Docket No. RM99-2-000 -238- 

335FERC Stats. & Regs. at 33,729.

336Id. at 33,730.

2. Scope and Regional Configuration (Characteristic 2)

The NOPR proposed as the second minimum characteristic of an RTO that the

RTO must serve an appropriate region—a region of sufficient scope and configuration to

permit the RTO to effectively perform its required functions and to support efficient and

nondiscriminatory power markets. 335 The NOPR noted that there is likely no one "right"

configuration of regions and proposed to establish a set of factors that encourage

appropriate regional configuration without prescribing boundaries. The NOPR suggested

that a region that is large in scope would facilitate the effective performance of many of

the RTO’s functions, but also recognized that there may be factors that might limit how

large an RTO should be. 336 The NOPR also proposed a set of factors that may affect the

location of regional boundaries These factors indicate that boundaries should facilitate

essential RTO functions and goals, recognize trading patterns, mitigate the exercise of

market power, do not unnecessarily split existing control areas or existing regional

transmission entities, encompass contiguous geographic areas and highly interconnected

portions of the grid, and take into account useful existing regional boundaries (such as

NERC regions) and international boundaries. The NOPR put forth for discussion the

appropriateness of existing configurations, such as the three electric interconnections
Docket No. RM99-2-000 -239- 

337See, e.g., South Carolina Authority, Cleco, SRP, LG&E, Detroit Edison,

Wyoming Commission, Entergy, UtiliCorp, NECPUC, MidAmerican, Enron/APX/Coral

Power, Duke, NASUCA, Industrial Consumers, Connectiv, Massachusetts Division, Iowa

Board.

within the continental United States, the ten NERC reliability councils, and the 23 NERC

security coordinator areas.

The NOPR also requested comments on what portion of the transmission facilities

within an appropriate region the RTO must control in order to be approved as an RTO. 

The Commission recognized that it might be difficult to obtain 100 percent participation

of all transmission owners within a region, but that, on the other hand, it would not be

appropriate to approve an RTO proposal that included only a small portion of the

facilities of the region. The Commission also requested comments on how much

deference the Commission should give to regions proposed to us, and to what extent state

commission approval or disapproval should be taken into account.

a. How Should Initial Boundaries be Established?

Comments

Most commenters agree with the Commission's proposal not to initially prescribe 

the boundaries for appropriate regions. 337 Among the rationales asserted by these

commenters is that this is a matter best left in the first instance to the stakeholders in the
Docket No. RM99-2-000 -240- 

338See, e.g., South Carolina Authority, NASUCA, Florida Power Corp.

339See, e.g., Entergy, MidAmerican.

340See, e.g., Southern Company, NECPUC, Nine Commissions, Florida

Commission.

341See, e.g., Duke, FirstEnergy, Allegheny, Iowa Board.

342See, e.g., NYPP.

various regions, 338 there should be deference to proposals by transmission owners and

market participants, 339 FERC should give deference to state commissions on scope and

configuration, 340 boundaries should be determined naturally in a way that facilitates

market transactions, 341 and size and configuration must be determined on a case-by-case

basis. 342 

However, some commenters argue that the Commission should prescribe regional

boundaries. APPA, East Texas Cooperatives, TDU Systems and the Michigan

Commission urge that the Commission use section 202(a) authority to establish initial

boundaries. APPA asserts that the Commission should establish a rebuttable presumption

in favor of specific regional district boundaries based on the topology of the transmission

network to enhance system security. East Texas Cooperatives argues that after the

Commission established regional districts, the burden would be on those proposing

different regions to show that they provide at least the benefits of the prescribed districts. 

Michigan Commission states that the electricity market is currently too immature to
Docket No. RM99-2-000 -241- 

determine by itself the size of the markets, and that firm guidance is needed rather than

allowing the RTO boundaries to be set by participants.

Several other commenters do not go as far in asserting that the Commission should

initially set boundaries, but argue that the Commission should take a strong role in

assuring proper boundaries. For example, Cinergy urges that the Commission be

aggressive in establishing boundaries consistent with the proposed criteria, noting that the

willingness of the Commission to exercise its authority over boundaries will determine

the success of the Commission's restructuring efforts. Coalition of Alliance Users

maintains that the Commission should take a direct and active role in formulating RTO

boundaries. WEPCO believes that the role of the Commission should be to set criteria

that encourage the establishment of sensible RTO boundaries. Project Groups assert that

if the stakeholders in a region do not determine boundaries by the end of 2000, the

Commission should make the determinations. LG&E states that while the Commission

should show deference to voluntary RTOs, it should not hesitate to disapprove proposals

with geographic shortcomings.

Commenters express a variety of views regarding whether particular regional

configurations would be appropriate. Some commenters support interconnection-wide
Docket No. RM99-2-000 -242- 

343See, e.g., South Carolina Authority, Conlon, Industrial Consumers, First

Rochdale, Los Angeles, PG&E, Sonat.

344See, e.g., South Carolina Authority, Desert STAR, MidAmerican, TDU

Systems, CREDA, SNWA, CRC, Platte River, PSNM, SRP, Metropolitan.

RTOs as a desirable goal, 343 while others regard either an Eastern or Western

interconnection RTO as unworkably large. 344 

Commenters offer specific ideas about the number and placement of RTOs. 

PG&E states that the long-term goal should be four or five RTOs nationwide. Williams

argues for 3 to 10 RTO nationwide, while Project Groups advocates 3 to 12 RTO

nationwide. WEPCO proposes the formation of five RTOs: (1) three in the Eastern

interconnection (one covering MAPP, MAIN, ECAR and portions of SPP; one covering

SERC, Florida and the rest of SPP; and one covering NPCC and MAAC); (2) one for

WSCC; and (3) one for ERCOT. APPA, supported by East Texas Cooperatives,

suggests: (1) no more than three RTOs in the West; (2) the combination of PJM, NY ISO

and ISO-NE into one RTO with the possible participation of Ontario; (3) the combination

of the Alliance RTO, Midwest ISO, and MAPP into one RTO; (4) Kansas to the

Carolinas under one RTO; and (5) separate RTOs for Florida, ERCOT and HydroQuebec.

With respect to specific regions, ISO-NE contends that it already operates a region

of appropriate size and configuration. Mass Companies agrees that ISO-NE is an
Docket No. RM99-2-000 -243- 

345See, e.g., Michigan Commission, South Carolina Authority, Midwest ISO,

Midwest ISO Participants, NASUCA..

346See, e.g., Florida Commission, JEA, FP&L, Florida Power Corp., Tallahassee,

Gainesville.

347See, e.g., SRP, Metropolitan. 

appropriate region. NYC argues that the formation of a northeastern RTO with a broader

geographic scope than the NY ISO would help remove existing institutional impediments

to the construction of new transmission lines. American Forest argues that PJM is too

small, while NASUCA and Mid-Atlantic Commissions believe that PJM satisfies the size

criteria. Some commenters object to a split between the area represented by the proposed

Alliance RTO and the Midwest ISO. 345 Most of the Florida commenters assert that

peninsular Florida represents an appropriate region. 346 For example, Florida

Commission claims that peninsular Florida is a large and efficient marketplace that does

not share parallel flows with other electrical regions; however, it states that the Florida

panhandle could be in a region with all of SERC or a subregion of SERC.

 Although some commenters encourage a Western interconnection-wide RTO, the

majority of commenters support three or four RTOs for the Western interconnection,

noting that the interests in the WSCC are too diverse and the area too large for control by

a single entity. 347 Cal ISO contends that California satisfies the minimum size criteria,

but does not represent the maximum feasible area. Commenters from the Pacific
Docket No. RM99-2-000 -244- 

348See, e.g., Seattle, PGE, Industrial Customers, BC Hydro, Powerex, Tacoma

Power, PNGC.

349See, e.g., South Carolina Authority, SPP.

Northwest generally agree that a region including Washington, Oregon, and all or

portions of Idaho and Montana is distinct enough to warrant an RTO limited to that

area. 

348 CREDA and Platte River envision one RTO for the Pacific Northwest, one for

California and one for the Rocky Mountain/Desert Southwest area; CRC suggests a

similar alignment, with the exception of the Rocky Mountain and Southwest areas as

separate RTOs. 

A number of commenters make the point that, regardless of where RTO

boundaries are drawn, it is important that there be integration and coordination among

RTOs. 349 NERC believes that there are two seams issues: reliability practices across

seams and market practices across seams. TDU Systems suggests that there be a set of

regions for reliability/operations purposes within a larger region for rates and scheduling. 

Industrial Consumers state that, if multiple RTOs are formed within an interconnection,

RTOs should be required to coordinate their operations to collectively "simulate" an

interconnection-wide RTO. Cinergy suggests that, if there were more than one RTO in a

large interconnection, a "super" RTO could be established to operate and coordinate

inter-RTO activities. Montana Commission states that RTO boundaries are less

important than ensuring that seams do not interfere with the market, and proposes, as do
Docket No. RM99-2-000 -245- 

others such as Ontario Power and CMUA, that the Commission require adjacent RTOs to

embody consistent methods of access, pricing, and congestion management to encourage

seamless trading. PacifiCorp asserts that reciprocity agreements among RTOs may be

easier to achieve than having all parties in a large region agree to one RTO. Allegheny

suggests that appropriate transmission pricing could provide some of the same benefits as

a large RTO. 

Several commenters express concern that multiple RTO proposals for the same

region will be submitted. Indiana Commission contends that the NOPR leaves the door

open for more than one RTO proposal for approximately the same wholesale power

market region and this could limit the operational efficiency and increase the cost of

transmission in the region. It suggests that the Commission consider requiring formal

mediation or play an assertive role in such circumstances. Snohomish suggests favoring

the RTO proposal that is negotiated pursuant to the most open process that included

consumers, transmission dependent utilities and others with a vital interest in the effective

and efficient operation of the transmission grid. Midwest ISO Participants submit that the

proponents of multiple RTOs meet a heavy burden and demonstrate the need for more

than one RTO. In particular, it would require demonstration that the proposals: do not

balkanize the market; allow for effective congestion relief; maintain reliability; facilitate
Docket No. RM99-2-000 -246- 

construction of new transmission facilities; and allow for effective tariff administration

and unbiased ATC determination throughout the region.

Commission Conclusion

We adopt the NOPR proposal on this characteristic. All RTO proposals filed with

us must identify a region of appropriate scope and configuration. The scope and

configuration of the regions in which RTOs are to operate will significantly affect how

well they will be able to achieve the necessary regulatory, reliability, operational, and

competitive benefits. 

As proposed in the NOPR, we will not at this time prescribe initial boundaries for

RTOs. Section 202(a) of the FPA does give us the authority, after consultation with state

commissions, to fix and modify boundaries for regional districts for the voluntary

interconnection and coordination of facilities. We acknowledge those commenters who

believe that it may be more efficient for the Commission to establish at least a rebuttable

presumption that particular boundaries are appropriate starting points. However, we

conclude, as a matter of policy, that we should not attempt to draw boundaries at this

time. We are convinced that the transmission owners, market participants, and regulators

in a particular region have a better understanding of the dynamics of the transmission

system in that region, and that they should, at least in the first instance, propose the

appropriate scope and regional configuration of an RTO. There are many technical
Docket No. RM99-2-000 -247- 

350See Statement of Ohio Commission Chairman Craig Glazer, RTO Conference

(St. Louis), transcript at 85-87.

considerations involved in discerning the appropriate scope and regional configuration of

an RTO, and we believe that those most familiar with such considerations in a region are

in a better position to propose a workable solution.

As noted above, some commenters advocate that the NERC regions be starting

points; others advocate that the Interconnections be the goal; and still others propose

specific configurations that would divide the Nation as many as three to 12 RTOs. 

Consistent with our decision to let the parties take the initiative to propose what is

appropriate for their region, we will not specifically endorse any particular scheme for

RTO configuration.

This is not to say, however, that we will deem appropriate any regional

configuration proposed. As stated in the regulatory text for this characteristic, an

appropriate region is one of sufficient scope and configuration to permit the RTO to

effectively perform its required functions and to support efficient and nondiscriminatory

power markets. A proposed RTO could simply be too limited to satisfy several of the

necessary functions. Further, we are aware that transmission owners could seek to gain

strategic advantage by the way an RTO is formed. For example, an RTO could be placed

to act as a toll collector on a critical corridor. 350 An RTO could propose a configuration

that interferes with the formation of a larger, more appropriately configured RTO. 
Docket No. RM99-2-000 -248- 

351The proposal could be accepted, however, as something less than an RTO that

represents an improvement over the status quo. 

352See section F on Open Architecture.

As we review a proposal by a regional transmission entity for its scope and

regional configuration, if we determine that the scope is inappropriate, that entity will not

be deemed to be an RTO, and its participants will not be deemed to be RTO

participants. 351 In response to the commenters questioning what the Commission would

do if it received multiple RTO proposals for a region, we note that we hope the

collaborative process we are encouraging in this Final Rule would foreclose that

circumstance. However, if we are faced with multiple proposals, we would have to

determine which RTO proposal best meets the objectives of this Rule.

As we stated in the NOPR, we are aware that there is likely no one "right"

configuration of regions. One particular boundary may satisfy one desirable RTO

objective and conflict with another. We recognize here, and elsewhere in this Final

Rule, 352 that the industry will continue to evolve, and the appropriate regional

configurations will likely change over time with technological and market developments. 

The Commission is also mindful of the interests of individual states regarding RTO

boundaries. Given all these considerations, the Commission believes that the public

interest will best be served if we provide guidance in this Final Rule, in the form of
Docket No. RM99-2-000 -249- 

353See, e.g., UtiliCorp, Desert STAR, Midwest ISO Participants, Metropolitan,

NECPUC, LG&E, PJM/NEPOOL Customers, Midwest Municipals, Industrial

Consumers, Dairyland, TDU Systems, ISO-NE, Midwest Energy, APX, APPA, Cal ISO.

354See, e.g., Cinergy, American Forest, EPSA, UtiliCorp, PG&E, NSP,

Pennsylvania Commission, NJBUS, LG&E, Enron/APX/Coral Power, NASUCA,

PJM/NEPOOL Customers, Cal ISO, Texas Commission, Conlon, Dynegy, Nine

Commissions, Michigan Commission, Lincoln, WPSC, First Rochdale, East Texas

Cooperatives, Los Angeles, Ohio Commission, EME, Ontario Power, H.Q. Energy

Services, Ogelthorpe, UMPA, PG&E, Indiana Commission.

355See, e.g., Cinergy, WPSC, Lincoln, Ohio Commission, PG&E.

factors that affect appropriate regional configuration, without actually prescribing

boundaries.

b. Scope and Configuration Factors

Comments

A large number of commenters agree that the factors listed in the NOPR for

determining a proper scope and configuration for an RTO are generally appropriate. 353

Industrial Consumers propose that the factors be codified as part of our regulations. 

Florida Commission, on the other hand, argues that the factors should not be mandated as

part of the Commission's regulations.

Many commenters argue that the RTO region should be as large as possible, i.e.,

bigger is better. 354 Several commenters suggest the minimum size should be the NERC

regions. 355 Conlon suggests a minimum area should be one containing a load of 50,000

MW. PJM states that its organization demonstrates that a very large RTOs is feasible, in
Docket No. RM99-2-000 -250- 

356See, e.g., LG&E, ComEd, Midwest ISO Participants, Midwest ISO.

357See, e.g., AEPCO, Tallahassee.

358See, e.g., Enron/APX/Coral Power, FirstEnergy, Tri-State.

359See, e.g., Dairyland, Minnesota Power.

that it manages a grid serving more than 57,000 MW of generation and containing more

than 8,000 miles of high voltage transmission lines. PJM states that even larger control

areas are possible as technology advances. PJM/NEPOOL Customers, claiming that all

potential factors that might limit size can be overcome, argue that the Commission should

not conclude that there are factors that limit size. As discussed below with respect to the

congestion management function, some commenters make a particular point of

emphasizing the importance of large scope to effective congestion management. 356

Other commenters argue that bigger is not necessarily better and that there are

factors that limit size. 357 CMUA argues that the role of security coordinator and

operational characteristics of a region may limit geographic scope. STDUG claims that

size breeds inefficiency. Several commenters claim that requiring maximum scope upon

creation may discourage RTO formation or make it more costly and take longer to

achieve. 358 NYPP expresses concern that, if an RTO is too large, it may not be able to

handle local reliability issues. Other commenters believe that the ability to plan new

transmission facilities may limit scope. 359 AEPCO expresses concern that the voice of
Docket No. RM99-2-000 -251- 

360See, e.g., South Carolina Authority, Desert STAR, MidAmerican, TDU

Systems, CREDA, SNWA, CRC, Platte River, PSNM, SRP, Metropolitan.

361See, e.g., Industrial Customers, Powerex, Tacoma Power.

smaller participants could be lost in a larger RTO. Florida Power Corp. claims that there

may be a security risk associated with concentrating control of too large an area into a

single facility, and that large areas of non-pancaked rates may eliminate incentives for

proper generator siting decisions. A number of commenters believe that either the

Eastern interconnection or the Western interconnection is too large an area to be

controlled by one RTO. 360 New York Commission argues that the Commission should

recognize that experience must be gained in stages before an RTO encompassing an

entire interconnection can be implemented. Several commenters in the Pacific Northwest

cite the failed attempt to create IndeGo as evidence that trying to create too large an RTO

is unworkable, and at some point "bigger" creates more problems than it solves. 361

Some commenters offer subjective parameters for the scope of an RTO. For

example, SNWA proposes that the RTO be large enough to accommodate as many market

participants as possible, but not so large as to be overly burdensome to manage. SRP

argues that a balance must be struck between an RTO that is too small to cover a

meaningful wholesale power market and one that is too large to form and operate

effectively. TDU Systems argue that RTOs should comprise the largest regions that
Docket No. RM99-2-000 -252- 

362See, e.g., CMUA, APPA, Florida Commission, Minnesota Commission.

363See, e.g., UtiliCorp, Reliant, Duke, South Carolina Commission, NU, Florida

Power Corp., Detroit Edison.

364See, e.g., South Carolina Authority, Williams, NSP, Dynegy.

could operate in a coordinated fashion within a short period of time with reasonable

investments of funds. 

A number of commenters emphasize particular factors that they consider

important in determining scope and configuration. Some commenters assert that

reliability and system security should be the primary determinant of scope and

configuration. 362 Others place prime importance on trading patterns and facilitating

market transactions. 363 EEI states that the most efficient size and configuration of an

RTO should be left to the market to determine. Other commenters propose electrical

configuration and physical power flows as important factors. 364 CREDA and Desert

STAR argue that the preservation of a Federal Power Marketing Administration project

marketing area is an important consideration. Chelan argues that cost shifts need to be

considered in determining scope. Platte River contends that established security

coordinators should be a factor. Southern Company argues that joint ownership

agreements should be a factor. Tacoma Power claims that traditional business

relationships and social and political commonality are factors that affect scope.
Docket No. RM99-2-000 -253- 

365See, e.g., Industrial Consumers, First Rochdale, Minnesota Power, STDUG,

NARUC.

366See, e.g., Ohio Commission, EAL, Florida Power Corp..

Commenters are divided on whether points where transmission facilities are

constrained should be used as an RTO boundary or internalized within an RTO. Some

commenters claim that constraints should be internalized to the extent possible and not

constitute boundaries between regions. 365 NERC states that boundaries should not be

placed at weak interconnections because a single entity is better able to strengthen them. 

On the other hand, other commenters believe that constrained facilities should constitute

the boundaries, either because they may form a natural boundary between robust systems

or because it makes more sense to internalize markets than to internalize constraints. 366

APPA states that, because it is not possible to internalize all constraints, the goal should

be to alleviate or mitigate the effects of interregional constraints through additional

construction and RTO operating rules and pricing policies. NECPUC argues that it does

not matter where constraints are if compatible methods of locational pricing are adopted

by contiguous RTOs. MidAmerican and Duke assert that constraints are not natural

boundaries between regions because the location of points of constraint change over time

as market conditions change. Several commenters, such as Dairyland and Desert STAR,
Docket No. RM99-2-000 -254- 

367This reiterates the conclusion we reached in the eleven ISO principles in Order

No. 888, where we stated that "[t]he portion of the transmission grid operated by a single

ISO should be as large as possible." Order No. 888, FERC Stats. & Regs. ¶ 31,036 at

31,731.

take the position that the issue whether to design RTO boundaries at constrained

interfaces cannot be stated generically, and must be decided on a case-by-case basis.

Commission Conclusion

The factors we believe should be used to develop appropriate regions are set out

here and called regional configuration factors. These cover such considerations as how

large a region should be and how boundaries should be evaluated. We do not see a

benefit to placing them in regulatory text, as suggested by one commenter, and we will

not do so. The factors are intended as guidance and, as such, must necessarily be applied

flexibly.

Regional Configuration Factors

As stated above, the principal consideration in evaluating the appropriate scope of

an RTO is that such scope must permit the RTO to perform its functions effectively. As

we stated in the NOPR, many of the characteristics and functions for an RTO proposed in

this section suggest that the regional configuration of a proposed RTO should be large in

scope. 

367 For example:
Docket No. RM99-2-000 -255- 

C Making accurate and reliable ATC determinations: An RTO of sufficient

regional scope can make more accurate determinations of ATC across a

larger portion of the grid using consistent assumptions and criteria.

C Resolving loop flow issues: An RTO of sufficient regional scope would

internalize loop flow and address loop flow problems over a larger region.

C Managing transmission congestion: A single transmission operator over a

large area can more effectively prevent and manage transmission

congestion.

C Offering transmission service at non-pancaked rates: Competitive benefits

result from eliminating pancaked transmission rates within the broadest

possible energy trading area.

C Improving Operations: A single OASIS operator over an area of sufficient

regional scope will better allocate scarcity as regional transmission demand

is assessed; promote simplicity and "one-stop shopping" by reserving and

scheduling transmission use over a larger area; and lower costs by reducing

the number of OASIS sites.

C Planning and coordinating transmission expansion: Necessary transmission

expansion would be more efficient if planned and coordinated over a larger

region.
Docket No. RM99-2-000 -256- 

We note that the comments on this issue express a range of views. Many

commenters assert that the bigger the RTO is the better, and that there really are no

serious limitations to RTOs representing loads as large as several hundred thousand

megawatts. Other commenters suggest a number of considerations that may militate

against RTOs that are too large, including the role of security coordinator, operational

characteristics, costs of formation, local reliability issues, and the effect on smaller

participants. In the NOPR, we recognized that there may be a limitation on how many

facilities or transactions can be overseen reliably by a single operator, imposed either by

hardware design or costs, or imposed by human limitations to process the required

amount of information. We further recognized that the difficulty and cost of transferring

operational control over many transmission systems to one RTO may affect regional

configuration. We also noted that, as regions get larger and involve more existing owners

of transmission, reaching consensus on an appropriate transmission rate design for the

region may prove challenging. 

We note that a number of commenters make the point that, at least for some

purposes and functions, the scope of an individual RTO is less important if it is part of a

group of RTOs that have adequately eliminated the negative effects of "seams" between

itself and the other RTOs. NERC identifies two seams issues: reliability practices across

seams and market practices across seams. We further note that other commenters suggest
Docket No. RM99-2-000 -257- 

368In a recent conference to address interregional ISO coordination in the

northeast, the three northeast ISOs (ISO New England, New York ISO, and PJM ISO)

and other market participants discussed current and future coordination efforts among the

ISOs intended to simplify market transactions and enhance reliability in the northeast. 

See http://www.dps.state.ny.us/isoconf.htm.

that large RTOs could be "simulated" through coordinated operations and consistent

methods of access, pricing, and congestion management, and that there may be different

acceptable scopes for reliability and operations purposes on one hand, and rates and

scheduling on the other. 368 We also detect a common theme that runs through a number

of comments: large geographic size is most important for trading areas. Thus, the

concept of large "seamless trading areas" for power emerges as a "scope" issue that is

distinct from the scope of the region for organizing the transmission functions of an RTO. 

We conclude that a large scope is important for an RTO to effectively perform its

required functions and to support efficient and nondiscriminatory power markets. 

Adequate scope is not necessarily determined by geographic distance alone; other factors

include the numbers of buyers and sellers covered by the RTO, the amount of load

served, and the number of miles of transmission lines under operational control. The

scope must be large enough to achieve the regulatory, reliability, operational and

competitive objectives of this Rule.

We are receptive to flexible and innovative ways for an RTO to achieve sufficient

scope. Where a proposed regional transmission entity may be of sufficient scope for
Docket No. RM99-2-000 -258- 

some RTO purposes, but not others, an RTO may be able to achieve sufficient "effective

scope" by coordination and agreements with neighboring entities, or by participating in a

group of RTOs with either hierarchical control or a system of very close coordination. 

We do not foreclose the possibility that an RTO may satisfy some of the minimum

characteristics and functions by itself, while satisfying others through a strong

cooperative agreement with neighboring RTOs to create a "seamless trading area." The

functions of a large RTO may be met by eliminating the effect of seams separating

smaller RTOs through a contract or other coordination arrangement. One of our concerns

about an RTO's scope is that the existing impediments to trade, reliability, and

operational efficiency be eliminated to the greatest extent possible. However, an RTO

application that proposes to rely on "effective scope" to satisfy Characteristic 2 must

demonstrate that the arrangement it proposes to eliminate the effect of seams is the

practical equivalent of eliminating the seams by forming a larger RTO.

Factors for Evaluating Boundaries

In addition to the factors affecting the size of a region, other factors may affect the

delineation of regional boundaries. As stated in the NOPR, the Commission proposed

that RTO boundaries be drawn so as to facilitate and optimize the competitive, reliability,

efficiency and other benefits that RTOs are intended to achieve, as well as to avoid

unnecessary disruption to existing institutions. The Commission proposed in the NOPR a
Docket No. RM99-2-000 -259- 

list of factors it would consider in evaluating the configuration for a proposed RTO. 

Nearly all of the comments agree that these factors are generally appropriate. 

We recognize that different factors may suggest different configurations and that

assessing the appropriateness of a region's configuration will require balancing factors

and a flexible approach. Given this qualification, the Commission, in evaluating an

RTO's boundaries, will consider the extent to which the proposed boundaries:

Facilitate performing essential RTO functions and achieving RTO goals: The

regions should be configured so that an RTO operating therein can ensure nondiscrimination and enhance efficiency in the provision of transmission and ancillary

services, maintain and enhance reliability, encourage competitive energy markets,

promote overall operating efficiency, and facilitate efficient expansion of the transmission

grid. For example, we understand that there have been instances where transmission

system reliability was jeopardized due to the lack of adequate real-time communication

between separate transmission operators in times of system emergencies. To the extent

possible, RTO boundaries should encompass areas for which real-time communication is

critical, and unified operation is preferred.

Encompass one contiguous geographic area: The competitive, efficiency,

reliability, and other benefits of RTOs can be best achieved if there is one transmission

operator in a region. To be most effective, that operator should have control over all
Docket No. RM99-2-000 -260- 

369Commenters are also divided on whether weak interfaces should be

encompassed within an RTO or act as a natural boundary. After consideration, we

conclude that there is not a universal answer applicable to all situations. Consequently,

we will address this issue as it arises in RTO proposals on a case-by-case basis. 

transmission facilities within a large geographic area, including the transmission facilities

of non-public utility entities. This consideration could preclude a noncontiguous region,

or a region with "holes." However, as we discuss below, we will not automatically deny

RTO status where the RTO is not able to obtain full participation in its region. 

Encompass a highly interconnected portion of the grid: To promote reliability and

efficiency, portions of the transmission grid that are highly integrated and interdependent

should not be divided into separate RTOs. One RTO operating the integrated facilities

can better manage the grid. This is not to say, however, that every weak interconnection

belongs on a regional boundary. Where a weak interface is frequently constrained and

acts as a barrier to trade, it may be appropriate to place that interface within an RTO

region. It may be more difficult to expand a weak interface on the boundary between two

regions; this may act as a barrier to trade between the two regions. 369

Deter the exercise of market power: While the industry should work toward a goal

of virtually seamless trade between RTOs, it may be that initially a significant amount of

trade may be contained within an RTO, especially if the RTO or the market establishes a

power exchange that covers the same area as the RTO. Thus, to have a competitive
Docket No. RM99-2-000 -261- 

market, it is important to create an RTO region that is not dominated by a few buyers or

sellers of energy. Also, the RTO configuration should not be one where the RTO

participants can exercise transmission market power by collecting congestion fees on a

critical corridor.

Recognize trading patterns: Given that a goal of this initiative is to promote

competition in electricity markets, regions should be configured so as to recognize trading

patterns, and be capable of supporting trade over a large area, and not perpetuate

unnecessary barriers between energy buyers and sellers. There may exist today some

infrastructure or institutional barriers unnecessarily inhibiting trade between regions that

could be economically reduced. RTO boundaries should not perpetuate these

unnecessary and uneconomic barriers.

Take into account existing regional boundaries (e.g. , NERC regions) to the extent

consistent with the Commission's goals for RTOs: An RTO's configuration should, to the

extent possible, not disrupt existing useful institutions. The Commission recognizes that

utilities have been working together regionally in different contexts for some time, and

that there is value in preserving historical institutions and relationships; but we also

recognize that in the evolving market, efficiencies may call for new configurations.

Encompass existing regional transmission entities: Because existing ISOs, and any

other regional transmission entities we may hereafter approve, already integrate
Docket No. RM99-2-000 -262- 

transmission systems, it may not be efficient to divide them into different regions. This is

not to say, however, that RTO boundaries must coincide with existing regional

transmission entities. An appropriate region may well be larger, and there may be

circumstances that support combining or reconfiguring existing entities.

Encompass existing control areas: Many existing control areas are relatively

small. It may be advisable not to divide them further. However, parties would not be

precluded from proposing to divide a control area if they show this to be beneficial.

Take into account international boundaries: The Commission recognizes that

natural transmission boundaries do not necessarily coincide with international

boundaries. Indeed, a large part of Canada's transmission system, and a small part of

Mexico's transmission grid, is interconnected on a synchronous basis with that of the U.S. 

Accordingly, an appropriate region need not stop at the international boundary. 

However, this Commission does not have, and is not intending by this rule to seek,

jurisdiction over the facilities in a foreign country. We will ask our international

neighbors to participate in discussion of these issues. Perhaps what may be thought of as

a "dotted line" boundary at the international border could be used to indicate that a

natural transmission region does not necessarily stop at the border, while this

Commission's jurisdiction does. 
Docket No. RM99-2-000 -263- 

Although most commenters generally support these factors, other considerations

are proposed as factors. For example, some commenters claim that we should make

reliability and system security the dominant factor, while other commenters propose that

we make trading patterns and market transactions the dominant factor. After

consideration, we do not think it appropriate to identify one factor as the most important. 

Although it is essential that reliability not be jeopardized by RTO formation, and it is

important to promote competition, we do not believe that one goal needs to be sacrificed

to achieve the other. 

Other commenters suggest additional factors that they deemed important to RTO

boundaries, including, for example, established security coordinators, joint ownership

arrangements, and Federal power marketing administration project marketing areas. We

do not intend the factors we have listed to be exclusive: other factors may have merit for

a particular region. We encourage parties to identify additional factors they believe

relevant as we consider specific RTO proposals.

c. Control of Facilities Within a Region

We proposed in the NOPR to accept as RTOs only those proposals for which a

region of appropriate scope and configuration is identified and the proponents represent a

large majority of the transmission facilities within the identified region. 
Docket No. RM99-2-000 -264- 

370See, e.g., Desert STAR, Southern Company, Metropolitan, MidAmerican,

Nevada Commission, Avista, Enron/APX/Coral Power, Duke, PJM/NEPOOL Customers,

Cal ISO, Midwest Municipals, CRC, NPRB, Minnesota Power, Tri-State, TVA.

We solicited comments on how best to balance our goal of having RTOs in place that

operate all transmission facilities within an appropriately sized and configured region

against the reality that there may be difficulties in obtaining 100-percent participation in

all regions in the near term. We asked if we should deny RTO status for any proposal

that does not include all transmission facilities within an appropriate region, or if we

should require that the RTO at least negotiate certain agreements with any nonparticipants within its region to ensure maximum coordination.

Comments

Almost all commenters argue that RTO status should not be withheld if the RTO

participants are unable to obtain participation by all transmission owners in the region. 370

Several commenters, such as Desert STAR and Minnesota Power, note that, if the

Commission does not mandate 100 percent participation, it does not make sense to make

it a condition of RTO approval. Other commenters propose standards to consider in

determining when a proposed RTO represents sufficient facilities in the region. For

example, Desert STAR suggests that the RTO have more than a majority of transmission

owners and has not restricted membership. Southern Company proposes a standard that

sufficient facilities include most of the major transmission facilities and the RTO can
Docket No. RM99-2-000 -265- 

show benefits. MidAmerican proposes that the RTO be able to demonstrate that it would

improve the wholesale market of any subregion of the country without hindering the

wholesale market of any other region of the country. Enron/APX/Coral Power argues

that an RTO should be approved if it provides an improvement even with "gaps." 

Midwest Municipals believe that an RTO should be accepted if the Commission can

make the judgment that the proposal with "gaps" is likely to encourage others to join

through the strength of its operations and the facilities support the development of a

competitive generation market. CRC suggests a standard that the proponents make a

showing that they have diligently tried to accommodate the concerns and needs of the

nonparticipating transmission owners. 

Some commenters, such as NJBUS and Cal ISO, believe that an RTO should

include the participation of all jurisdictional transmission owners in the region. Duke,

however, opposes any attempt by the Commission to determine the appropriate level of

participation, stating that the market should determine the participation level. Some

commenters, such as Metropolitan, support having the RTO develop coordinated

operations agreements with non-participants, while other commenters, such as Avista and

Duke, caution that requiring such agreements would be contrary to market principles and

would give the non-participating party too much bargaining power.
Docket No. RM99-2-000 -266- 

Seattle contends that the Commission should guard against utilities that would add

to the RTO some facilities that are not necessary for RTO operations merely to obtain

incentives. It argues that small municipal control areas should have some latitude to

determine which of their facilities are regional for RTO purposes. Seattle also questions

what "participation" entails for a utility that has limited transmission facilities.

Commission Conclusion

To satisfy the scope and configuration characteristic of this Final Rule, all or most

of the transmission facilities in a region must be included in the RTO. Any RTO

proposal filed with us should intend to operate all transmission facilities within its

proposed region.

We recognize, however, that the proponents of an RTO may not be able to obtain

agreement by all transmission owners in a region of appropriate scope and configuration

to transfer operating control of their facilities to the RTO. This may occur, for example,

because certain facilities may be owned by governmental entities that have restrictions on

transfer of control that may require time to resolve. We do not believe that it would be

desirable to deny RTO status or delay RTO start-up where the transmission owners

representing a large majority of the facilities within a region are ready to move forward,

while a few others are not. On the other hand, we do not believe it would be desirable to
Docket No. RM99-2-000 -267-

371FERC Stats. & Regs. ¶ 32,541 at 33,734 and proposed § 35.34(i)(3). In the

NOPR, we used the terms "operational authority" and "operational responsibility"

interchangeably. For purposes of clarity and consistency, we will use only the term

"operational authority" to describe this function and have revised the proposed regulatory

text accordingly.

approve an RTO proposal for a region if the proponents represent only a small portion of

the facilities in an otherwise satisfactory region.

Not knowing the full extent of difficulties that may be involved to achieve

participation by all transmission facilities, we will not decide generically to automatically

deny RTO status for lack of full participation. If an RTO proposal does not cover all the

transmission facilities within its proposed region, it should identify the reasons for this, 

any continuing efforts to include all facilities, and any interim arrangements with the nonrepresented facility owners to coordinate transmission functions within the region. The

Commission may at a future time determine whether the use of its authorities under FPA

sections 202(a) and 206 is appropriate to rationalize proposed regions in order to

accomplish the objectives of those sections, as discussed elsewhere in this Final Rule.

3. Operational Authority (Characteristic 3) 

In the NOPR, the Commission proposed that the RTO have operational authority

for all transmission facilities under its control. 371 We stated that this requirement raised

two questions: Which functions must an RTO perform? How should an RTO perform

the functions that it has reserved for itself? With respect to the question of which
Docket No. RM99-2-000 -268-

372FERC Stats. & Regs. ¶ 32,541 at 33,734 and proposed § 35.34(i)(3)(ii).

functions an RTO should perform, the Commission proposed that, at a minimum, the

RTO must have operational authority over all transmission facilities transferred to the

RTO and must be the security coordinator for its region. 372 As security coordinator, the

RTO would be responsible for real-time monitoring of system conditions (including

voltage, frequency, transmission and generation availability, and power flows) in order to

anticipate potential reliability problems, and for directing and coordinating relief

procedures to respond to transmission loading problems (such as assisting the control area

in alleviating the loading, halting additional interchange transactions, reallocating the use

of the transmission system, selecting the transmission loading relief procedure, and

implementing emergency procedures, including directing that the control area

immediately redispatch generation, reconfigure transmission or reduce load). Those

proposing an RTO may also decide to have their RTO perform other traditional control

area functions (such as maintaining the energy balance, interchange schedules and system

frequency). The Commission proposed, however, that an RTO would not be required to

be a single control area because of concerns over potentially high costs and technical

limitations. Instead those proposing an RTO would be given flexibility in determining

the best division of functions between the RTO and any providers of other control area

functions if there are no other grid operators in its region. However, the Commission
Docket No. RM99-2-000 -269-

373Id.

374Id. and proposed § 35.34(i)(3)(i).

375Id.

376Id. at 33,735.

insisted that an RTO must be ultimately responsible for providing reliable and nondiscriminatory transmission service. 373

 

With respect to the second question of how an RTO will perform its functions, the

Commission proposed that an RTO be given considerable flexibility in determining

whether it will control facilities directly, delegate functions, or use a combination of these

methods. 374 For example, we stated that an RTO proposal could have the RTO operate a

single control area, or establish a master-satellite hierarchical control structure with one

central and multiple distributed control centers (in either case it could propose to lease

equipment and convert employees from existing control centers). 375 The Commission

also proposed that the RTO must submit a public report assessing its operational

arrangements no later than two years after it begins operations. 376
Docket No. RM99-2-000 -270-

377Operational authority refers to the authority to control transmission facilities,

either directly or through contractual agreements with the entities that do have direct

control. In contrast, security coordination refers to real-time monitoring of system

conditions in order to anticipate potential reliability problems, and directing and

coordinating relief procedures to respond to transmission loading problems. 

378See, e.g., APPA, Cal ISO, Duke, East Texas Cooperatives, Entergy, EPSA, First

Rochdale, Georgia Transmission, Illinois Commission, IMEA, ISO-NE, Michigan

Commission, Minnesota Power, Montana-Dakota, NASUCA, NECPUC, Nevada

Commission, Mid-Atlantic Commissions, PacifiCorp, PJM, PJM/NEPOOL Customers,

SNWA, Southern Company, SRP, SPRA, Tri-State, UtiliCorp, WPSC.

379See, e.g., Illinois Commission, IMEA, NASUCA, PJM/NEPOOL Customers.

380See, e.g., First Rochdale, IMEA, UMPA.

381See, e.g., Montana-Dakota, Tacoma Power.

Comments

Comments on the Functions an RTO Must Perform?

Most commenters agree that the RTO must have operational authority 377 for the

transmission facilities under its control. 378 Some commenters claim that this authority is

necessary to prevent anticompetitive behavior by transmission owners. 379 Some

commenters further contend that this authority must extend to all facilities involved in

wholesale transactions so that the transmission owner does not retain control of "access

ramps" that happen to be at low (34kV or 69kV) voltage levels. 380 In contrast, some

utilities express concern that RTO authority over low voltage facilities will unnecessarily

complicate operations. 381
Docket No. RM99-2-000 -271-

382See, e.g., Florida Commission, Puget. It appears that the Florida Commission

interprets a transfer of operational control as a transfer of retail dispatch authority. 

Although other commenters such as WPSC support the RTO having operational

authority, they believe that the Commission may need legislative action to obtain the

authority to require such a transfer.

383See, e.g., Florida Power Corp., Georgia Transmission, JEA, MidAmerican,

Southern Company, Enron/APX/Coral Power.

Several commenters oppose operational authority over the transmission system by

the RTO. Some commenters claim that the Commission does not have the legal authority

to require transmission owners to transfer control to any other entity. 382 Midwest

Energy and SPP believe a transfer of authority would be too costly to implement. Other

commenters maintain that the owner and operator of the transmission system must be the

same entity in order to avoid liability disputes. 383 Mass Companies suggests that

transmission owners retain authority to ensure the safe and prudent management of their

facilities. ComEd suggests that transmission owners retain operational authority with the

RTO having oversight responsibility.

Commenters are divided whether the RTO should be required to be a control area

operator. The existing ISOs in California, New England and PJM, which are all control

area operators, report that this structure is working in their regions. Some commenters

express concern over potential harm to competitive markets if control area authority is not
Docket No. RM99-2-000 -272-

384See, e.g., APPA, APS, Arkansas Consumers, NASUCA, NJBUS, TDU Systems.

385See ,e.g., Conlon, Illinois Commission, Los Angeles, FirstEnergy, Minnesota

Power, SRP, TDU Systems.

386See, e.g., CP&L, ECAR, EEI, Entergy, EPSA, Southern Company.

387It appears that the Florida Commission and JEA believe that such a transfer

would involve RTO control of retail dispatch. It also appears that Dynegy believes that

the basic control area function of frequency control is identical to dynamic scheduling,

which they believe should not be centralized or consolidated.

transferred to an independent entity. 384 ICUA recommends that the RTO be the sole

control area operator. Many other commenters support a single control area as the

ultimate goal, but suggest that the RTO be allowed to evolve to this structure and not be

required to consolidate control areas immediately. 385 Other commenters express concern

about potential costs associated with control area consolidation, but agree that such action

would be acceptable if and when the RTO decides it is necessary for reliability or other

reasons. 

386

 

Commenters that oppose requiring control area consolidation provide a variety of

reasons. 

387 Enron/APX/Coral Power state that only an RTO that is a transco should

perform control area functions. The Florida Commission is concerned that control area

consolidation may result in a security risk. Tri-State and WEPCO believe that there are

higher priorities in RTO development (such as eliminating pancaking, and promoting
Docket No. RM99-2-000 -273-

388See, e.g., NASUCA, First Energy, Otter Tail, PJM, PJM/NEPOOL Customers,

Professor Hogan, Project Groups, SPRA, UtiliCorp, Williams, WPPI. We also discuss

below in more detail the issue of congestion management as an RTO minimum function.

389See, e.g., East Texas Cooperatives, WPPI, Project Groups.

390See, e.g., Allegheny, APPA, APX, Cal ISO, ComEd, Dynegy, East Texas

(continued...)

regional system planning) and that emphasizing control area consolidation may inhibit

RTO formation.

With respect to specific control area functions, numerous commenters discuss the

need for an RTO to have some control of generation in order to ensure system reliability,

especially during emergency situations. 388 Minnesota Power suggests that the

Commission include "control generation as required to ensure reliability" as an additional

minimum function in the final rule. It also recommends that responsibility for area

control error (ACE) and automatic generation control (AGC) be transferred to the RTO as

control area functions because separating these functions from transmission operations

can lead to reliability problems. Other commenters request that the balancing function be

transferred to the RTO to prevent discriminatory behavior by transmission owners. 389 

There is widespread agreement among commenters that the RTO must be the

security coordinator. Marketers, utilities, existing ISOs and customers all agree that

coordination and reliability will be enhanced if a regional organization is responsible for

maintaining grid security. 390 Some commenters state that the authority of a security
Docket No. RM99-2-000 -274-

390(...continued)

Cooperatives, Enron/APX/Coral Power, Entergy, EPSA, LG&E, Mass Companies,

MidAmerican, Midwest Energy, Montana-Dakota, NASUCA, NECPUC, NERC, NJBUS,

PJM/NEPOOL Customers, PPC, Professor Hogan, Seattle, South Carolina Authority,

SPP, SRP, Tri-State, UtiliCorp, Williams.

391See, e.g., LG&E, PJM/NEPOOL Customers, SPP, UtiliCorp. See also supra

section III.D.1 for a more detailed discussion of independence as an RTO minimum

characteristic.

392See, e.g., Montana-Dakota, PJM/NEPOOL Customers, South Carolina

Authority, Williams.

coordinator to receive commercially sensitive information to order the curtailment of

transactions and the shedding of firm load also grants it the ability to favor its own

merchant functions. Confidence in comparable and non-discriminatory transmission

service, therefore, will be improved if these functions are performed by an entity that is

independent of all market participants. 391 Though essentially in support of our proposal,

NERC and MidAmerican assert that is not necessary to link each RTO to a single security

center, but rather it is possible to allow a single security coordinator to assume

responsibility for more than one RTO. NERC points out that if an RTO performs all the

characteristics and functions specified in the NOPR, it will necessarily be a security

coordinator. 

A number of parties state that the RTO must have access to real-time system

information in order to perform its functions as security coordinator. 392 Montana-Dakota

explains further that security centers, by definition, will be equipped with the hardware
Docket No. RM99-2-000 -275-

393See, e.g., East Texas Cooperatives, First Rochdale, Illinois Commission,

PJM/NEPOOL Customers.

and software required to assume basic operational control of the system, which are

beyond that required strictly for security functions. 

Only two commenters express concern over the need for the RTO to be the

security coordinator. ComEd, though supporting some security functions for the RTO,

asserts that the RTO's role can be limited simply to one of oversight. ComEd does not

believe that the RTO needs access to real-time data, and instead would allow the

individual control areas to perform the bulk of the security functions. The only

commenter that argues against making the RTO a security coordinator is Avista, which

states that the security coordinator in the Pacific Northwest is already an independent

body and has the authority necessary for ensuring reliability; therefore, no changes are

required.

Comments on How an RTO Should Perform Its Functions

Overall, commenters strongly agree with the Commission's proposal to permit

those proposing an RTO the authority to decide the type of control they require: direct,

functional or a combination. Some commenters believe direct control is the best

approach to prevent abuse of sensitive information and better ensure reliability. 393 

However, Manitoba Board and Canada DNR express concern that continued coordination

between U.S. and Canadian utilities might be undermined if highly centralized systems
Docket No. RM99-2-000 -276-

394See, e.g., MidAmerican, Seattle, South Carolina Authority.

395See, e.g., ECAR, Enron/APX/Coral Power, EPSA, East Texas Cooperatives,

First Rochdale, Industrial Consumers, ISO-NE, LG&E, Los Angeles, Lincoln,

MidAmerican, Montana-Dakota, NECPUC, NASUCA, Otter Tail, PJM, PJM/NEPOOL

Customers, Project Groups, Seattle, South Carolina Authority, Tri-State. Many of these

commenters support eventual consolidation when any cost and technical barriers are

overcome and if the RTO decides it is necessary.

396See, e.g., EAL, East Texas Cooperatives, ISO-NE, Industrial Consumers,

LG&E, NASUCA, PJM, PJM/NEPOOL Customers, Powerex, Project Groups, Tri-State.

are developed and controlled by U.S. entities. A few commenters contend that it is best

for the RTO to delegate control authority. 394 The majority of commenters support some

form of hierarchical control structure, where the RTO would establish a master control

center and direct the operations in the existing geographically distributed control centers,

which would become satellite centers. 395 PJM and ISO-NE indicate that they both

currently operate with a hierarchical control structure, where the ISO control center is the

master control room that directs the actions of the satellite control centers. 

A number of supporters of the hierarchical structure specifically request that the

Commission ensure that the RTO has the authority to direct all actions at the satellite

control centers and that the satellite centers will be independent in order to prevent

discriminatory transmission service and the transfer of commercially valuable information

to market participants. 396 Montana-Dakota and Otter Tail believe a major benefit of the

hierarchical structure is improved emergency response and system security in a large
Docket No. RM99-2-000 -277-

397See NERC Operating Manual Policy 2 which can be found at www.nerc.com.

As we have stated before, the dividing line "between transmission control and generation

control is not always clear because both sets of functions are ultimately required for

reliable operation of the overall system." Midwest ISO, 84 FERC at 62,151. The idea

that the entity that controls the transmission system must have some degree of control

over some generation seems to be generally recognized. See Docket No. ER98-1438-000

Applicants' Response at 3.

398We note that the definition of a control area, and consequently the functions

that must be performed by a control area, is currently being reexamined by the NERC

Control Area Criteria Task Force in an open forum. See NERC web page at

www.nerc.com.

region if the RTO is coordinating and directing the actions of all operators in the region. 

Finally, Enron/APX/Coral Power believe the standardization of balancing practices for a

large region is an important benefit of a hierarchical system. 

Commission Conclusion

Which Functions Must an RTO Perform?

We reaffirm the determination proposed in the NOPR that an RTO must have

operational authority for all transmission facilities under its control and also must be the

security coordinator for its region. We recognize that it is difficult to draw a precise line

between transmission control and generation control, 397 and we also recognize that given

the changing nature of the industry, terminology such as "control area operator" is

undergoing definitional changes. 398 Accordingly, it is difficult to state precisely what

functions an RTO must have in order to have full operational authority for transmission

facilities. Moreover, our desire to allow RTOs flexibility dissuades us from trying to be
Docket No. RM99-2-000 -278-

too precise. However, certain concepts are basic and generally understood in the

industry.

One necessary aspect of operational authority as used here refers to the authority

to control transmission facilities. This includes, but is not limited to, switching

transmission elements into and out of operation in the transmission system (e.g.,

transmission lines and transformers), monitoring and controlling real and reactive power

flows, monitoring and controlling voltage levels, and scheduling and operating reactive

resources. Functions such as these must be included within the operational authority of

an RTO. 

We conclude, as proposed in the NOPR, that the RTO is also required to be the

NERC security coordinator for its region. The role of a security coordinator is to ensure

reliability in real-time operations of the power system. As security coordinator, the RTO

will assume responsibility for: (1) performing load-flow and stability studies to

anticipate, identify and address security problems; (2) exchanging security information

with local and regional entities; (3) monitoring real-time operating characteristics such as

the availability of reserves, actual power flows, interchange schedules, system frequency

and generation adequacy; and (4) directing actions to maintain reliability, including firm

load shedding. 

We believe that the RTO must be security coordinator for several reasons. The

functions of the security coordinator are enhanced when they are performed over large
Docket No. RM99-2-000 -279-

39984 FERC at 62,158.

regions. In addition, the independence of the security coordinator is important for

ensuring non-discriminatory transmission service, and the RTO will have that

independence. As we stated in Midwest ISO:

This role [the role of a security coordinator] is central to maintaining grid

reliability and non-discriminatory access. Under proposed NERC policies,

security coordinators would be required to anticipate problems that could

jeopardize the reliability of the interconnected grid. In the course of performing

these reliability functions, the Security Coordinator would receive considerable

information which is commercially sensitive. Therefore, it is important that the

proposed Midwest ISO Security Coordinator be performed by an entity that is

independent of market participants. [399]

However, we will allow flexibility in how the RTO performs its security

coordinator functions. For example, an RTO may contract these responsibilities out to an

independent security coordinator if this is justified. Also, this requirement does not

prevent more than one RTO from sharing a single security coordinator as suggested by

NERC.

As proposed in the NOPR, we will not at this time require the RTO to operate

what traditionally has been thought of as a single control area for its region. However,

the RTO must perform the control functions required to satisfy the minimum

characteristics and functions in this Final Rule, including the transmission control and
Docket No. RM99-2-000 -280-

400For example, several commenters state that an RTO must have some authority

over generation to ensure system reliability. The RTO is required to have some authority

as a minimum characteristic, as discussed with respect to short-term reliability.

401In our order approving the Midwest ISO, we stated that our approval of the ISO

was based on the applicants' commitment that the ISO would be able to "take all actions

necessary to provide nondiscriminatory transmission service, promote and maintain

reliability." Midwest ISO, 84 FERC at 62,159.

security coordinator functions discussed above, 400 in a non-discriminatory manner for all

market participants. 401 We will permit those developing an RTO proposal flexibility in

deciding on the particular division of operational responsibilities with existing control

areas. 

We recognize that the feasibility of consolidating existing control areas into a

single such area may be limited by cost and technical considerations. However, we note

that physical consolidation may be unnecessary when a hierarchical control structure is

used to define a single control area by making existing control areas subject to RTO

direction (and so avoiding the high costs and technical uncertainty associated with

centralization of physical control for a very large RTO region). Hierarchical control is a

form of power system control that relies on a master-satellite control structure, which

establishes a single controlling authority without requiring the construction of a single,

consolidated control room. Existing control centers are not replaced, but continue to

operate, independent from market participants, as satellite control centers reporting to the

RTO master control center. The RTO security center assumes the dual role of the master
Docket No. RM99-2-000 -281-

402See, e.g., Marija Ilic and Shell Liu, Hierarchical Power System Control: Its

Value in a Changing Industry, Springer-Verlag, 1996. 

403This issue is also addressed in greater detail in our discussion of the RTO's role

as a provider of ancillary services as an RTO minimum function.

control center and security center, with clear authority to direct all actions at the satellite

centers. 402

We conclude that each region should be free to decide if and when the region will

transition to a hierarchical control structure, consolidate the control areas in its region, or

adopt a different control structure that best meets the region's needs.

How Should the RTO Perform Its Functions?

We conclude that those designing the RTO should have flexibility to decide how it

would exercise its operational control authority. The RTO operate the transmission

system through direct physical operation by RTO employees, contractual agreements with

other entities (e.g., transmission owners and control area operators) or implement a

hierarchical control structure involving a combination of direct and functional control. 

Under these arrangements, the personnel of existing control centers might become

employees of the RTO or remain as employees of the control center owner, while being

supervised by RTO personnel. We will leave it to the discretion of the region to decide

on the combination of direct and functional control that works best for its

circumstances. 403
Docket No. RM99-2-000 -282-

 However, regardless of the method of control chosen, the RTO must have clear

authority to direct all actions that affect the facilities under its control, including the

decisions and actions taken at any satellite control centers. The system of operational

control chosen must ensure reliable operation of the grid and non-discriminatory access to

the grid by all market participants. In addition, to ensure that the RTO does not become

locked into an operational system that is unsatisfactory, the Commission will require the

RTO to prepare a public report that assesses the efficacy of its operational arrangements

no later than two years after it begins operations.

4. Short-Term Reliability (Characteristic 4)

The fourth proposed characteristic of an RTO is that it must have exclusive

authority for maintaining the short-term reliability of the transmission grid under its

control. In the NOPR we identified four basic short-term reliability responsibilities of an

RTO: (1) the RTO must have exclusive authority for receiving, confirming and

implementing all interchange schedules; (2) the RTO must have the right to order

redispatch of any generator connected to transmission facilities it operates if necessary

for the reliable operation of these facilities; (3) when the RTO operates transmission

facilities owned by other entities, the RTO must have authority to approve and disapprove

all requests for scheduled outages of transmission facilities to ensure that the outages can

be accommodated within established reliability standards; and (4) if the RTO operates

under reliability standards established by another entity (e.g., a regional reliability
Docket No. RM99-2-000 -283-

404FERC Stats. & Regs. ¶ 32,541 at 33,735.

405See, e.g., American Forest, Cal ISO, California Board, Cinergy, CMUA, CSU,

EAL, Enron/APX/Coral Power, Entergy, EPSA, Industrial Customers, NASUCA,

NECPUC, PJM, PNGC, SMUD, UtiliCorp, H.Q. Energy Services, Mass Companies,

Mid-Atlantic Commissions, MidWest Energy, Minnesota Commission, NY ISO,

PacifiCorp, PG&E, Williams, WPSC. 

council), the RTO must report to the Commission if these standards hinder its ability to

provide reliable, non-discriminatory and efficiently priced transmission service. 404

Comments

General Comments

Commenters address both general concerns about reliability as well as the four

basic proposed short-term reliability responsibilities of an RTO. Most commenters

generally agree that the RTO should have the responsibility for short term-reliability. 405

Several commenters raise questions regarding definition and scope of "short-term"

reliability. TEP requests that the Commission further define the time period involved. It

suggests that designating a specific time period (whether one month, six months or a

year) would be beneficial to evaluating this characteristic. Enron/APX/Coral Power

requests that the Commission make clear that "short-term" is intended to mean "realtime."

While agreeing that the RTO should be given ultimate control over facilities

necessary to preserve reliability, SMUD expresses concern that the RTO should not be
Docket No. RM99-2-000 -284-

encumbered with responsibility for facilities that do not serve a regional transmission

function. TANC requests that the RTO's responsibility over reliability not infringe on the

management responsibilities of local regulatory authorities or interfere with the

management and operation of the local system facilities of a utility distribution company. 

PG&E requests that the Commission require that the RTO rely primarily on market

mechanisms to maintain reliability. However, PJM/NEPOOL Customers urge the

Commission to ensure that the RTO’s actions in maintaining the short-term reliability of

the grid do not unreasonably impinge on the freedom of business decisions inherent in a

competitive supply market. Several commenters, such San Francisco and Minnesota

Commission, state that because the primary function of a RTO is ensuring short-term

reliability, it should be more clearly defined and should not be compromised by any other

RTO market functions.

PJM suggests that the Commission grant additional authorities to the RTO to

ensure reliability, including the authority to (1) collect information, (2) direct operations

in the control area, (3) assure that those it directs will respond in a predictable manner

(which the RTO can achieve through training and drills) and (4) declare an emergency,

direct emergency operations, and determine when emergency conditions have ended.

Southern Company notes that the industry has little, if any, experience in granting

a new entity control over the operations of a transmission system that encompasses a
Docket No. RM99-2-000 -285-

406Southern Company notes that the California and ERCOT ISOs operate within

the boundaries of a single state. In PJM, New York and New England, the control of the

grid remains remarkably unchanged because the ISOs in those regions were already

operating the system on behalf of the transmission owners and adopted the institutions

and infrastructures of an ISO.

407FERC Stats. & Regs. ¶ 32,541 at 33,735-36.

broad, multi-state region. 406 It claims that transmission owners and State commissions

must be assured that the RTO is capable of operating a regional transmission system

reliably before an RTO is formed. New York Commission indicates that the authority of

States to require the maintenance of electric system reliability should be recognized in

establishing responsibilities. Iowa Board believes that there is a need for greater regional

development of reliability standards to reflect regional needs and conditions. It requests

that State commissions be involved in the decisionmaking process of an RTO to ensure

that electric facilities are properly sized and located and that additions are not detrimental

to the reliability of the grid.

Comments on Interchange Scheduling

The Commission proposed that, in the context of the RTO’s role as the recipient

and evaluator of all requests for transmission service under its own FERC-approved

tariff, an RTO that is a control area operator must also receive, confirm, and implement

all interchange schedules between adjacent control areas. 407 The Commission expressed

concern that non-RTO control area operators would receive commercially sensitive
Docket No. RM99-2-000 -286-

408See, e.g., Cal ISO, CMUA, Entergy, Mass Companies, NECPUC, Nevada

Commission, PJM/NEPOOL Customers, PJM, SMUD, Southern Company, WPSC,

PG&E.

information involving its competitors in implementing interchange schedules and

questioned whether there is any Commission action, other than its current code of

conduct standards, and short of requiring consolidation of all control areas within a

region, which could address this concern.

Several commenters agree that the RTO should have authority over receiving,

confirming and implementing all interchange schedules. 408 PJM believes that an

independent ISO is in the best position to exercise the scheduling authority of an RTO. It

suggests that an RTO that is independent of commercial interests in the market does not

face the commercial information problem because it does not compete with market

participants and consequently would make scheduling decisions in an unbiased and fair

manner.

PJM/NEPOOL Customers claims that interchange scheduling oversight must be

performed by an independent entity because it would be neither possible nor desirable for

a non-RTO control area operator to perform this function without access to commercially

sensitive information. It suggests that the RTO maintain direct control over interchange

scheduling either by using RTO employees or a master satellite arrangement where

ultimate responsibility remains in the RTO master control area operating room. APX
Docket No. RM99-2-000 -287-

409See also Southern Company.

410See, e.g., Duke, Florida Power Corp.

suggests that requiring a contractor (acceptable to the RTO and the control area operator)

to operate the control area operator facility could help address this concern.

Enron/APX/Coral Power believes that the risk is eliminated if transmission

operations, including control-area operations, are operationally separated from the load

and generation of vertically-integrated utilities. Barring such complete separation, this

risk could nevertheless be substantially obviated if the RTO provided control area

operators with information only about scheduled net interchanges between control areas

without disclosing the individual transactions making up the new schedules. 409

However, other commenters contend that control area operators will continue to

need information on individual transactions in order to implement interchange schedules

and to ensure real-time reliability. 410 Desert STAR believes that work should be done in

this area to determine what information is required by control area operators and when

they must receive it in order to carry out their reliability responsibilities

Florida Commission states that this issue has already been resolved within the

Florida Reliability Coordinating Council (FRCC) by requiring all entities who operate

control areas within the region that require access to commercially sensitive information
Docket No. RM99-2-000 -288-

411FERC Stats. & Regs. ¶ 32,541 at 33,736.

412See, e.g., Cal ISO, Cinergy, CMUA, NECPUC, PJM, UtiliCorp, Entergy,

Allegheny, LG&E, Lincoln, Metropolitan, Minnesota Power, Nevada Commission, Otter

Tail, Southern Company, TDU Systems, NASUCA, Reliant, Mass Companies, TAPS.

to sign agreements that separate reliability personnel and the relevant information from

their wholesale merchant personnel.

Several commenters, such as Duke and Florida Power Corp., state that no

additional Commission action is necessary. These commenters believe that the existing

code of conduct standards are working and the reciprocity provisions of Order No. 888

provide for compliance with the code of conduct standards by all non-public utility

control area operators. Florida Power Corp. also notes that within the FRCC, all entities

operating control areas are required to sign agreements verifying functional separation.

Comments on Generation Redispatch

In the NOPR, the Commission proposed that the RTO's reliability authority

include the ability to order redispatch of any generator connected to the transmission grid

when necessary for the reliability of the grid. However, the RTO would have no

authority over initial unit commitment and normal dispatch decisions. 411

Several commenters agree that the RTO have some authority to order redispatch

when necessary to maintain the the reliability of the grid. 412 Sithe, however, believes

that, in the evolving competitive marketplace, redispatch authority alone is insufficient. It
Docket No. RM99-2-000 -289-

413See, e.g., Cinergy, Chelan, Southern Company, LG&E, Reliant.

argues that the RTO should also provide appropriate incentives to the owners of assets

that are needed for reliability to maintain those assets and make them available for

operation in constrained areas. Sithe urges the Commission to consider adopting a final

rule that provides RTOs with sufficient commercial authority, "including the necessary

financial resources" to enter into market-rate business arrangements, that assure

availability of assets needed for reliability. Sithe states that without this authority, the

RTO may not have sufficient tools to fully ensure reliability, because must-run generators

would have little incentive to continue to operate in constrained areas.

CMUA maintains that it is insufficient to vest authority in the RTO to maintain

short-term reliability without also vesting enforcement powers to ensure compliance with

RTO dispatch instructions. Allegheny and other commenters agree that RTOs should be

able to direct redispatch, particularly if the redispatch is accomplished under a marketbased compensation scheme as a part of transmission service pricing methodology that

uses the redispatch costs to set marginal system use costs. However, they argue that in no

case should the RTO be able to direct generation redispatch unless the generator is

compensated at market value (unless market power issues are involved). 413

Avista expresses serious concern with the breadth of a redispatch requirement. It

believes that the right to order redispatch of generation should be negotiated among the
Docket No. RM99-2-000 -290-

414See, e.g., CMUA.

parties in the region without a presumption that the RTO must have broad redispatch

authority, except in emergency circumstances. Avista and others note that a negotiated

approach is particularly important to operators of hydroelectric resources which are

subject to numerous environmental and operating restrictions that limit their ability to

redispatch. 414 Avista and SMUD request that the Commission clarify that the RTO’s

authority to redispatch is limited to emergency circumstances affecting reliability. 

Chelan believes that RTOs should be required to enter into arm's-length

agreements with those generators that are willing to service redispatch requests, and

compensate those generators for supplying this service. RTOs should not be allowed to

unilaterally redispatch a generating unit without the generator’s consent, and without

compensation.

Commenters, such as Cal ISO and Nevada Commission, suggest that the

Commission require reliability-related services (i.e. redispatch) be provided to RTOs

under a set of uniform rates, terms and conditions. Such a requirement would reduce the

Commission’s administrative burden of contracts governed by different sets of terms and

conditions.

EME believes that the RTO's control over dispatch of generation should be

carefully circumscribed. It recommends that reliability functions be internalized into
Docket No. RM99-2-000 -291-

415Metropolitan believes the Cal ISO’s definition of system emergency

appropriately describes the circumstances in which redispatch may be appropriate. A

"system emergency" is described as "any abnormal system condition which requires

immediate manual or automatic action to prevent loss of load, equipment damage or

tripping of system elements which might result in cascading outages or to restore system

operation to meet the minimum operating reliability criteria." 

416See, e.g., PG&E, Southern Company, Reliant, SMUD.

explicit procedures for congestion pricing. It states that in most cases proper pricing

signals can provide sufficient incentives for generators to schedule operation of their

facilities to ensure system reliability. 

Industrial Consumers states that the RTO’s redispatch decisions regarding "any

generator" must be qualified to excuse on-site generators that serve an industrial load,

especially those that serve a critical steam host. For environmental, safety and economic

reasons, these units should not be forced to redispatch except as a last resort option.

Metropolitan supports an RTO having authority to order redispatch of any

generating unit when necessary for the reliability of the grid. However, "reliability" must

be carefully defined to avoid RTO interference with normal market operations by

redispatching generation for its own convenience, or to alleviate adverse market

conditions. 415

Several commenters oppose the proposal to allow the RTO to redispatch

generation. 416 PG&E believes that the proposal would give too much latitude to RTOs

and create an incentive to impose centrally determined fixes on market operations, rather
Docket No. RM99-2-000 -292-

than allowing market mechanisms to self-correct. Therefore, PG&E argues that RTOs

should be allowed to redispatch generation facilities only when there is a true reliability

emergency as specified in the RTO tariff. Moreover, RTOs should be able to redispatch

only those units that have actually participated in the market.

PJM/NEPOOL Customers believes that the authority as proposed in the NOPR is

too broad and must be further defined. It requests that the Commission ensure that this

authority is exercised only during only the most serious circumstances when grid

reliability is truly in danger. It suggests that the Commission promulgate or pre-approve

reliability standards for determining when the RTO can order redispatch of generators,

the amount of generation assets that the RTO will have authority over and standards for

the redispatch order. Southern Company recommends that the Commission provide only

general guidance concerning redispatch and allow the regions to develop more specific

procedures.

When considering allowing an RTO to redispatch a Federal hydroelectric

generator, SPRA emphasizes that the Commission must recognize that individual Federal

hydroelectric generators are under the control of either the Corps, the Bureau of

Reclamation or the International Boundary Waters Commission, not the PMA. While a

PMA may belong to an RTO, it is unlikely that other Federal agencies will. The
Docket No. RM99-2-000 -293-

417FERC Stats. & Regs. ¶ 32,541 at 33,736-37.

Commission must give careful consideration to determine that RTO redispatch authority

does not prohibit or limit a PMA's ability to fulfill its statutory obligations.

Comments on Transmission Maintenance Scheduling

In the NOPR, the Commission proposed that an RTO which operates transmission

facilities owned by other entities be authorized to approve or disapprove all requests for

scheduled outages of transmission facilities in order to ensure that maintenance outage

schedules meet applicable reliability standards. 417

The Commission requested comments on a number of issues related to this

proposed requirement: Does it cede too much or too little authority to the RTO? If the

RTO requires a transmission owner to reschedule its planned maintenance, should the

transmission owner be compensated for any costs created by the required rescheduling? 

Would it be feasible to create a market mechanism to induce transmission owners to plan

their maintenance so as to minimize reliability effects? Should an RTO that is an ISO

have any authority to require rescheduling of maintenance if it anticipates that the

planned maintenance schedule will adversely affect power markets? If the RTO is a

transco, can it manipulate its transmission maintenance schedules in a manner that harms

competition?
Docket No. RM99-2-000 -294-

418See, e.g., Cal ISO, NECPUC, PJM, Desert STAR, Entergy, PGE, Allegheny,

Avista, LG&E, Lincoln, Tri-State, WPSC, CRC, Duke, EAL, First Rochdale, Industrial

Consumers, ISO-NE, Metropolitan, Montana-Dakota, NASUCA, New Smyrna Beach,

NYPP, Oneok, PG&E, Southern Company, SRP, Turlock, WPPI, Florida Power Corp.,

Nevada Commission.

The Commission stated that the RTO's regional perspective will allow it to

coordinate individual maintenance schedules with each other as well as with expected

seasonal system demand variations. Because the RTO will have access to extensive

information, it will see the "big picture" and be able to make more accurate assessments

of the reliability effect of proposed maintenance schedules than individual, sub-regional

transmission owners.

Commenters address essentially three issue related to transmission maintenance

scheduling: the RTO's authority; appropriate compensation; and use of market

mechanisms.

RTO Authority to Schedule Transmission Maintenance

Many commenters support giving an RTO authority over transmission

maintenance scheduling. 418 Duke, however, believes that an enforcement mechanism

may also be needed. First Rochdale recommends that transmission owners be given the

right to protest an RTO’s actions to the Commission. Reliant, however, opposes RTO

authority over maintenance scheduling, arguing that transmission maintenance decisions

must reside with transmission facility owners. 
Docket No. RM99-2-000 -295-

Seattle and NYPP suggest that the Commission define an RTO role only for

scheduling facility outages that are clearly associated with the regional transmission

network because internal subtransmission and radial transmission facilities do not have

regional significance. Turlock supports restricting the RTO's authority to the grid it

manages to prevent its outage scheduling authority extending beyond the grid for which it

is responsible. On the other hand, TDU Systems claims that an RTO should also

coordinate maintenance of interconnected distribution facilities that are not under its

control, if maintenance on those facilities would adversely affect RTO operations. 

 Duke suggests that with the creation of an RTO that is not a transco, a set of

governing principles for outage coordination should be established. The parties should

agree on the timing of requests for planned maintenance and the timing of responses to

those requests. If for any reason, other than the gross negligence of the transmission

owner, a scheduled maintenance outage were determined to be a problem after an

agreement is reached, rescheduling the outage would require the mutual consent of the

transmission owner and the RTO. 

EAL recommends that appropriate contracts with existing transmission facility

owners that ensure the continued reliable operation of the grid are required. Principal

elements of such contracts would include standards of service, provisions for information

sharing and reporting, maintenance scheduling, transmission facility ratings, testing and
Docket No. RM99-2-000 -296-

performance expectations. Maintenance scheduling should include provisions for

maintenance deferral under instructions from the RTO if required for system security

reasons only.

NYPP states that arrangements for outages should be made well in advance of the

outage start date because RTO approval of proposed schedules could become the critical

path. If approval is delayed, or subsequently revoked, the transmission owner will incur

significant expenses that should be reimbursed.

Montana-Dakota suggests that the effects of rescheduling can be decreased by

having the RTO review and approve all transmission maintenance schedules on a weekly,

monthly and quarterly basis. After reviewing the transfer capability and market effects of

the proposed outage, the RTO should communicate the need to reschedule to the

transmission owner far enough in advance of the planned outage to allow the owner to

reschedule, possibly to avoid any cost impact. Montana-Dakota notes, however, that the

closer the date of the outage, the higher the probability of an economic impact.

Southern Company requests that the Commission clarify that once an RTO

approves a scheduled outage, it should be allowed to change that schedule only if

implementing the plan would compromise system integrity or reliability. 

Seattle believes that the NOPR fails to provide adequate assurances to

transmission owners that a timely maintenance schedule will be adopted by the RTO. 
Docket No. RM99-2-000 -297-

419See, e.g., PJM, TANC, WPSC, Avista, Lincoln, CRC, Duke, Metropolitan,

Minnesota Power, Montana-Dakota, NASUCA, NPRB, NYPP, PJM/NEPOOL

Customers, Reliant, TDU Systems, Turlock, Florida Power Corp., Reliant, Desert STAR,

Southern Company.

The RTO must establish timely dates certain for maintenance outage requests from

operating entities. To do this the RTO must adequately balance safety considerations,

and the cost of deferring maintenance with commercial impact. For these reasons, an

RTO should not be permitted to arbitrarily postpone required maintenance.

Compensation

Nearly all of the commenters believe that transmission owners should be

compensated in some form if they are required by an RTO to reschedule maintenance. 419

 Avista argues that the transmission owners’ shareholders should not bear the burden of

decisions made by an independent body that result in reduced revenues or increased costs

for the transmission owner.

Metropolitan states that if an RTO requests a transmission owner to reschedule

planned maintenance for reliability concerns, a transmission owner should be

compensated only for its direct costs necessarily and reasonably incurred in complying

with the RTO’s request. Direct costs may include, for example, increased labor or

equipment expenses arising from the rescheduled maintenance. However, Metropolitan

does not believe a transmission owner should recover lost opportunity costs arising from

the rescheduled maintenance because opportunity costs are uncertain and speculative.
Docket No. RM99-2-000 -298-

 Southern Company argues that, if an RTO requires a transmission owner to

reschedule a previously approved outage, the RTO should compensate the transmission

owner for any additional costs caused by the rescheduling.

NASUCA believes that the RTO should compensate transmission or generation

owners only to the extent that incremental costs are incurred due to the rescheduling of

outages. NASUCA argues that it is unlikely that owners would incur significant

incremental costs, especially for transmission outages. 

Some commenters such as PGE and Minnesota Power state that if an RTO

requires a transmission owner to reschedule its planned maintenance for reliability

reasons in an emergency situation, the RTO should not be required to compensate the

transmission owner. However, if an RTO requires a transmission owner to reschedule its

planned maintenance for economic reasons, the RTO should be required to compensate

the transmission owner for liquidated damages. 

Other commenters such as Tri-State and Cal ISO oppose transmission owners

being compensated for the rescheduling of maintenance work. Cal ISO states that, where

an RTO properly exercises such authority by requiring a transmission owner to

reschedule a maintenance outage, that transmission owner is not entitled to compensation

for the costs associated with rescheduling. Tri-State recommends factoring any
Docket No. RM99-2-000 -299-

additional expense into the revenue requirement that the transmission owner receives

from the RTO.

Market Mechanisms

PJM/NEPOOL Customers suggests that the RTO enact a compensation mechanism

in transmission outage rescheduling situations or propose to use a market mechanism to

encourage transmission owners to plan maintenance so as to minimize reliability effects. 

Minnesota Power, however, argues that maintenance rescheduling to benefit power

markets is analogous to generation redispatch and should be paid for by the benefitting

market participants.

Montana-Dakota believes that an RTO should have the authority to reschedule

maintenance for market effects if there is an incremental cost reimbursement mechanism

in place that would provide an incentive to the transmission owner to change maintenance

schedules to benefit the market. 

Metropolitan argues that an RTO with authority to unilaterally reschedule

transmission maintenance for market considerations could have a destabilizing effect on

the power market. Emerging markets require predictability to thrive, and therefore RTOs

should interfere in market operations only when necessary to address reliability concerns.

Florida Power Corp. suggests that, while it may be feasible to develop a market

mechanism to induce transmission owners to plan their maintenance to minimize
Docket No. RM99-2-000 -300-

420FERC Stats. & Regs. ¶ 32,541 at 33,737.

reliability effects, it would be far simpler to retain the existing structure in which a single

entity both owns and operates the transmission system. When ownership and operation

are combined, a single entity is responsible for both reliability and maintenance, and thus

has a natural incentive to seek an optimal balance between these activities. Thus, Florida

Power Corp. opposes RTOs having authority to reschedule maintenance to manage the

performance of the market.

Turlock also does not believe an RTO should have authority to make transmission

outage decisions based on market considerations. Turlock, as well as Desert STAR and

CRC, believe instead that consideration should be given to motivating transmission

owners to appropriately schedule their maintenance outages, to minimize impacts on

competitive markets.

Comments Generation Maintenance Scheduling

The short-term reliability characteristic, as proposed in the NOPR, would not give

an RTO authority over proposed generation maintenance outage schedules. However, the

Commission noted that some generation control is necessary for reliable operation of a

transmission system. The Commission asked whether an RTO should have some

authority over generation maintenance schedules and, if so, how much. 420
Docket No. RM99-2-000 -301-

421See, e.g., Cinergy, NECPUC, PJM, Desert STAR, WPSC, Cal ISO, EAL,

Industrial Consumers, ISO-NE, Turlock, Florida Power Corp., Metropolitan, Minnesota

Power, Montana-Dakota, NASUCA, Nevada Commission, NYPP, PSNM, TDU Systems.

422See, e.g., Desert STAR, Metropolitan, Turlock, Florida Power Corp., PSNM,

NYPP.

423See, e.g., WPSC, LG&E, Montana-Dakota.

The majority of commenters support an RTO having at least some authority over

generation maintenance schedules. 421 However, most commenters suggest limiting the

RTO's authority. Some commenters suggest that an RTO have authority only for

generating units that are "must-run" or that the RTO has under contract due to the

requirement to maintain system reliability. 422 Desert STAR believes that an RTO should

not attempt to manipulate the commercial power market when reliability is not affected.

Cinergy supports an RTO having the ability to request changes to a schedule to

serve reliability needs, coordinate transmission outages, and maximize grid efficiency to

increase ATC for transmission customers' use, so long as generators receive

compensation at market-based prices for missed market opportunities. Other commenters 

agree that an RTO should compensate the generation owner if a schedule change is

necessary. 

423
Docket No. RM99-2-000 -302-

424See, e.g., Duke, PJM/NEPOOL Customers, SPRA, Tri-State, Empire District.

425See, e.g., Enron/APX/Coral Power, FirstEnergy, Mass Companies,

Metropolitan.

A few commenters claim that the RTO should not have any authority over

generation maintenance schedules. 424 SPRA states that requiring such authority would

discourage or prevent participation by PMAs because other Federal agencies own the

hydroelectric plants that generate the power marketed by the PMAs.

Tri-State does not believe that an RTO should have approval authority over

generation maintenance outages because these outages are driven by the cost

considerations associated with generation plant equipment replacement or rehabilitation. 

However, Tri-State agrees that an RTO must have advance knowledge of the scheduled

generation outages in order to assure transmission system reliability and adequacy of

reserves. Other commenters concur with a notification requirement. 425 Cinergy notes,

however, that while it believes a generator may be required to submit its maintenance

schedule to an RTO, the RTO should be prohibited from sharing that information with

any other market participants, or affiliates of market participants.
Docket No. RM99-2-000 -303-

426FERC Stats. & Regs. ¶ 32,541 at 33,737.

427See also LG&E.

Comments on Performance Standards

In the NOPR, the Commission discussed the establishment of performance

standards by an RTO for transmission facilities under its direct or contractual control. 426

For example, an RTO could establish a standard that identifies specific performance

targets for planned and unplanned outages of facilities. The Commission requested

comments on whether a non-profit ISO could establish incentive schemes for the

transmission owners whose facilities it operates.

PJM believes that an RTO will be capable of developing performance standards

and incentives to encourage transmission owners and generators to operate and maintain

reliable facilities. It states that market participants cooperatively can create marketoriented incentives to maintain their transmission and generation facilities effectively. 427

Duke also believes that incentive schemes can be developed. It suggests that the

revenues collected from users by the RTO could be returned to transmission owners

according to a prearranged formula that incorporates quality standards for reliability. 

Thus, the revenue allocation would reflect transmission owner performance in providing

a reliable system.
Docket No. RM99-2-000 -304-

PSE&G believes that RTOs will, and should, be able to offer incentives to

participants to ensure that reliability standards are not only met but exceeded. It states

that a mechanism of linking payment with performance, measured against accepted

benchmarks, has worked well for many years in PJM.

EAL states that appropriate contracts with existing transmission facility owners

that ensure the continued reliable operation of the grid are required. It suggests that these

contracts include standards of service, provisions for information sharing and reporting,

maintenance scheduling, transmission facility ratings, testing and performance

expectations.

Industrial Consumers believes that an RTO could establish performance standards

for transmission facilities that takes into account the “reliability” of each facility. It

argues that a facility that has frequent unplanned outages should not receive the same

compensation as a facility whose availability is more reliable. It suggests that a

transmission owner be precluded from recovering fixed costs during periods of unplanned

outages that exceed some minimum threshold based on superior performance.

Cal ISO indicates that its tariff provides for the implementation of maintenance

standards, and penalties under those standards, to ensure both adequate maintenance and

system reliability. These provisions act in concert with the California ISO's authority to

coordinate and approve maintenance outages. 
Docket No. RM99-2-000 -305-

428FERC Stats. & Regs. ¶ 32,541 at 33,737-38.

Southern Company believes that the establishment of performance standards for

transmission facilities controlled by an RTO is misplaced. Transmission owners plan and

operate their transmission systems according to NERC and regional reliability standards,

as well as State legal and regulatory requirements. Thus, while Southern Company

doesn't claim that performance-based incentives are inappropriate, it points out that there

already are existing standards to ensure reliable system operations.

Comments on Facility Ratings and Operating Ranges

Reliable operation of the transmission system in the short-term requires both

continuous monitoring of equipment availability and loading, and actions to maintain

loading levels within the established operating ranges and equipment ratings. The NOPR

suggested that RTOs are best situated to establish ratings and operating ranges for two

reasons. First, they will have the most complete information about expected and realtime operating conditions. Second, RTOs will be trusted because they will not have any

economic interests in electricity market outcomes and they will not be owned or

controlled by any market participants. The Commission proposed to let RTO established

equipment ratings prevail in a dispute with a transmission owner pending the outcome of

a dispute resolution process. 428
Docket No. RM99-2-000 -306-

Nearly all commenters that address this issue oppose the NOPR proposal. South

Carolina Authority urges the Commission to proceed with caution to prevent avoidable

damage to persons or property. SRP argues that ratings and operating ranges influence

the useful life and maintenance cost of equipment, as well as the level of service to the

end-use customer, and notes that each transmission owner has a legitimate interest in the

ratings. SRP believes that the ideal situation would be to establish ratings by mutual

consent of the transmission owner and RTO. If they cannot agree, the issue should go to

dispute resolution.

NYPP and Mass Companies oppose this proposal because transmission owners

have the fiduciary responsibility to protect their assets. Furthermore, they state that the

rating of equipment necessarily requires a particularized knowledge of the equipment and

related facilities that is unlikely to be possessed by the RTO. 

Metropolitan believes that a well-established reliability organization is best suited

for establishing maximum transmission line ratings that can be sustained over most of the

hours in a year because it will include the cooperation of technical groups representing all

systems, not just those under RTO control. It sees no benefit from moving this

responsibility to RTOs when the reliability councils have historically performed this

function with a minimum of controversy. EAL suggests that since the owner of the

transmission facility assumes the equipment, personnel and public risks for the operation
Docket No. RM99-2-000 -307-

429FERC Stats. & Regs. ¶ 32,541 at 33,738.

of its equipment, the RTO could fulfill an audit role to ensure that facility ratings by the

owners follow industry norms.

Seattle suggests that the Commission instruct RTOs to work cooperatively with

facility owners, since ratings on most power transmission equipment are a function of age

and past usage, and a new entity will not have such historical information.

Southern Company states that transmission owners have responsibilities to their

shareholders and State commissions to operate their equipment safely and reliably. 

SPRA believes that this proposal has the potential to create significant liability risks for

the United States.

Entergy believes that a transco has an advantage at performing this function

because it will have the natural incentive to maintain the highest and safest ratings for the

transmission facilities since it will be solely and directly responsible for the risks and

rewards of equipment ratings.

Comments on Liability for Actions

Given that an RTO has responsibility for system reliability, the NOPR requested

comments on the appropriate extent of an RTO's liability for its actions, and whether

RTO facility ownership changes this determination. 429
Docket No. RM99-2-000 -308-

430See, e.g., Seattle, PGE, Desert STAR, PSNM, South Carolina Authority.

431See, e.g., NY ISO, Cal ISO, Nevada Commission, New York Commission.

Most commenters believe that liability must be linked to the entity operating and

controlling the transmission assets. Several commenters recommend that all RTO

governing documents and operating agreements clearly establish the RTO’s liability for

any facilities that it operates but does not own. 430 SRP recommends that the

Commission not set a hard and fast rule, but rather give deference to assignments of

liability worked out between the RTO and the transmission owner in the course of

negotiating an operating agreement.

Salomon Smith Barney believes that an RTO should be paid to run the network,

and should suffer the consequences if it is not run well. Given this reasoning, it believes

that an RTO requires sufficient capital to bear the risk, and that it operates under a

regulatory scheme that acknowledges that higher risk taking requires a higher return.

Other commenters focus on how to apportion liability. Several commenters

suggest that the governing standard for liability for a particular activity should be the

same standard that the Commission has approved for comparable ISO conduct. Thus, for

example, the RTO would be subject to liability only on account of its reliability activities

when damage caused by its actions is found to be the result of gross negligence or

intentional misconduct. 431
Docket No. RM99-2-000 -309-

432See, e.g., Avista, Minnesota Power, SPRA, MidAmerican, Florida Power Corp.

Other commenters believe that, if the RTO assumes authority to ensure proper

maintenance and reliability of the system, it should assume that role fully (i.e., assume

liability for its decisions) and it should hold transmission owners harmless for any

increased cost responsibility. 432

Tri-State believes that an RTO should not be held liable for the inevitable errors

and omissions that will occur during transmission system operations except in the

instance of gross negligence. It believes that without some form of indemnification, the

RTO could be the target of numerous lawsuits alleging financial harm as a result of RTO

actions.

TANC believes that the RTO should be held liable for the consequential damages

resulting from the RTO’s instructions, if damage is caused to the transmission owners

facilities as a result of the RTO requiring a transmission owner to operate its facilities in a

manner that is inconsistent with prudent utility practice.

Comments on Reliability Standards

In the NOPR, the Commission expressed a potential concern regarding an RTO’s

implementation of reliability standards that are established by another entity. The

Commission identified two specific concerns: (1) regional or sub-regional reliability

groups may not be as independent from market participants as RTOs; and (2) almost
Docket No. RM99-2-000 -310-

433FERC Stats. & Regs. ¶ 32,541 at 33,738-39.

434See, e.g., Entergy, NECPUC, NASUCA.

every reliability standard will have a commercial consequence. The NOPR proposed to

require an RTO to notify the Commission immediately if implementation of externally

established reliability standards will prevent it from meeting its obligation to provide

reliable, non-discriminatory transmission service. 433

Most commenters generally support the proposal in the NOPR, although a few

commenters believe that the NOPR proposal does not go far enough. On the other hand,

some commenters seek clarification or oppose the NOPR proposal; most commenters that

oppose the NOPR proposal believe that RTOs must be subordinate to national or regional

reliability groups.

PJM/NEPOOL Customers and other commenters agree that the RTO is an

appropriate institution to evaluate whether other rules and requirements are impacting its

ability to perform its function and to inform the Commission of this fact. 434

PSE&G requests that the Commission clarify in its Final Rule that RTOs, not

reliability trade associations, will have primary responsibility for resolving reliability

issues in the future. It suggests that reliability trade associations can continue to play a

role in developing reliability standards to be incorporated into RTO tariffs; these

standards would then be implemented by the RTOs and ultimately enforced by the FERC. 
Docket No. RM99-2-000 -311-

435See, e.g., Cal ISO, Duquesne, Nevada Commission, Statoil.

The standards, however, must be developed through a fair and open consensus process,

such as the American National Standards Institute (ANSI) process.

EPSA believes that reliability standards should be uniform throughout the United

States. Reliability standards should be established at the national level through an

industrywide representative organization, subject to review and approval by the

Commission. Reliability rules should deviate regionally only if necessary to reflect

specific operating conditions that are unique to a particular region. EPSA requests that

existing reliability rules be considered carefully by the RTO, and reviewed by the

Commission, as to their function and importance. EPSA and other commenters suggest

that RTOs replace existing regional reliability councils as the entity responsible for

maintaining compliance with nationally established reliability standards. 435

Conlon claims that the RTO must have the ability to establish various reliability

standards that every participant. He suggests that the RTO, or the Commission with

delegated authority to the RTO, set mandatory standards and impose sanctions or fines

for violations.

Cal ISO believes that RTOs are the appropriate entities to establish reliability

standards. Regional organizations (not a single national standard-setter) should have the

flexibility to develop standards that reflect regional priorities as well as individual issues
Docket No. RM99-2-000 -312-

related to particular areas or configurations in the transmission grid. It recommends that

RTOs have the authority and responsibility to develop regional reliability standards,

subject to general oversight by an appropriate independent national reliability

organization such as NAERO.

Similarly, Entergy believes that the RTO should have the primary role, authority

and responsibility to adopt, implement and enforce regional reliability standards. Entergy

further argues that this authority must be subject to regional oversight, especially as to

reliability issues between and among interconnected RTOs.

Some commenters argue that the Commission should provide additional authority

to RTOs. For example, PJM believes that an RTO should have exclusive authority for

administering the regional reliability of the bulk power system. It argues that no entity

external to an RTO’s region should have authority to dictate reliability rules that

adversely affect the reliability in a region served by an RTO. Thus, PJM believes the

Commission should extend this proposal beyond the proposed reporting requirement. In

its opinion, RTOs that are responsible for a particular area of the bulk power market

system best can develop tools that are designed to meet the needs of their individual

areas. PJM requests that the Commission insist in its rule that RTOs play a significant

role in setting any national reliability standards. Sithe suggests that RTOs should also

have independent authority to modify existing rules, and/or to place new rules before the
Docket No. RM99-2-000 -313-

436See, e.g., Canada DNR, Manitoba Board, Cal DWR, Entergy, Minnesota

Commission, PSE&G.

Commission for its review and approval in order to promote rules that intrude less into

the markets and that promote efficiency goals, as well as system reliability.

Illinois Commission argues that the proposal is not adequate and that the

Commission must more directly address the concern over lack of independence between

reliability standards development, enforcement organizations and commercial market

interests. Illinois Commission suggests some possibilities: (1) require NERC/regional

reliability council reform so that the process of establishing and enforcing reliability

guidelines, standards, and policies is independent of discriminatory

generation/transmission owner influence; (2) require that all NERC/regional reliability

council guidelines, standards, and policies be approved by FERC prior to their adoption;

or (3) reform NERC so that it is independent of generation/transmission owners, then

eliminate MAIN and ECAR and require the Midwest ISO to act as the regional standards

setting entity and as the reliability enforcement entity for the Midwest Region.

A few commenters seek clarification. 436 British Columbia Ministry requests that

the Commission clarify how the RTO roles and responsibilities overlap with duties

outlined for the Self Regulating Reliability Organization in the North American Electric

Reliability Council's draft legislation. New York Commission and Iowa Board request
Docket No. RM99-2-000 -314-

that the Commission recognize the authority of the states to require the maintenance of

electric system reliability. 

NERC and several other commenters generally oppose the proposal. NERC urges

the Commission to include an obligation that the RTO adhere to the reliability rules

adopted by NERC and the relevant regional reliability council as a condition of becoming

an RTO. NERC states that RTOs must be designed, implemented and operated consistent

with NERC operating and planning policies. NERC notes it will revise its operating and

planning policies to recognize and accommodate these emerging institutions, as

necessary.

Several commenters such as Duke and SERC supports the work of NERC to

establish consistently applied reliability standards and supports NERC’s authority to

enforce these standards. Duke also supports NERC and the regional reliability councils

continuing to play a vital role in setting reliability standards. NERC oversight of

reliability should prevent different RTOs from applying different standards and will

ensure that inter-RTO reliability matters will be dealt with effectively. CEA suggests that

the reliability responsibilities authorized for RTO's be respectful of the carefully balanced

design of the evolving NERC/NAERO.

SRP requests that each RTO be required to join NERC, or NAERO when formed. 

In addition, other commenters such as SRP and Los Angeles propose that RTOs be
Docket No. RM99-2-000 -315-

437The Commission has authorized the establishment of the New York State

Reliability Council and has accepted the relationship between it and the NY ISO.

required to use planning and design criteria that comply with the criteria established by

the appropriate NERC (or NAERO when established) regional reliability council. 

NYPP believes that properly constituted local and regional reliability councils

authorized by FERC should have the authority to establish criteria necessary to maintain

the reliability of the transmission system including the reliability of discrete locations

(e.g., the supply of reactive power to support voltage in load pockets). 437

FirstEnergy requests that the role of the regional reliability councils be clarified 

with respect to regional RTOs. Also it would have us identify the need boundaries so

that each RTO reports only to one regional reliability council. In addition, the regional

reliability councils may need to undergo a transformation similar to NERC/NAERO to

expand the role of the various industry segments.

Commission Conclusion

The Commission adopts the proposal in the NOPR that the RTO must have

exclusive authority for maintaining the short-term reliability of the grid that it operates. 

Although many commenters support this requirement, some pose additional questions

regarding how this function will be performed by the RTO. Some commenters request

that the Commission define better the time period associated with "short-term" reliability. 

We clarify that the term "short-term" is intended to cover transmission reliability
Docket No. RM99-2-000 -316-

responsibilities short of grid capacity enhancement. It includes all time periods, including

but not limited to "real-time," necessary for the RTO to satisfy its reliability

responsibilities, up to the planning horizon. There is no time gap between what is

included within short-term reliability and the RTO's planning responsibilities.

Commenters also request more specificity in describing the RTO's functions. The

facilities that will be under RTO control, the specific functions that the RTO must

perform, and how the RTO will execute its responsibilities and direct operations, are all

defined above in the section on operational authority. PJM's additional request that the

RTO have authority to collect information is discussed in both the operational authority

and the market monitoring sections. 

PG&E requests that the RTO rely on market mechanisms to maintain short-term

reliability. PJM/NEPOOL Customers requests that reliability and commercial activities

be kept separate. We will not require the RTO to rely on market mechanisms in every

instance to maintain short-term reliability. The Commission believes that some reliability

functions may not be conducive to supply through competitive market mechanisms since

a reliable power system provided to one customer cannot be withheld from other

customers, viz., many reliability functions are, in economic terms, "public goods." In

Order No. 888, we identified some functions necessary to maintain grid reliability as

ancillary services and required them to be provided as separate products. These services
Docket No. RM99-2-000 -317-

and their potential inclusion in emerging markets is discussed in the section on ancillary

services below. We cannot conclude at this time that it is appropriate to rely solely on

market mechanisms to supply the reliability functions that the transmission system

operator must perform, but we expect that over time most of the generation services that

perform these functions will be competitively procured.

Interchange Scheduling 

We conclude that the RTO must have exclusive authority for receiving, confirming

and implementing all interchange schedules, which are often coincident with schedules

for unbundled transmission service. This function will automatically be assumed by

RTOs that operate a single control area. If the RTO structure includes control area

operators who are market participants or affiliated with market participants, the RTO will

have the authority to direct the implementation of all interchange schedules. As stated in

the NOPR, a remaining concern is that non-RTO control area operators, who are also

competitors in energy markets, have unequal access to commercially sensitive

information and could use this knowledge of their competitors' schedules and transactions

to gain an unfair competitive advantage in the energy markets. In the event that the RTO

filing includes a structure in which non-RTO control area operators receive sensitive

information, we will require the RTO to monitor for any unfair competitive advantage,

and report to the Commission immediately if problems are detected. In addition, to
Docket No. RM99-2-000 -318-

438Redispatch for congestion management is addressed under different rules, as

discussed in the section on congestion management.

address concerns about protecting commercially sensitive information, we will require the

RTO or any entities who operate control areas within the RTO's region that require access

to commercially sensitive information to sign agreements that separate reliability

personnel and the relevant information they receive from their wholesale merchant

personnel.

Redispatch Authority

We conclude that the RTO must have the right to order the redispatch of any

generator connected to the transmission facilities it operates, if necessary for the reliable

operation of the transmission system. 438 We also require each RTO to develop

procedures for generators to offer their services and to compensate generators that are

redispatched for reliability. In order to maintain the reliability of the transmission

system, the entity that controls transmission must also have some control over some

generation. In general, we believe this control should be through a market where the

generators offer their services and the RTO chooses the least cost options. This authority

does not extend to initial unit commitment and dispatch decisions for generators. 

However, for reliability purposes, the RTO should have full authority to order the

redispatch of any generator, subject to existing environmental and operating restrictions

that may limit a generator's ability to change its dispatch.
Docket No. RM99-2-000 -319-

439In general, a power system can be in one of three states: normal, emergency

and restorative. When all constraints and loads are satisfied, the system is in its normal

state; when one or more physical limits are violated, the system is in an emergency state;

and when part of the system is operating in a normal state yet one or more of the loads is

not met (partial or total blackout), the system is in a restorative state.

Some commenters request that we define what is meant by redispatch for

reliability. We clarify that we intend the authority for generator redispatch to be used by

the RTO to prevent or manage emergency situations, such as abnormal system conditions

that require automatic or immediate manual action to prevent or limit equipment damage

or the loss of facilities or supply that could adversely affect the reliability of the electric

system, or to restore the system to a normal operating state. 439

Transmission Maintenance Approval

We conclude that, when the RTO operates transmission facilities owned by other

entities, the RTO must have authority to approve and disapprove all requests for

scheduled outages of transmission facilities to ensure that the outages can be

accommodated within established reliability standards. Control over transmission

maintenance is a necessary RTO function because outages of transmission facilities affect

the overall transfer capability of the grid. If a facility is removed from service for any

reason, the power flows on all regional facilities are affected. These shifting power flows

may cause other facilities to become overloaded and, consequently, adversely affect

system reliability.
Docket No. RM99-2-000 -320-

440Since some of these transmission owners may also own generation, they may

have an incentive to schedule transmission maintenance at times that would increase the

prices received from their power sales. A transmission company, not affiliated with any

generators, would not have these same incentives.

The RTO is expected to base its approval on a determination of whether the

proposed maintenance of transmission facilities can be accommodated within established

state, regional and national reliability standards. The RTO's regional perspective will

allow it to coordinate individual maintenance schedules with other RTOs as well as with

expected seasonal system demand variations. Since the RTO will have access to

extensive information, it will be able to make more accurate assessments of the reliability

effect of proposed maintenance schedules than individual, sub-regional transmission

owners.

If the RTO is a transmission company that owns and operates transmission

facilities, these assessments will be an internal company matter. However, if there are

several transmission owners in the RTO region, the RTO will need to review transmission

requests made by the various transmission owners. 440 In this latter case, we expect the

RTO to: receive requests for authorization of preferred maintenance outage schedules;

review and test these schedules against reliability criteria; approve specific requests for

scheduled outages; require changes to maintenance schedules when they fail to meet

reliability standards; and update and publish maintenance schedules as needed.
Docket No. RM99-2-000 -321-

We conclude that, if the RTO requires a transmission owner to reschedule planned

maintenance, the transmission owners should be compensated for any costs created by the

required rescheduling only if the previously scheduled outage had already been approved

by the RTO. 

We encourage the RTO to establish performance standards for transmission

facilities under its direct or contractual control. Such standards could take the form of

targets for planned and unplanned outages. The rationale for this requirement is that two

transmission owners should not receive equal compensation if one owner operates a

reliable transmission facility while the other operates an unreliable facility. For RTOs

that are transcos, we will require that such quality standards be made explicit in any rate

proposal.

Generation Maintenance Approval

We conclude that the RTO is not required to have authority over proposed

generation maintenance schedules. However, we acknowledge that there are reliability

advantages to the RTO having this authority, and we would accept RTO proposals where

the participants choose to grant the RTO such authority. In our order approving the

Midwest ISO, we observed that "the dividing line between transmission control and

generation control is not always clear because both sets of functions are ultimately
Docket No. RM99-2-000 -322-

441Midwest ISO, 84 FERC at 62,180.

required for reliable operation of the overall system." 441 Because of this close

connection between generation and maintenance of system reliability, it is essential for

generator owners and operators to provide the RTO with advance knowledge of planned

generation outage schedules so that the RTO can incorporate this information into its

reliability studies and operations plan. However, although a generator may be required to

submit its maintenance schedule to an RTO, the RTO should be prohibited from sharing

that information with any other market participants, or affiliates of market participants.

Facility Ratings

After consideration of the comments, we conclude that is inappropriate here to

require RTOs to establish transmission facility ratings. We encourage, however, such

ratings to be determined, to the extent practical, by mutual consent of the transmission

owner and the RTO, taking into account local codes, age and past usage of the facilities. 

The Commission acknowledges the concern that changes in existing equipment

ratings may lead to problems of equipment safety and possible damage. We further

recognize that the RTO may initially need to rely upon existing values for equipment

ratings and operating ranges so as not to disrupt reliable system operation. However, as

an RTO gains experience operating or directing the operation of the transmission

facilities in its region, we expect this responsibility to migrate to the RTO, as facility
Docket No. RM99-2-000 -323-

ratings have at least an indirect effect on the ability of the RTO to perform other RTO

minimum functions (e.g., planning and expansion, ATC and TTC). If there is a dispute

over equipment ratings, the parties should pursue resolution through an ADR process

approved by the Commission.

Liability

After consideration, we will determine the extent of RTO liability relating to its

reliability activities on a case-by-case basis.

Reliability Standards

We conclude that the RTO must perform its functions consistent with established

NERC (or its successor) reliability standards, and notify the Commission immediately if

implementation of these or any other externally established reliability standards will

prevent it from meeting its obligation to provide reliable, non-discriminatory transmission

service.

E. Minimum Functions of an RTO

In the NOPR, we proposed seven minimum functions that an RTO must perform. 

In general, we proposed that an RTO must: 

(1) administer its own tariff and employ a transmission pricing system that will

promote efficient use and expansion of transmission and generation

facilities; 
Docket No. RM99-2-000 -324- 

442FERC Stats. & Regs. ¶ 32,541 at 33,739-740. The authority to file changes in

the RTO tariff is discussed above under the Independence Characteristic.

(2) create market mechanisms to manage transmission congestion; 

(3) develop and implement procedures to address parallel path flow issues; 

(4) serve as a supplier of last resort for all ancillary services required in Order

No. 888 and subsequent orders; 

(5) operate a single OASIS site for all transmission facilities under its control

with responsibility for independently calculating TTC and ATC; 

(6) monitor markets to identify design flaws and market power; and 

(7) plan and coordinate necessary transmission additions and upgrades. 

We basically affirm these seven functions with the clarifications and revisions as noted

below. In addition, we have added interregional coordination as an eighth minimum

function, as discussed below.

1. Tariff Administration and Design (Function 1)

Sole Administrator of Tariff

In order to ensure non-discriminatory service within the region, the NOPR

proposed that the RTO be the sole administrator of its own transmission tariff. 442 The

RTO would thus be the sole authority making decisions on the provision of transmission

service including decisions relating to new interconnections. The NOPR requested

comments on several aspects of this standard, including how the authority over
Docket No. RM99-2-000 -325- 

443See, e.g., Allegheny, APX, SMUD, NASUCA, NY ISO, East Kentucky,

Utilicorp, JEA, LG&E, Enron/APX/Coral Power, EPSA, South Carolina Authority, First

Energy, Cal DWR, California Board, PacifiCorp and NSP.

444PJM.

445PJM/NEPOOL Customers.

446UAMPS.

interconnections would work for ISOs that do not own transmission and would not be

performing the construction. The NOPR also sought comment on whether authority over

interconnection should apply to all new interconnections, including those for reliability

and connections to other regions.

Comments

The vast majority of commenters addressing these issues agree with the proposal

that the RTO be the sole administrator of its own tariff. 443 Commenters noted many of

the benefits of an RTO being the sole tariff administrator: it will eliminate confusion;

reduce transactions costs; assure that access decisions are independent; 444 reduce

reliability concerns; 445 and ensure consistent ratemaking across the RTO. 446 Some

commenters suggest that their respective organizations already meet this requirement,

including ISO-NE and NY ISO, which ask whether sharing authority with transmission

owners for non-discriminatory access meets the standard.
Docket No. RM99-2-000 -326- 

447Entergy.

448Illinois Commission.

449Canada DNR.

450New Smyrna Beach.

451See, e.g., Entergy, PJM, South Carolina Authority, Southern Company, TriState, Desert STAR, East Texas Cooperatives, Enron/APX/Coral Power, Sithe and

PG&E.

452Cal ISO.

But some of the commenters that support the proposal had specific concerns and

suggestions: the Commission should adopt specific pricing regulations and expressly

permit expedited declaratory orders on pricing; 447 the Commission should take a more

active approach in developing innovative rates; 448 there may be a problem for an RTO

located in both the United States and Canada if there is disagreement over the tariff by

the respective authorities; 449 and quicker decisions are likely if a stakeholder board is not

involved. 450

A number of commenters also supported the proposal with respect to the RTO's

authority over interconnections. 451 Some of these commenters expressed concerns and

recommendations about the Commission's proposal, e.g., transmission owners should be a

part of the decision process; 452 transcos will be better able to integrate interconnection

decisions into a unified strategy covering investment, operations, maintenance and facility
Docket No. RM99-2-000 -327- 

453Duke.

454Minnesota Power.

455PG&E.

456Southern Company.

457Distributed Power and EAL.

458SPRA.

459TANC.

design; 453 RTOs should not have the authority to deny a generator that is not optimally

located on the grid; 454 interconnection policy should rely more heavily on market

mechanisms; 455 the transmission owner should develop the actual interconnection

agreement to insure adequate protections for its equipment; 456 national fees and technical

standards should be established for interconnections; 457 authority over interconnections

should involve coordinated planning and construction, not "autonomous, unilateral

authority"; 458 RTOs need to develop procedures and guidelines so that there are no

adverse impacts of interconnection on existing facilities; 459 RTOs should have authority

to assess the impact of a new interconnection on regional facilities but should only have
Docket No. RM99-2-000 -328- 

460Metropolitan.

461Williams.

authority over interconnections involving RTO facilities, not all regional facilities; 460

and an RTO must be required to show harm to deny an interconnection request. 461

A few commenters opposed the Commission's proposal or suggested making

significant modifications. With respect to tariff administration, Seattle opposes the

Commission giving RTOs with small control areas blanket authority to approve new

interconnections and also argues that the RTO should not be given authority over the

interconnection of customer based backup and load shaving generators, QFs, or

subtransmission and radial transmission facilities (used to reinforce municipal grids). 

TXU Electric argues that the Commission should be more flexible and allow RTOs to

choose whether to administer the tariff of other entities. TXU Electric notes that in

ERCOT, each owner has its own tariff with its own revenue requirement but with

uniform terms and conditions of access and that this approach can protect the owner

better than an RTO tariff. Florida Commission recommends that the question of tariff

administration be determined on a regional basis with endorsement by state regulators.

With respect to RTO authority over interconnections, Mass Companies argues that

the RTO should not have the authority over interconnections because such authority is

unlawful, impairs reliability, and because the transmission owner is in a better position to
Docket No. RM99-2-000 -329- 

perform this function. SRP suggests that an RTO’s exclusive right to administer its own

tariff and the right to control interconnections may establish a property right that would

jeopardize a public power’s tax free status by being declared a private business use. This

would be a potential problem if the RTO were not a governmental entity or a 501(c)(3)

non-profit organization. To prevent this, SRP says that the RTO would have to be

structured carefully with these concerns in mind. DOE indicates that the authority over

interconnection is a concern for PMAs because of the NEPA requirements which must be

accommodated. Industrial Consumers would amend the proposed Regulatory Text on

tariff administration to add "throughout the interconnection within which the Regional

Transmission Organization resides" to the requirement to promote efficient use and

expansion. Industrial Consumers also propose that the Regulatory Text on

interconnection be amended to add the responsibility to coordinate transmission needs

across the interconnection. Finally, Industrial Consumers would amend the provision that

RTOs review and approve requests for new interconnections to add "by new loads that

take service at transmission voltages and by any new generation resource regardless of

the nominal voltage at the generator's point of interconnection. Any proposal to increase

the nameplate-rated capacity at an existing generating site shall be treated as a new

request for interconnection" to clarify that the RTO is to authorize such interconnections

and minimize entry barriers to new sources of generation.
Docket No. RM99-2-000 -330- 

462Of course, eligible applicants always have the right to seek interconnections

from the Commission pursuant to sections 202(b) and 210 of the FPA.

463See, e.g., ISO-NE at 9.

Commission Conclusion

We note the strong support for this standard in the comments and we adopt the

NOPR's requirement that the RTO be the sole provider of transmission service and sole

administrator of its own open access tariff. Included in this is the requirement that the

RTO have the sole authority for the evaluation and approval of all requests for

transmission service including requests for new interconnections. 462

With the RTO the sole provider of transmission service, transmission customers

have a nondiscriminatory and uniform access to regional transmission facilities. This

type of access cannot be assured if customers are required to deal with several

transmission owners with differing tariff terms and conditions. As noted in the NOPR, the

RTO must be the provider of transmission service in the strong sense of the term. Mere

monitoring and dispute resolution are insufficient to meet the requirements of this

standard.

The requirement that the RTO administer its own tariff and not the tariff or tariffs

of other entities received little objection in the comments, even from ISOs where this

requirement is not currently being met. 463 One commenter, SCE&G proposes that the

RTO's tariff only cover its own costs and wheeling. The transmission owners would
Docket No. RM99-2-000 -331- 

maintain standard open access tariffs which would be administered by the RTO. We

reject this proposal. To provide truly independent and nondiscriminatory transmission

service, the RTO must administer its own tariff and have the independent authority to file

tariff changes.

Mass Companies argues that the RTO is not in as good a position as transmission

owners to judge requests for new interconnections. SPRA and Metropolitan suggest that

an RTO's authority over new interconnections should be limited. Because the ability for

customers to obtain nondiscriminatory access to the regional transmission system,

whether over existing facilities or over new facilities, is integral to a competitive market

for generation, we reject these proposals to modify our original position on new

interconnections.

Other commenters, as noted above, support this standard but have specific

concerns they would like to see the Commission address. The concerns listed do not

cause us to change our original proposal. These concerns, to the extent they apply,

should be voiced at the time RTO proposals are filed and they will be considered on a

case-by-case basis.

Multiple Access Charges

The NOPR proposed that the RTO's tariff must not result in transmission

customers paying multiple access charges. We affirm that proposal in this Final Rule. 
Docket No. RM99-2-000 -332- 

464FERC Stats. & Regs. ¶ 32,541 at 33,741-43.

Because the issue of multiple access charges is a rate issue, we discuss in detail the

comments we received on this issue, the reasons for our conclusion, and the concepts of

pancaked rates, license plate rates, and uniform access charges in Section III.G of this

Final Rule addressing transmission ratemaking policy for RTOs. 

2. Congestion Management (Function 2)

In the NOPR, we proposed to include congestion management as a minimum

function that an RTO must perform. 464 Specifically, we proposed to require the RTO to

ensure the development and operation of market mechanisms to manage transmission

congestion. We proposed that the RTO must either operate such markets itself or ensure

that the task is performed by another entity that is not affiliated with any market

participant. In carrying out this function, we stated that the RTO must satisfy certain

standards or demonstrate that an alternative proposal is consistent with or superior to

satisfying the standard. We further proposed that the market mechanisms must

accommodate broad participation by all market participants, and must provide all

transmission customers with efficient price signals regarding the consequences of their

transmission usage decisions. We proposed to allow RTOs considerable flexibility in

experimenting with different market approaches to managing congestion through pricing. 

However, we stated that proposals should ensure that (1) the generators that are
Docket No. RM99-2-000 -333- 

465Id. at 33,754-55.

dispatched in the presence of transmission constraints are those that can serve system

loads at least cost, and (2) limited transmission capacity is used by market participants

that value that use most highly. We asked for comments as to what specific requirements,

if any, may best suit these goals. 465

We stated in the NOPR that traditional approaches to congestion management such

as those that rely exclusively on the use of administrative curtailment procedures may no

longer be acceptable in a competitive, vertically de-integrated industry. We thus

concluded that efficient congestion management requires a greater reliance on market

mechanisms, and stated our belief that a large regional organization like an RTO will be

able to create a workable and effective congestion management market. We stated that

while it is our intent to give RTOs considerable flexibility in experimenting with different

market approaches to managing congestion, we believe that a workable market approach

should establish clear and tradeable rights for transmission usage, promote efficient

regional dispatch, support the emergence of secondary markets for transmission rights,

and provide market participants with the opportunity to hedge locational differences in

energy prices.

The Commission invited comments on the requirement that RTOs must be

responsible for managing congestion with a market mechanism, and posed the following
Docket No. RM99-2-000 -334- 

466See, e.g., United Illuminating, CSU, Duke, NASUCA, Los Angeles, NYPP,

DOE, SMUD, Otter Tail, PG&E, FirstEnergy, Mass Companies, Enron/APX/Coral

Power, Nevada Commission.

questions. Can decentralized markets for congestion management be made to work

effectively and quickly? Can the RTO's role be limited to that of a facilitator that simply

brings together market participants for the purpose of engaging in bilateral transactions to

relieve congestion? If not, will these markets require centralized operation by the RTO or

some other independent entity? How can an RTO ensure that enough generators will

participate in the congestion management market to make possible a least-cost dispatch? 

Are there any special considerations in evaluating market power in a congestion market

operated or facilitated by an RTO? In addition, we proposed to allow up to one year after

start-up for this function to be implemented. We noted that market approaches to

congestion management may take additional time to work out, and asked for comments

on whether this additional implementation time period is warranted, and whether one year

is an appropriate additional time period.

Comments

Using Market Mechanisms to Manage Congestion

Although opinions vary as to the proper role of the RTO in managing congestion,

many commenters believe that efficient congestion management requires greater reliance

on market mechanisms. 466 CSU believes that congestion management is uniquely
Docket No. RM99-2-000 -335- 

467See, e.g., NERC, Sithe, NASUCA, Cinergy, Professor Hogan, PJM, Dr. Ilic.

amenable to a market solution. CSU states that there will be a continuing need for some

type of market mechanism to address constraints and this mechanism is best established

at the regional level and best placed with an entity independent of wholesale power

market participants. 

Some commenters emphasize that it is better to use market mechanisms to manage

congestion than to rely on the physical interruption of power flows. 467 NERC contends

that if the industry had in place more market-oriented mechanisms that dealt effectively

with constraints, then the frequency of transmission loading relief (TLR) procedures

would decrease. Professor Hogan claims that with efficient pricing, users have the

incentive to respond to the requirements of reliable operation. He asserts that, absent

such price incentives, market choices would need to be curtailed in order to give the

system operator enough control to counteract the perverse incentives that would be

created by prices that did not reflect the marginal costs of dispatch. PJM/NEPOOL

Customers argues that, when faced with a transmission congestion circumstance, the RTO

should redispatch generators to the extent possible.

Also, Statoil claims that the use of TLR procedures is inherently discriminatory. 

Statoil claims that most transmission owners serving retail load do not engage in

interchange transactions or use the pro forma tariff at the same level as new competitive
Docket No. RM99-2-000 -336- 

468See, e.g., PJM, Professor Hogan, CSU, Sithe, NERA, Duke, PJM/NEPOOL

Customers, H.Q. Energy Services, Minnesota Power, FTC.

469See, e.g., APX, SPP, South Carolina Authority, Alliant Energy, WPSC, NSP,

TANC, Williams.

market entrants attempting to enter historically captive markets. Statoil thus argues that,

even if TLR is applied in a comparable manner, it will still disproportionately and

adversely affect new competitive market entrants.

Role of the RTO in Congestion Management

Commenters offer a variety of views concerning the proper role of the RTO in

congestion management. Some advocate an active role for the RTO in operating an

energy market that is highly centralized. 468 Others envision the RTO's role as being

much smaller, perhaps limited to that of a facilitator that brings together market

participants for the purpose of engaging in voluntary transactions to relieve

congestion. 469 Still others, such as Southern Company and EEI, believe that RTOs are

not necessary to make congestion management work. EEI argues that while congestion

management does require a coordinated regional or interconnection-wide solution, it does

not require the extensive infrastructure and responsibilities associated with what the

Commission has proposed to define as RTOs. EEI notes that NERC’s Congestion

Management Working Group is exploring available options for congestion management,

independently of whether RTOs exist.
Docket No. RM99-2-000 -337- 

PJM/NEPOOL Customers believes that an independent entity must operate any

congestion management market. It believes also that that entity must have sufficient

power and centralization to address congestion problems effectively and quickly. 

Consequently, it urges the Commission not to consider proposals that include a

decentralized market for congestion management or that limit the RTO role to that of a

facilitator of bilateral transactions to relieve congestion. In addition, it contends that the

RTO must retain sufficient authority over generators that choose to make themselves

available to ensure that those generators will participate in the congestion management

market. Duke states that, eventually, decentralized markets may organize in a manner to

accomplish effective congestion management, but at this time, the congestion

management function should be centrally managed.

PJM claims that RTOs can facilitate efficient, broad-scale congestion

management. PJM states that by combining multiple transmission systems over a large

geographic region, an RTO can have an effective pricing system to price efficiently actual

transmission flows in a region. PJM argues that not only should the Commission require

that RTOs be responsible for managing congestion with market mechanisms, the

Commission also should prohibit any other entity from acting in a manner that detracts

from the RTO’s ability to employ its market mechanisms.
Docket No. RM99-2-000 -338- 

Cleveland believes that an effective way to manage congestion may be to combine

a market-based mechanism with a power exchange. It states that the RTO's redispatch

function and the bidding process available through a power exchange should jointly

operate to minimize the congestion. 

 H.Q. Energy Services contends that control over the management of congestion

goes hand-in-hand with control over reliability. It believes that, ideally, an RTO should

establish a congestion pricing system that manages congestion with minimal operator

intervention. However, H.Q. Energy Services argues that, without control over

reliability, an RTO will not be in the position to accurately and fairly allocate available

transmission capacity because it cannot send the correct congestion pricing signals.

Sithe contends that the Commission should not allow overly decentralized systems

whereby individual utilities in a region continue to manage congestion relief, especially if

those utilities continue to own generation. Arkansas Consumers believe that the RTO's

congestion management function helps provide a remedy for any anti-competitive activity

on the part of generators or transmission owners. First Rochdale contends that only fully

independent operation of an RTO is likely to lead to open markets in which all entities

can compete freely. Duke asserts that there are no special considerations in evaluating

market power in a congestion market operated or facilitated by an RTO.
Docket No. RM99-2-000 -339- 

Other commenters stress that the RTO's role in managing congestion using market

mechanisms should be strictly limited. Indeed, the South Carolina Authority opposes a

centralized arrangement for managing congestion as being unduly restrictive and perhaps

anti-competitive. WPSC argues that the role of the RTO should be limited to acting as a

clearinghouse so that market participants are aware of the range of alternatives available

for dealing with congestion. WPSC contends that the market will then dictate which

mechanisms are used in any particular instance. SPP suggests that the RTO can be a

facilitator of congestion relief and that there is no need for the Commission to require that

the RTO adopt a centralized approach, such as locational marginal pricing, for managing

congestion. SPP states that it is a facilitator of congestion relief and intends to continue

in that role under its new proposal. SPP states that it will identify which generators can

relieve a constraint and the relative impact of redispatching those generators. It will then

be the customer’s responsibility to contract with the owner of these generators for

redispatch services. SPP notes that this method relies on the market and bilateral

contracts for the redispatch solutions. SPP claims that the market can also provide for

price assurance and for long-term redispatch obligations. PG&E claims that with the

proper information, bilateral market-based redispatch could be used within an hour of the

occurrence of congestion on any part of the controlled system. 
Docket No. RM99-2-000 -340- 

APX argues that the RTO should not conduct the trading process because it will

impede the adaptation of trading to market conditions, which is essential for market

development. APX claims that all competitive industries use decentralized trading

through forward contracts, and no competitive industry uses a central bidding agent to

create its market. Consequently, APX believes that the Commission should limit the

RTO’s role in congestion management to that of a provider of last resort. PG&E argues

that although the RTO may administer certain market mechanisms such as congestion

management, it is important that the RTO not view itself as responsible for energy pricing

and other aspects of supply and demand interactions, all of which, PG&E contends, can

be most effectively managed by the market unless material and lasting market flaws are

present.

Similarly, Cinergy argues that the mechanism for price transparency in the

commodity market should be developed and implemented by the market, not the RTO. 

Cinergy recognizes, however, that an economic congestion management system depends

on a power market mechanism that provides price transparency for determining economic

dispatch of generation. Consequently, Cinergy notes, RTOs will be confronted with

issues of applying an economic dispatch valuation mechanism. Cinergy argues that such

mechanism should evolve from the marketplace, not directly from the RTO. Cinergy

proposes that the RTO would administer the congestion management system, but would
Docket No. RM99-2-000 -341- 

470See, e.g., Otter Tail, NERC, Allegheny, EME, NASUCA, East Kentucky,

Williams, Minnesota Power, CSU. See also supra section III.D.3, which addresses the

appropriate scope of the RTO's operational authority.

not be involved in the commodity market infrastructure unless its involvement was

mutually agreeable among all stakeholders.

Williams claims that decentralized markets for congestion management, operating

under the auspices of RTOs, can work effectively and quickly in an environment in which

market participants have the correct incentives. Williams states that depending upon the

geographic size of RTOs and the extent of congestion within each, zones for congestion

management may have to be developed. Williams provides a detailed description of how

a zonal approach to congestion management can be implemented.

Both CP&L and Enron/APX/Coral Power believe that the role of the RTO in

congestion management should depend on the time frame in which the decisions are

being made. These commenters prescribe different roles for the RTO in each of three

different time frames.

The Direct Dispatch Authority of the RTO

While supporting the use of pricing and other market mechanisms to manage

congestion, a number of commenters state that an RTO must have authority to direct

redispatch if necessary to ensure grid reliability. 470 For example, Otter Tail contends

that the RTO should have direct authority to order redispatch of generation for purposes
Docket No. RM99-2-000 -342- 

of relieving congestion and during system emergencies. Otter Tail states that this

dispatch should be directed for the generating units that can most economically reduce

the congestion. Otter Tail states that because there is a need for immediate, real-time

response to system contingencies and to relieve transmission congestion, the RTO should

have control of generating units. East Kentucky contends that to effectively manage

congestion, the RTO must have absolute authority to order redispatch of all generators on

the RTO transmission system. However, for this to work, East Kentucky states that the

RTO will have to compensate the generator with firm transmission service for the

additional out-of-pocket costs incurred due to the redispatch, plus an amount for lost

margins on lost revenue. It suggests that generators with non-firm transmission service

would have to redispatch as directed by the RTO but would have to bear their own costs.

NERC notes that market mechanisms may offer better ways of dealing with

congestion management than does physical interruption of power flows, but asserts that it

will always be necessary to have a non-market mechanism such as transmission loading

relief in place to ensure that the stability of the grid is always maintained. However,

EME believes that the extent of RTO control over dispatch of generation should be

carefully circumscribed to ensure maximum development of competitive markets in

wholesale power and ancillary services. Seattle contends that where transparent power

supply markets exist, price differences are widely known to the market and congestion
Docket No. RM99-2-000 -343- 

can be resolved bilaterally with no intervention by an RTO. PJM notes that since

implementing LMP, it rarely has needed to take emergency actions to alleviate

transmission congestion.

Minnesota Power believes that RTOs must have the authority to require that all

generators, existing and new, agree to redispatch as a condition of grid connection. 

Minnesota Power also believes that the RTO must have the authority to penalize

generators who subsequently refuse a redispatch order, or claim a false unplanned outage. 

CSU asserts that generation redispatch is essential in Front Range Colorado, which can

be expected to have an increasing population of gas-fired generation within the

boundaries of the constraints. It contends that the inability to redispatch these units for

any reason other than reliability would severely hinder the ability of an RTO to address

capacity constraints. 

MidAmerican states that, although congestion must be managed using pricing

signals from the market, circumstances may occur where immediate actions are required

and time does not permit normal bidding to allow the marketplace to respond. It contends

that during such events, the RTO must be required to follow previously established

procedures.

However, Seattle argues that the RTO should not have authority to redispatch

generation to accomplish congestion management without unanimous consent of the
Docket No. RM99-2-000 -344- 

471See, e.g., Williams, Powerex, Manitoba Board, Salomon Smith Barney.

stakeholders. Seattle notes that many Northwest generating plant operators are subject to

fishery-related hydroelectric dispatch constraints. Seattle states that because these

constraints are particular to the owners of the generating facilities, these resources are not

well suited to third party dispatch.

Managing Congestion by Eliminating It

Some commenters contend that the ultimate goal of RTOs should be the

elimination of congestion within their respective areas of control. 471 Powerex believes

that it is better to eliminate congestion at its source through facilities upgrades, if

economically and environmentally feasible, rather than attempting to manage congestion

on a long-term basis through congestion pricing schemes. Salomon Smith Barney

believes that the Commission has overemphasized congestion pricing as a vehicle to price

the existing network rather than as a vehicle to induce investment when such investment

is an economical alternative. 

TDU Systems state that they do not want management of significant transmission

congestion to become a long-term function of RTOs. They claim that minor congestion

(i.e., congestion that is economically dealt with through redispatch of generators) will

always be a feature of wholesale transmission markets, and an RTO should properly

manage it. However, they argue that an RTO should deal with significant persistent
Docket No. RM99-2-000 -345- 

472See, e.g., NASUCA, CMUA, NSP, PG&E, Statoil, SMUD, UtiliCorp,

PacifiCorp, PJM/NEPOOL Customers, Metropolitan, Cal DWR.

transmission congestion by constructing (or having constructed) the appropriate

transmission or generation facilities.

Desirable Attributes of Market Mechanisms

Many commenters offer their views on the desirable attributes of any market

mechanisms that are used to manage congestion. 472 For example, PJM/NEPOOL

Customers urges the Commission to employ three general criteria to evaluate any

proposal: simplicity, visibility and predictability. They state that the proposed approach

to relieve the congestion should be simple to administer, both for customers and for the

RTO. They believe that market participants should be able to examine the operation of

the congestion management mechanism on a real-time basis and verify that transmission

access is being appropriately accorded to entities that most desire transmission service. 

They state that such visibility will engender confidence by market participants in the

congestion management mechanism. In addition, they believe that the congestion

management mechanism must be predictable to all transmission users to determine the

anticipated price that will be necessary to ensure the continuation of transmission service

if congestion occurs. 

 Cinergy states that an economically efficient congestion management system must

begin with properly defining information posting requirements. Accordingly, Cinergy
Docket No. RM99-2-000 -346- 

argues that the Final Rule should ensure that requisite information on congestion is

posted on the OASIS. Similarly, Williams and Industrial Consumers believe that RTO

access to region-wide information on network conditions and power transactions, coupled

with efficient congestion management and well specified transmission rights, could help

RTOs in taking preemptive actions against potential curtailment incidents. Statoil and

EPSA believe that, ideally, economic rationing schemes should be uniform across RTOs

and should be implemented as an ancillary service under a regional transmission tariff. 

Montana Commission asserts that congestion management must be efficient. CMUA

believes that congestion management mechanisms must do their job, but not unreasonably

interfere with choices by market participants.

Some commenters believe that efficient congestion management requires a

transparent commodity market. Cinergy states that market mechanisms that include

locational pricing and financial rights for firm transmission have been successfully

implemented where they are supported by a power exchange or pool pricing mechanism

that provides market-clearing prices and price transparency. CalPX emphasizes the value

of a separate power exchange and argues that the bifurcation of the exchange and

transmission operator functions does not add to the market cost of congestion

management, as some have suggested. Also, Otter Tail believes that the development of

an hour-ahead power exchange within the RTO would improve grid reliability.
Docket No. RM99-2-000 -347- 

473See, e.g., PJM/NEPOOL Customers, United Illuminating, Allegheny, EPSA,

SMUD, Los Angeles, NASUCA, Duke, NERC, Professor Hogan, EME, PJM, DOE,

CSU.

474See, e.g., PJM/NEPOOL Customers.

475However, Montana Commission asks the Commission to specify more precisely

the nature of the pricing and congestion management methods that will satisfy the

NOPR's efficiency objectives. 

Many commenters support the NOPR's requirement that market mechanisms be

used to manage congestion and note the particular value of using price as a tool to

manage congestion. 473 Some commenters specifically endorsed the proposed

requirement that congestion pricing proposals must meet the two efficiency objectives set

forth in the NOPR. 474 PJM/NEPOOL Customers state that these two objectives are

fundamental to the operation of a market and to the ultimate goals of electricity supply

competition. 475 SMUD believes that a well-designed congestion management policy,

that provides proper locational price signals without creating opportunities for gaming or

cost shifting, will attract market participation. SMUD agrees that market participants

must be given efficient price signals concerning their use of the transmission system, but

claims that this is difficult because the existing transmission grid was not designed with

the capability to operate as a common carrier or to serve customers in an open access

manner. Also, a few commenters expressed doubts about the overall value of using
Docket No. RM99-2-000 -348- 

476See, e.g., LIPA, Transmission ISO Participants.

477See, e.g., EPSA, Tri-State.

478See, e.g., NASUCA, NJBUS, PJM/NEPOOL Customers, EPSA,

Enron/APX/Coral Power.

pricing mechanisms to manage congestion, 476 and others cited reasons to move

cautiously. 477 Tri-State is skeptical that market mechanisms for managing congestion

will lead to a least-cost dispatch. Tri-State states that entities with firm transmission

rights on the congested path may be reluctant to participate voluntarily in generation

redispatch that will jeopardize the economics of long-term power supply contracts or firm

resources, even if the result would lower costs.

Several commenters suggest principles to guide the design of congestion pricing

mechanisms. 478 NASUCA states that any mechanism for using congestion prices for

managing transmission system flows should be easy to implement; designed to minimize

cost shifts; designed to support an economically efficient dispatch; and coordinated with

the underlying transmission rate design. PacifiCorp states that key components of a good

market-based congestion clearing methodology are: (1) tradable transmission capacity

reservations; (2) a system in which all parties who can clear congestion can bid to do so;

(3) the establishment of congestion costs far enough in advance to facilitate reasoned

decision-making; and (4) the avoidance of any RTO rules that substantially reduce

liquidity in power markets. UtiliCorp believes that a congestion management system
Docket No. RM99-2-000 -349- 

should establish tradeable rights for transmission usage, promote efficient regional

dispatch, support the emergence of secondary market for transmission rights, and give

market participants the opportunity to hedge locational differences in energy prices. 

However, Enron/APX/Coral Power disagrees on the latter feature. It contends that the

monopoly wires business should not be allowed to encroach on what they see as the

highly competitive and innovative business of providing hedges against locational price

differences of energy or capacity or against price volatility of these or any other

competitive products.

Cal DWR and Metropolitan urge the Commission to adopt RTO ratemaking

principles that include off-peak rates. Cal DWR believes that customers should face

accurate transmission price signals and, therefore, transmission prices should be lower in

periods of off-peak demand for transmission. Cal DWR believes that off-peak pricing

provides an accurate price signal over the longer term, promoting investment necessary to

shift transmission usage to off-peak periods. In addition, Metropolitan believes that offpeak pricing can help to resolve problems of cost-shifting.

A number of commenters emphasize certain benefits of a well designed congestion

pricing policy, claiming that price signals can assist RTOs and market participants in

determining the efficient size and location of both new generation and new grid
Docket No. RM99-2-000 -350- 

479See, e.g., Allegheny, EME, United Illuminating, EPSA, SMUD, Los Angeles,

NASUCA, CSU.

480Other commenters emphasize the need for significant investments to expand

transmission capacity. See, e.g., EPRI, Salomon Smith Barney.

expansions. 479 Los Angeles argues that ensuring accurate market signals through the

creation of a congestion pricing mechanism will be the keystone to future system

planning. Los Angeles states that these signals should alert generators to the advantages

of siting in congested areas, motivate marketers and distribution companies to develop

demand-side management options, and generally foster marketplace innovation. Los

Angeles also believes that congestion price signals should help in determining the proper

size of transmission upgrades that the RTO might build to relieve congestion. Otter Tail

believes there exists a great need for new transmission capacity and, indeed, argues that

the overall focus of the NOPR and FERC transmission policy should be on providing the

appropriate financial incentives to assure investment in and expansion of the system. 480

To ensure that price signals translate into appropriate expansion of the grid, SMUD

believes that the RTO must be sufficiently independent and strong to require the

expansion of the grid. NASUCA notes that, while congestion cost pricing may help to

signal where new generation and transmission lines are needed, it may not be necessary

for the efficient daily operation of the transmission grid.
Docket No. RM99-2-000 -351- 

481See, e.g., Transmission ISO Participants, SoCal Edison, H.Q. Energy Services,

LIPA, NWCC.

Other commenters believe that it may be difficult to design market mechanisms to

provide incentives for the efficient expansion of the grid. 481 H.Q. Energy Services states

that currently, the rules for congestion management do not act as a sufficient incentive to

transmission owners to upgrade facilities. NWCC states that it is unclear whether

congestion charges can act as a means of driving transmission expansion, since adding

transmission is, by nature, capacity-based. NWCC also states that it is unclear whether

congestion costs will be an adequate incentive for market participants to finance

transmission expansion on their own, given the extensive permitting and regulatory

requirements that are involved. LIPA states that, while new location-based pricing

mechanisms have not been in place long enough to determine if they will provide

empirical evidence that is helpful in identifying efficient transmission expansions, it

believes that the mechanisms do not provide sufficient incentives for development of

transmission. Also, LIPA claims that they do not provide a useful signal when reliability,

as opposed to economic efficiency, drives the need for transmission enhancements. 

SoCal Edison criticizes the congestion management policies implemented by the

Cal ISO, stating that procedures intended to encourage the voluntary mitigation of

congestion through investment in new transmission may not provide a sufficient

incentive. SoCal Edison contends that, while correct congestion price signals will assist
Docket No. RM99-2-000 -352- 

482See, e.g., Professor Hogan, PJM, NERA, Sithe, Allegheny, Mid-Atlantic

Commissions, DOE, Duke, United Illuminating, EME.

in the identification of transmission investment needs, they will not eliminate

fundamental disputes among affected market participants over the responsibility for the

costs of new transmission or eliminate the risks associated with attempting to construct

new transmission projects. It asserts that the Commission cannot simply assume that the

market will respond to congestion signals if, at the same time, it is creating a regulatory

climate that discourages investment in new transmission. SoCal Edison believes that

impediments to grid expansion can be overcome only if the Commission adopts

transmission pricing policies that more accurately reflect the value that new transmission

investments bring to electric consumers. Similarly, FirstEnergy argues that if the

Commission desires an efficient generation market that optimizes the public good, then a

mechanism that allows transmission owners to capitalize on increases in the transmission

capacity at fair market value must be found. FirstEnergy contends that the interaction of

these free market forces will drive the proper allocation of resources between

transmission and generation over the long term. 

Locational Marginal Pricing

A number of commenters advocate the use of locational marginal pricing (LMP)

for congestion management. 482 Professor Hogan states that, with LMP, the securityconstrained economic dispatch process would produce prices for energy at each location,
Docket No. RM99-2-000 -353- 

incorporating the combined effect of generation, losses and congestion. He states that the

corresponding transmission price between the location where power is supplied and

where it is used would be determined as the difference between the energy prices at the

two locations. Professor Hogan therefore contends that this same framework is easily

extended to include bilateral transactions. Professor Hogan states that, with LMP, the

system operator coordinates the dispatch and provides the information for settlement

payments, with regulatory oversight to guarantee comparable service through open access

to the pool run by the system operator through a bid-based economic dispatch. He claims

that PJM implemented LMP after experimenting with an alternative market model and

pricing approach that proved to be fundamentally inconsistent with a competitive market

and user flexibility. He states that the earlier pricing system allowed market participants

the flexibility to choose between bilateral transactions and spot purchases, but did not

simultaneously present market participants with the costs of their choices. He states that

this created perverse incentives. Professor Hogan argues that LMP is the only workable

system that can support a non-discriminatory competitive market that allows for

participant choice and flexibility.

PJM states that the Commission correctly concludes that LMP will "encourage

efficient use of the transmission system, and facilitate the development of competitive

electricity markets." PJM notes that, under LMP, transmission customers are assessed

congestion charges consistent with their actual use of the system and the actual redispatch
Docket No. RM99-2-000 -354- 

that their transactions cause. It claims that this provides an economic choice to non-firm

transmission customers to self-curtail their use of the transmission system or pay

congestion charges determined by the market. PJM believes that by basing congestion

charges on the true redispatch cost, parties behave in a rational and efficient manner. It

states that the market determines the clearing price for transmission congestion and which

customers ultimately utilize the transmission system. PJM states that the use of fixed

transmission rights (FTRs) enables market participants to pay known, fixed transmission

rates and to hedge against congestion charges.

The FTC believes that accurate LMP signals for investment to reduce congestion

may become even more important as distributed generation presents opportunities for

small-scale, fine-tuned (with respect to both size and location) generation investments to

relieve transmission congestion, in place of large-scale transmission or generation

investments. EME endorses the LMP pricing approach adopted by PJM and the New

York ISO, and states that the Midwest ISO and the Alliance RTO should be encouraged

to adopt similar approaches. The CalPX notes that the separation of the CalPX and the

ISO in California does not prevent the use of a locational pricing model that incorporates

the individual buses and transmission lines in the network.

Allegheny believes that "[c]onsistent locational marginal price dislocations readily

identify system expansion, or other congestion relief, requirements as well as serve as an

indicator of the most economic fix to congestion patterns over time." It claims that there
Docket No. RM99-2-000 -355- 

483See, e.g., APX, LIPA, TDU Systems, CP&L, Virginia Commission, Tri-State,

Dynegy.

would be no incentives for the RTO or transmission owners to maintain congestion, since

there is no financial impact on them from LMP because any excess payments received by

the RTO during congestion are returned to holders of FTRs. Allegheny recommends that

the Commission remain flexible in considering other pricing innovations for congestion

management, but believes that a simplified locational marginal pricing methodology

should be established as a default market mechanism against which other pricing

innovations are evaluated.

Some commenters, however, criticize the locational marginal pricing approach to

congestion management. 483 APX argues that, because LMP requires the RTO to

implement a centrally optimized dispatch, it will discourage, if not eliminate, the

commitment of forward contracts in the energy market and replace the price discovery of

forward markets with ex post pricing. APX contends that because LMP price

calculations occur only periodically and in a single iteration, price visibility is restricted

compared to a continuous forward market. APX claims that this diminished visibility can

make the result less efficient and more vulnerable to an exercise of market power. APX

contends that, for most industries, a process of continuous trading creates efficiency in a

competitive market, while the LMP optimization process has no role for trading. APX

asserts that no competitive industry uses optimization to simulate and substitute for
Docket No. RM99-2-000 -356- 

market outcomes. APX contends that under LMP, the system operator, not the market,

will specify the structure of the optimization problem. APX claims that markets process

information much more flexibly and comprehensively through the self-interested trading

behavior of buyers and sellers. APX asserts that this is the strength of markets and the

critical shortcoming of LMP.

Dynegy claims that markets for FTRs have yet to fulfill their promise to provide

market participants with critically important price certainty for their transmission

transactions. For example, Dynegy states that allocation problems still exist, in that only

a small portion of available FTRs is being auctioned off in certain markets while a large

number are being withheld for incumbents' use. Dynegy argues that in order for FTRs to

provide a truly effective hedge against transmission price increases resulting from LMP in

the hourly market, hourly FTRs would have to be available in a liquid market at a

moment’s notice, but nothing close to such a market exists. Dynegy suggests that,

because the LMP model has yet to be implemented successfully due to the lack of a liquid

FTR market, the time is ripe to look at other models, such as a physical rights model. 

LIPA claims that neither the opportunity to obtain fixed transmission rights nor the

prospect of locational price reductions are sufficient to encourage efficient generation and

transmission expansions. For example, LIPA notes that awarding a transmission

expander transmission rights that entitle it to collect congestion rents on the expanded

capacity creates an incentive that runs counter to the purpose of the expansion; i.e., the
Docket No. RM99-2-000 -357- 

484The Brattle Group believes that, in addition to locational congestion pricing,

some form of regulatory incentives may be needed to bring about efficient investment in

the transmission grid.

more successful the expansion is in eliminating congestion, the less value the incentive

has for the expander. Also, LIPA believes that locational pricing systems are biased

toward using generation to solve congestion problems on the transmission grid and, as a

result, could lead to market power abuse by an operator that sites a new generator in a

load pocket and then takes advantage of transmission limitations to manipulate the

operation of other generators that it owns.

The Virginia Commission claims that pricing mechanisms incorporating locational

marginal prices tend to produce intense signals over short time frames, particularly when

constraints are seasonal and driven by extraordinary events such as extreme weather. The

Virginia Commission therefore believes that, at least initially, locational marginal prices

may provide incentives for short-term actions for congestion relief, rather than longer

term solutions such as the construction of additional transmission or generating facilities

in a particular location. 484 The Virginia Commission also states that the use of locational

marginal pricing is heavily dependent on the existence of transparent short-term

competitive power markets. It urges the Commission to evaluate carefully proposals that

place greater reliance on market mechanisms through the use of price signals, and to

condition the use of such mechanisms on the existence of such things as fully functioning
Docket No. RM99-2-000 -358- 

485See, e.g., PG&E, PJM/NEPOOL Customers, FTC, Tri-State, Dynegy.

power exchanges, the establishment of fixed transmission rights and the existence of

secondary markets for such rights. 

CP&L argues that while the proposed congestion management rule appears to

permit only PJM-redispatch types of arrangements, CP&L does not believe that the PJM

model is the only workable congestion management process. Rather, CP&L believes that

congestion is best managed through the coordinated reservation and scheduling of

transactions on the grid rather than post-congestion fixes. Also, TDU Systems states that

it may be difficult to transplant the PJM model to regions that do not have a centrally

dispatched, tight power pool to use as an RTO platform. 

Some commenters claim that LMP is more complex than necessary, 485 although

Allegheny believes that today's technology mitigates these concerns. The FTC states that,

despite the apparent virtues of LMP, it may be reasonable to back away from a full

application of an LMP approach if doing so provides benefits to consumers from

increased competition in generation markets. For example, the FTC states that, in light of

its alleged complexity and the difficulty that financial markets may have in anticipating

congestion charges, LMP may inhibit the formation of efficiency-enhancing futures

markets in electricity generation and trading because congestion prices are more uncertain

under LMP than under other pricing approaches (such as zonal transmission congestion

pricing). The FTC thus suggests that the Commission may want to continue to entertain
Docket No. RM99-2-000 -359- 

486See, e.g., PJM, SMUD, DOE, Enron/APX/Coral Power, EPSA, NSP, Seattle,

Professor Hogan, EME.

487See, e.g., DOE, NSP, Enron/APX/Coral Power, Seattle, Nevada Commission.

488See, e.g., APX, Enron/APX/Coral Power, Tri-State, Desert STAR.

alternatives to LMP if a reasonable case is made that benefits to consumers are greater

under the alternatives than under LMP.

Managing Congestion with Tradable Transmission Rights

Several commenters emphasize the importance of including explicit transmission

rights in any congestion management plan that relies on market mechanisms. 486 EPSA

believes that when transmission rights are clearly defined and allocated, ATC calculations

can be made more accurately and congestion management simplified. DOE notes that

financial transmission rights will provide a hedge against long-term fluctuations in spot

prices, will encourage the development of competitive markets and will likely contribute

to efficient generation and transmission resource planning. SMUD emphasizes that,

without the pricing hedge provided by such rights, it cannot guarantee its customerowners low cost or reliable transmission service.

A number of commenters emphasize that transmission rights must be tradeable in a

secondary market. 487 Indeed, some commenters believe that the use of firm (physical)

transmission rights along with a robust secondary market in these rights is the most

workable solution for efficient congestion management. 488 Seattle notes that with an
Docket No. RM99-2-000 -360- 

effective market for transmission rights, market participants may be afforded

transmission-based options for resolving congestion. It states that market participants that

invest in transmission facilities that increase capacity can receive the right to use or sell

that capacity. Enron/APX/Coral Power believes that the RTO should be charged with

developing a workable market approach to congestion and parallel-path management

based on clear and tradeable rights for transmission usage that promote efficient regional

dispatch, and support the emergence of secondary markets for transmission rights. 

Enron/APX/Coral Power contends that this will require that RTO systems be operated as

they are in the Western Interconnection based on physical rights. It suggests that, in

order to ensure a firm right to schedule service over an interface when it is constrained, a

customer would have to demonstrate ownership of sufficient property rights in the

interface. Enron/APX/Coral Power suggests three options for obtaining rights: (1) from

the RTO in the primary auction or other primary form of allocation; (2) from holders of

rights in the secondary market; and (3) from the RTO in the form of short-term released

rights not scheduled by their holders. Enron/APX/Coral Power states that by defining

and enhancing physical property rights, the market for those rights will provide ex ante

transmission prices that include the cost of purchasing rights in constrained interfaces. It

claims that this will permit dispatch decisions to be made on the basis of delivered energy

prices. Enron/APX/Coral Power states that to ensure that no market participant can
Docket No. RM99-2-000 -361- 

exercise market power by hoarding property rights, the rights should be designed as useor-lose so that if a right is not scheduled it can be used by others on a non-firm basis.

Similarly, Dynegy proposes a physical rights model in which a limited amount of

firm physical rights would be sold and only those holding physical rights would be

allowed to schedule when capacity is constrained. Under Dynegy's proposal, only those

with preassigned FTRs would be allowed to schedule on a firm basis at a set price. 

Dynegy states that others could submit non-firm schedules, subject to curtailment, or, if

the party is willing, redispatch. Dynegy adds that the proponents of rights that are

financial only argue that it is impossible to define physical rights as "100 percent firm"

from a given source to a given sink. Dynegy states that, while such arguments are

convincing, the capacity between a source and sink may actually be available for a

significant percentage of the time to a reasonable degree of certainty and, accordingly,

could be sold as firm.

APX states that the definition of transmission property rights requires the

calculation of stable power distribution factors that show the proportion of a power

transaction that flows over each path on the grid connecting the source-sink pair. It states

that after defining the property rights, the RTO can conduct an auction to allocate them. 

APX states that, following the auction, holders of transmission rights can retain them or

trade them in a secondary forward market. APX believes that FTR trading will provide a

more direct and comprehensive valuation of rights than LMP. Desert STAR states that it
Docket No. RM99-2-000 -362- 

489See, e.g., NERA, Professor Joskow, Allegheny.

490Professor Joskow notes that Enron/APX/Coral Power claims that two

unpublished papers he has co-authored with Jean Tirole conclude that physical rights

designed on a use-it-or-lose-it basis (so that they cannot be hoarded) more effectively

prevent the exercise of market power than financial rights, which can always be hoarded. 

He states that this is not what the papers conclude.

plans to rely on firm transmission rights markets as the primary vehicle for managing

commercially significant congestion, and the use of incremental/decremental generation

bids to manage other congestion.

Other commenters, however, doubt that a system of physical transmission rights

can be used effectively to manage congestion. 489 NERA states that most commodity

markets operate according to a process based on physical contracts or rights traded in

decentralized markets separated from physical operations. NERA adds, however, that

most commodities do not flow on an integrated grid where network externalities are so

strong and complex that a monopoly system operator is needed. NERA argues that

network externalities on any complex electricity grid make it virtually impossible to

define physical transmission rights that will use the system fully and yet can be traded in

decentralized markets. Also, Professor Joskow believes that on complex electric power

networks with loop flow, a financial rights system can be designed more easily and can

work more smoothly and efficiently than can a physical rights system. 490

Some commenters offer additional notes of caution regarding the use of

transmission rights. For example, APPA states that one must guard against market
Docket No. RM99-2-000 -363- 

participants using transmission rights to act strategically. APPA argues that if a generator

can adversely affect transfer capability, it may seek to purchase and resell transmission

rights in the secondary market after manipulating its internal operations to create

congestion on the grid. RECA considers proposals that allow customers to purchase

long-term rights to mitigate the risk of congestion pricing to be unacceptable because

such proposals result in long-term firm customers having to pay a premium for price

stability. Also, CSU contends that no party should hold any entitlement over a

constrained path due to transmission ownership which predates the formation of the RTO. 

CSU argues that, because all parties dedicating bulk transmission assets to the RTO will

be fully compensated for their embedded costs, there should exist no reserved rights of

use other than those purchased from the RTO. In addition, Great River is concerned that

the NOPR's proposal regarding the establishment of clear and tradable transmission rights

is not consistent with the flexibility that transmission customers currently have under

network service. Great River urges the Commission to carefully consider congestion

management proposals that preserve network-like service, even if such proposals do not

result in the identification of asset-based transmission rights.
Docket No. RM99-2-000 -364- 

491See, e.g., Cal ISO, Montana Commission.

Other Mechanisms for Managing Congestion

Some commenters support yet other market mechanisms for managing

congestion. 491 EPSA notes that other pricing approaches that deserve consideration

include the RTO's use of supply-side bids to relieve congestion in load pockets, as well as

the use of bilateral arrangements to solve congestion problems. Also, NSP recommends

that the RTO offer a "firming" service, at posted rates, that would provide customers with

the assurance that their transaction will occur under most curtailment conditions. In

addition, NSP proposes that the RTO offer a real-time redispatch service that will allow

transmission customers to buy through congestion at real-time prices. Cal ISO notes that

the Commission has accepted its zonal approach to congestion management, which relies

on market mechanisms to manage inter-zonal congestion. PG&E claims, however, that

while providing a more understandable picture of congestion, such a system must still

solve the problem of intra-zonal congestion. Also, the Montana Commission

recommends that the congestion management regime that was developed as a part of the

IndeGO proposal serve as a model for how to manage congestion on the transmission

system. However, Avista claims that the IndeGo proposal proved to be too complicated

to solve a problem that exists only on a few select transmission paths in the Pacific

Northwest.
Docket No. RM99-2-000 -365- 

492See, e.g., TDU Systems, NCPA, Los Angeles, Wyoming Commission, SMUD, 

South Carolina Authority.

493See, e.g., APPA, RECA, TDU Systems, Los Angeles, EPSA.

Costs and Revenues in Congestion Management

A number of commenters urge the Commission to pay close attention to issues

related to the distribution of the costs and revenues of congestion management among

market participants. 492 In particular, several commenters caution that congestion pricing

mechanisms should ensure that congestion costs are fairly allocated and should not result

in excessive revenues or monopoly profits for transmission owners. 493 APPA states that

only after we have a nationwide framework of truly independent RTOs should the

Commission consider a new approach to transmission pricing that would allow the RTO

to price transmission capacity rights and usage on congested paths above embedded costs

while discounting uncongested paths below embedded costs, subject to a balancing

account to ensure that the total transmission revenue requirement is not over-recovered.

Similarly, TDU Systems believe that while the formation of RTOs is a unique

opportunity to experiment with new forms of transmission pricing, the Commission

should be mindful that an RTO will be a large regional transmission monopoly. TDU

Systems question the wisdom of designing congestion pricing mechanisms to ensure that

limited transmission capacity is used by market participants who value that use most

highly. It states that such an auction-to-the-highest-bidder approach could reap monopoly
Docket No. RM99-2-000 -366- 

rents for transmission providers, at the expense of consumers. TDU Systems thus argues

that over-reliance on economic self-interest and market mechanisms in transmission

pricing may become a recipe for new forms of undue discrimination. It suggests that an

incentive to avoid expanding the system in order to collect monopoly rents can be

removed by placing any excess revenues from congestion pricing in a fund earmarked for

transmission system expansion. 

TDU Systems also recommends that the Commission encourage congestion

management plans that distinguish between congestion caused by the RTO’s obligation to

provide service to firm transmission customers, and congestion caused for economic

reasons. It argues that, in the case of the former, the costs of relieving the congestion

should be averaged over the firm RTO transmission customers that are using its system. 

However, it claims that economic congestion occurs because market participants wish to

take advantage of short-term production cost economies to minimize their power costs. 

In this case, TDU Systems argues that the specific loads purchasing the generation should

pay the associated congestion costs. Also, RECA states that long-term firm transmission

customers are the ones that use and pay to support the system throughout the year, but the

auction approach allows a short term trader to outbid these customers at the very times

they need it most. Enron/APX/Coral Power notes that, if the RTO's regulated rates for

transmission service, including congestion management, are properly designed to reward

the RTO for cutting operating costs and maximizing throughput, then it would not have to
Docket No. RM99-2-000 -367- 

assign the grid expansion costs to new generators that interconnect. Instead, the RTO

would charge the new generator only the cost of local interconnection with the grid.

Dynegy claims that, with respect to each transmission provider's system, there is a

predictable level of constraints and, similarly, some representative level of costs

associated with relieving those constraints. Dynegy believes that such costs should be

rolled into firm transmission rates that can be quoted up front and with certainty. Dynegy

argues that transmission providers would have an economic incentive to operate their

transmission systems efficiently if they are given an uplift cost target, and are rewarded

for beating the target and penalized for exceeding the target. EPSA states that some

congestion pricing mechanisms can impose potentially huge costs on individual

transactions, which can be detrimental to the goal of fostering wholesale competition. 

EPSA thus urges the Commission to consider whether these pricing mechanisms provide

greater benefits than a system that internalizes more of the congestion costs. Indeed,

EPSA argues that it is still appropriate to spread many of those costs to all system users

because redispatch generally benefits all users of the transmission system.

NCPA asserts that, in order to prevent large increases in the cost of generation for

customers in congested areas, some non-discriminatory way must be found to return the

extra revenues collected to those customers. NCPA believes that this will require

restructuring of tariffs, but failure to address the problem is likely to keep utilities with

customers in congested areas out of the California ISO. Similarly, the South Carolina
Docket No. RM99-2-000 -368- 

494See, e.g., Allegheny, Platte River, NERC.

Authority is concerned that certain centralized market mechanisms would cause cost

shifts for those participating in an RTO, and if so, potential participants opt out. Also, the

Wyoming Commission is concerned that, by offering rewards for transmission investment

such as a higher return on equity, the Commission would effectively be discouraging a

more market-oriented review of alternatives to building transmission to solve congestion

problems.

Some commenters emphasize the importance of ensuring full cost recovery for

generators that are redispatched by an RTO to alleviate transmission constraints or to

provide other support services. 494 NERC contends there must not be disincentives, in

the form of unrecovered costs, to having generators perform these vital functions. 

MidAmerican asserts that optimal dispatch will occur during congestion management as

long as all power suppliers are fully compensated at market prices. Cinergy claims that,

unless generators have the ability to recover lost revenues for reducing generation in

response to congestion management needs, generators have no incentive to follow

dispatch orders. SMUD contends that the Commission needs to develop congestion

management principles that ensure that market participants will receive fair market value

for facilities that they have owned and operated for many years.
Docket No. RM99-2-000 -369- 

495See, e.g., LG&E, ComEd, Midwest ISO Participants, Midwest ISO.

Importance of Scale in Congestion Management

A number of commenters argue that the achievement of an appropriate scale by an

RTO will be important to the effective management of congestion. 495

LG&E states that the Commission should require RTOs to be of sufficient size to

be capable of meaningfully addressing congestion. It believes that if a proposed RTO’s

ability to address congestion would be impaired by its size or configuration, then the

Commission should either refuse the RTO’s application or should condition approval on

attaining the necessary size and configuration to manage regional congestion issues. 

Industrial Consumers state that, although congestion management can be addressed with

non-market solutions such as transmission loading relief procedures, it is far better to

internalize the problem within an RTO with an appropriate scope and configuration. 

Minnesota Power notes that, currently, it can have transactions curtailed by two different

procedures, NERC Transmission Loading Relief and MAPP Line Loading Relief. It

claims that an RTO will provide transmission users with region-wide, standard,

congestion management.

The Midwest ISO states that an appropriately sized RTO will be able to relieve

congestion on a broad scale. However, it claims that its own redispatch options will be

limited by the failure of border companies, such as FirstEnergy and AEP, to join it. Also,

it notes that longer term congestion relief involves the construction of transmission
Docket No. RM99-2-000 -370- 

facilities. It claims that, if border companies are not members, the Midwest ISO will not

have the ability to coordinate required transmission construction by those entities. Also,

the Midwest ISO Participants state that new transmission facilities required to relieve

constraints may involve both the companies of the Alliance RTO and the Midwest ISO

Participants. The Midwest ISO Participants believe that, with planning and authority split

between these two regional entities, these facilities may not be optimally constructed or

located. 

Ontario Power, however, takes a different view. It claims that many of the

advantages that would flow from expanding U.S. markets to include Ontario can be

realized without requiring the Independent Electricity Market Operator (IMO) in Ontario 

to join a larger RTO at this time. Ontario Power believes that these advantages could be

achieved by negotiating agreements between the IMO and other RTOs. Also, Central

Maine states that if transmission line loading relief is performed on a market basis, many

of the benefits that might result from merging existing ISOs could be realized without

actually requiring those ISOs to merge.

Tri-State argues that the Commission should provide an incentive for nonparticipating transmission owners to join an RTO by allowing the RTO to use a pricing

and congestion management structure that withholds the benefits of the RTO from

entities that refuse to turn control of their transmission assets over to the RTO. Also,

Vernon claims that non-participants can take unfair advantage of ISO-controlled facilities
Docket No. RM99-2-000 -371- 

496See, e.g., NERC, Mass Companies, Industrial Consumers, Montana

Commission, Indiana Commission, AEP.

by scheduling their own loads over ISO grid facilities that parallel the non-participant

paths, instead of scheduling them over their own wires. Vernon contends that having thus

freed up their own wires, the non-participants can then put their facilities to various uses,

such as to avoid the increased ISO grid congestion. 

Congestion Management Between RTOs

Many commenters believe that effective congestion management must take into

account effects that extend beyond the RTO's boundaries. 496 NERC states that

congestion management approaches that work within a particular region may not

adequately deal with transactions that originate or terminate outside the region. NERC

believes that as RTOs develop congestion management approaches, the Commission must

require that they be compatible with what is happening elsewhere. 

Industrial Consumers believe that congestion management, especially during

emergency conditions, is an interconnection-wide responsibility. It asserts that, if

multiple RTOs are allowed within an interconnection, congestion management must be

coordinated across RTO boundaries. Industrial Consumers argues that an RTO can

accomplish this only by sharing data on system conditions (e.g., ATC calculations) with

neighboring RTOs, agreeing to protocols for cross-boundary actions to mitigate
Docket No. RM99-2-000 -372- 

497See, e.g., ISO-NE, EAL, New Smyrna Beach, Industrial Consumers.

congestion, and cooperating in a process to ensure fair compensation to generators that

are redispatched.

UAMPS believes that if a state is involved in the consideration of various potential

solutions to regional congestion, it will likely be more willing to accept that a particular

proposal to construct new transmission within its borders is indeed the most efficient

solution to a genuine problem, and to provide the necessary approvals for that

construction.

Transcos and Congestion Management

Some commenters are concerned that, if a for-profit company owns transmission

(e.g., a transco), it may not have the correct incentives to manage congestion

efficiently. 497 ISO-NE argues that if such a company seeks to operate transmission and

markets as an RTO, it will have competing responsibilities and economic interests. ISONE believes that, given the company’s economic motivations, market participants may

have insufficient confidence in such a company’s determinations of whether a

transmission-expansion solution to congestion is preferable to a generation-based

solution. EAL believes that compensating a wire-owning RTO on the basis of invested

capital could lead to over-building of transmission. New Smyrna Beach is concerned that

a for-profit transmission company will exhibit a bias toward transmission construction

when other, more economical alternatives might exist. New Smyrna Beach states that the
Docket No. RM99-2-000 -373- 

Commission should consider requiring the RTO to conduct a competitive bidding process

when it determines that transmission construction, or an alternative, is needed to relieve

transmission constraints.

Industrial Consumers asserts that transcos would compete head-on with generation

companies wherever there is congestion. It thus believes that transcos-as-RTOs would

have a serious conflict of interest if they have the authority over congestion management

and over the decision whether to eliminate congestion with new generation or

transmission facilities. Industrial Consumers believes that where new generation is a

more cost-effective option than construction of new transmission facilities, the cheaper

option should be built, and markets should be given the opportunity to make the choice. 

Industrial Consumers believes, however, that this will require that the markets have

access to redispatch costs, congestion valuations (from a secondary market for capacity

reservations), and other data on grid conditions. This is information that is better

disclosed by a disinterested independent RTO than a self-interested transco or generation

company.

Cal DWR questions whether either ISOs or transcos have an incentive to use

transmission alternatives (such as demand-side management, load shedding, distributed

generation, or generation) to reduce the overall cost of transmission. However, it believes

that this problem may be more acute for a transco, for which revenues and return are

directly tied to the use of their transmission assets. 
Docket No. RM99-2-000 -374- 

498See, e.g., Trans-Elect, FirstEnergy, Entergy.

However, other commenters claim that there is no basis for concerns that a transco

will favor a transmission solution to constraints. 498 Entergy contends that, if a

generation solution is the most efficient way to resolve congestion, a new generator will

likely realize that and try to locate in the appropriate area. Entergy states that an RTO's

obligations as an open access transmission provider leave it with no choice but to

interconnect with the new generator. Also, Entergy argues that an RTO will not have the

unfettered ability to propose and build inefficient transmission solutions. It believes that

review by state regulators with siting authority, and prudence review by the Commission,

will make it difficult for an RTO to build inefficient and unnecessary transmission

additions. Enron/APX/Coral Power and JEA believe that a transco may, in fact, be well

suited for congestion management. Enron/APX/Coral Power states that placing

responsibility for managing congestion in the RTO's hands complements their view that

an RTO-Transco must be obligated to assume delivery risk (i.e., deliver physically firm

power) in exchange for being rewarded for cutting costs and increasing system

throughput. 

The Need for Flexibility in the Design of Market Mechanisms

Commenters in general showed considerable support for the NOPR's proposal to

give RTOs considerable flexibility in experimenting with different market approaches to
Docket No. RM99-2-000 -375- 

499See, e.g., Mass Companies, SRP, CP&L, Southern Company, PJM/NEPOOL

Customers, United Illuminating, Georgia Commission, JEA, Florida Commission, NYPP,

Cinergy.

managing congestion. 499 Mass Companies state that the NOPR's willingness to allow

RTOs latitude to develop local approaches to congestion management is particularly

appropriate, given the difference in conditions in different parts of the country. CP&L

believes that congestion management is an area where a one-size-fits-all solution would

miss the mark and unnecessarily increase the cost of forming and operating an RTO. 

SRP believes that a flexible approach is needed because the use of market mechanisms

for congestion management is in its infancy, and poorly designed market mechanisms can

exacerbate problems and adversely impact reliability.

The Florida Commission states that the details of proposals for managing

congestion using a market mechanism should be determined on a regional basis with

endorsement by the state regulatory body. The Florida Commission recommends that the

Commission continue to monitor discussions of these issues within NERC and not

duplicate or foreclose their development and resolution at NERC. 

Montana-Dakota recommends that the Commission not limit the experimentation

with market mechanisms to the provision of firm transmission service. Montana-Dakota

believes that there is potential to further improve transmission services by allowing RTOs

the ability to implement congestion management methods for non-firm services rather

than relying only on the use of TLR to curtail such services.
Docket No. RM99-2-000 -376- 

500See, e.g., PJM/NEPOOL Customers, United Illuminating, Florida Power Corp.,

Desert STAR, Oregon Commission, NERC.

Many commenters express support for the proposal to allow RTOs flexibility in

developing approaches to congestion pricing. 500 Some, such as Florida Power Corp. and

Desert STAR, believe that allowing flexibility in pricing may provide incentives for

transmission owners to join or form an RTO. Florida Power Corp. argues that such

flexibility allows transmission owners to deal with issues such as cost shifting, and

believes that providing more specific guidance will only limit possible options. 

However, the FTC cautions that the Commission should not allow its policy of

flexibility to continue indefinitely. The FTC states that although experimentation with

transmission congestion pricing alternatives to LMP may be appropriate at present, it

does not believe that great uncertainty about the most effective approach to transmission

congestion management need exist indefinitely. It suggests that the Commission may

wish to establish a date in the not-too-distant future when it will undertake a comparative

analysis of the consumer costs and benefits of alternative transmission pricing regimes. 

The FTC states that if one or more approaches provide substantially superior results for

consumers, the Commission may wish to initiate a rulemaking on policies to encourage

RTOs to adopt these approaches. The Oregon Commission recommends that the

Commission evaluate the effectiveness and efficiency of various congestion pricing

experiments, and based on its evaluation, require RTOs to use the better methods. 
Docket No. RM99-2-000 -377- 

501See, e.g., Industrial Consumers, Allegheny, PGE, Entergy.

502See, e.g., SMUD, Tri-State, CMUA, TANC, Desert STAR, Cinergy.

However, the Oregon Commission estimates that the process of refining congestion

pricing methods may take a decade or more.

NERC states that there are strongly held, differing opinions throughout the

industry on how congestion prices should be designed. NERC states that, while

flexibility is one important consideration, the various regional solutions must be able to

work together. It believes that the Commission can provide the leadership needed to

bring the industry to closure on these issues. NERC notes that this may require the

Commission to be more proscriptive, and it should not hesitate to do so. In this regard,

Minnesota Power suggests that the Commission encourage neighboring RTOs with

constrained interfaces to jointly develop constraint relief procedures including common

constraint pricing where appropriate.

Timing of Implementation

With regard to the NOPR's proposal to allow RTO's up to one year after start-up to

implement the congestion management function, commenters express a variety of

opinions. Some indicate that one year is an appropriate additional time period. 501

Others, however, believe that it is essential that the RTO have some form of congestion

management system in place when it begins operation. 502 SMUD and CMUA state that

a significant deterrent to participating in the Cal ISO has been the fact that, in California,
Docket No. RM99-2-000 -378- 

Cal ISO transmission is strictly a short-term transaction given that Cal ISO has not yet

fully implemented FTRs. SMUD emphasizes that, without the hedge provided by FTRs,

it cannot guarantee its customer-owners low cost or reliable transmission service. TANC

believes that allowing an RTO to begin operations without a congestion management

procedure in place greatly increases the opportunity for market power abuses as well as

market inefficiency. 

Duke states that, ideally, the permanent congestion management function should

be in place on the first day of RTO operation. Then, Duke notes, it would not be

necessary to incur the cost of implementing, and developing strategies and behavior

appropriate to an initial system, only to have to incur additional costs and changes in

behavior to adapt to a permanent system. However, Duke states that congestion

management issues are complex and substantial information management systems must

be put in place. Consequently, Duke believes one year from the time the RTO becomes

operational may not be a sufficient length of time to implement the congestion

management function.

Desert STAR states that the new approaches to congestion management called for

by newly competitive markets will take additional time to work out and, therefore, the

Commission should be willing to consider additional time on a case-by-case basis. 

However, in order to ensure reliable operation, Desert STAR believes some congestion

management system must be in place when the RTO begins operation.
Docket No. RM99-2-000 -379- 

Some commenters believe that more than one year of additional time may be

needed for the RTO to implement the congestion management function. NSP states that

if the RTO has a state-estimator model with the necessary properties, it is possible that a

congestion management system, of the type preferred by NSP, could be implemented

within about 18 months from the time of project initiation. However, for regions without

the necessary models, NSP expects the time-line would likely be three years from time of

project initiation.

Montana Power believes that there will be many "growing pains" associated with

implementation of RTOs that will take time to work out, especially in areas like the

Pacific Northwest, which have no history of tight pool operation. Montana Power

believes that allowing one-year for implementing a market mechanism for congestion

management is a very aggressive schedule. Montana Power thus encourages the

Commission to allow up to three years. Similarly, Avista states that, with the IndeGo

experience in mind, it encourages the Commission to allow two to three years for

implementation of this function, especially where it is demonstrated that the RTO will

comply immediately with other characteristics and functions identified in the

Commission’s Final Rule. 

The Florida Commission believes that the Commission should not impose any

arbitrary time period for implementation of congestion management. It states that NERC

is working with the regions on this issue and FERC should monitor those activities before
Docket No. RM99-2-000 -380- 

setting any deadlines, if at all. Also, JEA believes that requiring the congestion

management function to be in place within one year from the start-up of RTO operation

may be feasible only for those RTOs structured as transcos from the beginning.

Commission Conclusion

As we proposed in the NOPR, we conclude that an RTO must ensure the

development and operation of market mechanisms to manage congestion. Furthermore,

as we proposed, we will require that responsibility for operating these market

mechanisms reside either with the RTO itself or with an another entity that is not

affiliated with any market participant.

We agree with the large number of commenters that believe that the use of market

mechanisms to manage congestion is superior to the use of administrative curtailment

procedures or other approaches that do not take into account the relative value of

transactions that are curtailed and those that are allowed to go forward. In addition, we

conclude that the RTO or an independent entity must assume an active role in developing

and implementing any congestion market mechanisms, because the use of such

mechanisms must necessarily be closely coordinated with the operational activities that

the RTO performs on a day-to-day and, in many cases, moment-to-moment basis.

Some commenters argue that an RTO should not be allowed to operate a

centralized market for congestion management. The commenters contend that, if such a

market is operated by an RTO or other entity that is independent of the market, a robust
Docket No. RM99-2-000 -381- 

503See, e.g., the market redispatch experiment of NERC (Docket No. ER99-2012-

000).

market in forward contracts for energy will not develop. As a result, these commenters

claim, society will never obtain the efficiency benefits that would otherwise flow from a

marketplace in which buyers and sellers are able to trade actively among themselves. 

These commenters also argue that the price certainty provided by forward markets will be

replaced with the uncertainty of prices that are determined after the fact. 

We disagree with these commenters and see no reason why the RTO's operation of

a market for congestion management should inhibit the ability of others to offer forward

contracts for energy, or other market instruments that provide price certainty. We

recognize that some of the market redispatch programs undertaken to date are

experimenting with various ways to manage congestion efficiently-including relying upon

decentralized markets to effect the necessary redispatch. 503 It is too early to tell if these

decentralized markets will work efficiently. But given the short time frame in which

system operators often must react to congestion situations, experience may ultimately

show that markets for congestion management can achieve more efficient and effective

results if they are centrally operated. Therefore, we will not deny here the RTO, or other

independent entity, the opportunity to operate a market-either centralized or decentralized-for congestion management.
Docket No. RM99-2-000 -382- 

504See PJM, 81 FERC at 62,252-53.

As we proposed in the NOPR, we will require the RTO to implement a market

mechanism that provides all transmission customers with efficient price signals regarding

the consequences of their transmission use decisions. We are convinced that efficient

congestion management requires that transmission customers be made aware of the cost

consequences of their actions in an accurate and timely manner, and we believe that this

is best accomplished through such a market mechanism. Also, as we proposed in the

NOPR, we believe that congestion pricing proposals should seek to ensure that (1) the

generators that are dispatched in the presence of transmission constraints are those that

can serve system loads at least cost, and (2) limited transmission capacity is used by

market participants that value that use most highly. Although we agree with some

commenters that price signals can also assist in determining the efficient size and location

of new generation and grid expansions, we share the view of LIPA and others that price

signals alone cannot be relied upon to identify all needed enhancements.

While we will not prescribe a specific congestion pricing mechanism, we note that

some approaches appear to offer more promise than others. As we stated in our order

approving the PJM ISO and reiterated in the NOPR, markets that are based on locational

marginal pricing and financial rights for firm transmission service appear to provide a

sound framework for efficient congestion management. 504 A number of commenters

express strong support for the LMP approach. As PJM notes in its comments, LMP
Docket No. RM99-2-000 -383- 

assesses congestion charges directly to transmission customers in a manner consistent

with each customer's actual use of the system and the actual dispatch that its transactions

cause. In addition, LMP facilitates the creation of financial transmission rights, which

enable customers to pay known transmission rates and to hedge against congestion

charges. We further note that, where financial rights holders are entitled to receive a

share of congestion revenues, the availability of such rights helps to address the concerns

of commenters who fear that congestion pricing can lead to the over-recovery of

transmission costs. The Commission recognizes, however, that LMP can be costly and

difficult to implement, particularly by entities that have not previously operated as tight

power pools.

The principal alternative to LMP advocated by commenters is an approach that

manages congestion by means of physical transmission rights that are tradable in a

secondary market. Under this approach, the RTO may be required to issue the

transmission rights initially through an auction or allocation process. Market participants

would then generally have to demonstrate ownership of sufficient rights in a constrained

interface before they would be allowed to schedule firm service over the interface. Such

an approach greatly reduces the role of the RTO in congestion management. While the

approach of trading physical transmission rights in a secondary market may prove to be

workable in regions where congestion is minor or infrequent, in other regions where

congestion is more of a chronic problem, it may not be workable. Also, commenters such
Docket No. RM99-2-000 -384- 

as NERA and Professor Hogan claim that the network interactions on complex electricity

grids make it difficult to define physical transmission rights that will use the system fully

and yet can be traded in decentralized markets. We expect RTOs and any affected

stakeholders to consider carefully such issues as they formulate specific pricing

proposals.

While our experience has shown that, in specific situations, some approaches to

congestion pricing appear to have advantages over others, we have not yet identified one

approach as being clearly superior to all others. Furthermore, the Commission recognizes

that an RTO's choice of a congestion pricing method will depend on a variety of factors,

many of which may be unique to that RTO. Therefore, we will allow RTOs considerable

flexibility to propose a congestion pricing method that is best suited to each RTO's

individual circumstances.

Some commenters appear to confuse the need to redispatch generators to maintain

reliability with the need to take specific actions to relieve congestion. Commenters

generally agree that the RTO should have clear authority to order redispatch for reliability

purposes. However, for congestion management, we conclude here that the RTO should

attempt to rely on market mechanisms to the maximum extent practicable. We recognize,

of course, that there may be times when even well-functioning markets will fail to

provide the RTO with the options it needs to alleviate a specific instance of congestion. 

In those cases, the RTO must have the authority to curtail one or more transmission
Docket No. RM99-2-000 -385- 

service transactions that are contributing to the congestion. Although the act of curtailing

a transaction may sometimes require the redispatch of generation, we clarify that we are

not requiring the RTO to redispatch any generators exclusively for the purpose of

managing congestion.

In the NOPR, we stated that a workable market approach to congestion

management should establish clear and tradeable rights for transmission usage, promote

efficient regional dispatch, support the emergence of secondary markets for transmission

rights, and provide market participants with the opportunity to hedge locational

differences in energy prices. Most commenters agree that these are reasonable features of

any congestion management proposal. However, Enron/APX/Coral Power believes that

the RTO should not be allowed to provide a hedging instrument. It contends that the

"monopoly wires business" should not be allowed to encroach on what it views as the

highly competitive and innovative business of providing hedges against locational price

differences of energy or capacity, or against price volatility of these or any other

competitive products. In response, we note that, while decentralized markets may

ultimately prove to be capable of providing such products, as these commenters claim, we

do not yet have evidence to that effect. Therefore, in the interest of allowing RTOs

flexibility to experiment with different market approaches, we will not prohibit the RTO

from offering such products through markets that it may operate.
Docket No. RM99-2-000 -386- 

505The terms "parallel path flow" and "loop flow" are sometimes used

interchangeably to refer to the unscheduled transmission flows that occur on adjoining

transmission systems when power is transferred in an interconnected electrical system.

506FERC Stats. & Regs. ¶ 32,541 at 33,743-44.

Finally, with regard to the timing of implementation of the congestion management

function, we will adopt our proposal to allow the RTO to take up to one year after startup to implement market mechanisms for managing congestion. Most commenters agree

that some period of time is needed for implementation. However, a number of them

indicate that the RTO must have some form of congestion management system in place

when it begins operation. We agree, and clarify that, upon start-up, the RTO must have

in place effective protocols for managing congestion while preserving reliability. 

Because the NOPR did not make this point explicitly, we do so here.

3. Parallel Path Flow (Function 3)

In the NOPR, the Commission proposed to require that an RTO develop and

implement procedures to address parallel path flow issues within its region and with other

regions. 505 The Commission noted that measures to address parallel path flow between

regions may not necessarily be in place on the first day of RTO operation, and proposed

to allow up to three years after start-up for this function to be implemented. 506 The

Commission sought comments on whether such an additional implementation time period

is warranted, and whether three years is an appropriate additional time period.
Docket No. RM99-2-000 -387- 

507See, e.g., ComEd, East Texas Cooperatives, EPSA, Industrial Consumers,

LG&E, NASUCA, NSP, PJM, Southern Company and Williams. However, Cinergy

argues that parallel path flows should not be considered as a separate function but should

be considered as a characteristic under the scope and regional configuration because that

will allow an RTO to address congestion management issues along with parallel path

issues.

508Industrial Consumers also notes that the first sentence in the proposed

regulation should be modified to read as: "RTO must develop and implement procedures

to address parallel path flow issues within its region and with other regions in the

interconnection within which it resides." (Suggested change underlined) 

509See, e.g., EPSA, Florida Power Corp., FTC, Georgia Transmission, LG&E,

Mass Companies, NSP and PJM.

Comments

Virtually all commenters support the NOPR's proposal to require that an RTO

develop and implement procedures to address parallel path flow issues as a separate

function. 507 Industrial Consumers states that parallel path flow-related disputes will

diminish as a result of RTOs addressing this issue. 508 But PGE notes that grandfathering

existing transmission contracts may impede the RTO's ability to address loop flow. 

Many commenters assert that parallel path flow and congestion management issues

are closely related to one another since both the issues involve identification of power

flows resulting from a specific transaction. 509 Therefore, they argue that any solution to

parallel path flow should recognize this close relationship. For example, Industrial

Consumers believes that an RTO can take preemptive actions against potential

curtailment situations to manage congestion resulting from loading of chronically
Docket No. RM99-2-000 -388- 

510See, e.g., LG&E, Michigan Commission, NASUCA, New Smyrna Beach, NSP,

PJM and South Carolina Authority.

511See, e.g., Cleveland, East Texas Cooperatives, Georgia Transmission, Industrial

Consumers, NY ISO, Southern Company, TEP. Industrial Consumers note that several

other issues need to be addressed at the interconnection level and not at the regional level. 

They are: ATC calculation, inadvertent flows and congestion management.

512Central Maine Reply at 9; NYPP Reply at 10.

constrained transmission interfaces due to loop flow. PJM suggests that the use of

redispatch solutions like LMP not only is more efficient and beneficial to a competitive

market, but is preferable to curtailing transactions under TLR to address congestion due

to loop flow. South Carolina Authority is convinced that over the long run the problem

of parallel path flow needs to be addressed as a planning issue, focusing on appropriate

reinforcements to constrained transmission lines. 

Many commenters recommend that an RTO should encompass as large a region as

possible so that it can "internalize" most of the loop flow within its region. 510 However,

others argue that the loop flow issue can be solved satisfactorily only if it is addressed at

the interconnection level. 511 They believe that while a large RTO will "internalize" most

of the parallel path flows within its region, parallel path flows between RTOs will

remain. Some other commenters are convinced that cooperative efforts among regional

entities works best when it comes to resolving issues such as parallel path flow issue. 512

NERC notes that it is in the process of developing the needed information system to

address the parallel path flow issue on an interconnection basis and urges the
Docket No. RM99-2-000 -389- 

513See, e.g., PG&E, Seattle, SRP and TEP.

Commission to direct the RTOs to work closely with it to coordinate efforts to resolve

this issue. Southern Company and Industrial Consumers support NERC's initiative in

solving the loop flow issue. Cleveland states that the national grid should be viewed as a

single electrical system which calls for a universal approach rather than a regional

approach to resolve the loop flow issue. The universal approach, Cleveland argues, will

not only improve the integrity and reliability of the national grid but also eliminate the

need for any policy shift in the future.

Commenters from Western System Coordinating Council (WSCC) assert that the

loop flow issue in their region was solved by the adoption of WSCC Flow Mitigation

Plan (Plan) that provides for controlling unscheduled flows through the use of phase

shifting transformers. 513 SRP suggests loop flow in WSCC should continue to be

addressed at the WSCC level and not at the RTO level because WSCC may end up with

four or more RTOs. PG&E recommends that the establishment of property rights such as

FTRs be explored as a means to solve loop flow issues, on the basis that developing

property rights will ensure the most efficient use of the transmission lines. 

Enron/APX/Coral Power urges RTOs in the Eastern Interconnection to move toward the

Western model. NASUCA believes that RTOs should perform a cost-benefit analysis of

controlling loop flows with phase shifting transformers. 
Docket No. RM99-2-000 -390- 

514See, e.g., Cal ISO, Desert STAR, Entergy, Industrial Consumers, NECPUC,

NERC, NY ISO, PGE, SRP, Tri-State, TVA, UtiliCorp and WPSC. Cleveland also

argues that a similar grace period should be given for the implementation of function # 5.

(TTC and ATC Calculation). Cleveland at 14.

Most commenters support the NOPR's proposal for an additional implementation

time period of three years for coordination among RTOs. 514 They argue that the proper

resolution of loop flow presents a number of complex issues that may require

negotiations and agreements among neighboring RTOs and that the additional time period

will give them an opportunity to coordinate their efforts. Allegheny supports an

additional time period for implementation of this function but urges the contract path

methodology be replaced at a faster pace than three years. Industrial Consumers notes

that an additional time period of three years is necessary for NERC to solve the loop flow

issue at the interconnection level. However, Florida Power Corp. and Florida

Commission observe that the severity of parallel path flow varies from region to region

and therefore opposes setting an arbitrary time limit for the implementation of this

function. Duke likewise believes that the deadline for the implementation of this function

should be determined by the Commission on a case-by-case basis. 

Commission Conclusion

We reaffirm our preliminary determination that an RTO should develop and

implement procedures to address parallel path flow issues within its region and with other

regions. Most commenters agree that the formation of RTOs, with their widened
Docket No. RM99-2-000 -391- 

geographic scope of transmission scheduling and expanded coverage of uniform

transmission pricing structures, provide an opportunity to "internalize" most, if not all, of

the effect of parallel path flow in their scheduling and pricing process within a region. 

NERC notes that it is in the process of developing the needed information system to

address parallel path issues on an interconnection basis, and we will direct RTOs to work

closely with NERC, or its successor organization, to resolve this issue. As noted by

Industrial Consumers, parallel path flow-related disputes will diminish as a result of

RTOs addressing this issue.

Commenters from Western System Coordinating Council (WSCC) state that they

adopted the WSCC Flow Mitigation Plan (Plan) to address parallel path flow issue in

their region. SRP suggests that parallel path flow in WSCC continue to be addressed at

the WSCC level and not at the RTO level because WSCC may end up with more than one

RTO. We will not here make any judgments on the merits of WSCC's Plan as a solution

for parallel path flow issues. However, we clarify that this rule does not prevent

addressing parallel path flow issues on a larger-than-single-RTO basis. In fact, we

require RTOs to develop and implement procedures for addressing parallel flow issues

with other regions.

In the NOPR we proposed that the RTO have measures in place on the date of

initial operation to address parallel path flow issues within its own region. We also noted

that measures to address parallel path flow issues between RTO regions may not
Docket No. RM99-2-000 -392- 

515Florida Power Corp., Florida Commission and Duke.

necessarily be in place on the first day of RTO operation. We proposed to allow up to

three years after start-up for this function to be implemented. Most commenters support

the NOPR's proposal for an additional time period of three years. A few commenters 515

prefer a case-by-case approach. Since severity of the parallel path flow varies from

region to region, some parts of the Nation may choose to resolve inter-regional parallel

path flow issues sooner than the required three years. Consequently, we will adopt our

proposal in the NOPR that the RTO have measures in place to address parallel path flow

issues in its region on the date of initial operation. We also adopt three years as an

adequate time period for implementation of measures to address parallel path flow issues

between regions.

We recognize that these measures to address parallel path flows combined with the

requirement that the RTO be the sole provider of transmission services over facilities that

it owns or controls will eliminate or diminish the ability of transmission users to choose

among different contract paths owned by different service providers within the RTO

region. However, these users will have the ability to move power anywhere within the

RTO at a single rate and under a single set of terms and conditions. We believe this is

pro-competitive and represents one of the fundamental benefits that is envisioned by the

Rule. As we noted in the NOPR, the creation of large RTOs that can internalize most, if

not all, of the effect of parallel path problems through their scheduling and pricing actions
Docket No. RM99-2-000 -393- 

516See FERC Stats. & Regs. ¶ 32,541 at 33,744.

517FERC Stats. & Regs. ¶ 32,541 at 33,744.

provides a unique opportunity to resolve a major operating concern that has caused

problems on both the Eastern and Western Interconnections and which is a significant

impediment to promoting efficient competition in generation markets. 516 Therefore, in

reviewing the competitive implications of a proposed RTO application under section 203,

we believe that any inability of transmission customers to choose among different

contract path suppliers within an RTO will be outweighed by their enhanced ability to

reach numerous buyers and sellers of electricity throughout the region.

4. Ancillary Services (Function 4)

The fourth proposed minimum function is that the RTO must serve as the supplier

of last resort for all ancillary services required by Order No. 888. 517 This supply

obligation for the RTO is necessary because only the single grid operator will be able to

provide certain ancillary services, not all transmission customers may be able to selfsupply (some own generation, others do not), and because it typically is more efficient for

the RTO to provide some ancillary services for all transmission users on an aggregated

basis.

In carrying out this function, the Commission proposed that all market participants

would have the option of self-supplying or acquiring ancillary services from third parties. 

In addition, the RTO must have the authority to decide the minimum required amounts of
Docket No. RM99-2-000 -394- 

518See, e.g., Entergy, Industrial Consumers, NECPUC, Cal ISO, EPSA,

FirstEnergy, LG&E, PacifiCorp, Empire District, EME, Southern Company, UtiliCorp,

PGE, PNGC, PSNM, TDU Systems, Nevada Commission.

519See also Florida Power Corp.

each ancillary service and, if necessary, the locations at which these services must be

provided; must be able to exercise direct or indirect operational control over all ancillary

service providers; must promote the development of competitive markets for ancillary

services whenever feasible; and must ensure that its transmission customers have access

to a real-time balancing market.

Comments

Supplier of Last Resort

Comments on whether an RTO should serve as a supplier of last resort are mixed. 

A large number of commenters support the Commission's proposal, as written. 518

Detroit Edison believes that the RTO should serve as the sole supplier of ancillary

services to transmission customers and that the RTO should be permitted either to

purchase services directly from generation suppliers or to purchase generation resources

for this purpose. First Energy believes that the RTO's obligation as the supplier of last

resort for ancillary services cannot be eliminated, since it is the basis of reliability. 519

On the other hand, a few commenters suggest that the Commission allow

flexibility. Duke believes that an RTO should always have the responsibility for ensuring

that transmission customers have arranged adequate ancillary service and that those
Docket No. RM99-2-000 -395- 

520See, e.g., NASUCA, Seattle, CalPX, Mass Companies.

521Southern Company notes that NERC's Interconnected Operations Services

Working Group is currently addressing the ancillary services that should be required in a

competitive environment and has issued a proposed policy for public comment and

review.

522NWCC recommends that additional research regarding the application of

ancillary services to wind and other intermittent generation technologies be conducted.

services are delivered. They suggest that where a competitive market for ancillary

services exists, the RTO should not be required to provide such ancillary services as a

supplier of last resort. 520 And a number of commenters take issue with one or more

aspects of the proposed requirements, although many of these commenters generally

support the proposal.

For example, some commenters suggest that more information is needed. 

Southern Company suggests that the Commission allow NERC to finalize an ancillary

services policy before mandating changes to ancillary service requirements. 521 Professor

Hogan suggests further investigation into developments in ancillary services. 522

Other commenters believe that the focus of the proposal should be narrowed. Los

Angeles suggests that an RTO should be the "safety net" of last resort for providing

generation-based ancillary services. As such, the RTO would not play a significant role

in the energy market and can remain essentially indifferent to energy market issues. 

PG&E believes that an RTO could set appropriate rules for ancillary services but would

not itself procure such services from the marketplace absent clearly defined emergency
Docket No. RM99-2-000 -396- 

situations or in its role as provider of last resort. Avista states that while a transitional

"supplier of last resort" role may be appropriate, an RTO should generally not become

deeply involved in any of the markets for generation services.

A number of commenters suggest that the obligation to provide ancillary services

should be expanded to include more or different sellers. MidAmerican believes that each

control area should retain responsibility for the provision of ancillary services and should

be allowed to self-provide or acquire necessary ancillary services in the most economical

means it sees fit to meet performance compliance standards. East Texas Cooperatives

suggests that the Commission require both transmission owners and the RTO to offer

ancillary services at cost-based rates unless a seller can demonstrate a competitive market

in a particular ancillary service. PPC and Desert STAR also believe that the role of

provider of last resort of ancillary services would better rest with local control areas or

independent generators that can supply ancillary services. Steel Dynamics requests that

the final rule require generation-owning members of RTOs to maintain Commission

approved cost-based tariff schedules for ancillary services. Georgia Transmission

believes that any RTO members that are capable of providing ancillary services should be

the providers of "first resort," and the ability to acquire such services from different

providers would enhance competition in these markets. 

While not specifically objecting to the RTO being the supplier of last resort for

ancillary services, some parties suggest that the Commission should allow other
Docket No. RM99-2-000 -397- 

523See, e.g., CMUA, LPPC, California Board, San Francisco, Oneok, SMUD,

Avista, Sithe, Seattle.

524See also Empire District.

mechanisms to work. 523 California Board urges the Commission to allow consideration

of other means for ensuring that the need for ancillary services is addressed. It

recommends that the final rule reflect a requirement that the RTO filings must indicate

how default provision of ancillary services will be accomplished without necessarily

requiring the RTO to be the provider of last resort. Enron/APX/Coral Power advocates a

form of performance-based ratemaking in which the RTO would have an incentive to

perform its ancillary service function as efficiently and economically as possible. Florida

Commission recommends that an RTO only be responsible for providing non-competitive

ancillary services and should require users to purchase or self-provide the other

competitive services.

Similarly, FTC suggests that the Commission consider arrangements in which the

RTO's primary role is to provide a market mechanism for transmission customers to

acquire ancillary services for themselves. It argues that this method may reduce costs by

allowing customers to customize their purchases of ancillary services to better fit their

specific needs. 524 Some commenters suggest that final RTO regulations expressly

recognize the administration of an ancillary service exchange as an alternative to the

provider-of-last-resort obligation that is imposed on a RTO under the proposed
Docket No. RM99-2-000 -398- 

525See, e.g., Cinergy, APX, EAL, NY ISO, JEA.

526FERC Stats. & Regs. ¶ 32,541 at 33,745.

527See, e.g., WPSC, APS, Florida Commission, Duke.

regulations. 525 For example, ISO-NE believes that a competitive market for ancillary

services is a superior supply mechanism, and ISO-NE suggests that the text of proposed §

35.34(j)(4) be amended to read:

An RTO must develop and maintain a market or other contractual

arrangements for the supply of all ancillary services required by Order No.

888, FERC Stats. & Regs. ¶ 31,036 (Final Rule on Open Access and

Stranded Costs), and subsequent orders.

Comments were also sought on the circumstances under which an RTO's

obligation as supplier of last resort could be eliminated. 526 Several commenters believe

that the supplier of last resort obligation can be eliminated once a viable competitive

market develops within the RTO region. 527 For example, WPSC suggests that an RTO

must continue to fulfill the role of supplier of last resort for these services or a power

exchange must be available to supply these services. WPSC believes that it would be

difficult to predict the circumstances under which the market for ancillary services is

sufficiently robust that the RTO's role as supplier of last resort may be eliminated. 

WPSC believes that it would be a mistake to eliminate that role in any market where the

generation market concentration levels as measured by the Herfindahl-Hirschman Index

exceed 1,800. TDU Systems states that it is not aware of a market in any of the ancillary
Docket No. RM99-2-000 -399- 

528See, e.g., PGE, TDU Systems, Cal ISO, Duke, Tri-State.

services that is now sufficiently competitive to warrant elimination of an ancillary service

from this obligation. However, TDU Systems acknowledges that there may never be a

competitive market for certain ancillary services and that an alternative mechanism must

be created.

The NOPR also asked for comments on whether a different set of ancillary

services requirement for RTOs is needed because RTOs will not own generating

resources. Comments on this issue were mixed. 

Sithe and several other commenters 528 generally believe the Commission’s initial

set of guidelines on ancillary services is reasonable, and that a new set of ancillary

services requirements for RTOs is unnecessary. LG&E adds that, as already is the case

under the open access tariff, an RTO should be allowed to choose to add to the list of

ancillary services in recognition of local or regional conditions. MidAmerican believes

that while no additional or revised ancillary services are required, an RTO must ensure

that sufficient transmission capacity is available to allow delivery of backup supply,

planning reserves and the existing six ancillary services.

On the other hand, Los Angeles believes that a different set of ancillary services

requirements than those required currently from a vertically integrated utility should

apply to an RTO which does not own generation resources. They envision an ultimate

industry structure of complete desegregation of generation and transmission assets so that
Docket No. RM99-2-000 -400- 

529See also Eric Hirst.

any incentive (either real or perceived) for the transmission provider to act in a

discriminatory manner is eliminated.

NSP requests that the Commission refer to the draft NERC policy that discusses

the role of an operating authority as an unbundled procurement agent for community

ancillary services. They describe this document as a good "guidepost" for the

Commission to follow in the RTO NOPR, and for the establishment of additional

ancillary services such as system blackstart and frequency responsive reserve. 529 Desert

STAR and Cal ISO agree that additional blackstart ancillary service may be required. 

TDU Systems believes that RTOs should be required to offer backup service and an

additional load following service. It describes backup service as required to meet

contingencies during periods following those covered by the OATT’s reserve services,

and load following service as required to complement the OATT’s minute-to-minute

regulation service with a service matching hour-to-hour variations in load. Industrial

Consumers recommends that the Commission remove Schedule 4 (energy imbalance

service) from any tariff administered by an RTO. They suggest that this service be

provided by the real-time balancing market as proposed in the NOPR.

Self-Supply Option

Nearly all who commented on the self supply option generally agree that, where

feasible, all market participants should have the option of self-supplying or acquiring
Docket No. RM99-2-000 -401- 

530See, e.g., CMUA, Cal ISO, LG&E, PG&E, PJM/NEPOOL Customers, PPC,

APX, Metropolitan, MidAmerican, NSP, Seattle, SMUD, Desert STAR, TDU Systems,

Tri-State.

ancillary services from third parties. 530 Some commenters strongly endorse the selfsupply model. For example, APS believes that it should be the aim of the RTO to have

each transmission customer self-supply its generation-related ancillary service

requirements to the fullest extend practical. Los Angeles suggests that the role of the

RTO should be limited to ensuring that the transmission customer has adequately

provided for the necessary ancillary services for each transaction, and the RTO provide

such services only in the event of non-compliance. It believes that the RTO should

develop specific rules and protocols that would support the self-provision of ancillary

services. Some commenters, including PJM/NEPOOL Customers and LG&E, suggest

that it is important for the development of a competitive market in ancillary services that

RTO customers not be required to purchase them from the RTO, and that an RTO must

not prohibit or interfere with the ability of all market participants to have the option of

acquiring competitive ancillary services or providing such services through buy/sell

transactions from customer-owned generation.

On the other hand, FirstEnergy states that the Commission should be very cautious

that policies that encourage self-supply of ancillary services do not compromise the very

ability of the RTO to ensure reliable and secure network operation. It maintains that the

provision of "self-supplying" ancillary services is untested, the infrastructure needed is as
Docket No. RM99-2-000 -402- 

531FirstEnergy notes that NERC is developing certification and verification criteria

for ancillary service providers.

532See, e.g., Industrial Consumers, PJM, Turlock, Cal ISO, Florida Power Corp.,

PJM/NEPOOL Customers, LPPC, PGE, SMUD, TDU Systems, NYPP, Tri-State, Nevada

Commission.

yet undeveloped, and the process of providing them could potentially lead to abuses. 

FirstEnergy identifies this issue as one of the reasons that NERC is pushing for

mandatory compliance requirements. 531 It believes that an RTO must have the ability to

evaluate and accept/approve those NERC-certified sources that reliably contribute to

support the grid.

Authority to Determine Amounts and Location of Ancillary Services

Most commenters generally support the proposal that the RTO have the authority

to determine the quantities and, where appropriate, the location at which ancillary

services must be provided. 532 In addition, CMUA suggests that the RTO be responsible

for enforcing compliance with established standards.

PJM/NEPOOL Customers requests that RTO decisions regarding the amounts and

locations of ancillary services consider both stakeholder input and NERC standards. It

believes that this requirement would ensure that the RTO does not impose unnecessarily

high ancillary service obligations that will inhibit the operation of the competitive market. 

In addition, PJM/NEPOOL Customers asks that the Commission ensure that the RTO

exercises this authority only to the extent necessary for reliability purposes, since
Docket No. RM99-2-000 -403- 

533Citing FERC Stats. & Regs. ¶ 31,036 at 31,705 (1996).

534See also Eric Hirst.

decisions regarding ancillary services could impact the competitive electricity supply

market.

NYPP requests that the RTO's authority not be exclusive. It suggests that properly

constituted local and regional reliability councils authorized by FERC should have the

authority to establish criteria necessary to maintain the reliability of the transmission

system including the reliability of discrete locations.

Duke notes that the Commission has previously recognized NERC's leadership

role in developing concepts in the area of ancillary services. 533 It encourages the

Commission to recognize and adopt NERC's development of ancillary service definitions

and reliability standards. 534

Industrial Consumers and Steel Dynamics request that the Commission first

approve the standards by which the RTO determines the requirements. They requests

that these standards include the development of "metrics," i.e., standardized units of

measurement such that the performance of each service can be verified. In addition,

Industrial Consumers recommends modifying the requirement to ensure seamless

application between multiple RTOs and for transactions that only go through an RTO. It

suggests adding an additional requirement to § 35.34(j)(4)(ii):
Docket No. RM99-2-000 -404- 

535See, e.g., PJM, Cal ISO, Florida Power Corp., Cinergy, Los Angeles, PSNM,

SMUD, Duke.

536See also Cinergy.

The Regional Transmission Organization must support the minimum

required amounts of each ancillary service for transactions between itself

and other Regional Transmission Organizations in the interconnection and

through itself.

Control Over Ancillary Services Providers

All commenters that commented on this subject believe that the RTO should be

able to exercise some operational control, either directly or indirectly, over any supplier

of ancillary services. 535 SMUD supports the RTO establishing well documented and

specific operating criteria and the ability to require compliance with such operating

criteria, including monetary penalties and commission-approved sanctions. JEA believes

that this control should be exerted only where pre-existing contractual rights are

established. 536

Some commenters would broaden the requirement. For example, FirstEnergy is

concerned that limiting the RTO's control to ancillary services providers rather than all

generation located within the RTO may compromise the RTO's ability to operate the

transmission system reliably. It suggests that the Commission allow a greater flexibility

for the RTO and all generation owners located within the RTO to develop an agreement

for provision of ancillary services through the RTO that provides for the necessary

requirements for voluntary generation participation in the ancillary services market
Docket No. RM99-2-000 -405- 

537See also NYPP, PSNM.

538See, e.g., FTC, LPPC, Avista, APX, PJM/NEPOOL Customers, Seattle.

including operational control if appropriate, and the necessary requirements for calling on

ancillary services from connected generation necessary for the reliable operation of the

transmission system. 

On the other hand, PJM/NEPOOL Customers suggest that the RTO control be

limited to those providers that the RTO will rely on to fulfill its obligation as supplier of

last resort for ancillary services. It claims that control over additional generators is

unnecessary and may affect the operation of the competitive market.

Metropolitan recommends that the Commission allow RTO indirect control of

existing large hydroelectric plants to protect and facilitate use of existing systems that

have been operational for a substantial period of time and to preserve the integrity of the

FERC hydro license. It states that allowing indirect control would eliminate the need for

costly installation of software and infrastructure. 537

Promote Competitive Markets for Ancillary Services

Most commenters support the proposal in the NOPR that RTOs promote

competitive markets for ancillary services. 538 Seattle suggests that the RTO provide

incentives to ensure a robust, transparent market with many buyers and sellers of

ancillary services. PJM/NEPOOL Customers states that it is important that the RTO not

impede the development of competitive markets for ancillary services and that the RTO
Docket No. RM99-2-000 -406- 

539See also TDU Systems.

actually facilitate the development of these markets. However, it stresses that the RTO

and incumbent transmission owners should not be permitted to have market-based rates

for ancillary services until a viable competitive market for such services develops. 539

Sithe advocates that the final rule grant RTOs the authority to administer spot

markets for ancillary services and establish rules obligating all participants to meet

uniform requirements. PG&E believes that the RTO should not be the sole purchaser of

ancillary services. Instead, it should facilitate the development of bilateral markets for as

many of the ancillary services as possible, thereby allowing market participants to selfprovide those ancillary services.

Access to Real-Time Balancing Markets

In the NOPR, the Commission proposed that an RTO must ensure that its

transmission customers have access to a real-time balancing market. We proposed that

the RTO must either develop and operate such markets itself or ensure that this task is

performed by another entity that is not affiliated with any market participant. The

Commission noted that although system-wide balancing is a critical element of reliable

short-term grid operation, this does not necessarily require that there be a moment-tomoment balance between the individual loads and resources of bilateral traders and loadserving entities and the schedules and actual production of individual generators. We

also noted that unequal access to balancing options for individual customers can lead to
Docket No. RM99-2-000 -407- 

540See, e.g., Duke, PJM, Illinois Commission, Cal ISO, NERA.

541See, e.g., Enron/APX/Coral Power, Eric Hirst, NYPP, Powerex, East Texas

Cooperatives, Industrial Consumers, Professor Hogan.

unequal access in the quality of transmission service available to different customers, and

that this could be a significant problem for RTOs that serve some customers who operate

control areas and other customers who do not. The Commission proposed to give RTOs

considerable discretion in how a real-time balancing market would be operated.

We invited comments on the use of market mechanisms to support overall system

balancing and imbalances of individual transmission users. In addition, we invited

responses to the following questions. Is it feasible to rely on markets to support a

function that is so time-sensitive? Can such markets be made to function efficiently if the

RTO is not a control area operator? For the imbalances of individual transmission

customers, should a distinction be made between loads and generators? Should

customers have the option of paying for all imbalances in such a market or only

imbalances within a specified band? 

Several commenters hold the view that it is indeed feasible to rely on markets to

support a balancing function that is time-sensitive, 540 and many agree that access to a

real-time balancing market would be of considerable benefit to market participants. 541

NERA claims that technical logic dictates that an electricity system have a central process

to co-ordinate real-time physical operations. NERA argues that to the extent that this
Docket No. RM99-2-000 -408- 

process is not based on markets, it must be based on less efficient command-and-control

methods. NERA also claims that economic and commercial logic requires that a

commodity market have short-term trading arrangements to bring market positions into

agreement with physical reality, and argues that to the extent that market trading does not

reflect physical reality, some non-market process must close the gap between the market

and reality. NERA asserts that these two propositions imply that the best way to

maximize the role of the market and minimize the role of non-market processes is to base

real-time physical operations on a spot market and to allow market participants to use this

market for commercial purposes to the extent they find this useful.

Enron/APX/Coral Power states that access to a real-time energy balancing market

is central to assuring comparability in open access, and Industrial Consumers believes

that this proposal is the beginning of a much needed "paradigm shift" in the manner in

which ancillary services are defined and provided in the marketplace. Eric Hirst states

that implementation of a real-time balancing market would permit FERC to eliminate the

Order No. 888 requirement that transmission providers offer an energy imbalance service

to transmission customers. He argues that elimination of energy imbalance service, with

its awkward and arbitrary deadband and penalty payments, would be a pro-competitive

change. Professor Hogan claims that without an efficient spot market and the associated

transparent spot prices, it will be much more expensive and difficult to arrange balancing

and settlement for the increasing number of retail access programs in the states. East
Docket No. RM99-2-000 -409- 

542See EPA and Project Groups.

543See, e.g., PJM, PJM/NEPOOL Customers, Professor Hogan, NERA.

544See, e.g., Tri-State, Illinois Commission, MidAmerican, Duke.

Texas Cooperatives agrees that real-time balancing markets are desirable but believe that

simply commanding RTOs to promote the development of competitive markets for

ancillary services provides no incentive for the RTO and its members to do so. 

Also, two commenters argue that access to real-time balancing markets would

eliminate some significant barriers to entry for non-traditional resources such as

renewable and distributed energy. 542 In particular, EPA notes that providing such access

would eliminate arbitrary energy imbalance penalties that are a major barrier to

intermittent resources such as wind and solar energy.

Some commenters believe that the RTO itself should develop and operate a realtime balancing market. 543 PJM/NEPOOL Customers believe that the development of

such a market is an essential function of the RTO that will facilitate the further

development of retail competitive supply markets. PJM states that a real-time balancing

market can best be provided through a power exchange operated by an RTO. 

Commenters are divided as to whether the development of a real-time balancing market

requires that the RTO be a control area operator. Several believe that such markets are

possible whether or not the RTO operates a control area. 544 Indeed, MidAmerican

believes that, to function efficiently, these markets normally must operate in a region that
Docket No. RM99-2-000 -410- 

545See, e.g., PJM/NEPOOL Customers, Southern Company, FirstEnergy.

546See, e.g., Professor Hogan, Allegheny.

is larger than a typical control area. However, others take an opposite view. 545 

FirstEnergy, for example, argues that the timing, dispatch and telecommunications

infrastructure needed to operate a real-time balancing market today can only be done by a

control area operator and then only for a combined load within a control area with ample

generation resources under automatic generation control. 

Some commenters provide detailed recommendations regarding the rules that

should govern the RTO's operation of real-time balancing markets. 546 Professor Hogan

notes that the complex network interactions in an electric grid require that there be an

entity that can provide certain critical coordinating services, and that the most obvious

example of such services is energy balancing. He states that the operator should offer an

energy balancing redispatch service where market participants can make offers to buy and 

sell energy.

He believes that the best approach would be to run the balancing market as a "bidbased, security-constrained economic dispatch" with voluntary participation by

generators and loads. Professor Hogan emphasizes that the RTO must not reject

voluntary bids, stating that the natural extension of open access and the principles of

choice would suggest that participation in the coordinated balancing market offered by

the operator should be voluntary. He states that market participants can evaluate their
Docket No. RM99-2-000 -411- 

547See, e.g., Seattle, FirstEnergy, Florida Power Corp..

own economic situation and make their own choice about participating in the operator's

economic dispatch or finding similar services elsewhere. He believes that any other rule

would require some form of discrimination, and adds that there should be a strong burden

of proof for those who argue that it is necessary to restrict voluntary bids, or discard

consideration of some bids. Professor Hogan claims that experience in PJM and

elsewhere shows that his suggested approach can work.

However, several commenters take a very different view, claiming that the

development of a real-time balancing market is not a viable option. 547 For example,

FirstEnergy is concerned that a real-time balancing market is not practical to implement. 

It claims that transmission customers do not yet have the real-time metering and

associated communication needed to dispatch and match fluctuating loads to generation. 

FirstEnergy argues that it would be much better to tie this service to the NERC effort of

certifying ancillary service providers for control of generation, and activate the service

when the technology and installation can be accommodated. Seattle states that it

performs its own real-time energy balancing and expects to continue to do so. Seattle

opposes adding this function to an RTO because Seattle believes it will increase the

overhead costs of the organization. Seattle believes that market participants that require

this service should contract with third parties that stand ready to provide it. Florida

Power Corp. states that, given the complexity of implementing short term transmission
Docket No. RM99-2-000 -412- 

548See, e.g., Southern Company, Tri-State.

549See, e.g., UtiliCorp, Avista, APX..

service in general, it is difficult to imagine that a market for energy imbalance service

could be developed. It argues that if the market is limited to the generators needed for

control, the development of market mechanisms will depend on resolving issues such as

the mitigation of potential market power. Florida Power Corp. suggests that an RTO

could contract with generators to perform this balancing function using a mechanism that

is market-like in that generators would be selected based on their bids to perform the

function over some designated period of time, albeit not on an hourly basis.

Several commenters believe that control areas or RTOs should not be the sole

provider of energy imbalance services, 548 while others argue that the role of RTOs

should be limited to that of a supplier of last resort. 549 UtiliCorp states that, in addition

to serving as a supplier of last resort, the RTO must ensure public access to real-time

balancing information. SMUD argues that any burden on the RTO that falls outside of

the core function of ensuring regional transmission reliability will add cost and

complexity to an already costly and complex endeavor. SMUD recommends that the

Commission should limit its focus on generation to the role that generation-related service

plays in promoting reliable transmission. Desert STAR and FirstEnergy believe that the

Commission should give deference to RTOs regarding the development of markets for

real-time balancing. 
Docket No. RM99-2-000 -413- 

FirstEnergy believes that, ultimately, ancillary service provision must be based on

a free-market pricing mechanism, and Southern Company believes that if a real-time

balancing market is desired in a region, it will develop without a mandate. FirstEnergy

asserts that the detrimental effects of regulated and capped ancillary service markets have

been observed in the California and PJM markets. Also, APX believes that the

Commission should let the market, not the RTO, provide the trading arrangements in the

power industry. APX asserts that efficiency in the competitive market comes from the

de-centralized trading activity of self-interested buyers and sellers, and that competition

will develop further when market participants self-provide their ancillary services which

they acquire in forward contract markets. In APX's view, the RTO should not provide a

centrally optimized dispatch because a central dispatch will discourage, if not eliminate,

the commitment of forward contracts in the energy market and replace the price discovery

of forward markets with ex post pricing. To the extent that the RTO must acquire

ancillary services, including balancing services, APX believes that the RTO should

acquire them from a market created by market participants, and not create its own

markets. NERA, however, states that this argument ignores the fact that preventing the

ISO from operating balancing markets does not eliminate the network interactions and

real-time events that are inherent in any electricity network. Rather, according to NERA,

it merely forces the ISO to manage these interactions and events by less efficient and

more intrusive non-market means. NERA contends that if the objective really is to
Docket No. RM99-2-000 -414- 

550See, e.g., Enron/APX/Coral Power, LG&E, PJM/NEPOOL Customers,

FirstEnergy, TDU Systems, Florida Power Corp..

maximize the role of competitive market forces and minimize the extent to which the

monopoly ISO determines the outcome, the ISO should operate market-clearing

mechanisms that reflect network interactions and real-time events as accurately as

possible. Similarly, ISO-NE claims that it does not understand how operating a market in

which (as in New England, currently) an RTO does not buy and sell the pertinent

commodities can constitute "taking a position" in those markets such that its operation is

perceived as biased. ISO-NE believes that because it does not own market assets or

commodities, an ISO-type RTO is exceptionally well situated to run a fair and nondiscriminatory market. ISO-NE states that the linkages among transmission

operation/dispatch, generation commitment/dispatch, and economic and market forces

strongly support the integration of a physical market with an RTO's operations. 

Nevertheless, ISO-NE states that other financial power markets are welcome and can coexist in the same region with an RTO market.

Several commenters offered their views as to whether unequal access to balancing

options leads to unequal access in the quality of transmission service available to

different customers, and whether this is a significant problem when RTOs serve some

customers that operate control areas and other customers that do not. 550 A number of
Docket No. RM99-2-000 -415- 

551See, e.g., Enron/APX/Coral Power, PJM/NEPOOL Customers, TDU Systems.

commenters believe that the present system does lead to undue discrimination. 551

Enron/APX/Coral Power states that both the NERC and pro forma tariff rules are

inequitable and discriminatory in that large customers rarely will be significantly out of

balance due to the law of large numbers. Enron/APX/Coral Power states that such

customers are given great flexibility to balance their scheduled deliveries and load, while

smaller customers are much more likely to exceed the 1.5 percent deviation band, making

them immediately subject to penalties. Enron/APX/Coral Power believes that by offering

real-time balancing to all transmission customers, the NOPR promises to redress this

inequity. TDU Systems recommends that, pending the development of competitive

balancing markets, the existing inequity between control area operators and other users be

partially redressed by enlarging the deadband for imbalances to be repaid or received in

kind to no less than five percent of scheduled amounts. It also recommends that the penal

character of these charges should be reduced to a ten percent premium, except in cases of

abuse.

PJM/NEPOOL Customers argue that, to the extent current control area operators

wish to maintain access to inadvertent energy accounts to pay back imbalances and avoid

penalties, other transmission customers must have the same opportunity. In the

alternative, it recommends that all users be required to cash-out through the RTO

balancing process. Utility Engineers recommends implementing a pricing plan for
Docket No. RM99-2-000 -416- 

inadvertent interchange by participants of the RTO, where the price for inadvertent

interchange is geographically differentiated to reflect losses and constrained transmission

paths. They claim that such a pricing plan would need a continuous auction, which could

be achieved through establishing a pricing formula.

With regard to providing access to inadvertent energy accounts, other commenters

argue that there are valid reasons for distinguishing between customers that are control

areas and those that are not. FirstEnergy argues that no other entity, other than control

areas, can or should have that access to inadvertent accounts. It claims that, if market

participants are provided with the authority to "go inadvertent" as control area operators

currently have, the strain on the grid would drastically degrade system reliability,

requiring much higher reserve capacity requirements. FirstEnergy believes that marketers

would "borrow" from the grid during high price time periods and make whole on their

borrowing during low price time periods, thus distorting the true price signal. Florida

Power Corp. notes that in addition to balancing generation against load, control area

balancing also includes a requirement for contributing to the maintenance of system

frequency. In contrast, it notes that the non-control area transmission customer's

balancing requirement is limited to the directly measured load it serves. Florida Power

Corp. also claims that, if a system of payments was substituted for the inadvertent

payback system presently used, control area operators would simply be circulating large

sums of dollars between themselves to accomplish the same result at a higher
Docket No. RM99-2-000 -417- 

administrative cost. LG&E suggests that the Commission treat such technical issues

separate from the RTO NOPR and work in conjunction with NERC’s parallel efforts in

this area. Also, Florida Commission believes that inadvertent energy accounting between

control areas should continue to be allowed within the operating standards of NERC. 

With regard to any requirement that loads and resources must be in balance from

moment-to-moment, Professor Hogan and Eric Hirst believe there is no need for

individual loads and generation to balance their schedules separately, and PJM/NEPOOL

Customers states that balancing should be required only to ensure that generators deliver

the amount scheduled and committed. Professor Hogan argues that individual balancing

requirements both complicate the task for the RTO and provide a device to reinforce

market power. Eric Hirst states that the RTO's costs of providing or absorbing imbalance

energy should be charged equitably to those that under-generate and over-consume, with

compensation to those that over-generate and under-consume. He states that this will

result in charges and payments netting roughly to zero in each hour. However,

Enron/APX/Coral Power believes that any RTO proposal should include development of

an ex post energy balancing market in which buyers and sellers are given a finite amount

of time after the market has closed to find others with offsetting positions. 

Regarding the imbalances of individual transmission customers, commenters

disagree as to whether a distinction should be made between loads and generators. 

MidAmerican and Florida Power Corp. believe that loads and generators should be
Docket No. RM99-2-000 -418- 

treated differently. MidAmerican contends that it is much easier to control generators

than it is to control load, and in the future managing imbalances will become more

complex in that control from the load-side will involve the response of potentially

thousands of entities that may or may not respond as quickly as central generation. 

MidAmerican states that a distinction exists between loads and generators both in

magnitude and response time. Florida Power Corp. claims that load and generators are

not always similarly situated. It states that the nature of energy imbalance service

depends on whether a generator and the load that it serves are in the same control area or

are in different control areas. Eric Hirst, TDU Systems, and Duke believe that, in

general, the market rules and principles should be the same or comparable for generators

and loads, although TDU Systems believes that loads may be less likely than generators

to abuse the system by leaning on it. Eric Hirst states that the use of imbalance markets

would eliminate the asymmetry between generation and load in FERC’s definition of

energy imbalance. 

Finally, the NOPR also asked whether customers should be able to pay for all

imbalances in a market or only imbalances within a specified band. Duke believes that it

is appropriate to let the market participants determine how imbalances will be determined

and paid. PJM/NEPOOL Customers believes that the RTO should provide transmission

users with as many service offerings as possible, including the ability to opt for different

balancing pricing proposals. Florida Power Corp., however, believes that there should
Docket No. RM99-2-000 -419- 

only be one method of settling the imbalance market. It claims that complexity and

opportunities for gaming increase with options for settlement.

MidAmerican believes that transmission customers should pay for all energy

imbalances caused by the mismatch of scheduled energy and actual load. It recommends

that imbalance charges be based on market prices at the time the imbalance occurred, and

should include a penalty, in appropriate circumstances, to deter future imbalances. 

MidAmerican contends that if transmission customers are allowed to avoid payment

within a specified bandwidth, gaming of the transmission system will occur.

 PJM/NEPOOL Customers and Professor Hogan, however, argue that the RTO

should not be allowed to impose balancing penalties on transmission users. Eric Hirst

states that RTOs should maximize the use of price signals rather than penalties to

encourage appropriate behavior on the part of generators and loads, and Professor Hogan

states that such prices should reflect the marginal cost for power. Eric Hirst believes that

penalties should be imposed only to counter the perverse incentives that are created when

metering or billing procedures require prices to be calculated over time intervals that do

not correspond to those used to measure generation and consumption quantities. Using

the example of the California ISO, he states that mismatches between ten minute prices

and hourly quantities provide unintended incentives to generators to ignore ISO dispatch

instructions or to ignore their schedules. He claims that aligning the time periods for
Docket No. RM99-2-000 -420- 

552See, e.g., LPPC, Los Angeles, Georgia Transmission, JEA, PPC. A direct

supplier of ancillary services either owns or operates generation.

price determination and billing would eliminate these perverse incentives. He adds that,

where penalties are needed, they should be closely tied to the costs incurred by the ISO.

TDU Systems argues that if markets for balancing services are fully competitive,

transmission users should be able to use them to deal with any amount of imbalance. 

TDU Systems recommends that until such markets are fully competitive, it may be

necessary to restrict such purchases to a deadband to prevent abuse. It believes that any

such deadband should be less restrictive than that of the pro forma tariff. In that regard, it

recommends that the minimum within-band allowance should be no less than the greater

of two megawatts or five percent for loads or capacities up to 200 MW, with declining

percentage tolerances as loads and capacities increase in size.

Commission Conclusion

We conclude that an RTO must serve as the provider of last resort of all ancillary

services required by Order No. 888 and subsequent orders.

Since some commenters interpreted the "supplier" of last resort obligation as

proposed in the NOPR to require that the RTO be the direct supplier of ancillary

services, 552 we have made a minor change to the requirement by substituting the term

"provider" for "supplier." We clarify that this obligation requires that the RTO have

adequate arrangements in place for the provision of ancillary services.
Docket No. RM99-2-000 -421- 

The ancillary services adopted in Order No. 888 were defined using the control

area and its operator as the basis because a majority of transmission service was provided

by control area operators and they controlled the generation facilities that supplied

ancillary services. We note that since we are not requiring that the RTO to be a single

control area operator, we can not require an RTO that owns no generation to be the direct

supplier of ancillary services. Therefore we will give the RTO and its participants

flexibility in developing adequate arrangements for the provision of ancillary services to

all transmission customers that request service over the facilities under RTO control.

The RTO could fulfill its ancillary services obligations through a variety of

mechanisms, including contractual arrangements, indirect or direct control of specified

generation facilities, or market mechanisms. However, regardless of the method of

provision, the ancillary services must be included in the RTO administered tariff so that

transmission customers will have access to one-stop shopping for transmission service.

We conclude that all market participants must continue to have the option of selfsupplying or acquiring ancillary services from third parties subject to any general

restrictions imposed by the Commissions's ancillary services regulations in Order No. 888

and subsequent orders. In such instances, the RTO must determine if the transmission

customer has adequately obtained these services. The Commission believes that allowing

self-supply provides a possible competitive check on the RTO to ensure that to the extent

it does provide the services, it acquires them at lowest cost.
Docket No. RM99-2-000 -422- 

In the NOPR we asked whether additional or revised ancillary services are needed.

While a completely unbundled and competitive environment may require a modification

to the ancillary services required by Order No. 888, comments suggest that an immediate

change is unnecessary. We will not, at this time, make changes to the ancillary services 

described in Order No. 888. However, we will allow an RTO to propose other services in

recognition of local or regional conditions.

We conclude that the RTO must have the authority to decide the minimum

required amounts of each ancillary service and, if necessary, the locations at which these

services must be provided. All generators or other facilities that provide ancillary

services must be subject to direct or indirect operational control by the RTO. The RTO

must promote the development of competitive markets for ancillary services whenever

feasible. To ensure the reliable operation of the system, an RTO must have authority to

determine quantities and locations for ancillary services. The RTO should consider

stakeholder input as well as established industry standards in determining these

requirements. The Commission anticipates that some of the generation-based ancillary

services could be acquired in short-term markets. This has been the approach taken by

most of the ISOs that we have approved, and we see no reason that this would be

different for transcos or other types of RTO entities. Apart from establishing the general

requirement to use competitive markets, the Commission will allow the RTO
Docket No. RM99-2-000 -423- 

considerable flexibility in determining many of the detailed market design questions, with

case-by-case review by us.

As we proposed in the NOPR, we conclude that an RTO must ensure that its

transmission customers have access to a real-time balancing market that is developed and

operated by either the RTO itself or another entity that is not affiliated with any market

participant. We have determined that real-time balancing markets are necessary to ensure

non-discriminatory access to the grid and to support emerging competitive energy

markets. Furthermore, we believe that such markets will become extremely important as

states move to broad-based retail access, and as generation markets move toward nontraditional resources, such as wind and solar energy, that may operate only intermittently.

Some commenters believe that implementation of real-time balancing markets

presents technical problems that may prevent RTOs in some areas of the country from

making such markets available to market participants. For example, some argue that it is

difficult if not impossible for an RTO that is not a control area operator to operate an

efficient real-time balancing market. These commenters suggest that to the extent such

markets are feasible and desirable in a particular region, the RTO, its stakeholders and

market participants should be given the flexibility to develop markets in accordance with

their needs and capabilities.

We are not convinced that, at this time, technical considerations preclude the

development of a real-time balancing market for any potential RTO. As discussed
Docket No. RM99-2-000 -424- 

elsewhere in this Final Rule, we are requiring each RTO to be the security coordinator for

its region and to have, at a minimum, the authority to exercise a combination of direct and

functional control over facilities within its region. Thus, even if an RTO is not a control

area operator, it should have sufficient operational authority to ensure that a real-time

balancing market can be implemented. With regard to the issue of flexibility, we believe

that real-time balancing markets are essential for development of competitive power

markets. Therefore, although we will give RTOs considerable discretion in how they

operate real-time balancing markets, we will not allow implementation of such markets to

be discretionary.

Our conclusions regarding provision of real-time balancing markets are similar to

our conclusions regarding markets for congestion management; that is, we will not

prevent an entity other than an RTO that is unaffiliated with market participants, from

seeking to offer transmission customers a real-time balancing market. However, because

this function is so time-sensitive and requires such close coordination with the actual

dispatch, experience may ultimately show that it cannot be performed to a high degree of

efficiency unless it is made a part of the RTO's central or hierarchical dispatch activities. 

Also, we do not agree that an RTO's operation of a real-time balancing market will

interfere unduly with the efforts of others to establish markets in forward contracts for

energy.
Docket No. RM99-2-000 -425- 

We asked in the NOPR whether customers should have the option of paying for all

imbalances in a real-time balancing market or only imbalances within a specified band. 

Based on the comments received, we decline to give a generic solution for all RTOs in

this rule. An RTO may propose one approach or the other but should explain how it

proposes to overcome any disadvantages of the approach selected. 

In the NOPR, we noted that unequal access to balancing options can lead to

unequal access in the quality of transmission service, and that this could be a significant

problem for RTOs that serve some customers who operate control areas and other

customers who do not. We conclude that control area operators should face the same

costs and price signals as other transmission customers and, therefore, also should be

required to clear system imbalances through a real-time balancing market. We believe

that providing options for clearing imbalances that differ among customers would be

unduly discriminatory.

Finally, we asked in the NOPR whether, for the imbalances of individual

transmission customers, a distinction should be made between loads and generators. We

conclude that, for the purpose of determining cost responsibility for imbalances, no

distinction needs to be made. The system-wide balance between load and generation is

affected comparably by changes in load and changes in generation. Therefore, the cost of

an imbalance is unaffected whether the imbalance is determined ultimately to be the

responsibility of load or of generation. However, commenters point out certain
Docket No. RM99-2-000 -426- 

553FERC Stats. & Regs. ¶ 32,541 at 33,747.

554Id. at 33,748.

differences between loads and generators (such as in the time needed to respond to an

operator's instructions) that are important from the standpoint of system operation. These

differences can be relevant to the determination of the appropriate penalties to assess to

loads and generators that fail to submit accurate schedules. Thus, for purposes of

assessing penalties for inaccurate schedules, we conclude that a penalty mechanism that

treats loads and generators differently may be appropriate.

5. OASIS and Total Transmission Capability (TTC) and

Available Transmission Capability (ATC)

In the NOPR, the Commission proposed that an RTO must be the single OASIS

site administrator for all transmission facilities under its control and independently

calculate TTC and ATC. The Commission stated that the most controversial aspect of

OASIS operation is the calculation and posting of ATC 553 and noted that there is

widespread dissatisfaction with the reliability of posted ATC numbers. To alleviate this

problem, the Commission proposed that the RTO become the administrator of a single

OASIS site for all transmission facilities over which it is the transmission provider. 554

The NOPR outlined three levels at which an RTO could be involved in ATC calculations. 

At Level 1, the RTO would post ATC values received from transmission owners. At

Level 2, the RTO would receive raw data from transmission owners and itself calculate
Docket No. RM99-2-000 -427- 

555See id.

556Id.

557See, e.g., NASUCA, WPSC, EAL, NERC, Industrial Consumers, Entergy, Mass

Companies, JEA, LG&E, NY ISO, NJBUS, Sithe, TAPS, How Group, Southern

Company, PG&E, PJM, UtiliCorp, Williams, Cinergy, Oneok, East Texas Cooperatives,

Cal DWR, Tri-State, Seattle, New Smyrna Beach, RUS, Cinergy, Nevada Commission,

(continued...)

ATC values. At Level 3, the RTO would itself calculate ATC values based on data

developed partially or totally by the RTO.

In the NOPR, the Commission envisioned that RTOs would operate at Level 3 to

ensure that ATC values are based on accurate information and to minimize the

opportunities for manipulation. 555 The Commission also proposed that: (1) an RTO

must formulate a validation system to check any ATC data supplied by others; (2) in the

event of a dispute over ATC values, the RTO's data should be used pending the outcome

of the dispute resolution process; and (3) the RTO must formulate the operating standards

(subject to regional and national reliability requirements) underlying ATC

calculations. 556

Comments

Most commenters who address the subject agree with the Commission's

observations regarding dissatisfaction with ATC/TTC data. Moreover, most commenters

on the subject endorse the proposal that an RTO must be the single OASIS site

administrator for all transmission facilities under its control. 557 Some commenters,
Docket No. RM99-2-000 -428- 

557(...continued)

and Enron/APX/Coral Power.

558See, e.g., Sithe, RUS, TAPS, PG&E, SMUD, Cal DWR, New Smyrna Beach,

East Texas Cooperatives, WPSC, EAL, NERC, NASUCA, Seattle, Georgia

Transmission, First Rochdale, Tri-State, Industrial Consumers, Enron/APX/Coral Power,

Cinergy, Oneok, PJM, Williams, Empire District, PJM/NEPOOL Industrial Customers,

Entergy, Mass Companies, Nevada Commission, NJBUS, and LG&E.

559E.g., FMPA, East Texas Cooperatives, NJBUS, Empire District, Entergy,

Oneok, First Rochdale, Seattle, EAL, Sithe, WPSC, Sithe, PG&E, SMUD, New Smyrna

Beach, and PJM/NEPOOL Customers.

however, are opposed to mandating the RTO as the OASIS site administrator. For

example, Central Maine argues that it should not be precluded from operating its own site

because as a "wires-only company" it has an incentive to operate an efficient site in order

to maximize use of transmission capacity. EEI asserts that OASIS operation can occur

independently of formation of an RTO and that the tasks and problems of OASIS

operation will not become naturally easier to solve with the creation of an RTO.

Most commenters also support the Commission's proposal to have the RTO

independently calculate ATC and TTC. 558 In addition, a number of commenters

emphasize that independent and disinterested RTOs could be trusted and empowered to

maintain reliable ATC data and calculate accurate values. 559 Moreover, several

commenters are concerned with consistency across RTOs and contend that RTOs must
Docket No. RM99-2-000 -429- 

560See, e.g., Industrial Consumers, Seattle and WPSC.

also coordinate ATC values with adjacent regions and with the NERC regional reliability

councils. 560 

Many commenters concur with the Commission's conclusions about the different

levels of RTO involvement in ATC calculations. These commenters believe that Level 1

is insufficient for reliable and trustworthy data and that an RTO should independently

calculate ATC values. Several commenters, however, disagree about the appropriate

timing for Level 3 compliance. Some commenters, such as Cinergy, argue that upon

commencement of operation, an RTO should be required to perform all studies and

analysis needed for accurate ATC values consistent with Level 3. APX supports each

RTO reaching Level 3 as quickly as possible. Enron/APX/Coral Power asserts that upon

commencement of operation, an RTO should operate at Level 2 and, as it gains

operational experience, migrate to Level 3. SMUD supports RTO operation at Level 3

but is concerned about the significant costs associated with developing data. 

JEA is opposed to any RTO structure that gives an RTO complete authority over

ATC calculations for transmission that JEA will continue to own. JEA asserts that

transmission owners are in the best position to assess the capabilities of their own

transmission system. Therefore, absent formation of a transco, JEA does not support

relying on an RTO for ATC and TTC calculations because JEA argues that ownership
Docket No. RM99-2-000 -430- 

561See, e.g., Williams, EPSA, Cinergy, Empire District and PJM/NEPOOL

Customers.

and control of the assets would be split between two or more entities whose interests are

not always the same.

Both Cal ISO and NY ISO argue that the final rule should provide flexibility in the

OASIS requirements to accommodate network systems like the Cal ISO and the NY ISO

in which transmission service is not explicitly reserved. In addition, numerous

commenters argue that the Commission should expand the minimum requirements to have

every RTO employ a single set of OASIS practices and terminology. 561 They note that

consistency in OASIS procedures will allow seamless trades across RTOs.

How Group also focuses its comments on the standardization of transmission

transactions. It notes that without some level of standardization only a limited number of

market participants who learn all of the differences between RTOs can perform

transactions that span multiple RTOs. How Group proposes that each RTO establish a

coordinating committee with neighboring RTOs and transmission customers in order to: 

(1) coordinate the naming of interconnected facilities, sources, sinks, paths, points of

receipt and/or delivery between the RTO and its neighbors; (2) coordinate the sharing of

necessary data for the calculation of transmission capability on interconnected paths; and

(3) foster coordination with neighbors in adopting standardized business practices. It also

suggests that continued industry-wide coordination is necessary to formulate common
Docket No. RM99-2-000 -431- 

562See, e.g., Ontario Power, Williams, NERC and EPSA. 

definitions for types of transmission and ancillary services, curtailment priorities, and

timing requirements for arrangement of transmission services. 

Only one commenter expressed concern about the proposal to use the RTO's ATC

values in the event of a dispute. Southern Company contends that the existing

transmission owner's data are preferable to the RTO's data. Southern Company argues

that existing transmission owners have experience in operating the regional transmission

facilities and, therefore, are best qualified to determine ATC values.

Some commenters raise other OASIS-related issues that were not addressed in the

NOPR. For example, commenters argue that: (1) all reservations and scheduling,

including that for network service, should occur on the OASIS; (2) sanctions should be

levied against transmission providers that skew their ATC values; and (3) the power flow

methodology rather than the contract path model should be used for scheduling. 562 A

few commenters address issues relating to Capacity Benefit Margin (CBM). NASUCA

argues that administration of CBM should be a required function of RTOs and that a

uniform methodology for calculating CBM is needed. Similarly, Idaho Commission

asserts that requiring the posting of CBM on OASIS with a narrative explanation of its

derivation would be beneficial. Empire District states that the Commission should

provide better guidance about how to calculate CBM.
Docket No. RM99-2-000 -432- 

Commission Conclusion

After considering the comments, we continue to believe that an RTO must be the

single OASIS site administrator for all transmission facilities under its control. As

numerous commenters note, independent RTOs can be trusted to maintain an OASIS site

with reliable and current data that is easy to use. In addition, a single OASIS site for each

region instead of multiple sites will enable transactions to be carried out more efficiently. 

However, in response to those who argue for flexibility in OASIS requirements,

we clarify that this requirement does not mean that each RTO must itself operate the

OASIS for its region. Our concern is that there be no more than one OASIS site for the

facilities under the RTO's control, and that the RTO ensure that the OASIS site operator

have the same attributes of independence we require for an RTO. Thus, we will allow an

RTO the flexibility to contract out OASIS responsibilities to another independent entity,

if justified. More specifically, we do not intend to keep an RTO from participating in a

"super-OASIS" jointly with other RTOs.

We reaffirm that an RTO should operate at what the NOPR characterizes as Level

3 for ATC/TTC calculations, which requires the RTO itself to calculate ATC values

based on data developed partially or totally by the RTO. Most commenters believe that

Levels 1 and 2, where the RTO would accept the transmission owners' ATC calculations

or data, are insufficient for reliable and trustworthy ATC values. Level 3 ensures that
Docket No. RM99-2-000 -433- 

ATC values are based on accurate information and consistent assumptions. When data

are supplied by others, the RTO must create a system for tests and checks that ensure

customers of coordinated and unbiased data. We also agree with commenters who

recommend that RTOs coordinate ATC values with adjacent regions.

We recognize that the NOPR was silent on the appropriate timing for Level 3

compliance. Commenters suggested that: (1) an RTO should reach Level 3 compliance

upon commencement of operation; (2) an RTO should reach Level 3 as quickly as

possible; or (3) an RTO should operate at either Level 1 or 2 upon commencement of

operation and as it gains operational experience, migrate to Level 3. We conclude that an

RTO OASIS site, including ATC calculations, must be fully operational at Level 3 upon

commencement of service. All parties to a transmission transaction need precise ATC

values to make scheduling decisions.

We affirm that in the event of a dispute over ATC values, the RTO's values should

be used pending the outcome of a dispute resolution process. Only one commenter,

Southern Company, disagreed with this proposal and we are not persuaded by its

arguments. Each RTO must develop procedures to validate its ATC values.

How Group and other commenters address issues relating to the standardization of

transmission transactions. Standardization of transactions involves two separate

concerns: (1) many transactions will cross RTO boundaries; and (2) numerous customers
Docket No. RM99-2-000 -434- 

563We believe that the communications standards and protocols would, like the

current OASIS, make use of: (1) the Internet for communications; (2) interactive displays

using World Wide Web browsers; (3) file uploads and downloads for computer-tocomputer communication; and (4) templates defining the file uploads and downloads.

will do business with multiple RTOs. Without standardized communications protocols

and business practices, the costs of doing business will be increased as market

participants will be required to install additional software and add personnel to transact

with different RTOs and regions. Therefore, to promote interregional trade, standardized

methods of moving power into, out of, and across RTO territories will be needed.

We believe that standards for communications between customers and RTOs must

be developed to permit customers to acquire expeditiously common services among

RTOs. For example, we envision the creation of standardized communications protocols

to schedule power movements and to acquire auction rights. These protocols would not

standardize what the rights are, or the nature of the auctions. Instead, the focus of the

communications protocols would be on how customers communicate their intentions to

an RTO and how customers receive an RTO's responses. 

We agree with How Group and others that certain business and communication

standards 563 are necessary, and we believe that these standards will facilitate the

development of efficient markets. We believe, however, that these issues need further

examination based on a complete record. 
-435-

A few other commenters discussed issues that were not addressed in the NOPR. 

For example, commenters argue that: (1) all transmission transactions (reservations and

scheduling) should occur on the OASIS; (2) sanctions should be levied against

transmission providers that skew their ATC values; and (3) the power flow methodology

for scheduling, rather than the contract path model, should be utilized. In addition,

NASUCA, Empire District and the Idaho Commission raise issues relating to CBM. 

These issues are too detailed for this proceeding and we will not address them at this

time. Commenters will have the opportunity to bring up these issues in response to

specific RTO filings, as well as during OASIS Phase II proceedings and in the CBM

docket (Docket No. EL99-46-000).

6. Market Monitoring (Function 6)

In the NOPR, the Commission proposed that RTOs perform a market monitoring

function. Specifically, RTOs would be required to: (1) monitor markets for transmission

service and the behavior of transmission owners and propose appropriate action; (2)

monitor ancillary services and bulk power markets that the RTO operates; (3)

periodically assess how behavior in markets operated by others affects RTO operations

and how RTO operations affect those markets; and (4) provide reports on market power

abuses and market design flaws to the Commission and affected regulatory authorities,

including specific recommendations. In addition, the Commission asked a number of
Docket No. RM99-2-000 -436-

564See, e.g., New York Commission, South Carolina Authority, Mass Companies,

LG&E, ISO-NE, TAPS, SMUD, NECPUC, WPSC, Project Groups and Tri-State.

questions regarding the role of RTOs in market monitoring, the tools RTOs should use,

and similar issues.

Comments

Commenters address a number of issues regarding the market monitoring function. 

The issues can be grouped into three general areas: (1) the need for and scope of a

market monitoring function; (2) who should perform the market monitoring function and

how it should be performed; and (3) what are the specific components or procedures of a

market monitoring plan.

Need For and Scope of Market Monitoring

As a general proposition, a variety of commenters favor having RTOs serve as

market monitors. 564 Commenters, such as Blue Ridge, argue that RTOs should conduct

market monitoring because they will be in the best position to deal with the growing

volume of multiparty transactions and discern any manipulation or preferential treatment.

Several commenters, such as the Florida Commission, note that the appropriate role for

RTOs in market monitoring and the various aspects of the function will depend upon the

nature of the RTO that is ultimately established. TEP claims that RTO market monitoring

needs to be flexible given the costs involved in such a function. PP&L Companies

believes that RTO market monitoring should focus on properly structuring business rules
Docket No. RM99-2-000 -437-

565See, e.g., Metropolitan, DOE, CMUA, NASUCA and Project Groups.

to foster efficient transactions and gathering statistical information to make available to

the Commission or other enforcement agencies. EEI and Allegheny recommend that

RTO market monitoring identify market design flaws and propose solutions that lead to

greater efficiency, competitiveness and reliability.

A number of commenters support having the RTO should serve as the "first line of

defense" for detecting design flaws and market power abuses. 565 Cal ISO suggests that 

the RTO serve as a first line of defense in conjunction with state commissions and local

regulatory authorities in the region, particularly in the operation of hourly and real-time

markets where potential buyers may not have the ability to decline electric service, and

where transmission and ancillary services markets tend to have high concentrations. PJM

believes that market monitoring by RTOs provides a continual check on market activities

and accordingly, RTOs should have clear authority to investigate potential market power

abuses or flaws and to compel market participants to produce relevant information. 

SMUD contends that although RTO monitoring should be the first line of defense, an

independent RTO monitoring unit must not be a substitute for review by the Commission

and other regulatory agencies. 

In contrast, some commenters, such as Cinergy, argue that, if transmission markets

realize the efficiencies envisioned in the NOPR, the commodity market should be able to

regulate itself, with the Commission and the courts serving as backstops. SNWA
Docket No. RM99-2-000 -438-

cautions that RTOs may be too focused on safe and reliable operations to be a first line of

defense. Some commenters, such as Metropolitan and Southern Company, claim that

there is no benefit in having RTO monitoring replicate the costly regulatory responsibility

that already exists in state and Federal agencies. 

Several commenters propose an expansive RTO market monitoring role. 

NECPUC proposes that monitoring include mitigation of both market flaws and market

power. East Texas Cooperatives and SMUD believe that RTO market monitoring should

include remedying market abuse. Project Groups believes that an RTO should monitor

energy and ancillary services markets and their interplay, and develop indices and criteria

to evaluate activities and behaviors that may reflect market power abuse. Advisory

Committee ISO-NE suggests that the RTO monitor transmission and ancillary services

markets to identify design flaws and market power, and to administer or propose remedial

actions. Dynergy claims that monitoring should include oversight of transmission

owners' behavior. EPSA proposes that the RTO also document any significant market

impacts attributable to application of reliability rules.

Some commenters support limits on market monitoring by the RTO. Commenters,

such as Southern Company and Entergy, argue that RTO monitoring should not reach to

any market the RTO does not operate, nor should it encompass market power abuse and

the effect of existing structural conditions on the competitiveness of electricity markets.

Entergy adds that the RTO will not be in a good position to monitor markets it does not
Docket No. RM99-2-000 -439-

566See, e.g., Desert STAR, CRC and Tri-State.

operate. Several commenters claim that the purpose of monitoring should be to look for

market flaws, not act as policeman looking for bad behavior. 566 Desert STAR

recommends that any proposed remedy be restricted to market flaws within the RTO's

area of operation. Enron/APX/Coral Power argues that evaluation of the structure of

power markets and policing market power lies outside of an RTO's core competencies as

the operator of the transmission system. Tri-State opposes RTO monitoring of power

markets because it would add to the complexity and cost of RTOs and impermissibly

involve the RTO in issues about generation market power. NY ISO opposes monitoring

to the extent that it encompasses the RTO playing an investigative and enforcement role. 

Nonetheless, in its view, the RTO could mitigate evident market power problems on a

prospective basis by applying pre-approved remedies.

Sithe recommends that RTOs not have the authority to compel the provision of

commercially sensitive data and should instead rely on nonproprietary information to

monitor markets. PG&E contends that commercially sensitive information should not be

released to anyone except in accordance with Commission-approved rules. PP&L raises

concerns regarding the ability of the RTO market monitoring organization to guarantee

confidentiality of commercially sensitive information supplied to it. Seattle argues that

any claims of commercial sensitivity must be tempered by the need to create an efficient,

self-policing, transparent market for nondiscriminatory transmission services.
Docket No. RM99-2-000 -440-

567See, e.g., CP&L, TDU Systems, PP&L and PG&E.

568See, e.g., Industrial Consumers, Williams, Southern Company, PSE&G,

Arizona Commission, Georgia Transmission and East Kentucky.

Various commenters would limit the RTO market monitoring function to

information gathering. 567 They argue that the NOPR proposal is overly broad, too

extensive and open-ended, and a potentially burdensome requirement. Sithe argues that

the application of mitigation measures by the RTO could have real commercial impacts

on market participants that often cannot easily be measured or repaid after the fact;

therefore, market participants should have an opportunity to review and comment on

monitoring procedures prior to their implementation. Seattle claims that the Commission

should take a minimalist approach by facilitating market monitoring through greater

public information disclosure. PG&E believes that the RTO should not regulate the

functioning of the energy market. Duke supports RTO identification and description of

alleged market abuses to appropriate authorities through the regulatory framework that

exists today. 

Other commenters question the need for or otherwise oppose an RTO market

monitoring function, in general, as a form of back door regulation. 568 They contend that

RTO monitoring will be unduly burdensome, overtaxing and costly to the ratepayers. Los

Angeles and Salomon Smith Barney argue that RTO monitoring may interfere with the

proper relationship between the RTO and its customers, which they claim should be
Docket No. RM99-2-000 -441-

focused solely on providing nondiscriminatory open access transmission services. 

UtiliCorp argues that the assignment of market monitoring functions to a commercial

entity such as a transco (other than those functions concerned strictly with transmission

pricing) may raise antitrust concerns both for the transco and its customers.

Commenters differ on whether market monitoring should continue indefinitely. 

East Texas Cooperatives believes that continuous RTO market monitoring is necessary

because, in its view, antitrust laws and complaints to the Commission provide only a

slow, after-the-fact remedy. Entergy recommends that any RTO self-monitoring be 

allowed to terminate after a fixed period, subject to Commission approval. Industrial

Consumers suggests that market monitoring be limited to the period when the risk of

discriminatory conduct is greatest. Los Angeles claims that, once the Commission

determines that generation markets are workably competitive, market forces should be

allowed to discipline the markets. If an RTO market monitoring function is required,

PSE&G suggests a five-year sunset provision.

Who Should Perform Market Monitoring and How Should it Be 

Performed

Many commenters address the issue of whether the RTO should perform market

monitoring depending on the form of the RTO (i.e., whether the RTO is a for-profit or a

not-for-profit organization). Most commenters raise concerns about and generally oppose
Docket No. RM99-2-000 -442-

569See, e.g., Dynegy, South Carolina Authority, Industrial Consumers and East

Texas Cooperatives.

570See, e.g., PJM/NEPOOL Customers, Cal ISO, Tri-State and Metropolitan.

571See, e.g., Entergy and Duke.

572See, e.g., PJM, ISO-NE, NY ISO, WPSC and East Texas Cooperatives.

a for-profit RTO monitoring markets. 569 The commenters generally argue that, due to its

economic and business interests, a for-profit RTO cannot objectively monitor itself. 

CP&L submits that a for-profit RTO may be a competitor of other market participants in

the provision of congestion relief and ancillary services, which would make unbiased

monitoring of those markets difficult. TDU Systems would limit a for-profit RTO's role

to data collection. Other commenters recommend that for-profit RTOs employ a fully

independent organization to monitor market conditions. 570 A few commenters, however,

support for-profit RTOs serving as market monitors. 571 Entergy claims that market

monitoring conducted by a transco could be as effective as for any other type of RTO as

long as procedures are in place that ensure its independence.

Commenters also address whether an RTO that is an ISO needs to insulate its

market monitoring function from other RTO functions to ensure independence and

objectivity. A number of commenters generally believe it is appropriate for ISOs to

internally monitor market activities either through staff devoted to the function or through

a committee of ISO members assigned to the function. 572 They argue that an ISO, which

would be free of commercial interests, can be trusted by market participants, and
Docket No. RM99-2-000 -443-

therefore should not have to undertake costly establishment of autonomous monitoring

units. Mid-Atlantic Commissions note that PJM ISO's monitoring unit is a neutral body

that has access to and maintains confidentiality of market sensitive data in accordance

with sharing arrangements with each of the states in the region. California Board

contends that, if the internal unit is independent and has the ability to report and/or

consult with state and Federal authorities without needing additional approval, those

regulators are likely to respect the opinions and recommendations of the market

monitoring unit. CalPX suggests that RTOs and separate power exchanges coordinate

their market monitoring functions and jointly conduct research to lower costs. EPSA

suggests that the information and market data, if collected by an independent and

unbiased RTO, could be relied upon by market participants in formulating business

strategies, and by regulators for purposes of reviewing and approving modifications to

regulated aspects of RTO structures and operations. 

Most commenters, however, would require an ISO (i.e., a not-for-profit RTO) to

make its market monitoring function more independent. Pennsylvania Commission

contends that an independent ISO is absolutely necessary to perform market monitoring

functions. EEI points out that while an RTO's independence may ensure that its

recommendations do not favor particular market participants, this does not ensure that it

will monitor its own performance objectively. In its view, an ISO should use outside

experts within the monitoring committee or on an ad hoc basis to address concerns about
Docket No. RM99-2-000 -444-

objectivity. Similarly, PG&E contends that experience has shown that an ISO's rules and

actions may interfere with the proper functioning of the market. Industrial Consumers

contend that an RTO's operations must be sufficiently transparent that it is the market

participants that do the real monitoring. FTC suggests that internal RTO monitoring

could be problematic if the internal monitoring unit is given enforcement powers, because

this could both devolve into re-regulation and raise conflict of interest issues. FTC

recommends that the Commission's RTO rules explicitly make clear that self-monitoring

controlled by an RTO does not create an antitrust exemption for the RTO and its

participants.

Los Angeles believes that market monitoring should be conducted by an

independent body. CP&L, however, believes that delegation to a private party is

questionable, where its objectivity may also be challenged on grounds of conflict of

interest, particularly, if the delegated authority includes the ability to impose sanctions

and penalties. Oregon Commission believes that RTOs should appoint a local committee

to use RTO data to monitor the market for ancillary services because RTOs, as major

buyers and sellers of such services, will want to protect their market shares. The

Commission should consider establishing its own regulatory advisory bodies to monitor

markets. DOE also claims that the Commission should avoid reliance upon RTO

monitoring to the exclusion of the Commission's own monitoring efforts. Alliant believes

that moving responsibility for monitoring market power to another organization would
Docket No. RM99-2-000 -445-

allow the RTO to focus on the many technical demands that will be placed on it. 

Metropolitan believes market monitoring should occur on two levels: an internal group

responsible for data gathering and publication and frequent preliminary analysis of

anomalous conduct; and formal analyses performed by a group or committee independent

of RTO management whose results and recommendations would not require RTO

approval.

 LG&E proposes that the RTO make its monitoring findings public and refer them

to an appropriate regulatory body. Industrial Consumers opposes giving deference to the

RTO's recommendations for correcting such market power abuses and flaws. Instead, it

believes that stakeholders and market participants should use the RTO reports to make

their own recommendations. 

 NYPP believes that structural solutions are matters for legislators, courts or

regulatory agencies. In contrast, PJM believes that, if the market issue is a structural one,

the RTO should be able to propose structural remedies to the Commission.

In the case of localized market power, MidAmerican submits that it would be

inappropriate for the RTO to take corrective competitive actions in the case of localized

must run generating unit market power. Similarly, PG&E contends that RTOs should

allow temporary supply and price issues to be resolved by the competitive forces of the

market, unless there is a threat to the physical supply of power or a Commission

determination that markets are not workably competitive.
Docket No. RM99-2-000 -446-

573See, e.g., Salomon Smith Barney, South Carolina Commission, PG&E,

Enron/APX/Coral Power and Duke.

574See, e.g., SMUD, Tri-State, Cinergy, TDU Systems, EPSA, Industrial

Consumers, CMUA, PJM/NEPOOL Customers, NY ISO, ISO-NE and DOE.

CalPX believes that monitoring and reporting should be simplified in order to

reduce costs and to rationalize staff and committee work loads. Also, the RTO and power

exchange compliance related staffs should jointly conduct research that is beneficial both

to increase coordination and reduce costs. NY ISO submits that RTOs that are ISOs

should not be required to establish costly and otherwise burdensome autonomous market

monitoring units.

Many commenters address the issue of the appropriate role for the Commission

and the state commissions in market monitoring. Commenters overwhelmingly believe

that the Commission and state commissions have an important role to play, whether it is a

primary role as market monitors, or a secondary role providing oversight of market

monitoring activities by RTOs. 

Some commenters believe that market monitoring is better handled by the existing

statutory and regulatory agency frameworks than by RTOs. 573 They suggest a

continuing, if not mandatory, role for the Commission and other Federal and state

authorities in conjunction with any market monitoring undertaken by RTOs. 574 PP&L
Docket No. RM99-2-000 -447-

575411 U.S. 747 (1973).

Companies argues that, in Gulf States Utilities Co. v. FPC, 

575 the Supreme Court made it

clear that the Commission is charged with serving as the first line of defense to protect

and preserve competition in wholesale power markets.

TDU Systems and Sithe contend that regulatory commissions cannot abdicate to

RTOs the responsibility to ensure that wholesale electric markets are free of market

power. Many commenters see RTOs serving to forward any claims of market abuse and

market power to the various federal and local regulatory agencies consistent with their

respective jurisdictions. PJM and LG&E see the Commission reviewing remedies and

approving penalties and sanctions. Desert STAR and CRC see the Commission acting as

a backstop to an RTO's ADR process or mitigation plan. EEI suggests that RTOs

regularly inform the Commission about monitoring results, which will enable it to

respond quickly to problems not resolved by the RTO. SoCal Cities suggest that RTOs

share responsibility to remedy structural defects in the market or impose general

sanctions for market power abuse with appropriate state and federal agencies, but not

duplicate their responsibilities such as implementation of the FPA. CalPX believes that

there is a decreasing role for regulatory oversight as a result of a progression toward

greater RTO self-regulation.

Florida Power Corp. and Nevada Commission suggest close coordination of RTO

market monitoring with state regulators. Nevada Commission also suggests that RTOs
Docket No. RM99-2-000 -448-

collaborate their monitoring efforts with neighboring RTOs, as well as audit the records

of those parties who violate the RTO's rules. Project Groups recommends adding an

eighth minimum function under which RTOs provide data support for states' policies,

monitoring the competitive impacts of emissions regulations, verifying compliance with

state generation portfolio standards.

NARUC claims that the states need to be heavily involved in RTO market

monitoring and that the Commission should work with the states to make utility codes of

conduct more effective. In its view, such collaboration is the most effective means of

monitoring market power in generation, since the RTO would have information for the

region on transmission planning, generation expansion and transmission constraints, and

state commissions would have utility specific data and information on local operations. 

NARUC argues that such collaboration is critical because state commissions are

responsible for both evaluating local markets to assure competitiveness and for licensing

electric supplies, and abusers of market power can inhibit competition and distort the

prices of locally regulated services. NASUCA similarly claims that market participants,

state and federal regulatory agencies, and state consumer advocates periodically review

the indices and screens to be used for RTO market monitoring. The RTO should

periodically issue confidential reports to federal and state regulatory authorities and state

consumer advocate offices, that describe the state of the markets and the results of

matters under investigation. 
Docket No. RM99-2-000 -449-

576See, e.g., Florida Commission, New York Commission and Michigan

Commission.

577See, e.g., Florida Power Corp., CMUA and DOE.

A number of state commissions suggest a continuing oversight role over RTO

monitoring by the Commission and the states. 576 Oregon Commission recommends that

the Commission establish its own regulatory advisory bodies to monitor ancillary services

markets. For a for-profit RTO, it recommends that a regional oversight committee

perform this function with the Commission reviewing any oversight committee reports. 

Commenters also address a number of issues related to the ability of RTOs to

perform self-assessments. A number of commenters believe that RTOs are capable of

objective analysis. NY ISO contends that an ISO will have no incentive to distort the

results of its analysis. Cinergy recommends that RTOs be limited to monitoring the

behavior of the markets they administer because of the ready access to relevant

information. Los Angeles comments that, if the RTO is not primarily responsible for

providing ancillary services, it should not be burdened with surveying that market.

Other commenters oppose RTOs monitoring the markets that they operate because

of conflict of interest concerns. 577 EEI argues that independence from market

participants does not ensure that the RTO will be able to monitor its own performance

objectively, e.g., a non-profit RTO may not have sufficient incentives to minimize the

costs under its control. Oregon Commission comments that RTOs cannot be entrusted to
Docket No. RM99-2-000 -450-

monitor ancillary services markets, where they will be providing services and have

incentives to protect market share. Industrial Consumers contends that market

participants must perform monitoring and, accordingly, an RTO's operations should be

fully transparent. SNWA and PG&E claim that the RTO should establish an independent

body to monitor and evaluate its performance.

Some commenters, such as Salomon Smith Barney and Michigan Commission,

oppose the RTO monitoring markets where the RTO takes a market position because the

RTO plays the dual role of seller of services and policeman. Alliant contends that an

RTO will be competing with generation providers in congestion management and have an

incentive to build transmission facilities. Similarly, CP&L contends that a for-profit RTO

may compete with others in providing ancillary services, and therefore any proposal by

the RTO monitor for remedial action raises serious conflict of interest concerns. 

Industrial Consumers suggests that, even in markets where the RTO is the supplier of last

resort, the RTO should not have quasi-regulatory powers.

Commenters also address the issue of whether RTOs should be required to provide

periodic assessments of markets they do not participate in or operate, thereby assessing

the effect of existing structural conditions on the competitiveness of their region's

electricity markets. Some commenters oppose this proposal. Tri-State opposes an RTO

monitoring of power markets because it would not only violate the Commission's goal of

separation between transmission and power sales, it would also add a level of complexity
Docket No. RM99-2-000 -451-

and cost to the operation of the RTO. Justice Department believes that the RTO cannot

reasonably be expected to monitor activities with which it has no involvement. Justice

Department therefore recommends that the Commission consider requiring each separate

electric power trading institution to monitor any market that it operates.

On the other hand, a number of commenters favor extending RTO monitoring

responsibility to markets they do not operate. PJM/NEPOOL Customers argues that the

independence of the RTO would enable market participants and the Commission to have

confidence in the RTO's assessments. ISO-NE favors RTOs monitoring power markets. 

NASUCA recommends that RTOs monitor bulk power markets, capacity markets,

transmission rights markets, ancillary services markets and any other potentially

competitive markets. FTC suggests that, where an RTO is smaller than one of the major

interconnects, the Commission may wish to encourage all the RTOs within each of the

interconnects to coordinate their efforts to examine the effects of market rules or

variations between RTOs in market rules on the volume and price of inter-RTO

transactions. Cal ISO also sees collaborative market monitoring and assessment by

neighboring RTOs and at the national level.

Florida Power Corp. recommends that an RTO that is an ISO be required to make

regular assessments as to whether it has sufficient operational authority to ensure its

ongoing ability to provide reliable, open access transmission service on a comparable

basis to all customers—nonetheless, the RTO should not be self-regulating. 
Docket No. RM99-2-000 -452-

For those regions where the real-time balancing function is performed by an ISO,

Advisory Committee believes that the ISO should monitor market power in generation

markets. SoCal Edison claims that, where markets are not yet workably competitive, the

RTO, with Commission approval, should ensure that prices are just and reasonable

through appropriate temporary mechanisms such as price caps. PG&E counters that, in

no case, should RTOs be permitted to use control of a power exchange for unilaterally

capping prices set by the market. 

Many commenters address the issue of how the RTO should report, if at all, its

monitoring activities. The Commission did not propose to establish detailed standards on

the format and content of monitoring reports, noting that such matters are best left to the

RTO. We asked commenters to address whether reporting should be limited to when a

specific problem is encountered, or whether periodic reporting on the state of competition

and transmission access would be more appropriate.

Commenters express mixed views on reporting requirements. CRC supports the

concept of RTOs reporting to the Commission regarding RTO design flaws, and New

York Commission suggests that RTOs report on market power abuse as well. Florida

Power Corp. submits that, if market monitoring is necessary, it should be performed by

the RTO reporting and filing appropriate information with state and Federal regulators. 

Project Groups wants the provision of data to support state programs pertaining to the

monitoring of the competitive impacts of emissions regulations. Project Groups argue
Docket No. RM99-2-000 -453-

that RTOs would be uniquely positioned to support data collection for verification of

green marketing claims and compliance with information disclosure requirements and

portfolio standards. EEI opposes a Commission mandate for RTOs to track generation

source and emissions data. EEI recommends the RTO voluntarily undertake this task to

meet specific state compliance requirements provided appropriate safeguards protect

competitively sensitive information. EEI expresses concern regarding the possibility that

the RTO would have authority to collect and disclose information from a generation

source where the state has not imposed such a requirement. 

Several commenters favor issuance of monitoring reports at regular intervals. 

Project Groups believes that RTO monitoring units should issue public reports on their

activities and findings, including annual reports on the general state of the market. 

Metropolitan supports reporting at regular intervals from an external monitoring source;

however, during initial startup, more frequent reporting is advisable to assist participants'

understanding of the market operation. East Texas Cooperatives believes that RTOs

should prepare periodic reports to the Commission with the precise form left to the

discretion of the RTO.

California Board contends that regular reports on market performance should issue

at least on a yearly basis, and include all relevant data that can be made publicly

available. NASUCA contends that, to further create trust in the RTOs' ability to

effectively and objectively monitor the market, RTOs should periodically issue reports
Docket No. RM99-2-000 -454-

578See, e.g., Entergy, Duke, PG&E, PSE&G, PJM/NEPOOL Customers and

Williams.

describing the state of the markets that it is monitoring, items under investigation by the

RTO, and any results from completed investigations. In its view, market participants,

state and federal regulatory agencies and state consumer advocates should participate in

the development and periodic review of the indices and screens the RTO will use to

monitor the operation of the markets. Reports should be provided to state and federal

regulatory authorities as well as state consumer advocate offices, on a confidential basis,

to enable them to independently assess whether additional investigation is merited. Cal

ISO submits that the Commission should specify regular reporting requirements for the

RTO's monitoring unit. PJM believes that RTOs should periodically report results of

monitoring activities to the Commission and state agencies.

Components of a Market Monitoring Plan

Commenters address various issues regarding particular elements of a market

monitoring plan. Many commenters address the issue of whether RTOs should be

allowed to impose penalties and sanctions. Most commenters would limit the RTO's

ability to impose penalties or sanctions. Many of them argue that such authority should

remain the province of the regulatory and antitrust agencies. 578 Justice Department

claims that RTOs lack experience either in detecting exercises of market power or in

making recommendations on correcting market power problems. SPRA questions
Docket No. RM99-2-000 -455-

whether the imposition of sanctions by the RTO may conflict with the Supremacy Clause

of the Constitution and whether affected public power bodies could only consent to such

sanctions if they do not create indefinite or uncertain liabilities. PP&L argues that,

because it will be judge and jury, the RTO must demonstrate competitive harm before

taking any market action. Some commenters, such as CP&L, note that a for-profit RTO

may not be objective in imposing sanctions because it competes with other market

participants. Other commenters, such as Salomon Smith Barney, claim that RTOs should

be limited to extracting ordinary commercial penalties when market participants fail to

follow the market's rules. EPSA claims that RTOs should be empowered to intervene in a

market within the strict confines of the Commission's oversight only when a situation has

the potential to become catastrophic. Mass Companies opposes allowing a private RTO

or one that is operated by a non-stakeholder board to enforce violations of market

standards and impose sanctions and penalties.

Canada DNR claims that it will be problematic for Canadian entities subject to the

jurisdiction of Canadian provincial and Federal energy regulators also to be subject to an

RTO that has its disciplinary authority backstopped by the Commission. In its view, the

issue will not be resolved by simply having the appropriate Canadian regulator serve as

the regulatory backstop to the RTO for each Canadian entity because the Canadian

regulator may take a different position than the Commission. 
Docket No. RM99-2-000 -456-

A few commenters support authority for RTOs to impose penalties and sanctions. 

Among them, CalPX believes that RTO governing boards and power exchange market

monitoring committees must be able to take appropriate action either by referral to

regulatory agencies or directly through applicable sanctioning authority. It views this as

critical for self-policing and providing prompt remedies before problems detrimentally

affect market results. ISO-NE believes that an RTO should have the ability to impose

penalties and sanctions, but suggests that the RTO not act as an antitrust agency, in order

to increase the acceptability of sanctions among participants.

The Commission specifically sought comment on whether penalties should be

limited to violations of RTO rules and procedures, or whether the RTO should be allowed

to impose penalties for the exercise of market power. More commenters oppose than

support RTOs imposing sanctions and penalties for market power abuse. Among them,

Allegheny and Metropolitan claim that this is a proper function of regulatory or antitrust

authorities. Central Maine argues that the Commission cannot grant RTOs the authority

to impose corrective actions without affording the affected public utilities with procedural

due process. EEI believes that the RTO tariff may include RTO authority to impose fines

or sanctions to ensure compliance with RTO rules in accordance with the costs imposed

by their actions. Pointing to similar positions taken by Justice Department and FTC, EEI

contends, however, that the RTO should not attempt to define or prosecute alleged

exercise of market power because it is not a regulatory body or an antitrust agency
Docket No. RM99-2-000 -457-

authorized to take such actions. It also suggests that limited additional authority might be

granted during the transition to restructured markets to permit the RTO to deal effectively

and timely with identified market design flaws, software errors, or other unanticipated

situations that could be costly if no action is taken. 

Cinergy also argues that the RTO should not be allowed to take corrective action

against individual market participants. It believe that claims of market abuse and the

exercise of market power should be forwarded to the Commission to address consistent

with its jurisdiction. Similarly, MidAmerican recommends that RTO penalties be limited

to (1) willful violations of material RTO directives related to the operation of regional

transmission facilities, Commission approved RTO standards for transmission facility

operations, and material provisions of RTO agreements that conflict with the RTO

transmission tariff, and (2) violations of RTO transmission tariff provisions relating to

operating reserves and energy imbalances. NASUCA recommends that compliance with

RTO rules be enforced with penalties and sanctions imposed through a collaborative

process involving all market participants, regulatory agencies and consumer advocates. 

However, the Final Rule should specify that any actions taken by the RTO cannot

substitute for penalties or other remedies which may stem from independent

investigations by governmental authorities. Similarly, ISO-NE and SNWA generally

would impose sanctions based on a participant's engaging in patterns of conduct defined

in the RTO's rules or its tariff.
Docket No. RM99-2-000 -458-

NYPP, DOE, and LG&E generally concur that RTO sanctions and penalties

should only be levied for violations of RTO rules and procedures, whereas penalties and

sanctions for market power abuses are matters for the regulatory and antitrust agencies,

legislators, or the courts. Florida Power Corp. argues that, since an RTO does not have

authority to grant or terminate market-based rate authorizations premised respectively on

the absence or presence of market power, the RTO should therefore have no role in

passing judgement or imposing penalties for the exercise of market power. 

On the other hand, some commenters, such as East Texas Cooperatives, are more

comfortable with RTO imposition of penalties and sanctions for market power abuse. 

PJM recommends that RTOs be able to take corrective action to ameliorate market abuses

or flaws and to seek Commission approval to add penalties and sanctions to its market

monitoring plan. NECPUC recommends that market monitoring be expanded to include

formalized mitigation and sanction rules in connection with market design,

implementation flaws and market power. NY ISO claims that RTOs should mitigate

evident market power problems, on a prospective basis, by applying pre-approved

remedies. CRC submits that RTOs investigate whether market power abuse results from

a design flaw and report the results to the Commission for approval of its mitigation plan. 

WPSC sees RTOs being effective because they will have access to real-time data on

system conditions and should be given authority to take appropriate corrective action

immediately to respond to market abuses. 
Docket No. RM99-2-000 -459-

Some commenters also want sanctions against market participants for reliability

rule violations. PSNM claims that RTOs should defer to existing mechanisms where they

exist (such as the WSSC's Reliability Management System RMS, and NERC Reliability

Standards and Measures) for sanctions against market participants for poor performance,

rather than create new monitoring and sanction systems for RTOs. Similarly, Desert

STAR submits that any RTO should be allowed to pass the reliability performance

standards sanctions on to participants who do not comply. SMUD concurs that an

important aspect of enforcing reliability standards is ensuring that the RTO has sufficient

authority to police and investigate the markets they administer, and assess fines and other

appropriate penalties, or resolve disputes amongst market participants as to any alleged

market abuse.

A few commenters also address the Commission's questions about how much

discretion the RTO should have in setting penalties (e.g., should the RTO's penalty

authority be limited to collecting liquidated damages). Nevada Commission submits that

RTOs should be allowed to impose specific penalties and sanctions for non-compliance

with RTO rules based on liquidated damages and not punitive damages. Cal ISO and

Metropolitan believe that penalties should be limited to liquidated damages. Cal ISO

argues that for cases of repeated or intentional violations or serious abuses of market

power, the RTO should seek relief, including imposition of punitive damages, from the

Commission or other appropriate agencies such as the Justice Department. Metropolitan
Docket No. RM99-2-000 -460-

argues that liquidated damages sought by an RTO should be approved by the

Commission. And Duke opposes the RTO assuming the role of market monitor and

enforcer; therefore, it recommends that terms and conditions for any penalties the RTO

might impose should be agreed upon by contract during the RTO development process.

On the other hand, WPSC claims that the RTO should have the discretion to

determine the amounts of adequate sanctions and penalties to discourage anti-competitive

conduct. Whether the RTO has acted properly can always be reviewed after the fact

through a dispute resolution procedure either through the Commission or the Justice

Department. NASUCA contends that sanctions and other penalties should be large

enough to be an effective deterrent. It suggests that a for-profit RTO may have incentives

to impose unjustified penalties and should be required to allocate all revenue derived

from sanctions and penalties in a way that benefits customers. SMUD offers that, since

liquidated damages are a mere proxy designed to make a victim whole for a transgression,

they do not really serve as a deterrent to market abusive conduct.

Several commenters address whether the SEC model of regulating stock

exchanges, i.e., requiring extensive and sophisticated market monitoring of stock

exchanges, should applicable to RTO market monitoring. Some commenters, such as EEI

and PP&L, do not believe the model is applicable. EEI claims that monitoring scheme in

the securities industry is an exception because in most industries the market participants

bring competitive problems to the attention of antitrust authorities. Sithe also opposes
Docket No. RM99-2-000 -461-

any emulation of the NASD or NYMEX model of self-regulation at this time because of

the limited amount of market experience to date.

PJM/NEPOOL Customers and Cal ISO, however, contend that the RTO

monitoring function should be similar to that of a stock exchange because the RTO is

designed to ensure that the exchange of electricity can occur readily and easily in a

competitive marketplace. 

Commission Conclusion

In the NOPR, the Commission proposed that RTOs perform a market monitoring

function. Many commenters raise a number of issues regarding market monitoring. The

issues largely encompass the following concerns: the need for and scope of a market

monitoring function; who should perform this function and how it should be performed;

and what are the specific components or procedures of a market monitoring plan. 

The Commission recognizes that the market monitoring concept is new and not yet

well-refined, either at the Commission or within existing ISOs. We also acknowledge the

apprehensions of some parties that market monitoring by an RTO could intrude into

markets and affect their behaviors. The Commission, however, is engaged in finding

ways to understand market operations in real-time, so that it can identify and react to any

problems that are preventing the most efficient operations. It also has a responsibility to
Docket No. RM99-2-000 -462-

579See Gulf States Utilities v. FPC, 411 U.S. 747, 758-59 (1973).

protect against anticompetitive effects in electricity markets. 579 If we are to satisfy this

goal, we must systematically assess whether our policies and decisions are consistent

with this responsibility. Market monitoring is an important tool for ensuring that markets

within the region covered by an RTO do not result in wholesale transactions or operations

that are unduly discriminatory or preferential or provide opportunity for the exercise of

market power. In addition, market monitoring will provide information regarding

opportunities for efficiency improvements. 

However, in light of the different forms of RTOs that could be developed by

market participants and the varying types of markets an RTO may be operating within its

region, different market monitoring plans are likely to be appropriate for different RTOs. 

Consequently, after careful consideration of the comments, the Commission will require

that RTO proposals contain a market monitoring plan that identifies what the RTO

participants believe are the appropriate monitoring activities the RTO, or an independent

monitor, if appropriate, will perform. We believe that such approach will provide those

proposing an RTO sufficient flexibility to design a monitoring plan that fits the corporate

form of the RTO as well as the types of markets the RTO will operate or administer. We

have revised the regulatory text for the RTO market monitoring function to reflect our

decision to allow this flexible approach.
Docket No. RM99-2-000 -463-

Although we decline at this time to prescribe a particular market monitoring plan

or the specific elements of such a plan, the RTO must propose a monitoring plan that

contains certain standards. The monitoring plan must be designed to ensure that there is

objective information about the markets that the RTO operates or administers and a

vehicle to propose appropriate action regarding any opportunities for efficiency

improvement, market design flaws, or market power identified by that information. The

monitoring plan also must evaluate the behavior of market participants, including

transmission owners, if any, in the region to determine whether their behavior adversely

affects the ability of the RTO to provide reliable, efficient and nondiscriminatory

transmission service. Because not all market operations in a region may be operated or

administered by the RTO (e.g., there may be markets operated by unaffiliated power

exchanges), the monitoring plan must periodically assess whether behavior in other

markets in the RTO's region affect RTO operations and, conversely, how RTO operations

affect the efficiency of markets operated by others. Reports on opportunities for

efficiency improvement, market design flaws and market power abuses in the markets the

RTO operates and administers also must be filed with the Commission and affected

regulatory authorities.

In developing its market monitoring plan, the RTO should identify the markets that

will be monitored, i.e., transmission, ancillary services or any other market it may

develop (e.g., congestion management). With regard to those markets, the monitoring
Docket No. RM99-2-000 -464-

plan should examine the structure of the market, compliance with market rules, behavior

of individual market participants and the market as a whole, and market power and

market power abuses. The monitoring plan should also address how information will be

used and reported. The monitoring plan should indicate whether the RTO will only

identify problems and/or abuses or whether it also will propose solutions to such

problems. We note that sanctions and penalties may be appropriate for certain actions

such as noncompliance with RTO rules. However, the monitoring plan should clearly

identify any proposed sanctions or penalties and the specific conduct to which they would

be applied, provide the rationale to support any sanctions, penalties or remedies (financial

or otherwise) and explain how they would be implemented. With regard to the reporting

of market monitoring information, the monitoring plan should indicate the types and

frequency of reports that will be made and to whom the reports will be sent. Under the

FPA, the Commission has the primary responsibility to ensure that regional wholesale

electricity markets served by RTOs operate without market power. An appropriate

market monitoring plan must provide an objective basis to observe markets and, if

appropriate, provide reports and/or market analyses. Market monitoring also will be a

useful tool to provide information that can be used to assess market performance. This

information will be beneficial to many parties in government as well as to power market

participants. This includes state commissions that protect the interests of retail

consumers, especially where they are overseeing the development of a competitive
Docket No. RM99-2-000 -465-

electric retail market. We note, however, that the market monitoring function for the

RTO does not limit the ability of each state within the RTO's region or other authorities

to decide the nature and extent of its own market monitoring activities. 

We are not requiring a plan that necessarily involves the collection of data the

RTO would not collect in its ordinary course of business. We believe that the

information collected through the RTO market monitoring plan will reflect data that the

RTO will collect or have access to in the normal course of business (e.g., bid data,

operational information). In light of our requirements that the RTO have operational

control over the transmission facilities transferred to it and the RTO be the security

coordinator for its region, the RTO will be in the best position to perform (or provide

information to another entity, if appropriate, for it to perform) objective monitoring

functions for the markets that the RTO operates or administers in the region. 

In response to commenters' arguments that RTO market monitoring results in an

impermissible shift of Commission authority to other entities, we emphasize that

performance of market monitoring by RTOs is not intended to supplant Commission

authority. Rather it will provide the Commission with an additional means of detecting 

market power abuses, market design flaws and opportunities for improvements in market

efficiency. Further, because market monitoring plans will be required to be filed with

and approved by the Commission as part of an RTO proposal, we will retain the ability to

determine what, how and by whom activities will be performed in the first instance.
Docket No. RM99-2-000 -466-

Because we believe market monitoring is essential, we decline to set any sunset

date for monitoring at this time. However, as bulk power markets evolve and become

more competitive, we may revisit the need for the type of monitoring the Rule requires.

7. Planning and Expansion (Function 7)

In the NOPR, the Commission proposed that the RTO planning and expansion

process must satisfy certain standards. Specifically, RTOs would be required to: (1)

encourage market-motivated operating and investment actions for preventing and

relieving congestion; and (2) accommodate efforts by state regulatory commission to

create multi-state agreements to review and approve new transmission facilities,

coordinated with programs of existing Regional Transmission Groups (RTGs) where

necessary. We suggested that RTOs be designed to promote efficient use, which requires

efficient price signals such as congestion pricing, and efficient expansion of their regional

grid, which requires control over planning and expansion. We specifically proposed that

the RTO have ultimate responsibility for both transmission planning and expansion

within its region. If the RTO is unable to satisfy the planning and expansion requirement

when it commences operation, we proposed that the RTO must file a plan with specified

milestones that will ensure that it meets this requirement no later than three years after
Docket No. RM99-2-000 -467-

580FERC Stats. & Regs. ¶ 32,541 at 33,751-53.

581See, e.g., United Illuminating, Wyoming Commission, Industrial Consumers,

Champion, NSP, PG&E, Williams, LG&E, FTC and APX. 

initial operation. In addition, the Commission sought comment on whether three years is

an appropriate amount of time for implementation of this function. 580

Comments

Encourage Market-Motivated Operating and Investment Actions for

Preventing and Relieving Congestion

Many commenters support the Commission's proposal to require that an RTO must

ensure the development and operation of market mechanisms to plan and refinance

transmission system expansion. As part of this an RTO should provide all transmission

customers with efficient price signals that show the consequences for their transmission

use decisions. 581

Some commenters, such as JEA and Williams believe that this role is best

performed by for-profit entities because system expansion decisions must be driven by

economic considerations. Entergy also contends that a transco will not create any bias in

the method of grid expansion.

Los Angeles agrees that an RTO should rely upon market signals and market

solutions in assessing all feasible options (e.g., construction of new generation, redispatch

of existing generation, grid expansion) to assure the least-cost option is pursued. 

NASUCA also argues that the Commission should mandate that RTOs use least-cost
Docket No. RM99-2-000 -468-

planning on a region-wide basis for transmission system expansions and upgrades. It

notes that the larger the region over which least-cost planning is conducted, the more

economically efficient the outcome is likely to be. If market solutions do not develop or

are not timely, Los Angeles believes that the RTO must have the power to resolve the

transmission problem. LG&E proposes that RTOs be permitted to use competitive

bidding as a means to meet new transmission investment needs.

EPA believes that RTOs should adopt a resource planning process with sufficient

flexibility to consider non-traditional resources and to assign appropriate values to their

unique benefits. EPA further believes that RTOs should be encouraged to take into

account environmental costs and benefits that are not reflected in resource prices. 

Puget suggest that the Commission should recognize that the concept of RTOs

may contain some elements that do not enhance the reliable operation of the transmission

grid. Puget requests that the Commission should address more fully how it will mitigate

the effects of the severance of generation and transmission planning and operation and

how it plans to ensure maximum reliability at the lowest integrated costs.

NASUCA recommends that the Commission require RTOs to develop a baseline

regional transmission expansion plan that would identify the regional system's ability to

meet essential NERC reliability criteria and isolate potential constraint areas of the

existing system where upgrades may be necessary or additional generation desirable. 

Such a baseline plan could provide a valuable tool to market participants in signaling the
Docket No. RM99-2-000 -469-

582See, e.g., EME and Seattle.

best locations for new generation projects. Entergy proposes the use of a regional

transmission plan that includes a regional transmission planning summit process

involving all stakeholders. 

TAPS, however, questions whether market-based mechanisms to expand the

transmission grid will emerge readily from an efficient short-term transmission pricing

regime that accounts properly for the costs of congestion. TAPS asserts that, while

efficient congestion pricing is an important component of a well-designed transmission

regime, it is not the answer to the concerns that have been raised regarding the lack of

economic and regulatory incentives to expand the transmission grid.

Many commenters agree that RTOs should be responsible for conducting the

studies necessary to assess the need for new transmission system enhancement. 582

However, some commenters argue that the role of the RTO should be to facilitate market

investment by others in new transmission and generation, not to lead the market by

making its own plans for new facilities. For example, Seattle suggests that the RTO

should generate information on the locations, frequencies and costs of congested paths to

guide capital investment. It believes that the RTO need not make capital investments

directly; rather it should seek market mechanisms, such as requesting bids for needed

capacity, to encourage investments. EME states that performance of this role requires
Docket No. RM99-2-000 -470-

583See, e.g., PNGC, Wisconsin Commission, EAL, Entergy, PJM, Minnesota

Power and Montana-Dakota. 

accurate accounting for the impact of congestion and new generation, and proper

allocation of costs to those that require such costs to be incurred. 

To ensure that transmission expansion decisions are not biased, ComEd proposes

that RTO functions be performed by two linked organizations that together make up a

"Binary RTO." ComEd envisions that the Binary RTO would consist of for-profit

independent transmission companies (ITCs), each operating a large aggregation of

existing transmission systems, under the oversight of an independent, not-for-profit

Regional Transmission Board (RTB). The ITCs will identify transmission additions,

upgrade opportunities, and prepare long-range plans which would be reviewed by the

RTB and subsequently integrated in an RTB-wide planning system.

Powerex believes that it is better to eliminate congestion at its source through

facilities upgrades, if economically and environmentally feasible, than to attempt to

manage congestion on a long-term basis through congestion pricing schemes.

Many commenters support the concept that RTOs must be responsible for

transmission planning and that single-system planning should be the objective of the RTO

planning process. 583 Commenters differ, however, on the extent of the RTO's role in the

planning process. Some commenters, such as Powerex, argue that the RTO must have

control over transmission service, planning, system impact studies and facilities studies,
Docket No. RM99-2-000 -471-

and the authority to determine the need for, and require the implementation of,

transmission upgrades by member utilities. Other commenters, such as LIPA and H.Q.

Energy Services, propose that, in the absence of transmission expansion proposals from

current or proposed market participants, the RTO should have the responsibility for

assessing whether transmission improvements are needed and, if a need is found, the

RTO should have the authority to order such expansion. 

Some commenters such as NY ISO, on the other hand, express concern that

exclusive authority by the RTO over transmission planning is overly restrictive. NY ISO

claims that entities which are responsible for coordinating transmission expansion, but

which lack authority to make enforceable planning decisions, can nevertheless achieve

the Commission's primary transmission expansion-related goal, i.e., ensuring that

investments in new transmission facilities are coordinated to ensure a least-cost outcome

that maintains or improves existing reliability levels.

H.Q. Energy Services objects to NY ISO's arguments as being merely concerned

with preserving its so-called "two-tier" governance system which provides NY ISO

transmission owners with significant authority, or veto power, over interconnections with

generating facilities and over decisions related to transmission system planning and

expansion. H.Q. Energy Services does not believe that the two-tier approach is

appropriate unless the RTO has ultimate decision-making authority.
Docket No. RM99-2-000 -472-

584See, e.g., San Francisco, SoCal Cities and CMUA.

585See, e.g., NYPP, Industrial Customers, Mass Companies and Nevada

Commission.

Many commenters agree with the proposal that an RTO must be ultimately

responsible for all transmission expansions and upgrades. 584 These commenters claim

that transmission operations must be conducted on an independent and fair basis and must

be undertaken by an impartial entity if transmission services are to be offered on a truly

non-discriminatory basis. They argue that vesting the RTO with the ultimate

responsibility for expanding transmission systems eliminates the conflict that is inherent

in vesting these responsibilities with an entity that also has commercial interests that are

competing with users of the system.

Although SMUD supports having the RTO be responsible for transmission

planning and expansion, it cautions that, in such a paradigm, people that have no

responsibility to the ratepayers will be deciding planning and expansion issues. 

Therefore, SMUD argues that the Commission needs to scrutinize the recovery of the

costs of such expansion to ensure that such expansion decisions and costs are prudent,

just and reasonable.

Several commenters agree that the RTOs can and should play a significant role in

the transmission planning and expansion process. 585 Some of these commenters, such as

NYPP and Mass Companies, however, do not believe that the Commission should require
Docket No. RM99-2-000 -473-

that RTOs have authority to order a transmission owner to modify or expand its

transmission system. Nevada Commission believes that transmission owners should be

allowed to assist an RTO in the development of grid planning criteria and could take the

lead in such grid planning with RTOs performing more of an overview role. Professor

Joskow states that the transmission owners, operating through a sound RTO/ISO

transmission planning process should be expected to be the primary, but not necessarily

the exclusive, source of network enhancement initiatives. WEPCO argues that

transmission owners should be integrated into the RTO regional transmission plans where

they can be improved and expanded to meet regional needs most efficiently. Turlock

contends that the RTO's authority over the transmission system it operates must be

limited to that system. Turlock argues that the RTO should not have the ability to force

expansion of lower voltage or tangentially related facilities which are beyond the area of

its responsibility, even if those other facilities might have a small but theoretically

possible impact on the RTO's facilities.

CP&L supports a coordinated planning approach which would be similar to the

planning approaches identified in the Midwest ISO and the Alliance RTO filings, where

the RTO would have responsibility for review of the transmission plan, but the individual

transmission-owning entities would provide the necessary input to facilitate the

development of the comprehensive RTO transmission plan. East Kentucky argues,
Docket No. RM99-2-000 -474-

however, that an individual transmission owner should be able either to require or to veto

the building of a particular RTO facility. 

MidAmerican disagrees with the proposal that the RTO have the ultimate

responsibility for both transmission planning and expansion in the region. MidAmerican

claims that existing regional transmission groups (RTGs) have clear and prominent roles

in transmission expansion decisions in which planning for transmission improvements are

coordinated through collaborative processes that already involve many interested

stakeholders in the widest fashion possible. MidAmerican states that throughout the

MAPP region there is broad support for continuing transmission planning and expansion

decisionmaking as a collaborative function and that the existing collaborative processes

adequately accommodate RTO participation. 

Central Maine believes that RTOs/ISOs can and should play a significant role in

the transmission planning and expansion process, but disagrees with the Commission's

proposal to give ISOs ultimate responsibility for transmission planning and expansion.

Central Maine does not object to ISOs having oversight responsibility in these area, but

Central Maine believes that the planning and engineering functions should be a shared

responsibility between utilities and RTO, i.e., the Commission should consider utility

planners as a satellite to the ISO/RTO similar to satellite function served by utility control

centers in monitoring, switching and dispatching. Central Maine states that the
Docket No. RM99-2-000 -475-

586See, e.g., Project Groups, LIPA and SRP.

Commission should grant individual transmission owning utilities an equal voice in

determining the technical aspects of transmission planning and expansion.

Although Big Rivers believes that, as proposed in the NOPR, the RTO should be

the default provider of transmission planning and expansion, it agrees with NRECA that

incumbent transmission owners should have the first opportunity to build required

transmission system expansion with RTO ability to facilitate needed construction by

others. 

Some commenters suggest specific tasks and functions that the RTO should

perform or have the ability to require as part of the transmission planning and expansion

function. 586 For example, SRP proposes that at a minimum, each RTO should have the

authority to: (1) direct transmission owners to study and evaluate system performance

and to develop plans to solve known reliability or adequacy problems; (2) revise or

combine elements of transmission owners' plans to achieve the most efficient and reliable

transmission expansion plan; (3) approve or reject any component of the RTO

transmission plan developed by a transmission owner; and (4) approve facility additions

by third parties.
Docket No. RM99-2-000 -476-

587See, e.g., Illinois Commission, DOE and New Smyrna Beach.

Accommodate Efforts by State Regulatory Commission to Create MultiState Agreements to Review and Approve New Transmission Facilities

Many comments concur that multi-state agreements are to be encouraged and that

the RTO should be designed to work within that structure. 587 Commenters, including

NSP and Nevada Commission, encourage the Commission to provide an active role for

RTOs to participate with state and local government in the siting and licensing of new

facilities. PJM states that a cooperative relationship between RTOs and the states is

essential to effective transmission expansion planning. In PJM's view, states are more

likely to trust the planning decisions of RTOs that have no commercial interest in

transmission and generation expansion than decisions made by transmission-owning

entities, which have commercial interests.

Cinergy recommends that the final rule include a Commission commitment to

proceed aggressively to establish a forum to encourage coordination of RTO planning and

expansion among states through multi-state certification agreements and multi-state

regional planning boards. Cinergy notes, however, that the creation of a forum or agency

to review grid planning and expansion that would consider the public interest beyond the

constraints of state boundaries may require federal legislation. If so, the Commission

should be aggressive in its dialogue with Congress to obtain the requisite legislative

relief.
Docket No. RM99-2-000 -477-

The Kentucky Commission suggests creating a voluntary "Joint Board on Regional

Transmission Siting" to develop and review standards for transmission expansion. The

Joint Board would include participation from the Commission, state commissions, RTOs,

and other interested parties. The Joint Board would also convene ad hoc committees to

review specific transmission expansion proposals. Pennsylvania Commission also prefers

a joint Federal-state approach towards regulating RTO site approvals, expansion,

innovation and customer service. It notes that a joint Federal-state approach has been

used with success in other areas, such as the Susquehanna River Basin Commission, the

Delaware River Basin Commission and the Joint Pipeline Office which regulates the

Trans-Alaska Pipeline System.

Illinois Commission recommends that accommodation of multi-state efforts be

expanded to include the possibility of multi-state regional regulatory oversight

organizations. Such organizations could be instrumental in coordinating regional

solutions to regulatory and policy issues.

Otter Tail expresses concern that multi-state agreements may not actually add to

the efficient use and expansion of the interstate transmission system due to a danger that

these types of agreements could be mired in state-versus-state political conflict and

become unworkable, to the detriment of transmission owners, generators, and ultimately

customers. Industrial Consumers also does not believe that requiring an accommodation

with "multi-state agreements" is necessarily productive. It states that nothing now
Docket No. RM99-2-000 -478-

588See, e.g., Wisconsin Commission, Industrial Customers and SRP.

prevents such coordination among states, yet there is no obvious evidence that this will

work. Industrial Customers believes that states will always reserve the right to veto a

project that may be partially situated within their jurisdiction, regardless of the benefits

elsewhere. 

East Texas Cooperatives believes that retention of state public utility commission

authority over siting (and other necessary approvals) is necessary to control the risk of

overbuilding because RTOs will have no real incentive to limit facility construction.

Commenters generally express support for the proposal that the RTO build on

existing RTG processes. 588 For example, Industrial Consumers urges that the

Commission require existing RTGs to merge their functions with the RTOs because

RTGs should not be allowed to develop an institutional culture that diverges from the

goals and objectives of RTOs.

New Smyrna Beach and Oneok claim that market participants will undoubtedly

benefit from a multi-state siting process for transmission because it may make siting of

new generation easier if there is more certainty that related transmission siting decisions

will be made on a timely basis with one-stop shopping. 

Several commenters address the role of the Commission in the RTO planning and

expansion process. Detroit Edison and Wolverine Cooperative support the establishment

of the Commission as the primary channel of certification for transmission siting,
Docket No. RM99-2-000 -479-

construction, and expansion. Detroit Edison states that regional reliability organizations

and the RTOs in each reliability region should be permitted to determine necessary

changes and additions in transmission with input from transmission owners, control area

operators, and other interested parties. It is vital, it states, that a single administrative

agency resolve issues related to the siting of transmission facilities on a regional basis and

have the authority to approve transmission expansion plans on a timely basis. Detroit

Edison believes that the Commission should fill the important role of sole regulator over

transmission siting and construction, just as it currently does in approving the siting and

construction of natural gas pipelines, and it urges the Commission to work to gain such

authority.

Pennsylvania Commission recommends that, if an RTO determines that

transmission expansion is necessary, it should file with the Commission to demonstrate

that need. Once the Commission determines a need exists within the RTO, the RTO

should then file with the appropriate states for a determination of the siting issues. 

Pennsylvania Commission believes that vesting authority for determining the need for

transmission expansion with the Commission solves several problems that are certain to

arise in state forums. Federal determination of the need for transmission expansion

obviates the burden of filing with multiple jurisdictions and possibly receiving conflicting

determinations.
Docket No. RM99-2-000 -480-

Otter Tail states that Commission should seriously consider whether the public

interest would be better served through adoption of a transmission siting policy that is

similar to review of interstate natural gas pipelines. 

NY ISO claims that in many cases transmission expansion is delayed or blocked

entirely by environmental and other transmission siting regulations. Nevertheless, NY

ISO supports the NOPR's proposal that RTOs participate in efforts to create multi-state

transmission expansion agreements.

East Kentucky believes that there needs to be some regulatory oversight authority

for facilities that are deemed necessary by an RTO planning staff. East Kentucky

proposes that this regulatory authority be the Commission or a regional regulatory

authority.

Conlon recommends that the Commission have the necessary authority to enforce

reasonable siting request, or critically needed future transmission lines could be delayed

causing a reliability risk. Granting the right of eminent domain to transcos or ISOs in

Federal legislation would be another approach. This could be accomplished by the

Commission recommending to Congress that it have the right of eminent domain.

LG&E believes that it is important that state authority over system expansion not

impede necessary improvements that enhance the efficiency of the regional grid that is, or

will be, subject to RTO control. Ultimately there may be a need for a congressional

solution to the current balkanized system for authorizing grid expansion. In its
Docket No. RM99-2-000 -481-

comments, the East Central Area Reliability Council explicitly calls for such legislative

action based on its concern that transmission facility expansion requests will fail as they

become bogged down in multiple state reviews. LG&E shares this concern. Still, until

such time as the statutory framework for transmission expansion is amended, LG&E

believes that RTOs represent an opportunity for coordinating regional transmission

expansion needs among transmission owners and state authorities.

Project Groups maintains that RTOs should be required to coordinate and lead in

the development of comprehensive least cost regional plans for assuring short- and longterm system reliability, and they must coordinate the actions necessary for implementing

timely system upgrades and additions pursuant to those plans. For example, RTOs must

be given the authority to petition state and local regulators for necessary siting

authorizations, including certificates of need or public necessity and environmental

permits, as well as the authority to order construction of facilities sited and permitted

under state regulatory authorities. The Commission should encourage state reliance on

RTO-approved plans as the primary basis for the exercise of eminent domain powers

under state law.

Puget notes that state condemnation powers granted to utilities are usually limited

for the benefit of the citizens of the state in which the utility operates. It is not clear that

a state utility can delegate its state condemnation power to a regional RTO. Therefore,
Docket No. RM99-2-000 -482-

the final rule should expressly address how state condemnation authority can be legally

exercised by a regional RTO.

NASUCA maintains that the RTO regional planning efforts must not displace state

government siting authority. NASUCA states that the final rule should specifically

recognize state statutory authority to regulate siting of transmission facilities. For other

planning and expansion matters, the Commission should require RTOs to establish a

process to ensure that the RTO obtains input from state government agencies with respect

to the regional transmission plan. Nevada Commission states that it is imperative that the

RTO coordinate transmission siting and planning with state agencies. Tri State believes

that states should continue to fulfill their traditional roles in siting transmission facilities. 

However, it notes that it may be necessary for the states to consult with the RTO on

transmission facility certification since the RTO will be charged with overall

responsibility for transmission planning and will be required to work cooperatively with

states and other regional groups.

CP&L supports state and local governments retaining the authority for certification

and siting of new transmission facilities. These government agencies are closer to the

local residents who will be affected and can best evaluate the great number of factors that

must be considered in approving transmission routes.

Several commenters address the issue of eminent domain authority as a component

of the transmission planning and expansion function. East Kentucky believes that the
Docket No. RM99-2-000 -483-

issue of eminent domain needs to be addressed for not only RTOs, but also for the entire

open access transmission network. East Kentucky questions whether an entity, if

required by an RTO or the Commission to construct a transmission facility, has eminent

domain authority that is sufficient to allow the entity to acquire all property rights

necessary to construct the required facility. Consequently, East Kentucky argues that, as

a general proposition, Congress needs to grant federal eminent domain authority to any

entity that is required by the Commission or any form of RTO to build a facility so that

such entity can acquire private property rights under Federal law. Because it believes that

siting of transmission has become the principal impediment to transmission expansion,

EPSA also advocates that the RTO should be delegated sufficient authority to direct

transmission owners or others to excise their eminent domain authority, as necessary, to

implement transmission system expansion plans independent of the source of funds or the

beneficiary of the project. Under current law, this authority must come from the states. 

Thus, EPSA also advocates the passage of Federal legislation that vests the Commission

with primary jurisdiction over major transmission planning and siting decisions, perhaps

subject to a requirement that the Commission consult with a regional siting authority or a

consortium of affected state siting boards. 

Central Maine disagrees and recommends that the Commission should reject

EPSA's comments. Central Maine notes that, if a state government intends that an RTO

have the power of eminent domain, the state legislature will grant it. Central Maine
Docket No. RM99-2-000 -484-

589See, e.g., Tri State, SoCal Edison and PNM.

590See, e.g., NECPUC, Duke and South Carolina Authority.

591See, e.g., Champion, NYC, Turlock, SRP, TDU Systems and Industrial

Customers.

argues that RTOs should not be granted the power to do something indirectly that they

may not do directly. Consequently, it believes that EPSA must pursue its proposal

through the enactment of state legislation.

Whether Three Years Is an Appropriate Amount of Time for

Implementation of This Function

Several commenters support the Commission's proposal to allow up to three years

to implement the planning and expansion function. 589 Some commenters, however,

believe that three years is too short. 590 South Carolina Authority suggests a five-year

period. Florida Commission believes that it is premature to set any time limit for

implementation of the planning and expansion function.

On the other hand, several commenters believe that three years is too long a

period. 591 Most of these commenters believe that the planning and expansion is such an

important function that its implementation should not be delayed at all. NYC suggests

that implementation should not delayed more than a year. SRP argues that the 

uncertainty the currently exists about who ultimately will be responsible for building and

paying for new transmission facilities is causing delays in upgrades. According to SRP,

requiring the RTO to perform this function upon commercial operation will eliminate this
Docket No. RM99-2-000 -485-

uncertainty. Industrial Customers also argues that any delay should not be used as an

excuse to stall the construction of any facility for which the need has been established. 

SRP suggests that, if a delay in implementation is permitted, the RTO should be required

to identify the entity responsible for financing and building transmission expansion prior

to the RTO assuming such responsibility.

Commission Conclusion

We reaffirm the NOPR proposal that the RTO must have ultimate responsibility

for both transmission planning and expansion within its region that will enable it to

provide efficient, reliable and non-discriminatory service and coordinate such efforts with

the appropriate state authorities. In carrying out this overall responsibility, the

Commission has concluded that the NOPR's three separate requirements for RTO

planning and expansion must also be satisfied or, in the alternative, the RTO must

demonstrate that an alternative proposal is consistent with or superior to these three

requirements. Specifically, an RTO must satisfy the requirement to: (1) encourage

market-motivated operating and investment actions for preventing and relieving

congestion; (2) accommodate efforts by state regulatory commissions to create multi-state

agreements to review and approve new transmission facilities, coordinated with programs

of existing Regional Transmission Groups (RTGs) where necessary; and (3) file a plan

with the Commission with specified milestones that will ensure that it meets the overall
Docket No. RM99-2-000 -486-

592FERC Stats. & Regs. ¶ 32,541 at 33,751-52.

593Id. at 33,752.

planning and expansion requirement no later than three years after initial operation, if the

RTO is unable to satisfy this requirement when it commences operation. 

As noted above, the RTO should have ultimate responsibility for both transmission

planning and expansion within its region. The rationale for this requirement is that a

single entity must coordinate these actions to ensure a least cost outcome that maintains

or improves existing reliability levels. In the absence of a single entity performing these

functions, there is a danger that separate transmission investments will work at crosspurposes and possibly even hurt reliability. We also recognize that the RTO's

implementation of this general standard requires addressing many specific design

questions, including who decides which projects should be built and how the costs and

benefits of the project should be allocated. 592 As with other requirements of the Final

Rule, we propose to give RTOs considerable flexibility in designing a planning and

expansion process that works best for its region. It is both inevitable and desirable that

the specific features of this process "should take account of and accommodate existing

institutions and physical characteristics of the region." 593 We emphasize that, as the

transmission provider in the region, the RTO is required to provide service under a tariff

that is consistent with or superior to the Commission's pro forma tariff, and that tariff

obligates the transmission provider to expand and modify its system to provide the
Docket No. RM99-2-000 -487-

594See, e.g., Section 15.4 of the pro forma tariff which requires the transmission 

provider to use due diligence to expand or modify its transmission system to provide

requested services. Also, Section 28.2 of the pro forma tariff requires the transmission

provider to plan, construct, operate and maintain its transmission system in order to

provide network service, and to endeavor to construct and place into service sufficient

transmission capacity to deliver network resources to network customers on a basis

comparable to its own use of the transmission system. 

595We note that existing ISOs have addressed similar issues successfully. For

example, the PJM ISO is responsible for expansion planning, but the transmission owners

remain obligated to undertake upgrades necessitated by the plan, 81 FERC ¶ 61,257 at

62,275 (1997).

services requested under the pro forma tariff. 594 Because an RTO may not own all of the

facilities it operates, we clarify that nothing in this Rule relieves any public utility of its

existing obligation under the pro forma transmission tariff to expand or upgrade its

transmission system upon request. Accordingly, we shall evaluate each RTO proposal to

ensure that the RTO can direct or arrange for the construction of expansion projects that

are needed to ensure reliable transmission services. 595 However, the Commission

reiterates, as discussed below, its strong preference for market-motivated operating and

investment actions.

We further note that the pricing mechanisms and actions used by the RTO as part

of its transmission planning and expansion program should be compatible with the pricing

signals for shorter-term solutions to transmission constraints (i.e., congestion

management) so that market participants can choose the least-cost response. Otherwise,

their choices may reflect less efficient outcomes for the marketplace. For example, if the
Docket No. RM99-2-000 -488-

price of expansion overstates its cost (or the price of congestion management understates 

actual congestion cost), market participants likely will continue congestion management

solutions to a transmission constraint when expanding the system to relieve congestion is

more efficient. 

Market-Motivated Actions

Planning new generation or new transmission requires a coordinated approach to

ensure reliability and efficient congestion management. However, this does not

necessarily imply that all transmission expansions must be centrally planned by the RTO. 

Where feasible, an RTO should encourage market approaches to relieving congestion. A

market approach will require providing all transmission customers with access to welldefined transmission rights and efficient price signals that show the consequences of their

transmission usage decision. If the RTO's market approach is successful, the decisions of

where, when and how to relieve congestion will be driven by economic considerations. 

Most commenters agree with the NOPR proposal that RTOs should rely upon

market signals and market solutions in assessing all feasible options (e.g., construction of

new generation, redispatch of existing generation, as well as expansion of the

transmission grid) to assure that the least costly option is pursued. If an RTO can

facilitate market-motivated decisions, several commenters point out that its planning role

may largely be limited to extreme circumstances where continuing congestion in an area

threatens reliability. However, we also recognize that different market approaches to
Docket No. RM99-2-000 -489-

596For example, TDU Systems and other commenters suggest that, by promoting

competition for new construction, the RTO can minimize construction cost and also

reduce its own risk profile. For example, an ISO in Victoria, Australia (VPX), which

operates, but does not own transmission assets, uses competitive bidding for new

transmission facilities. At the Regional ISO Conference in Richmond, Virginia on June

8, 1998, Raymond Coxe described how VPX's strategy resulted in a number of bidders

competing for the right to build, own and operate new facilities. He concluded that the

"result of this competition was a lower price to the consumers of Victoria than would

have resulted from regulated transmission service by the largest incumbent provider."

Transcript at 86, Docket PL98-5-006. 

relieving congestion are still in the early stages of development. Similarly, while market

approaches to expansion are the subject of much discussion, they are also in the early

stages of development. 596 It is not the intent of the Commission either to mandate a

market approach to the exclusion of an executive decision by the RTO or to mandate any

particular market approach. 

 Nevertheless, if any market-driven approach is to be successful, there must be

accurate price signals that reflect the costs of congestion and expansion costs. As we

stated in the NOPR, accurate price signals are the link between current usage and future

expansion. Therefore, as discussed in more detail in Section III.E.2 Congestion

Management, every RTO must establish a system of congestion management that

establishes clear rights to transmission facilities and provides market participants with

price signals that reflect congestion and expansion costs. In implementing its planning

and expansion responsibility, an RTO must ensure that its decisions are not unduly

discriminatory and produce efficient outcomes.
Docket No. RM99-2-000 -490-

The Commission reaffirms its statement in the NOPR that independent governance

of the RTO is a necessary condition for nondiscriminatory and efficient planning and

expansion. While accurate price signals can signal the need for expansion, such

expansion may not be achieved if an RTO operates under a faulty governance system

(e.g., a governance system that allows market participants to block expansions that will

harm their commercial interests).

Multi-State Agreements and RTGs.

The final rule fully recognizes the statutory authority of the states to regulate siting

of transmission facilities. Currently, state and local governments and regulatory agencies

have exclusive authority over the siting process. Therefore, an RTO's planning and

expansion process must be designed to be consistent with these state and local

responsibilities.

RTOs must accommodate efforts by state regulatory commissions to create multistate agreements to review and approve new transmission facilities. The Commission

encourages the development of multi-state agreements or compacts to review and approve

new transmission facilities. This would expedite transmission construction and eliminate

duplicative (and possibly conflicting) reviews by multiple states. To facilitate any

voluntary actions taken by our state colleagues, we will require that the RTO planning

and coordination system must able to accommodate the possible emergence of new

regional regulatory systems.
Docket No. RM99-2-000 -491-

Existing RTGs have clear and prominent roles in transmission expansion decisions

in which planning for transmission improvements are coordinated through collaborative

processes. To avoid duplicative efforts, the RTO process must build on existing RTG

planning processes. Over time, since the RTO will have ultimate responsibility for

planning the entire transmission system within its region, we expect that the functions of

an RTG will be assumed by an RTO to avoid unnecessary duplication of effort.

Three-Year Implementation.

If the RTO is unable to satisfy the planning and expansion function when it

commences operation, it must file a plan with the Commission with specified milestones

that will ensure that it meets this requirement no later than three years after initial

operation. Recognizing that the planning and expansion function may require

coordination among multiple parties and regulatory jurisdictions, we do not require this

function to be in place at the initial operation of the RTO. We continue to believe that

three years is a reasonable deadline for creating an operational planning and expansion

system. Therefore, we will not extend this deadline or the requirement to file a plan with

the Commission with an implementation timetable. This time period could be affected by

the RTO's scope, the number of states and market participants, and implementation costs;

however, the urgent needs of the electricity markets make us disinclined to extend these

deadlines.
Docket No. RM99-2-000 -492-

597Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,730-32.

598FERC Stats. & Regs. ¶ 32,541 at 33,758.

However, the delay should not stall the construction of new or enhanced facilities

for which needs have been established, unless the RTO makes a positive decision that the

facility is not in the best interests of the region. Delaying transmission expansion could

result in significant market inefficiencies as well as unacceptable risks to reliability given

the long regulatory and construction lead times required to build new facilities.

8. Interregional Coordination (Function 8)

In Order No. 888, the Commission identified eleven principles it would use to

assess Independent System Operator (ISO) proposals submitted to the Commission. 597

One of these principles required that the ISO develop mechanisms to coordinate with

neighboring control areas to ensure reliability and the provision of transmission services

that cross system boundaries. The RTO NOPR encouraged transmission entities to

consider ways to reduce impediments to transactions among themselves, 598 but a

coordination requirement was not included explicitly in the RTO NOPR. Several

commenters pointed out that there was no explicit coordination requirement proposed in

the RTO NOPR and recommended including a function for RTOs similar to the

coordination principle in Order No. 888.

Comments
Docket No. RM99-2-000 -493-

599Many parties supported this requirement including NERC, Justice Department,

NARUC, NASUCA, Oneok, PJM, Duquesne and Industrial Consumers.

Several commenters identify coordination with other regions as a necessary

element that should be added more explicitly to the RTO functions. 599 These

commenters express this need as either required to ensure reliability or necessary for bulk

power markets to operate over sufficiently large areas. For example, NERC states that

the need for such coordination effort has increased as the management of short-term

reliability of the interconnected bulk power system and the operation of increasingly

competitive bulk power markets have become inseparable. Accordingly, NERC

recommends that an additional function be added to the final rule that requires RTOs to

integrate their market interface practices and reliability practices. It identifies OASIS

standards, information sharing with neighboring RTOs, ancillary services requirements,

parallel path flows, transmission loading relief, and interregional congestion management,

as practices and standards that need to be integrated.

Duquesne states that efficiencies can be realized from coordinating and developing

a seamless marketplace. It recommends that the Commission require RTOs to coordinate

and plan for seamless and uniform transmission rules, scheduling systems and

procedures, and reliability standards. In addition, Oneok suggests that the Commission

encourage neighboring RTOs to form reliability compacts under which loop flow and
Docket No. RM99-2-000 -494-

600ISO-NE, NY ISO and PJM recently signed a memorandum of understanding

concerning interregional coordination activities.

601This is similar to the existing ISO Principle #10 in Order No. 888 for single

control area ISOs: "An ISO should develop mechanisms to coordinate with neighboring

control areas."

other issues involving interregional reliability impacts can be resolved. 600 Also,

Wyoming Commission believes that the Commission should be flexible with respect to

inter-RTO interaction and that it may be appropriate to address these issues later rather

than in initial RTO filings.

Commission Conclusion

Coordination of activities among regions is a significant element in maintaining a

reliable bulk transmission system and for the development of competitive markets. In the

NOPR, we discussed several region-to-region coordination activities in connection with

the parallel path, congestion management, and expansion planning functions. However,

the comments persuade us to add a more general inter-regional coordination requirement

as one of the minimum RTO functions.

We will require an RTO to develop mechanisms to coordinate its activities with

other regions whether or not an RTO yet exists in these other regions. 601 If it is not

possible to set forth the coordination mechanisms at the time an RTO application is filed,

the RTO applicant must propose reporting requirements, including a schedule, for itself to

provide follow-up details as to how it is meeting the coordination requirements of this
Docket No. RM99-2-000 -495-

602"Interconnection" is a term used by the North American Electric Reliability

Council and others to refer to an interconnected alternating current transmission system. 

Engineering considerations require all generators connected to any one interconnection to

operate in a coordinated manner, that is, synchronously.

function. We expect the RTO to work closely with other regions to address inter-regional

problems and problems at the "seams" between the RTOs. Therefore, as recommended

by NERC and others, we will add the following regulatory text to our RTO Final Rule

functions:

(8) Interregional Coordination: The Regional Transmission Organization

must ensure the integration of reliability practices within an interconnection

and market interface practices among regions.

An RTO proposal must explain how the RTO will ensure the integration of

reliability and market interface practices. An RTO may ensure the integration of these

practices either by developing integration practices itself or by cooperating in the

development of integrated practices with an independent entity that covers all regions or,

for reliability practices, covers an entire interconnection. The term, interconnection, 602

refers here to any one of three large U.S. transmission systems. The Eastern

Interconnection covers most of the area east of the Rocky Mountains in the United States

and Canada. The Western Interconnection covers an area that is mostly west of the

Rocky Mountains in the United States and Canada, as well as a small portion of Mexico. 

The Electric Reliability Council of Texas (ERCOT) Interconnection covers much of

Texas.
Docket No. RM99-2-000 -496-

This provision does not mean that all RTOs necessarily must have a uniform

practice, but that RTO reliability and market interface practices must be compatible with

each other, especially at the "seams." RTOs must coordinate their practices with

neighboring regions to ensure that market activity is not limited because of different

regional practices.

We understand, as NERC pointed out in its comments, that the reliability and

market interface practices are becoming highly interrelated. The reliability practices

affect how markets interface with each other, and the market interface practices affect

reliability. For example, TLR and congestion management are both used to unload an

overloaded transmission interface, and these two practices must work together. We

consider congestion management and TLR are best used as sequential steps to unload a

line, with congestion management used first to unload a line in a market-oriented manner,

and TLR used to unload a line in a fair manner when either congestion management is

unavailable or an emergency condition requires immediate action. We therefore list

below TLR as a reliability practice and congestion management as a market interface

practice, understanding that these and other practices listed affect both reliability and

markets.

The integration of reliability practices involves procedures for coordination of

reliability practices and sharing of reliability data among regions in an interconnection,

including procedures that address parallel path flows, ancillary service standards,
Docket No. RM99-2-000 -497-

603FERC Stats. & Regs. ¶ 32,541 at 33,753.

transmission loading relief procedures, among other reliability-related coordination

requirements in this Final Rule. 

The integration of market interface practices involves developing some level of

standardization of inter-regional market standards and practices, including the

coordination and sharing of data necessary for calculation of TTC and ATC, transmission

reservation practices, scheduling practices, and congestion management procedures, as

well as other market coordination requirements covered elsewhere in this Final Rule.

F. Open Architecture

In the NOPR, the Commission stated its commitment to a policy of "open

architecture" and proposed to require that RTOs be designed so that they can evolve over

time. The Commission noted that there should be no provision in any RTO proposal that

precludes the RTO and its members from improving their organization to meet market

needs. 603 The Commission sought comments regarding the open architecture policy in

general and the flexibility needs of RTOs in particular.

Comments

Virtually all commenters support the NOPR's open architecture concept and

recommend that an RTO have the ability to evolve over time as it gains operating
Docket No. RM99-2-000 -498-

604See, e.g., APX, Arizona Commission, Cal ISO, Central Maine, Consumers

Energy, CP&L, Conectiv, Desert STAR, DOE, Duke, Entergy, EPSA, FirstEnergy,

Florida Commission, Georgia Transmission, Illinois Commission, Industrial Consumers,

LG&E, NERC, NPCC, NSP, NU, NY ISO, Oglethorpe, PJM, Seattle, Southern

Company, SMUD, SRP, TDU Systems, TEP, Tri-State and WEPCO.

605NSP states that the configuration of electric markets will be much different five

or ten years from now.

606WEPCO notes that costs savings associated with creating large, efficient

electricity markets will dwarf the savings attained by reducing the number of operators

through control area consolidation.

experience. 604 They endorse the principle of flexibility to accommodate the changing

needs of the market. 605 WEPCO notes that open architecture should permit flexibility

and urges the Commission not to require an RTO to be the only control area operator in

the region. 606 Ontario Power states that the open architecture policy should enable

RTOs to accommodate Canadian entities in the future. Oglethorpe observes that open

architecture policy would allow RTOs to utilize existing infrastructure and avoid high

transition costs.

However, Central Maine and Southern Company argue that the flexibility implied

by open architecture should not be used carte blanche. For example, there should be

limits to an RTO's evolution process because transmission owners have some

fundamental rights, such as: (1) the right to terminate their participation in the RTO; (2)

the right to switch to another RTO; (3) the right to merge RTOs; (4) the right to recover
Docket No. RM99-2-000 -499-

their costs and a return on investment; and (5) the right to protect their assets and

employees from damages and injuries.

LG&E states that the flexibility inherent in the open architecture concept should

be applied fairly to all market participants, including those transmission owners that have

already committed to existing or proposed ISOs. For example, a member of an existing

ISO should be allowed to move to another RTO.

Industrial Consumers perceives a potential downside to the open architecture

policy in that it may give existing IOUs a license to continue their opportunistic behavior

rather than facilitating true market transformation. Therefore, Industrial Consumers

argues that it supports the notion of flexibility inherent in the open architecture policy

only in the absence of market power. Illinois Commission argues that the pace of

evolutionary improvement of RTOs should not remain in the hands of vertically

integrated utilities because their interest in structural change may not be consistent with

the public interest.

Cinergy, EPSA and Georgia Transmission state that the flexibility implied by open

architecture should not be used to support deviations from minimum characteristics and

functions. However, CP&L believes that the proposed minimum characteristics and

functions are too stringent and do not allow for much flexibility that a changing market
Docket No. RM99-2-000 -500-

607CP&L and Southern Company state that the Commission should establish basic

RTO guidelines through a policy statement rather than by a rule. They contend that the

rules under the NOPR are too prescriptive, and will stifle the development of new RTOs.

608CP&L notes that participants in Midwest ISO identified certain conditions that

could be altered only by the transmission owners, including revenue distribution, pricing

methodology and withdrawal rights.

609Entergy at 42.

needs. 607 Georgia Transmission supports the Commission's commitment to providing

regulatory flexibility to allow RTOs to evolve.

 Many commenters state that the open architecture concept is so broad that it will

prevent stakeholders from developing meaningful RTO proposals. To bring some

certainty to the negotiating parties to an RTO proposal, CP&L recommends that the

Commission find that some necessary and reasonable limitations on modifications to

RTOs are permissible, and these can be overridden only by unanimous consent or a

supermajority vote. 608 MidAmerican states that the Commission should accept RTO

proposals that contain stated limitations, such as a transmission owner's right to withdraw

from an RTO. MidAmerican argues that such limitations are consistent with the

Commission's open architecture policy and would prevent transmission owners from

being discouraged to join RTOs. To promote certainty, Entergy notes that the

Commission should establish a general policy of grandfathering previously approved

RTOs and not altering their requirements except in extraordinary circumstances. 609
Docket No. RM99-2-000 -501-

Southern Company is concerned that RTOs could evolve in ways that are

undesirable to the participants that initiated its formation. Therefore, it argues that the

parties should have some assurance that certain key provisions of an RTO would not

change in the name of RTO evolution. For example, functions, boundaries, transmission

rate design, and allocation of transmission revenues should not be amended by the RTO

except by vote of the transmission owners, at least for the duration of a specified

transition period. Southern Company contends that the transmission owners will then

know what they are "getting into" when they join an RTO.

Many commenters recommend that the Commission should not mandate the

ultimate organizational form of the RTO given the electric industry's current state of

structural flux and the uncertainty of the future. These commenters argue that the

Commission's open architecture policy should encourage market participants to develop

transmission institutions that are effective in meeting the needs of the marketplace. 

FirstEnergy and NU state that there is a range of organizational and functional forms—

power pool (tight and loose): gridco, transco, marketco—which can accomplish the

Commission's goal of improving the efficiency of the transmission grid, and only time

and market forces should determine which form is best suited for a specific region of the

country. Southern Company believes that there should be no requirement that would

prohibit an RTO with no transmission ownership to transform into one that owns

transmission (i.e., change from an ISO to a transco). 
Docket No. RM99-2-000 -502-

610 PSE&G Reply Comments at 6-7.

PJM urges the Commission to clarify that RTOs can propose improvements to the

RTO independently of its members to meet changing market needs. PSE&G is opposed

to giving such authority to RTOs because it believes that the market participants rather

than RTOs should drive changes in the structure and operation of electric markets. 610

Cal ISO recommends that the Commission's open architecture policy should support the

creation of a structure that facilitates the addition of new participants, both within and

outside of the existing RTO boundaries. Illinois Commission urges the Commission to

modify the proposed paragraph 35.34(k) of proposed regulations to include an affirmative

expectation that RTOs will change to meet new competitive market needs and to improve

over time.

Commission Conclusion

As proposed in the NOPR, we adopt the principle of open architecture in order

that the RTO and its members have the flexibility to improve their organizations in the

future in terms of structure, geographic scope, market support and operations to meet

market needs. We will require that the RTO design have the ability to evolve over time. 

In addition, we will provide flexibility to allow RTOs to propose changes to their

enabling agreements to meet changing market, organization and policy needs.

Open architecture will permit RTOs to evolve in several ways, as long as proposed

changes continue to satisfy RTO minimum characteristics and functions. As a first
Docket No. RM99-2-000 -503-

example, open architecture will allow basic changes in the organizational form of the

RTO to reflect changes in facility ownership and revised corporate strategies. As noted

by Southern Company, an RTO that initially does not own any transmission facilities

might acquire ownership of some or all of those facilities. With an open architecture

design, the RTO's enabling agreements should anticipate and facilitate changes of this

nature.

Second, open architecture design accommodates change in the geographical scope

of RTOs. Electric markets are evolving quickly and future market trading patterns cannot

be foreseen at the time of RTO organization. An open architecture design will enable an

RTO to grow geographically and possibly merge with another RTO as changes in markets

suggest a realignment of organizations to meet evolving market needs.

Third, market support is another area that benefits from open architecture design. 

For example, an RTO may not initially operate a PX to support a regional spot market,

but later determine that the establishment of a PX would provide additional benefit in its

region. With open architecture, the RTO can propose to add a PX function (or a PX

monitoring function) to its design. Open architecture design ensures that such future

developments that are beneficial to the marketplace are not foreclosed.

Fourth, open architecture design accommodates changing operational needs. Most

commenters agree that, as RTOs gain operating experience, some changes will become

necessary. Cal ISO acknowledges that it had to make significant changes to its tariff and
Docket No. RM99-2-000 -504-

operational practices as it gained operating experience, and it believes further

modifications are likely to be identified as additional experience is gained regarding

evolving competitive markets. 

Finally, as noted in the NOPR, technological change make changes in RTO design

inevitable and desirable. Accommodating that change will require flexibility and

adaptability in the RTO organization; open architecture will permit design modification to

keep pace with technology.

Some commenters argue that the flexibility implied by open architecture design

should not be interpreted to mean unfettered ability on the part of the RTO to modify its

structure or processes. We agree. Although under our open architecture policy the RTO

will have the ability to propose whatever changes it believes are appropriate to meet the

evolving needs of the RTO and the region, any such proposals or changes to existing

agreements, which will be changes to the RTO's jurisdictional rate schedule(s) and

contracts, will be subject to Commission review and approval under the FPA. The

Commission will consider the merits of any changes to an approved RTO on a case-bycase basis. Interested parties will have the opportunity to comment on any such proposal. 

This process will enable all parties and the Commission to guard against proposed

changes that are likely to stifle competition.