and Sussex. 

District of Columbia 

City: Washington. 

Maryland 

Counties: All are included except 

Somerset. Those included are Allegany, 

Anne Arundel, Baltimore, Calvert, 

Caroline, Carroll, Cecil, Charles, 

Dorchester, Frederick, Garrett, Harford, 

Howard, Kent, Montgomery, Prince 

George’s, Queen Anne’s, St. Mary’s, 

Talbot, Washington, Wicomico, and 

Worcester. 

City: Baltimore. 

New Jersey 

Counties: All are included—Atlantic, 

Bergen, Burlington, Camden, Cape May, 

Cumberland, Essex, Gloucester, Hudson, 

Hunterdon, Mercer, Middlesex, 

Monmouth, Morris, Ocean, Passaic, 

Salem, Somerset, Sussex, Union, and 

Warren. 

New York 

Counties: Albany, Bronx, Broome, 

Cayuga, Chenango, Clinton, Columbia, 

Delaware, Dutchess, Erie, Franklin, 

Fulton, Genesee, Greene, Herkimer, 

Jefferson, Kings, Lewis, Livingston, 

Madison, Monroe, Montgomery, Nassau, 

New York, Niagara, Oneida, Onondaga, 

Ontario, Orange, Orleans, Otsego, 

Putnam, Queens, Renssalaer, Richmond, 

Rockland, St. Lawrence, Saratoga, 

Schenectady, Schoharie, Seneca, Suffolk 

Sullivan, Ulster, Wayne, Westchester, 

and Wyoming. 

Ohio 

Counties: Belmont, Carroll, 

Columbiana, Harrison, Jefferson, and 

Stark. 

Pennsylvania 

Counties: Adams, Allegheny, 

Armstrong, Beaver, Bedford, Berks, 

Blair, Bradford, Bucks, Butler, Cambria, 

Centre, Chester, Clearfield, Clinton, 

Columbia, Dauphin, Delaware, Fayette, 

Franklin, Fulton, Greene, Huntingdon, 

Indiana, Jefferson, Juniata, Lackawanna, 

Lancaster, Lebanon, Lehigh, Luzerne, 

Mifflin, Monroe, Montgomery, Montour, 

Northampton, Northumberland, Perry, 

Philadelphia, Pike, Schuylkill, Snyder, 

Somerset, Susquehanna, Union, Wayne, 

Washington, Westmoreland, Wyoming, 

and York. 

Virginia 

Counties: Arlington, Clarke, Culpeper, 

Fairfax, Fauquier, Frederick, Loudon, 

Madison, Page, Prince William, 

Rappahannock, Rockingham, 

Shenandoah, Stafford and Warren. 

Cities: Alexandria, Harrisonburg, 

Fairfax, Falls Church, Manassas, 

Manassas Park, and Winchester. 

West Virginia 

Counties: Barbour, Berkeley, Braxton, 

Brooke, Calhoun, Clay, Doddridge, 

Gilmer, Grant, Hampshire, Hancock, 

Hardy, Harrison, Jackson, Jefferson, 

Lewis, Marion, Marshall, Mineral, 

Monongalia, Morgan, Nicholas, Ohio, 

Pendleton, Pleasants, Pocahontas, 

Preston, Randolph, Ritchie, Roane, 

Taylor, Tucker, Tyler, Upshur, Webster, 

Wetzel, Wirt, and Wood. 

IX. Draft Southwest Area National 

Corridor 

A. Alternatives and Recommendations 

In response to the Congestion Study, 

the Department received a number of 

National Corridor alternatives and 

recommendations for the Southern 

California Critical Congestion Area. 

SCE recommended a National 

Corridor to encompass the general 

anticipated route of a transmission line 

it is proposing to build between the Palo 

Verde hub in Arizona and Palm Springs, 

California (Devers-Palo Verde 2 or 

DPV2). EEI supported SCE’s 

recommended National Corridor, citing 

the need to remedy the existing and 

growing congestion problems in the 

Southern California Critical Congestion 

Area as well as the need for utilities in 

the State to meet renewable energy 

requirements. 

San Diego Gas and Electric Company 

(SDG&E) recommended a National 

Corridor to encompass the general 

anticipated route of a transmission line 

it is proposing to build through Imperial 

County, California to San Diego, 

California (Sunrise Powerlink). 

The Nevada Hydro Company, Inc. 

(Nevada Hydro) recommended a 

National Corridor to encompass the 

general anticipated route of a 

transmission line associated with its 

proposed Lake Elsinore Advanced 

Pumped Storage project (LEAPS) in 

southern California. 

Los Angeles Department of Water and 

Power (LADWP) noted that the 

Congestion Study had not mentioned 

LADWP’s proposed Green Path North 

project (Green Path), which it regards as 

very important to relieving congestion, 

maintaining reliability in the area west 

of Devers, and diversifying generation 

sources by increasing access to 2000 

MW of potential geothermal power in 

the Imperial Valley region. LADWP 

stated, ‘‘DOE may wish to consider the 

Green Path North project as a [National 

Corridor].’’

The California Independent System 

Operator (CAISO) 91 recommended 

designation of a National Corridor in 

southern California, citing the current 

congestion problem in that area as well 

as the increased congestion expected as 

a result of high load growth and the 

potential development of significant 

wind generation in the Tehachapi area. 

CAISO stated that the boundaries of a 

National Corridor in southern California 

depend on the success of current 

planned transmission projects. Thus, 

according to CAISO, if either DVP2 or 

Sunrise Powerlink were to fail to 

materialize, there would be a critical 

need for another transmission link to 

one of the major substations in the 

southern part of the Southwest region 

and/or the Imperial Valley area. CAISO 

also recommended consideration of a 

National Corridor that would connect 

the broader Tehachapi area to the Los 

Angeles Basin. 

CEC agreed with the classification of 

southern California as a Critical 

Congestion Area and noted that ‘‘the 

San Diego region’s transmission 

problems are acute and graphically 

illustrate the importance of adequate 

transmission.’’ CEC commented that 

‘‘California interests could be served by 

the Federal [National Corridor] planning 

and permitting processes under certain 

limited conditions, given the State’s 

history of impediments in developing 

needed transmission capacity.’’

However, CEC stated that the focus of 

the Congestion Study was too narrow to 

accommodate State laws and policies on 

renewable portfolio standards.92 CEC 

further commented that because the 

Department has not discussed how it 

intends to address environmental 

assessments in the National Corridor 

designation process, it remains 

concerned whether DOE will designate 

a National Corridor in a manner that 

adequately considers California’s 

environmental resources, legislation 

concerning State designation of electric 

transmission corridors, and use of 

existing rights of way.93

IID acknowledged that the Congestion 

Study correctly identified the presence 

of congestion on the intertie between 

IID’s control area and SCE’s control area 

(Path 42). However, IID noted that it has 

already identified two feasible solutions 

to mitigate congestion on Path 42, and 


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94Since submission of its comments on the 

Congestion Study, CPUC issued a decision that 

created a rebuttable presumption in favor of certain 

economic evaluations by the CAISO. See Opinion 

on Methodology for Economic Assessment of 

Transmission Projects, CPUC D.06–11–018 (Nov. 9, 

2006). 95Since submission of its comments on the 

Congestion Study, CPUC approved construction of 

the portion of DPV2 within California. See Opinion 

Granting a Certificate of Public Convenience and 

Necessity, CPUC D.07–01–040 (Jan. 25, 2007). The 

Arizona Commission has not yet ruled on SCE’s 

application for the portion of the project that would 

be located in Arizona. 

96Since submission of its comments on the 

Congestion Study, CPUC approved construction of 

Antelope Segments 1, 2 and 3. See Opinion 

Granting a Certificate of Public Convenience and 

Necessity, CPUC D.07–03–012 (Mar. 1, 2007); and 

Opinion Granting a Certificate of Public 

Convenience and Necessity, CPUC D.07–03–045 

(Mar. 15, 2007). In its comments on the Congestion 

Study, CPUC also notes the progress of two other 

projects, which are not subject to its jurisdiction, 

that would alleviate congestion in southern 

California: The Desert Southwest Project sponsored 

by a number of municipal utilities and LEAPS 

pending at FERC. 97See DOE response, Section II.D above. 98See DOE response, Section VII.C above. CPUC 

also argued that instead of designating National 

Corridors in California, the Department should 

make certain designations of energy corridors on 

Federal land under EPAct section 368. The 

Department will address these comments in the 

ongoing section 368 proceeding. 99ACC commented on the Phoenix-Tucson 

Congestion Area of Concern identified in the 

Congestion Study as well as the Tucson to Nogales 

corridor, but did not comment on the Southern 

California Critical Congestion Area. ACC also 

emphasized the need for the Department to consult 

with it prior to designating any National Corridors 

in Arizona. See DOE response, Section IV.B above. 

100WECC is responsible for coordinating and 

promoting electric system reliability in all or part 

of the 14 western States and British Columbia, 

Canada. To facilitate analysis of grid operations, 

WECC and its members have defined and numbered 

a total of 67 major transmission paths in the 

Western Interconnection. A ‘‘path’’ frequently 

consists of several related transmission elements 

from one important area of the grid to another, as 

opposed to a single transmission line. 

is working on a 500 kV transmission 

project that would connect with 

SDG&E’s Sunrise Powerlink to alleviate 

congestion elsewhere in southern 

California. IID believed that in light of 

these projects, as well as other efforts 

underway, it may not be necessary to 

designate a National Corridor in 

southern California at this time. 

CPUC recommended against any 

National Corridor designations in 

southern California at this time. Noting 

that skepticism about California’s siting 

of infrastructure may have contributed 

to the identification of southern 

California as a Critical Congestion Area, 

CPUC argued that California 

stakeholders, including CPUC, CAISO, 

CEC, and the transmission owners, have 

worked closely together to achieve 

significant progress in transmission 

expansion, completing $1.8 billion 

worth of transmission projects between 

2000 and 2004. CPUC noted that it 

would soon be considering the adoption 

of a proposed decision that would grant 

a rebuttable presumption in a CPUC 

siting proceeding to a CAISO 

determination that a proposed project is 

needed.94

CPUC further asserted that specific 

progress is being made in southern 

California: DPV2 is in the final stages of 

permitting; 95 a final permitting decision 

on Sunrise Powerlink is expected the 

fourth quarter of 2007 or early in the 

first quarter of 2008; and the permitting 

processes for three segments of a 

transmission project related to wind 

development in the Tehachapi region 

(Antelope Segments 1, 2, and 3) are 

close to completion.96 CPUC stated that 

National Corridor designation is 

unwarranted unless there is evidence 

that State and regional processes are not 

addressing the problem in a timely 

manner.97 CPUC also argued that the 

Congestion Study exaggerated the 

significance of congestion into southern 

California.98

After reviewing the alternatives and 

recommendations provided,99 the 

Department believes that designation of 

a National Corridor for the Southern 

California Critical Congestion Area may 

be warranted. In the following sections, 

the Department will detail its factual 

finding of the existence of constraints or 

congestion that adversely affects 

consumers in the Southern California 

Critical Congestion Area and explain the 

considerations that it believes warrant 

designation of a National Corridor for 

this area. Finally, the Department will 

delineate and explain the specific 

boundaries of the draft National 

Corridor. 

B. Finding of Constraints or Congestion 

That Adversely Affects Consumers 

The Congestion Study identified 

southern California as a Critical 

Congestion Area, based on evidence of 

historical, persistent congestion caused 

by numerous well-known transmission 

constraints into and within southern 

California. The congestion caused by 

these constraints is projected to 

continue or worsen unless it is 

addressed through remedial actions. In 

conducting the Congestion Study, the 

Department identified and assessed 

these constraints based on a review of 

the extant transmission studies and 

expansion plans available prior to the 

publication of the Congestion Study. 

DOE has assessed these constraints at 

two levels. In the Congestion Study, 

DOE assessed congestion at the WECC 

Path 100 level. (See Figures IX–1, –2, and 

–3, which are taken from the Congestion 

Study.) More recently, DOE has 

reviewed congestion data provided by 

the Western Area Power Administration 

(WAPA), and branch group congestion 

data reported by CAISO. ‘‘Branch 

groups,’’ as defined by CAISO, consist 

of major groups of lines between CAISO 

and other areas, plus two large internal 

paths, WECC Path 15 and WECC Path 

26. (See Figure IX–4). 

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The historical review performed for 

the Congestion Study confirmed the 

presence of congestion in years 1999 

through 2005 on Path 26 (Northern—

Southern California), Path 45 (San Diego 

County—Baja California Norte), Path 46 


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101Unlike PJM’s and NYISO’s LMP day-ahead 

and hour-ahead markets, energy is not traded in 

CAISO’s day-ahead and hour-ahead markets. 

Instead, market participants submit desired 

transmission schedules along with bids for 

adjusting those schedules. Transactions scheduled 

over congested inter-zonal interfaces are assessed a 

congestion charge based on these adjustment bids. 

The day-ahead and hour-ahead markets do not 

account for intra-zonal congestion, which CAISO 

must manage during real-time operations. 

(West of the Colorado River), Path 49 

(East of the Colorado River), and Path 65 

(Pacific DC Inter-tie). Path 65 exceeded 

75 percent of its flow limit 32 percent 

of the time and Paths 26, 45, and 49 

exceeded 75 percent of their flow limits 

between 15 to18 percent of the time. 

The modeling performed for the 

Congestion Study projected that several 

of these constraints will continue to 

cause congestion in 2008. These include 

Paths 42, 45, 49, and 65. Of these, Path 

42 IID-SCE (near Riverside, California) 

had a projected U75 of 84 percent and 

a projected U90 of 65 percent. 

CAISO data document the presence of 

congestion on paths going into southern 

California. The CAISO footprint is 

divided into three zones. Based on the 

branch groups, CAISO manages 

congestion into and out of these zones 

through operation of a day-ahead and an 

hour-ahead market.101 At the CAISO 

branch group level, constraints were 

binding and thus produced congestion 

in both markets in calendar years 2004, 

2005, and 2006. (See Table IX–1.) 

In the day-ahead market, the 

Adelanto, Blythe, Eldorado, Mead, and 

Palo Verde branch groups had the most 

binding hours of all the CAISO branch 

groups. The Palo Verde and Mead 

branch groups were the most congested 

in 2006 with binding hours of 15 and 13 

percent respectively. Congestion on Palo 

Verde, in terms of binding hours, 

diminished somewhat in 2006 as 

compared to 2004 and 2005, but the 

congestion prices increased. On Mead, 

both binding hours and congestion 

prices were higher in 2006 than in 2004 

and 2005. On Path 26, the congestion 

price diminished after its capacity limit 

was raised in late June 2005, but the 

number of binding hours increased. As 

shown in Table IX–1, these same branch 

groups are also congested in CAISO’s 

hour-ahead market. The aggregate 

annual congestion revenues for several 

of these branch groups are shown in 

Table IX–2, and range from $122,000 to 

$17 million in 2006. 


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102RMR units are generally local generators that 

would otherwise not be commercially viable, but 

are needed because transmission constraints 

prevent the use of other generating units. RMR units 

generally operate subject to cost-of-service contracts 

that ensure they will remain in business, available 

to operate when needed. 

103See CAISO, 2006 Annual Report on Market 

Issues and Performance, p. 6–4, 6–5 (April 2006) 

(‘‘Total estimated intra-zonal congestion costs for 

2004, 2005, and 2006 were $426 million, $222 

million, and $207 million, respectively. These costs 

have been declining over the period due to 

installation of appropriately located new generation 

and transmission upgrades.’’). 

104CAISO, 2005 Annual Report on Market Issues 

and Performance, p. 6–2 (April 2006); see also 

CAISO, 2004 Annual Report on Market Issues and 

Performance, p. 6–13 (April 2005) (CAISO 2004 

Annual Report) (in 2004, ‘‘the bulk of OOS 

dispatches of incremental energy (96 percent) are 

for locational constraints within the CAISO’s 

southern zone (SP15)’’). 

CAISO data also demonstrate the 

existence of congestion on paths within 

southern California. When congestion 

arises in real time within one of the 

three CAISO zones, CAISO must engage 

in redispatch. CAISO draws from three 

sources for this redispatch: Reliabilitymust-run (RMR) units; 102 long-start 

thermal units lined up day-ahead in 

return for minimum load cost 

compensation (MLCC); and other 

generators whose bids are accepted out 

of sequence (OOS). The Department 

recognizes that the magnitude of RMR, 

MLCC, and OOS costs is, in part, a 

function of CAISO’s market design, and 

that CAISO is in the process of replacing 

its zonal congestion management system 

with an LMP congestion management 

system. Nevertheless, RMR, MLCC, and 

OOS costs are indicators of the presence 

and persistence of intra-zonal 

congestion. RMR, MLCC, and OOS costs 

were incurred in 2004, 2005, and 

2006.103 CAISO states further that 

‘‘[m]ost of the major points of intrazonal congestion in 2005 were located 

in the CAISO’s southern congestion 

zone (SP15).’’ 104

Data from WAPA also demonstrate 

that routes into SP15 via the Blythe, 

Gene, Marketplace, and Mead 

substations are frequently congested, as 

indicated by numerous denials of 

requests to reserve capacity for transfers 

of power into SP15. (See Table IX–3). 

Thus, the Department has 

documented the existence of persistent 

congestion into and within the Southern 

California Critical Congestion Area, as 

well as the constraints causing that 

persistent congestion. As discussed in 

Section II.A above, whenever there is 

persistent congestion, buyers must rely 

on power from less-preferred generating 

sources, a smaller range of generators is 

able to serve load, and grid operators 

have fewer options for dealing with 

adverse circumstances or unanticipated 

events, all of which adversely affects 

consumers. Therefore, the Department 

finds under FPA section 216(a)(2) that 

there are ‘‘constraints or congestion that 

adversely affects consumers’’ in the 

Southern California Critical Congestion 

Area. 

C. Determination That Designation of a 

Southwest Area National Corridor Is 

Warranted 

Given the presence of constraints or 

congestion that adversely affects 

consumers in the Southern California 

Critical Congestion Area, the Secretary 

has the discretion to consider 

designation of a National Corridor. As 


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105CAISO, 2007 Summer Loads and Resources 

Operations Assessment, p. 3 (March 7, 2007). 

106CAISO, 2007 Transmission Plan, Table 2–4, 

item 7; Table 2–5, item 8; and Table 2–6, items 1 

and 3 (Jan. 2007). 

107CEC, A Survey of the Implications to 

California of the August 10, 1996 Western States 

Power Outage, p. 43 (June 1997). 

discussed above in Section II.A, the 

Secretary will determine whether to 

exercise his discretion based on the 

totality of the information developed, 

taking into account relevant 

considerations, including the 

considerations identified in FPA section 

216(a)(4), as appropriate. In this section, 

the Department discusses the 

considerations that it believes warrant 

designation of the Southwest Area 

National Corridor. 

1. Reliability Considerations 

In recent years, southern California’s 

electricity supply capability, combined 

with what supplies can be imported 

from external sources, has been barely 

enough to meet peak electricity demand. 

In the summer of 2005, CAISO declared 

two Stage 2 Emergencies in southern 

California (July 21 and 22) and a 

transmission emergency occurred on 

August 25 that resulted in the 

curtailment of 900 MW of firm load. In 

the summer of 2006, rolling blackouts 

were avoided during a period of 

extremely hot weather only through a 

combination of good fortune, 

extraordinary efforts by the utilities, 

CAISO, and the Bonneville Power 

Administration, and timely cooperation 

by electricity consumers to reduce 

electricity demand. 

In its comments to DOE, CAISO noted 

that load in southern California has 

been growing at a rate of approximately 

1.5 percent annually, which translates 

into a total of approximately 657 MW of 

new load that needs to be served each 

year. CAISO notes that this rate of load 

growth, combined with the threat of 

extreme weather conditions, such as a 

1-in-10-year heat wave, could mean that 

by 2015, the loss of a single critical 

transmission path could necessitate the 

curtailment of approximately 1,500 MW 

of load. CAISO notes that the San Diego 

area is projected to be deficient in 

overall generation capacity by the year 

2010 due to severe import limits. CAISO 

also notes looming reliability problems 

on the South of Lugo path, a major 

CAISO internal path that serves the Los 

Angeles Basin. CAISO states that in the 

event of a double-line contingency on 

that path at peak load, anywhere from 

500 to 1,000 MW of load would need to 

be curtailed. 

Since submission of its comments on 

the Congestion Study, CAISO has 

published additional analyses that 

identify potential reliability problems in 

southern California. In its assessment 

for the summer of 2007, CAISO 

concludes that there is a 23 percent 

chance of entering into a Stage 1 

emergency in the area south of Path 26 

(SP26), and a 12 percent chance of 

entering into a Stage 2 emergency.105

Further, according to CAISO’s 2007 

Transmission Plan, a number of 

transmission enhancements are needed 

in the Devers area to mitigate existing or 

projected reliability violations.106

Similarly, LADWP stated in its 

comments to the Department that ‘‘Zone 

SP26 is a large load center that is 

currently experiencing reliability 

problems because of transmission 

constraints. * * * Zone SP26 will likely 

continue its dependence on imports, so 

transmission improvements are needed 

to avoid future violations of reliability 

standards. * * *’’

In its comments to DOE, SDG&E 

described the San Diego area’s situation 

as follows: 

The San Diego region has only two points 

of interconnection to the interstate electric 

transmission grid: A 500 kV line at SDG&E’s 

Miguel substation that delivers power from 

the east, and a series of 230 kV lines 

connecting at the San Onofre Nuclear 

Generating Station (‘‘SONGS’’) switchyard to 

the north. Taken together, these two paths are 

capable of serving only a portion of the peakload requirements of the SDG&E local 

reliability area. Neither of these paths is 

capable of serving the full peak-load 

requirements of the SDG&E local reliability 

area if the other is out of service. In fact, 

these two paths are barely sufficient to serve 

the average load of the region. As a result of 

growing loads in southern California, 

coupled with the addition of new generation 

in the desert southwest, the import capability 

into the San Diego area is often fully utilized. 

To put the San Diego constraints in 

perspective, there are more than forty-five 

500 kV transmission lines in the state of 

California. The two major utilities serving the 

Los Angeles area have more than thirty 500 

kV AC transmission lines as well as two 

+/¥500 kV DC lines. Phoenix, America’s 

sixth largest city, has eight 500 kV 

transmission lines and six 345 kV 

transmission lines. By comparison, among 

the large electric service areas in the State 

and the west, San Diego is extremely underserved in terms of high voltage access to the 

rest of the grid. [footnotes omitted] 

The data detailed above indicate that 

consumers in the Southern California 

Critical Congestion Area face threats to 

reliability if existing congestion 

problems are not addressed. Reliable 

electricity supplies are vital to the 

economic and social well-being of any 

metropolitan area. Electricity supply 

disruptions may come in many forms, 

ranging from brief disturbances in 

power quality and localized outages to 

large-scale, cascading blackouts. The 

exact cost of electric supply disruptions 

is difficult to quantify and varies 

depending upon the specific 

circumstances. However, such 

disruptions can impose enormous costs 

on consumers and may also, under 

certain circumstances, pose dangers to 

public health and safety. 

For example, on Saturday, August 10, 

1996, a blackout affected several 

western States, including much of 

California, for several hours. CEC 

conducted a survey to gauge the effects 

and implications of the blackout. The 

outage affected slightly less than half of 

California’s residential electricity 

customers, 20 percent of the commercial 

customers, and 25 percent of the 

industrial customers. Forty-one percent 

of the commercial respondents and 31 

percent of the industrial respondents 

said that the outage was ‘‘very 

disruptive’’ to their operations. The 

losses reported ranged from $40 to $5 

million.107

Another California analysis provides 

further insights: 

Blackouts impose a wide range of costs on 

the economy, but these costs are incredibly 

difficult to quantify. The primary costs are 

direct and roughly proportional to the 

duration of the outage and the amount of 

undelivered power, including lost 

production and idled labor. Frequently, 

however, actual losses are much greater than 

this. For example, when production systems 

are shut down, it can take hours or days to 

restart them and return to full productivity. 

Often, information technology equipment 

and even basic manufacturing equipment is 

damaged when power is suddenly lost; and 

industries dependent on climate control 

(from bioscience labs to supermarkets) are 

threatened with damaged research or spoiled 

goods. Finally, power interruptions 

frequently result in lost data, which can be 

costly and sometimes impossible to 

reproduce. 

Loss of power can also impose longer-term 

costs by damaging external relationships and 

customer interactions. For example, a power 

interruption for an internet-based business 

can compromise security and harm its 

reputation, leading to lower sales in the 

future * * *. For a brick-and-mortar 

business, inadequate lighting and lack of 

power to security systems increase the 

potential likelihood of vandalism and theft. 

Loss of climate control and 

telecommunications capabilities makes it 

especially difficult for restaurants and retail 

establishments to attract and retain 

customers. However, all of these factors still 

only point to direct costs. Indirect costs 

multiply the impact several times over as the 

effects of a power interruption ripple through 

the economy; for example, lost sales by a 


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25918 Federal Register / Vol. 72, No. 87 / Monday, May 7, 2007 / Notices 

108Bay Area Economic Forum, The Bay Area— A 

Knowledge Economy Needs Power, pp. 25–26 

(April 2001). 

109CEC Report, Net System Power: A Small Share 

of California’s Power Mix in 2005, Pub. No. CEC–

300–2006–009–F, p. 4 (April 2006). 

110CEC Staff Report, Natural Gas Assessment 

Update: Executive Summary, Pub. No. CEC–600–

2005–003, p. iv (Feb. 2005). 

111U.S. Census Bureau, State & County 

QuickFacts, http://quickfacts.census.gov/qfd/states/ 

00000.html and http://quickfacts.census.gov/qfd/ 

states/06/06073.html. 

112See Northwest Midwest Institute, Total Gross 

State Product by State, 2001–2005, http:// 

www.nemw.org/gsp.htm. Total gross state product 

attributable to southern California in 2005 was 

estimated by prorating the State total for 2005 

according to the estimated 2005 population in 

seven California counties: Imperial, Kern, Los 

Angeles, Orange, Riverside, San Bernardino, and 

San Diego. 

113See FPA sec. 216(a)(4)(A). 

114See FPA sec. 216(a)(4)(B). 

115The potential wind, geothermal, and solar 

generation capacity used to establish the source 

areas was identified through State-level maps of 

potential wind, geothermal, and solar resources. 

Those maps are provided in Appendix B, which is 

available at http://nietc.anl.gov. 

retailer can lead to reduced orders to 

suppliers, and so forth.108

Further, one of the considerations 

identified in FPA section 216(a)(4) is 

whether ‘‘the economic vitality and 

development of the corridor, or the end 

markets served by the corridor, may be 

constrained by lack of adequate or 

reasonably priced electricity.’’ FPA 

section 216(a)(4)(A); 16 U.S.C. 

824p(a)(4)(A) (emphasis added). 

Therefore, the Department believes 

that reliability considerations warrant 

designation of a National Corridor for 

the Southern California Critical 

Congestion Area. 

2. Supply Diversity Considerations 

Much of the existing generation fleet 

on which southern California relies is 

fueled by natural gas. During 2005, 

about 38 percent of the electricity 

generated within California was 

produced from units fueled by natural 

gas, as compared with 20 percent from 

coal, 17 percent from large hydro, and 

14 percent from nuclear.109 California’s 

total annual consumption of natural gas, 

approximately 2.2 trillion cubic feet, 

would make this State the tenth largest 

natural-gas consuming ‘‘country’’ in the 

world. The State’s industrial and 

electricity-generation sectors consume 

the most natural gas, approximately 66 

percent of the total amount. Natural gas 

used for electricity generation is the 

largest contributor to the State’s growing 

demand rate, one percent per year.110

One of the consequences of congestion 

in southern California is that it prolongs 

and exacerbates the area’s dependence 

on natural gas. 

Natural gas is relatively high in price 

and must be purchased in markets that 

are highly volatile and subject to 

unanticipated international trends and 

adverse events. Inadequate transmission 

capacity leaves consumers in the 

Southern California Critical Congestion 

Area exposed, perhaps increasingly, to 

the higher prices and higher price 

volatility associated with this generation 

fuel, with a resulting impact on business 

certainty, especially for industrial 

consumers. Thus, economic growth may 

be jeopardized. 

Moreover, the Department takes note 

that CPUC has adopted an interim 

Emissions Performance Standard, which 

is a facility-based emissions standard 

requiring that all new long-term 

commitments for base-load generation 

to serve California consumers be with 

power plants that have emissions no 

greater than a combined cycle gas 

turbine plant. In addition, the State of 

California has established standards 

requiring load-serving entities to meet 

20 percent of their electricity needs 

through renewable-based generation 

capacity (wind, geothermal, and solar) 

by 2010, and 33 percent by 2020. In 

order to meet these goals and to provide 

for steady economic growth, consumers 

in the Southern California Critical 

Congestion Area will need additional 

transmission access to a range of sources 

of supply, particularly renewable 

energy. 

Further, one of the considerations 

identified in FPA section 216(a)(4) is 

whether ‘‘(i) economic growth in the 

corridor, or the end markets served by 

the corridor, may be jeopardized by 

reliance on limited sources of energy; 

and (ii) a diversification of supply is 

warranted.’’ FPA section 216(a)(4)(B); 16 

U.S.C. 824p(a)(4)(B). 

Therefore, the Department believes 

that supply diversity considerations 

warrant designation of a National 

Corridor for the Southern California 

Critical Congestion Area. 

3. National Defense and Homeland 

Security Considerations 

The Southern California Critical 

Congestion Area is home to 20.7 million 

people (7.0 percent of the Nation’s 2005 

population) 111 and produces about $950 

billion of gross state product (7.7 

percent of the 2005 gross national 

product).112 Given the large number of 

military and other facilities in the 

Southern California Critical Congestion 

Area that are extremely important to the 

national defense and homeland security, 

as well as the vital importance of this 

populous area to the Nation as an 

economic center, any deterioration of 

the electric reliability or economic 

health of this area would constitute a 

serious risk to the well-being of the 

Nation. Further one of the consideration 

identified in FPA section 216(a)(4) is 

whether ‘‘the designation would 

enhance national defense and homeland 

security.’’ FPA section 216(a)(4)(E); 16 

U.S.C. 824p(a)(4)(E). 

Therefore, the Department believes 

that national defense and homeland 

security considerations warrant 

designation of a National Corridor for 

the Southern California Critical 

Congestion Area. 

D. Boundaries of the Draft Southwest 

Area National Corridor 

In this section, the Department first 

explains how it determined the general 

extent of the draft Southwest Area 

National Corridor using a source-andsink approach. Then, the Department 

explains how it delineated specific 

boundaries for the draft Southwest Area 

National Corridor. 

1. General Extent of the Draft Southwest 

Area National Corridor 

In order to set the boundaries of the 

draft Southwest Area National Corridor, 

DOE used the general source-and-sink 

approach described above in Section III. 

The sink areas are the locations of the 

consumers adversely affected by the 

persistent congestion documented in 

Section IX.B above. Specifically, the 

sink areas are the urban areas 

downstream of the constraints identified 

in Section IX.B above, including the 

cities of Los Angeles, San Bernardino, 

Riverside, Anaheim, San Diego, and 

other nearby municipalities. 

With regard to selecting source areas, 

as discussed in Section III above, the 

Department was guided by the 

considerations identified in FPA section 

216(a)(4). In particular, the Department 

focused on the considerations of 

ensuring adequate supplies of power 113

and diversifying supply.114 Applying 

those considerations, DOE identified as 

source areas locations with substantial 

amounts of existing, under-used 

generation capacity (see Table IX–4), 

and locations with potential for 

substantial development of wind, 

geothermal, or solar generation 

capacity.115 The existing, under-used 

generation could readily provide 

additional power to the sink areas if the 

required transmission capacity were 

available. In addition, improved 

transmission access to the areas with 

renewable-based generation potential 

would diversify supply. Figure IX–5 

indicates the locations of the source 


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areas in southern California and western 

Arizona. 

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Having identified the source and sink 

areas, DOE sought to delineate a draft 

National Corridor that would connect 

those areas, encompass all of the 

relevant constraints contributing to 

congestion in southern California, and 


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116For example, CAISO states that the Southern 

California Import Transmission (SCIT) operating 

nomogram: Places limits on imports into southern 

California based on a variety of conditions. They 

include power flows on five major paths into 

southern California, actual flow East of the River 

(EOR), and system inertia from generation within 

southern California. When the SCIT nomogram 

becomes binding, the CAISO must increment 

additional generation from a limited number of 

units in southern California to mitigate flows. Intrazonal congestion initiating the SCIT nomogram 

often is due to the large quantity of low cost energy 

from imports from Arizona or Mexico being used 

to serve southern California load. 

CAISO 2004 Annual Report, p. 6–3. 

encompass a range of potential 

transmission projects and a range of 

potential routes. The Department is also 

including the sink areas in the draft 

Southwest Area National Corridor, 

because it is frequently the case that 

local upgrades to the transmission 

system and related facilities are needed 

in such areas in order to achieve the full 

benefits of developing major new highvoltage transmission lines. Further, the 

Department has included the source 

areas in the draft Southwest Area 

National Corridor. 

Finally, the draft Southwest Area 

National Corridor includes the several 

substations and related transmission 

facilities between Los Angeles and the 

Hoover Dam area southeast of Las 

Vegas, Nevada. This area and the area 

around Palo Verde, Arizona are the two 

principal portals from the east for 

transferring bulk power into southern 

California. From both a transmission 

planning perspective and an operational 

perspective, it is useful to think of these 

two pathways as closely related. Adding 

facilities or changing the operating rules 

on one is almost certain to require 

changes in the other so as to maintain 

an appropriate balance between 

them.116

2. Specific Boundaries of the Draft 

Southwest Area National Corridor 

After determining the general area to 

be covered by the draft National 

Corridor, DOE addressed the question of 

establishing its specific boundaries. 

DOE relied on county boundaries to 

determine the perimeter of the draft 

Southwest Area National Corridor. That 

is, if a portion of the general area 

identified in Section IX.D.1 above (i.e., 

the source areas, the sink areas, and the 

areas in between encompassing the 

constraints of concern) is located within 

a county, then the entire county is 

assumed to be within the draft National 

Corridor, and the outer perimeter of the 

group of counties thus identified defines 

the draft National Corridor as whole. 

This approach establishes boundaries 

that are precise and identifiable. 

Moreover, this approach helps ensure 

that the draft National Corridor 

encompasses a range of potential 

projects and a range of potential routes, 

as discussed in Section III above. The 

resulting draft Southwest Area National 

Corridor is shown in Figure IX–6. 


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The counties that comprise the draft 

Southwest Area National Corridor are as 

follows: 

California 

Imperial, Kern, Los Angeles, Orange, 

Riverside, San Bernardino, and San 

Diego. 

Arizona 

La Paz, Maricopa, and Yuma. 

Nevada 

Clark. 

The Secretary of Energy has approved the 

publication of this notice. 

Issued in Washington, DC, on April 25, 

2007. 

Kevin M. Kolevar, 

Director, Office of Electricity Delivery and 

Energy Reliability. 

[FR Doc. 07–2115 Filed 5–4–07; 8:45 am] 

BILLING CODE 6450–01–C 


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