Testimony, Comments & Press Releases

_____________________________________________________________________
NATIONAL ASSOCIATION OF STATE UTILITY CONSUMER ADVOCATES’
COMMENTS ON REGIONAL TRANSMISSION ORGANIZATIONS
NOTICE OF PROPOSED RULEMAKING
_____________________________________________________________________

Charles Acquard, Executive Director
National Association of State Utility
Consumer Advocates
1133 15^th Street, NW, Suite 550
Washington, D.C. 20005
(202) 727-3908
Dated: August 20, 1999 TABLE OF CONTENTS
Executive Summary 1
Introduction 3
I. Overall Policy Objectives 5

 
II. Expedite Issuance of a Final RTO Rule; Analyze Other Competitive Market Issues

Separately But Promptly 7
III. Minimum Characteristics of RTOs 10
A. Characteristic 1: Independence 10
1. Composition of RTO Boards Of Directors 12
2. Collaborative Committee Process 14
3. RTO Ownership Issues 15

 
a) Ownership of RTOs 15

b) Financial Interests Held By RTO Owners,
Directors and Employees 17
4. RTO Ownership of Transmission Facilities; RTO
Status For For-Profit Transcos 18
a) Arguments Against Ganting RTO Status to

For-Profit Transcos 1

b) Necessary Conditions Under Which RTO Status For

For-Profit Transcos Can Be Allowed 21
5. Other Issues Related To Independence 22
B. Characteristic 2: Scope and Regional Configuration 23
1. The Possible Effect of RTO Scope on Horizontal Market Power
In Generation and Transmission Markets 24
2. Scopes of Existing ISOs 24
3. Extent of Integration Within Each RTO Territory 25
4. FERC Changes To Proposed RTO Scopes And Regional
Configurations 26
C. Characteristic 3: Operational Control 26
1. RTO Reports on Effects of Dividing Control Area
Operator Responsibilities 28
2. RTOs As Security Coordinators 28
D. Characteristic 4: Short-Term Reliability 29
1. RTO Authority over Scheduled Transmission and Generation
Outages 29

IV. Minimum Functions 31
A. Function 1: Tariff Administration and Design 31

Operations and on System Expansion 31
2. Authority over New Interconnections 32
3. Authority over Other Transmission System Changes 33
4. Required Standards If RTO Is A For-Profit Transco 34
5. Single Transmission Access Charge 34
B. Function 2: Congestion Pricing 35
C. Function 3: Parallel Path Flow 37
D. Function 4: Ancillary Services 38
E. Function 5: OASIS and TTC and ATC 39
F. Function 6: Market Monitoring 40
1. RTOs Should Monitor the Operation of the Various
Competitive Markets 42
2. RTOs Should Evaluate Whether Design Flaws Exist In
RTO Rules or Procedures 44

Violating Any RTO Rules 44

 
G. Function 7: Planning and Expansion 46
V. Additional Issues 48

A. Issue F.3: Performance Based Regulation for RTOs 48
B. Issue F.4: Consideration of Incentive Pricing

Proposals (for Transmission Owners) 49 
C. Issue G: Public Power Participation in RTOs 52
 
VI. Conclusion 53

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

Notice of Proposed Rulemaking :

_____________________________________________________________________
NATIONAL ASSOCIATION OF STATE UTILITY CONSUMER ADVOCATES’
COMMENTS ON REGIONAL TRANSMISSION ORGANIZATIONS
NOTICE OF PROPOSED RULEMAKING
_____________________________________________________________________ Executive Summary
If competitive electric generation markets are to develop, the coordination of access to and control of transmission facilities on a regional basis by an independent Regional Transmission Operator, or RTO, is essential. Consequently, the Commission should use its authority under Sections 202(a), 203, 205, 206 and 210 of the Federal Power Act to require participation in RTOs by all investor-owned utilities subject to the Commission’s jurisdiction. The Commission should strongly encourage other types of transmission owners to participate to the extent otherwise authorized by various laws and regulatory requirement.
The formation of RTOs to operate transmission systems, however, does not in and of itself, ensure the creation of competitive energy markets. Prompt additional inquiry will be necessary into the need for coordinated control or market development of power exchanges and power markets. The Commission should not defer issuance of a final rule in this proceeding while those issues are addressed, however. Instead, the Commission should move forward expeditiously with the issuance of a final rule in this proceeding establishing guiding principles for the formation and operation of RTOs. The Commission should also immediately initiate a further inquiry into the competitive energy market issues discussed in Section II of these Comments.
The three most critical criteria governing RTO formation and operation include independence of the governance structure, actual operation control of the transmission system and tariffs, and the development of structural tools which allow the RTO to ensure the maintenance of short-term reliability of the grid. Governance must be independent of market participants. Governance must also be open and collaborative and financial interests of market participants in RTOs, or by RTO employees and directors in market participants, should be prohibited or restricted. Market monitoring and regional coordination of transmission planning and expansion are two additional critical functions RTOs must perform. Only by ensuring that the governance, control, operation and coordination of the expansion of the transmission facilities are truly independent can the Commission provide the required assurance to market participants that the system will be operated in a competitively neutral manner, free of discrimination by any particular market participant or stakeholder group.
The end goal the Commission seeks to achieve in the NOPR is the promotion of competitive generation markets. Even the smallest consumers on the system must be able to benefit from that competition. If RTOs are structured and operated in a truly neutral fashion free from control by any single market participant or stakeholder group, smaller consumers such as the consumers NASUCA represents will have the best opportunity to benefit from such competitive markets. NATIONAL ASSOCIATION OF STATE UTILITY CONSUMER ADVOCATES’
COMMENTS ON REGIONAL TRANSMISSION ORGANIZATIONS
NOTICE OF PROPOSED RULEMAKING Introduction
 
The National Association of State Utility Consumer Advocates ("NASUCA") hereby submits the following comments in response to the Federal Energy Regulatory Commission's ("the Commission's") Notice of Proposed Rulemaking ("NOPR") issued May 13, 1999 in the above-captioned docket concerning the formation of Regional Transmission Organizations ("RTOs"). Regional Transmission Organizations, Docket No. RM99-2-000, 87 FERC ¶ 61,173 (1999), 64 Fed. Reg. 31390 (June 10, 1999). In 1996, the Commission issued Order No. 888, requiring that all electric utilities subject to its jurisdiction file open-access transmission tariffs in order to facilitate the introduction of competition into wholesale electricity markets. In addition, in Order No. 888, the Commission encouraged the coordinated control of transmission services among multiple electric utility transmission systems through the development of Independent System Operators ("ISOs"). The Commission in this NOPR now seeks comment on whether the boundaries and functions of such ISOs should be broadened to encompass larger regions known as RTOs, proposes minimum characteristics and functions for forming and operating RTOs, and further seeks comment on the extent to which the Commission should encourage or mandate participation in such RTOs.
NASUCA files these comments in response to this NOPR. NASUCA’s comments generally urge the Commission to require participation in RTOs by all investor owned utilities subject to its jurisdiction, urge the Commission to encourage the participation in such RTOs by non-jurisdictional entities owning transmission facilities, and provide the Commission with general principles that the Commission should use to guide the formation and operation of such RTOs.
NASUCA is an organization comprised of offices from 39 states and the District of Columbia charged by their respective state laws to represent utility consumers before federal and state utility regulatory commissions and before federal and state courts. Each NASUCA member has extensive experience with regulatory policies governing the electric utility industry and has actively participated in the recent debates concerning restructuring of the industry to foster greater competition in wholesale and retail electric markets. NASUCA’s primary interest is the protection of residential and small commercial consumers.
The purpose of these comments is to provide input into the Commission's policy analysis in establishing guiding principles for the formation and operation of RTOs from the perspective of these small retail customers. We begin with a general discussion of the types of competitive issues facing market participants in the process of forming RTOs and the context within which proposed changes in regulation should be assessed. This context consists of the current and projected markets for electricity services and the broad policy objectives the Commission is trying to achieve through its regulation of the market participants that provide these services. We then address the specific minimum characteristics and functions proposed in the NOPR for regulation of regional transmission organizations.

NASUCA agrees with the Commission statement in the NOPR that the "traditional means of grid management is showing signs of strain" and that "continued discrimination in the provision of transmission services by vertically integrated utilities" may be impeding the development of fully competitive electricity markets. 64 Fed. Reg. at 31391. Although ISOs have been formed in California, New England, New York, Texas, the Mid-Atlantic states and several Mid-Western states, many sections of the country do not enjoy the benefits of regional coordination of electric transmission systems serving those regions. The development of ISOs, where formed, has promoted, and has the potential to promote, greater competition in wholesale markets. It has also facilitated competition in retail markets in the regions they serve. However, each functioning ISO has different governance structures and different degrees of operational control of the transmission facilities within its boundaries. Some of the ISOs that have been approved so far exercise control over the operation of wholesale markets, to varying degrees. Others have no responsibility for operating wholesale markets. It is interesting to note that the degree of competition in these different ISOs likewise differs.
Access to competitively priced alternatives for electric generation depends directly on regional coordination, operation and control of the transmission systems which provide the highways for delivery of this supply to consumers throughout the nation. Independent RTOs could provide an efficient means of undertaking the regional coordination and control of these facilities. However, the required degree of continued regulatory oversight of RTO operations depends directly on the degree of independence of the RTO’s governance structure and the operational and functional control the RTO has over managing the regional grid. Moreover, NASUCA would caution that just establishing RTOs, no matter how efficient, may not be sufficient to create workable, viable, competitive wholesale markets.
The electric grid in this nation consists of interconnected electric generators, transmission facilities and distribution facilities. The reliability of the nation’s electric supply depends on the high level of coordination among these various services and among the providers of these services. Transmission systems today exhibit characteristics of monopolies. These systems are comprised of essential facilities. Non-discriminatory access to these essential facilities is critical for effective competition to develop in wholesale and retail generation markets. Whether small consumers are able to benefit from this competition is directly related to the ability of competitive suppliers of generation to access all transmission related services on a non-discriminatory basis.
Consequently, independence must be the hallmark of RTO governance in order to ensure that competing suppliers of generation services can access transmission services on terms comparable to those enjoyed by vertically integrated electric utilities and to ensure that market signals regarding the amount and location of new transmission and generation investments are not distorted or suppressed. The policies and principles the Commission adopts as a result of this NOPR inquiry must ensure this comparability of access and level playing field for transmission and generation investment, and must ensure that the smallest consumers on the system, whether they are bundled native load customers or retail choice customers, can enjoy the benefits of competitive generation markets. NASUCA’s recommendations are grounded in attaining this objective.
 
 

The creation of RTOs facilitates the development of competitive energy markets. However, the creation of an RTO does not necessarily translate into the creation of a competitive market. The Commission must go forward immediately with the publication of a final rule in this docket mandating participation in RTOs and providing guiding principles on the minimum characteristics and functions for such RTOs. As of August 1, 1999, 24 states had passed legislation or regulatory orders for restructuring, and most of these states are moving forward with retail choice programs for electric consumers. Such programs fare a better chance of success if RTOs are created to coordinate non-discriminatory management of the transmission services critical to moving energy from generators to consumers.
It is important to recognize that the issues entailed in the development of energy markets, power exchanges, power pools, ancillary services, and energy imbalance mechanisms also require the Commission’s attention. These additional issues, however, require substantially greater discussion before guiding principles can be developed in these areas. NASUCA therefore recommends that the Commission move forward immediately with the adoption of a final rule requiring participation in RTOs and establishing guiding principles for the formation and operation of RTOs. However, because of the importance of the additional issues involved in the creation of power markets, NASUCA urges the Commission to seek public comments as soon as possible regarding these additional issues through a further notice of inquiry.
This NOPR raises many issues that relate to or bear on the general issue of what kinds of wholesale electricity services can and should be delivered through the use of competitive markets rather than under traditional rate regulation. For example, the questions the Commission asks on page 214 of the NOPR do not sufficiently address many of the key issues associated with power exchanges. 64 Fed. Reg. at 31434 (Slip op. at 214). Other issues that are touched on in the NOPR, but receive limited attention, involve congestion cost pricing, locational marginal cost pricing, markets in transmission capacity rights, ancillary service markets, energy balancing mechanisms, energy markets, short-term system reliability, system dispatch and re-dispatch, and others. Still other issues that are integrally related to establishing competitive markets for electricity service, but do not seem to be addressed in the NOPR, include long-term reliability, installed capacity markets, operable capacity markets, price caps for must-run generation units, and specific aspects of energy market structures (such as bilateral contract markets).
Because so many of the above issues are highly complex, and because the current NOPR does not solicit comments on a sufficiently wide-range of these inter-connected issues as noted above, it would be preferable to begin to implement the key guiding principles for RTO governance and administration if consideration of the above listed issues relating to competitive market mechanisms and structure were addressed separately from the current NOPR. These issues would be better addressed in a more thorough fashion through one or more notices of inquiry that should commence as soon as possible. However, it is imperative that the Commission move forward immediately with at least the core aspects of the RTO NOPR in order to begin the process of facilitating competitive electricity markets.
One significant omission from the Commission’s discussion in the NOPR of power exchange-related issues centers on the need for, and desirability of, generation capacity markets. This issue directly couples with the issue of how to best preserve system reliability at adequate levels in the long run. As the Commission must know, there is a substantial debate as to whether a regional power exchange should have both a capacity and energy market, or whether just an energy market will suffice to preserve system reliability in the long run. In fact, the PJM Energy Markets Committee and the PJM Reliability Committee have created a hybrid user group charged with the task of investigating whether alternative mechanisms to energy price caps and capacity obligations can adequately ensure long-term reliability for consumers.
Since the manner in which capacity prices are established in a region will directly affect how energy prices are bid or established, whether a capacity market exists will directly affect the congestion costs or prices as computed by the RTO. For example, congestion costs for a transmission system where an energy poolco exists could be computed using bid prices for energy, not short-run marginal energy costs. California provides an example of an existing ISO that co-exists with an energy-only power exchange, whereas PJM and NEPOOL are existing ISOs that operate capacity and energy markets, albeit in different forms. Nevada, on the other hand, is exploring the concept of a state-wide Independent System Administrator ("ISA"), i.e. regional coordination of scheduling of transmission services without the operation of any power exchange mechanism. The Midwest ISO and Alliance RTO proposals also follow the path of leaving the development of power exchanges to the market.
Even the question of whether an RTO needs to require a certain level of capacity reserves is still controversial. Many have argued that without a generation capacity reserve requirement, the market cannot be relied upon to provide adequate amounts of generation capacity to maintain system reliability at a sufficient level and at a reasonable price. PJM, New England, and New York require reserve margins, while in California there is no such requirement. The Midwest ISO functions on the basis of operating reserve requirements to ensure long-term reliability.
The specific examples noted above illustrate the difficulty inherent in addressing power exchange related issues at this time. An attempt to resolve these issues in the context of the current RTO NOPR will likely greatly lengthen the time needed to turn the NOPR into a final rule. The Commission should not attempt to cover too much ground in this NOPR. Fair access to and use of the transmission system are still a necessary pre-condition for establishing competitive electricity markets, and must be accomplished without delay. The Commission should promptly initiate an additional Notice of Inquiry to consider the multi-faceted issues at stake in addressing power exchanges and related power market issues.
III. Minimum Characteristics of RTOs
A. Characteristic 1: Independence
The societal benefits produced by RTOs will depend largely on the degree to which they are able to ensure non-discriminatory access by all market participants to transmission services and to any other services for which RTOs have responsibility. However, because the interests of some market participants conflict with the objective of non-discriminatory access, influence by these market participants and stakeholders could lead to discrimination. As the Commission notes in the NOPR, RTOs must be independent in perception as well as in reality. 64 Fed. Reg. at 31403 (Slip Op. at 119). The perception of discrimination, whether accompanied by true discrimination or not, can dampen competition by affecting the willingness of certain entities to participate in the market, "including, for example, building new generating units, thus thwarting the development of robust competition." The Commission further noted that such perception could harm reliability, since there would be a greater reluctance on the part of market participants to share operational real-time and planning data with RTOs due to suspicions that such RTOs are sharing this data with the market participants’ competitors. Id.
To prevent both the appearance and reality of discrimination, RTOs should be independent of market participants. In this context, we define "independent" as "free from dominance by any stakeholder or category of stakeholders." RTO independence depends on the influence any category of stakeholders could exert. The influence of any category of stakeholders over the RTO must be limited such that no category is able to control or direct the RTOs’ decisions.
While the Commission’s proposals in the NOPR with respect to the Independence Characteristic lay the foundation for ensuring independence of governance, the Commission should strengthen these provisions to decrease the potential for disproportionate influence by individual categories of stakeholders. There are five areas in which NASUCA recommends additional guiding principles: 1) composition of RTO boards of directors; 2) collaborative governance process; 3) ownership of RTOs and RTO relationship with transmission owners; 4) RTO ownership of transmission facilities; and 5) operational control over scheduling transmission flows and tariff management.
1. Composition of RTO boards of directors
The Commission should require that RTO boards of directors and/or managers be free of control by individual stakeholders or groups of stakeholders. Such independence is best achieved by non-stakeholder boards, comprised of candidates recruited by an independent executive search firm and elected by all stakeholder groups in the RTO through a process which is not controlled by any single stakeholder, or stakeholder group. A non-stakeholder board will reduce the likelihood of real or perceived discrimination, while bringing the financial and management skills necessary to govern the RTO in an open and non-discriminatory process.
Even a non-stakeholder board could disproportionately represent the interests of a particular category of stakeholder if that category exerted a disproportionate influence over the selection of directors and used that influence to select directors sympathetic to that category’s interests. Therefore, the selection of directors must be conducted with sufficient participation by all categories of stakeholders, but with domination by none.
While non-stakeholder boards are preferable, NASUCA would not rule out the possibility that RTOs may be appropriately governed by stakeholder boards of directors or managers. If stakeholder boards of directors or managers are allowed, four conditions must be met:

 

First, the board should contain sufficient representation from all stakeholder groups;

Second, there should be no domination by any one category of stakeholders, nor by any single stakeholder;

Third, the size of the board or the committees should be manageable in order to allow for effective governance; and,

Fourth, governance should be designed to foster constructive collaboration among the stakeholders.

Compliance with these minimum criteria is critical if a stakeholder board is to effectively govern the RTO’s operations in a non-discriminatory manner.
The first and second of these conditions, adequate representation and lack of domination, merit further elaboration. All end users should have a vote on a stakeholder board. On a non-stakeholder board, all such end users should have direct access to the independent board of managers or directors. For example, PJM, which operates with an independent board, provides large industrial end users with the opportunity to participate in goverance through the opportunity to purchase membership voting rights. Smaller end users, such as residential customers, are unlikely to pay the thousands of dollars in membership fees, and consequently are less likely to acquire voting rights. However, PJM provides these smaller classes of end users the opportunity to present matters directly to the board through an alternative process. State consumer advocate agencies in the states in which PJM operates are provided ex officio, i.e. non-voting, membership status, and are authorized to take issues and proposals directly to the board.
On stakeholder boards, the composition of the various types of stakeholders’ voting rights is critical. Suppliers of electric services should hold no greater than fifty percent of the voting power on such boards. The other fifty percent should be held by end users, i.e. customers who purchase the services provided by the suppliers described above. End users are likely the only market participants that would exercise voting power in a manner which is consistent with an RTO’s key objectives, i.e. non-discriminatory transmission service and economically efficient decisions regarding the operation and expansion of transmission systems. These demand-side market participants are also more likely to vote in favor of economic efficiency in markets for generation and ancillary services.
The voting power of end users should be divided among the classes of users according to each class’s expenditures on transmission services. Different regions will have different preferences about how the representatives of end users are to be selected. More than one approach is acceptable, provided that the FERC is convinced that the proposed mechanism for selecting representatives will result in representation that will truly serve the interests of end users.

The committee structure of the RTO should allow all stakeholders to provide timely input regardingthe organization’s decisions, including structural changes and tariff amendment decisions. Both PJM and the Midwest ISO currently function on this basis. Within PJM and MISO, committee meetings are open to all stakeholder groups, whether or not individual representatives of particular stakeholder groups are voting members of the ISO. PJM and MISO actively solicit input not only from voting members, but also from non-member stakeholder groups such as state regulatory commissions, state consumer advocate offices and environmental groups with respect to all proposed structural, rule and tariff changes.
Additionally, all RTO board and committee meetings should be open to all stakeholder groups. Narrowly defined exceptions to the open meeting architecture could be crafted to allow the RTO board to address sensitive administrative discussions such as those pertaining to hiring, firing, and disciplining of the staff or those relating to market power abuse investigations involving confidential information. Open meetings are essential to avoid any appearance of discrimination, which, as discussed above, in and of itself could dampen competition within the RTO’s boundaries.
While the open and collaborative committee governance structure is critical to ensure that all stakeholder groups have their concerns addressed, final authority with respect to all such structural, rule and tariff changes and all other decisions must rest with the board of directors. No single stakeholder group or committee should possess any rights to veto the board’s final decisions. The only recourse should lay in appeal or petition to regulatory authorities.
3. RTO Ownership Issues
Two separate issues must be addressed relating to ownership interests: a) ownership of RTOS by market participants; and b) ownership interests which RTO owners, employees and directors may hold in market participants.
a) Ownership of RTOs
There is no justification for allowing parties with financial interests in market participants to hold ownership interests in RTOs. In the NOPR the Commission seeks comment on whether it should adopt a 1% financial interest threshold for market participant ownership in RTOs. The optimum threshold is zero. Market participant ownership of the RTO could have only one primary benefit: the ability to control the governance and operation of the RTO. While ownership of an RTO by a market participant would also provide the shareholder dividend, or profit benefit, the Commission’s traditional rate policies which require just and reasonable rates with an allowance for a fair return on investment will ensure that these profits were limited to a level which is just and reasonable and commensurate with other enterprises of comparable risk. Consequently, the primary benefit to ownership could only stem from ability to control governance of the RTO.
The alternative to prohibiting parties with financial interests in market participants from having ownership shares in RTOs would require meticulous monitoring on a continuous basis. This structure would be inconsistent with the Commission’s goal of light-handed regulation of RTOs. One such alternative would be to limit the ownership share of any single market participant to 1% or less, as proposed in the NOPR. However, to be effective, that alternative would also require that the Commission further limit the ownership share of each category or stakeholder group of market participants. Should the Commission pursue the 1% threshold proposed in the NOPR, any particular stakeholder group, for example electric utilities could potentially acquire a dominant share of the RTO’s stock. If the Commission allows market participants to own any financial interest in an RTO, the Commission should mandate that each category of stakeholders be limited to a collective ownership share of five percent or less.
NASUCA strongly recommends against allowing market participants to hold any ownership stake in RTOs. Allowing market participants to hold such ownership interests would require regulators or the RTO to continually track the ownership share of each market participant, including affiliates as well as all of the market participant’s owners, above a de minimus threshold. Doing so would be time-consuming, difficult and expensive. This paradigm is the antithesis of the independent, lightly regulated structure the Commission seeks to foster by initiating the RTO concept.
b) Financial Interests Held By RTO Owners, Directors and Employees
The Commission, in the NOPR, proposes to prohibit RTO employees and directors from holding ownership interests in market participants. NASUCA endorses this concept, however the Commission should exclude from this prohibition employee and director interests in market participants which stem from pension plans and other post-employment benefits received while a former employee of a market participant. The Commission approved this exception in the Midwest ISO proceeding by order dated November 24, 1998. Midwest Independent System Operator, Docket No. ER98-1438-000, 85 FERC ¶ 61,250 (1998). The Commission’s order on this date allows "directors, officers, and employees of the Midwest ISO to participate in the pension plans of Members, Users, or affiliates as long as they are defined benefit types of plans that do not involve the ownership of the company’s securities." Such an exception would ensure that RTOs are able to acquire employees, officers and directors who have expertise in the management of the electric grid. Absent such an exception, the potential pool of experienced employees could be substantially narrowed, depriving the RTO of talented staff.
Without a restriction on the types of financial interests employees and directors could hold in market participants, an RTO’s employees and directors might try to directly or indirectly influence the RTO’s decisions and actions. While all market participants will exert some influence on an RTO’s governance through participation in open committee meetings, an internal bias in employees and directors could result in attempts to the benefit the market participants in which they have financial interests. Such undue influence could discriminate against consumers or other types of market participants in a manner which is not readily transparent. In order to ensure avoidance of the perception of discrimination, the best course is to restrict the ability of RTO employees and directors to hold financial interests, other than pensions, in market participants.

Some members of NASUCA take the position that, under no circumstances, should the Commission provide RTO status to for-profit Transcos. Other members of NASUCA take the position that the Commission should not rule out RTO status for for-profit Transcos, as long as the RTO remains completely independent of generation market participants.
The issue that NASUCA is addressing in these Comments is not whether for-profit Transcos should be created. Nor does NASUCA take a position on whether such Transcos should be included as part of an independent RTO. The issue is whether a for-profit Transco can itself serve as an RTO. The question that must be addressed by the Commission here is whether the combination of ownership of monopoly transmission facilities with the profit maximizing financial incentives inherent in a for-profit Transco provides a structure capable of satisfying the Commission’s criteria for RTOs.
In any case, all RTOs, whether for profit or not, must meet strict standards of economic operation, minimization of prices to consumers, open and comparable access, competitive neutrality and public accountability.
a. Arguments Against Granting RTO Status To For-Profit Transcos
Some members of NASUCA take the position that RTOs should be governed by entities and persons that are independent of both generation and transmission owners as well as other broadly defined market participants. It follows, then, that RTO governance should be as independent of for-profit Transcos as it should be of any other entity with a direct financial interest in the market. The owners of for-profit Transcos have natural goals which conflict, in this view, with the RTO goals of fairness and economic efficiency. For-profit Transcos will have a fiduciary obligation to maximize profits for their owners, regardless of whether such profit maximizing activity results in least cost solutions to problems that have both transmission and generation components. Indeed, in some circumstances, transmission may actually compete with generation. Faced with the alternative of interconnecting new generation (which the for-profit Transco does not own) to remedy transmission constraint problems, or the prospect of either constructing new transmission assets on which the for-profit Transco would earn a return, or reaping additional transmission revenues through monopoly pricing of transmission services, the for-profit Transco’s financial self-interest will prefer the most profitable outcome even if such outcome is not justified from an economic efficiency or societal cost standpoint. If the for-profit Transco is the RTO, decisions based on self-interest factors rather than economic efficiency and public interest factors could cost ratepayers significantly more than would be the case if the RTO was not controlled by such self-interested parties.
A for-profit Transco would have the monopolist’s natural incentive to extract monopoly rents from consumers. Such a structure serving as an RTO would require extreme vigilance by regulatory agencies. Such a paradigm would be the antithesis of the Commission’s goal of establishing RTOs in order to promote competitive, economically efficient markets under a framework of light-handed regulation. RTOs should be designed to be free of disproportionate control by for-profit Transcos, just as they should be designed to be free of disproportionate control by any other market participants. The for-profit Transco RTO’s pursuit of profitability preferences could distract it from the proper RTO public service role of facilitating the reliable, low-cost provision of electric energy through competitively priced alternatives.

Some NASUCA members do not oppose allowing for-profit transmission companies (Transcos) to be eligible for RTO status. Proponents of for-profit Transcos have argued that combining ownership and control of transmission assets will provide greater benefits in the form of economic efficiencies as compared to an ISO, which controls transmission assets but does not own the transmission assets. While these arguments remain unproven, it may be worth allowing some regions to experiment with the for-profit Transco form of RTO to test the claims being made by its proponents.
If the Commission decides to allow for-profit Transcos to qualify as RTOs, it must be particularly vigilant to assure that the RTO remains completely independent of market participants. To date, each of the for-profit Transco proposals of which we are aware has provided for traditional integrated utilities, which would continue to be providers of electric generation services, to maintain a direct or indirect ownership interest in the for-profit Transco. The Commission must make it clear that entities in which generation owners or other market participants maintain an ownership interest, even a so-called "passive" interest, cannot meet the requirement of independence. In that regard, although the Commission has recently decided that it may be theoretically possible for a for-profit Transco in which a generation owner maintains a passive interest to meet the independence requirement of the Commission's ISO principles, we strongly urge the Commission to prohibit such passive ownership in the rules it issues in this proceeding.
In encouraging discussion regarding for-profit Transcos, the Commission has recognized in the NOPR that certain proposed requirements, such as market monitoring, may not be equally applicable to for-profit Transcos and ISOs. In that regard, we agree with the Commission’s suggestion that it may not be appropriate for a for-profit entity to perform the market monitoring function. Rather, a for-profit Transco’s role in market monitoring should be limited to information gathering and reporting. Similarly, it will be important for the Commission to require the RTO to maintain and implement objective, competitively neutral interconnection standards, so RTOs are not enabled to limit generation availability in order to further their own interests.
5. Other issues related to independence
At the top of page 128 of the NOPR, the Commission poses four questions about RTOs’ authority to file tariff and policy changes before the Commission. 64 Fed. Reg. at 31416 (Slip op. at 128). RTOs should have the authority to file with the Commission on any matter without the approval of market participants or transmission owners. If RTO filings are subject to the approval of any market participants, the independence of RTOs will be diminished. Most operational functions undertaken by an RTO will likely be undertaken subject to terms and conditions specified in tariffs. If the RTO has limited authority to control the terms and conditions under which it operates, it will lack the ability to independently operate the RTO. Consequently, if market participants rather than the RTO have final authority with respect to tariff filings or other petitions to this Commission, they will hold the reins of governance.
The RTO’s authority to file tariff changes and other petitions with the Commission should be limited only by the oversight of this Commission. It is possible that an RTO could file a proposal with an unjust and unreasonable element that is detrimental to consumers or specific market participants. The Commission will have the power to reject any unreasonable proposal. Any party aggrieved by an RTO filing, or an RTO’s failure to make a filing, may petition the Commission under Section 206 of the Federal Power Act for an appropriate remedy.

Below, NASUCA sets forth proposed guiding principles for the scope and regional configuration of RTOs. Size ought to be determined in the first instance by the stakeholders participating in the RTO formation process. However, the Commission should review the proposed RTO boundaries to ensure that the proposed RTO satisfies general criteria. The sizes and shapes of RTOs ought to be selected and assessed with an emphasis on the following objectives:

The collaboration of electric utilities in coordinating regional control of their transmission systems certainly creates the potential for horizontal market power. The size of the RTO will impact the ability of the utilities to exert such market power. Horizontal market power can generally be reduced by making RTOs larger rather than smaller. Absent a great degree of coordination between RTOs, larger RTOs allow electricity to be traded over a larger area. This also tends to increase the number of generation providers who are able to compete cost-effectively to provide power to each customer, even though it may not necessarily decrease the market concentration of any single generator or any single owner of generation assets. The overall result, however, of increasing the number of entities selling generation in a geographic area within which pancaked transmission tariffs have been eliminated should be to generally lessen horizontal market power concerns.

Many existing ISOs have boundaries which likely satisfy the RTO scope and configuration criteria recommended above. For example, the PJM ISO operates efficiently under current boundaries as it tracks historically developed market boundaries. The Midwest ISO and proposed Alliance RTO, on the other hand, do not currently satisfy the criteria set forth above, particularly the efficiency and contiguity criteria. The Midwest ISO is like a jigsaw puzzle with pieces missing. AEP’s participation in the Alliance RTO means that transactions between some Midwest ISO members, and other Midwest ISO members must cross Alliance RTO boundaries. The fact that such transactions must cross two ISOs’ boundaries results in pancaked rates and difficulty in scheduling and managing loop flow problems and planning unless regional coordination occurs between these two ISOs. In addition, these two proposed ISOs carve up a potential natural electric market region. Such difficulties would not exist if these two ISOs merged to form a single RTO. Discussions are on-going as to whether the Alliance organization should merge with the Midwest ISO. Several state commissions, consumer advocate agencies and others have encouraged this outcome. However, progress is slow and positive results seem unlikely absent regulatory agency involvement.

We support the provision discussed on pages 135-136 of the NOPR that the territory encompassed by each RTO should be contiguous. 64 Fed. Reg. at 31417 (Slip op. at 135-136). This minimizes loop flow problems and helps to eliminate rate pancaking. We also agree that "holes" would reduce the effectiveness of an RTO. With mandatory contiguity provisions and requirements that all utilities participate in an RTO, such "holes" should not exist. However, if "holes" remain a problem in any particular region, the Commission should require that RTOs at least negotiate agreements with either other RTOs or any non-participant transmission owners in its region to ensure maximum coordination.
In Section V of these comments, NASUCA urges the Commission to require participation in RTOs by all investor-owned transmission systems. NASUCA further urges the Commission to require participation by public transmission owners to the extent they are able to overcome any legal, tax, or other barriers to their participation. In the context of such mandates, there would be no need for punitive treatment of non-participating utilities in coordination agreements. Rather, the coordination agreements could simply be designed to integrate non-participating utilities with the RTO’s system to the full extent feasible so that transmission barriers are minimized, system efficiency is maximized, and loop flow problems are internalized to the greatest possible extent.

In the middle of page 140 of the NOPR, the Commission seeks comment on how readily it should require changes to the scope and regional configuration of RTO proposals if they do not match the Commission’s criteria adopted in this rulemaking proceeding. 64 Fed. Reg. at 31418 (Slip op. at 140). Given that the Commission’s proposed scope and configuration criteria are sensible and flexible, the Commission should require changes if the proposed scope and regional configuration of any specific RTO filing do not reasonably satisfy the guiding principles. Naturally, the Commission should make sure that its final rulemaking on RTOs sets forth comprehensive criteria so that potential RTO participants can, themselves, attempt to arrive at a proposed scope and regional configuration during the formation process that will be reasonable and acceptable. However, the Commission should not require any utility join a specific RTOs over any state regulatory commission’s objection.

The Commission’s proposed rule would require that "the Regional Transmission Organization must have operational responsibility for all transmission facilities under its control." 64 Fed. Reg. at 31438 (Slip Op. at 235). NASUCA believes that operational control is critical if RTOs are to facilitate competitive wholesale and retail generation markets.
We share the concern expressed on page 141 of the NOPR that leaving decisions about the operation of the transmission system in the hands of control area operators who are market participants (either directly or by affiliation) could allow those control area operators to favor their own or their affiliates’ power marketing efforts. 64 Fed. Reg. at 31419 (Slip Op. at 141). In the case of the Alliance RTO proceeding, there exists concern about transmission owners’ retention of control area functions, in particular control involving decisions relating to automatic generation control. For example, the Coalition of Midwest Transmission Customers, on pages 24-26 of its Motion to Intervene and Protest in the Alliance RTO proceeding before FERC, highlights the problems of leaving decisions in the hands of control area operators who are market participants. Alliance RTO, Docket Nos. ER99-3144-000 and ER99-80-000, Motion to Intervene and Protest of Coalition of Midwest Transmission Customers. The control area operator must have knowledge of transmission schedules. Such knowledge conveys a competitive advantage to any control area operator who is, or who is affiliated with, a market participant. It also allows the control area operator to avoid penalties for a mismatch between the ancillary service demands of its customers and the amount the control area operator provides.
To remedy these potential conflicts, the Commission should require RTOs to be the control area operators for their territories. Where complete centralized control by the RTO is not feasible at the outset, the Commission should consider master-satellite arrangements. Under these arrangements, the RTO would centrally control all control area operation functions which are technically and economically feasible, while the remainder of the control area operation functions would be directed by the RTO from two or more "satellite" facilities, each of which would have responsibility for a portion of the RTO’s territory. However, the RTO would have the authority to direct the satellite office functions.
While NASUCA urges the Commission to place complete control area authority within the hands of the RTO, in the event the Commission allows the control area operator functions to be carried out by one or more market participants, the Commission must ensure separation between control area staff and the staff of the market participant who schedule affiliated generation. This separation must be accompanied by rules to prevent the transfer of valuable, non-public information from control area operation staff to other, affiliated staff.

The Commission should require that each RTO which shares or delegates operational responsibilities with other entities must issue "a public report that assesses whether any division of operational responsibilities hinders the Regional Transmission Organization in providing reliable, non-discriminatory and efficiently priced transmission service." 64 Fed. Reg. at 31438 (Slip Op. at 236). Such a reporting requirement provides all stakeholders as well as the RTO and the Commission an opportunity to make an informed assessment of whether a change in the division of operational responsibilities is warranted.

The last item in the proposed rule under "operational authority" includes a proposed requirement that the RTO be the security coordinator for the facilities that it controls. NASUCA agrees that the security coordinator functions described on pages 144-145 of the NOPR are important, and we support the requirement that they be carried out by the RTO. 64 Fed. Reg. at 31419 (Slip Op. at 144-145) The Commission requires in the NOPR that the security coordinator will collect confidential information, and so should be independent of market participants. Requiring that the RTO be the security coordinator is likely more efficient than having a second independent entity assume those duties, because the security coordinator functions are closely related with the functions the RTO will undertake, such as providing for ancillary services and negotiating potential agreements with neighboring RTOs.

Maintaining adequate system reliability must be given top priority along with the independence characteristic. Reliable operation of the grid must be maintained as the development and expansion of markets leads to an increase in the level of transactions.

In subsection (c) of the NOPR’s discussion of characteristic 4, the Commission seeks input on RTO authority to approve and disapprove all requests for scheduled outages of transmission facilities. 64 Fed. Reg. at 31420. The Commission should require that RTOs exercise full control over transmission maintenance outages. The Commission should extend this authority so that RTOs are also required to exercise control over scheduled generation outages. Authority over both transmission and generation outages is important for reducing the likelihood of a transmission system outage, for reducing congestion and minimizing associated costs, and for limiting the exercise of market power through capacity withholding. Authority over generation outages is also important for ensuring adequate levels and geographic diversity of ancillary services.
Similarly, the RTO must have sole authority over the ability of the system operator to redispatch generating units in the most economically efficient way when congestion occurs or when other reliability-related problems occur. If the RTO could not re-dispatch plants, its ability to maintain short-term system reliability would be severely diminished. In fact, the Commission conditioned approval of the Midwest ISO application on the Midwest ISO making a compliance filing which provided that ISO such re-dispatch authority.
On page 150 of the NOPR, the Commission asks whether transmission owners should be compensated for costs resulting from the rescheduling of transmission outages. 64 Fed. Reg. at 31420 (Slip op. at 150). The same question could be asked about the rescheduling of generation outages. Two principles should prevail in this matter. First, transmission and generation owners should only be compensated if the prior scheduled outage had already been approved by the RTO. This will discourage transmission and generation owners from proposing scheduled outages at times when they will have a larger-than-necessary upward effect on electricity prices. Outages at such times are less likely to be approved by the RTO. Second, if the first principle is met, the RTO should compensate transmission or generation owners only to the extent that incremental costs are incurred due to the rescheduling of outages. It is unlikely that owners would incur significant incremental costs, especially for transmission outages.

The fourth section of the proposed rules concerning short-term reliability would require that "if the Regional Transmission Organization operates under reliability standards established by another entity (e.g. a regional reliability council), the Regional Transmission Organization must report to the Commission if these standards hinder it from providing reliable, non-discriminatory and efficiently priced transmission service." 64 Fed. Reg. at 31438 (Slip Op. at 237). NASUCA supports adoption of this requirement. The RTO must have the ability to bring potential conflicts to the Commission’s attention in order to mitigate or remedy any discrimination concerns.

NASUCA supports the Commission’s proposals that the RTO be the only provider of transmission service over the facilities under its control and that the RTO be the sole administrator of its own open-access tariff. As noted above, full operational control over the provision of transmission services by the RTO is essential in order for the RTO to ensure non-discriminatory access to the transmission network. Such control necessarily entails the ability to administer the tariff and rate design. Sharing these responsibilities with any market participant or any other entity would be inefficient and would not ensure the necessary independence in administration of the tariff. Other entities, particularly market participants, would have an incentive to let self-interest dictate the influence they would exert on the transmission system and tariff.

The Commission proposes that the tariff rate design must be one which employs "a transmission pricing system that will promote efficient use and expansion of transmission and generation facilities." 64 Fed. Reg. at 31421 (Slip Op. at 155). It is very important that the Commission clearly distinguish between system operation and system expansion and planning when addressing the transmission pricing issues raised in this NOPR. Tariff rate design and congestion pricing issues discussed below entail both operational and expansion issues. However, these pricing approaches may have different impacts on each of these two issues. These differing impacts need to be carefully separated. For example, congestion cost pricing may help provide appropriate price signals to indicate where new transmission lines are needed, but it may not be necessary for the efficient daily operation of the transmission grid.

RTO structure and tariffs must provide the RTO authority to review and approve all requests for new interconnections. The RTO should also have the authority to internally originate proposals for new interconnections, and to require that transmission owners or other entities make new interconnections, subject to any constraints imposed by the states. The current language in the NOPR is unclear as to the extent of RTO authority over new generation interconnection requests. The Commission should ensure that the final rule unambiguously grants RTOs authority to:

On pages 159-160 of the NOPR, the Commission poses a two-part question. 64 Fed. Reg. at 31422 (Slip Op. at 159-160). The first part implicitly asks whether the scope of the RTO’s authority should be limited to the connection of new generators to the transmission system, or whether it should encompass interconnections for other reasons, such as improving system reliability or expanding trading opportunities with neighboring regions. The RTO’s authority over interconnections should apply to all interconnections to the transmission system regardless of their purpose, with the possible exception of most distributed generation projects.
Distributed generation projects will, more often than not, be connected to electric distribution systems, because these projects are likely to be relatively small in size. Consequently, it is unlikely that RTOs would, or should, have authority to approve or reject the interconnection of such projects. However, distributed generation projects could produce net energy inflows into the distribution systems. These distribution systems are physically interconnected to the transmission systems. Since electricity flows along the path of least resistance, the net energy produced by distributed generation projects could impact the transmission system. RTOs should at least be provided notice of such projects and account for such energy in any overall regional transmission plan developed by the RTO.

The second part of the question that extends from page 159 to page 160 of the NOPR seeks comment on whether RTOs should have authority to review proposed transmission investments and to order that transmission investments deemed necessary by the RTO be undertaken. 64 Fed. Reg. at 31422 (Slip Op. at 159-160). NASUCA believes that they should. Furthermore, RTOs should have authority over all changes to the transmission system at appropriate voltage levels, including additions, retirements, and other alterations. The RTO should be required to develop a dollar amount threshold and a qualitative standard for defining what additions require RTO approval. However, for retirements and alterations, the standards of what requires RTO approval should be qualitative, since significant changes of these types may not be expensive. Since such retirements or alterations could affect congestion issues, the Commission should require the RTO to develop standards governing approval or rejection of such changes.
As with generation interconnections, RTOs should have authority not just to review proposed changes to the transmission system, but also to internally generate proposals for any necessary changes and to see that the proposals it approves are implemented. By exercising authority to propose, approve, and secure implementation of interconnections and other changes to the transmission system, an RTO would essentially be coordinating generation and transmission expansion plans on a regional basis.

The discussion of RTO authority over new generation interconnection requests and proposed or necessary changes in transmission system investment provides a good illustration of the dangers of allowing for-profit Transcos to serve as RTOs unless stringent standards for regulating such entities are established as set forth above. Regional planning for transmission and generation investments requires complete independence from market participants if stakeholders are to feel confident that discriminatory decisions are not being made. Consequently, the RTO administration of new generation interconnection and transmission tariffs, as well as coordination of regional system expansion plans, must be independent of financial self-interests inherent in market participants.

NASUCA supports the elimination of multiple access charges for transmission, both transmission within a single RTO and, to the extent feasible and efficient, transmission that crosses an RTO boundary. Replacing multiple transmission access charges with a single charge reduces transaction charges and tends to increase the number of generation providers that can compete cost-effectively to provide power to each customer.
The elimination of rate pancaking could occur by either adopting a single, system-wide transmission rate for all transactions within the RTO, or by adopting a zonal rate concept during a transition period. PJM ISO uses a zonal approach, in which the zones are identical to the service territories of the existing electric utilities and the zone of delivery defines the single rate to be charged for the transaction. PJM plans to convert to a single system rate by the end of a five year transition period. The Midwest ISO proposes to use a similar zonal approach. While NASUCA does not take a position on whether a single system rate is necessary as a beginning or end state, certainly the use of a single charge for each transaction across an RTO regardless of how many transmission systems are crossed will help achieve the Commission’s goal of fostering competitive wholesale and retail energy markets.

Congestion management provides an RTO the opportunity to send market participants important price signals relating to the need for new generation or transmission lines, the best location to site such generation or transmission, and the range for anticipated market prices for such generation and to allocate non-firm transmission capacity to the transaction that places the greatest value on the use of this capacity. While an RTO could manage congestion merely by employing NERC’s Transmission Loading Relief ("TLR") procedures, pricing congestion may be a more useful tool to stimulate greater competition within energy markets. Any mechanism for using congestion prices for managing transmission system flows should be:

PJM manages congestion through Locational Marginal Pricing, an economic pricing mechanism. At certain times, PJM must shed load in order to manage constraints. In such an event, the PJM tariff now provides market participants an opportunity to buy through the constraint and stay on the system.
The Midwest ISO has not yet proposed a method for managing congestion solely through curtailment procedures. However, as noted above, in its order conditionally approving the Midwest ISO, the Commission required that, at a minimum, the ISO must be able to manage congestion through redispatch of generation. Midwest ISO, Docket No. ER98-1438-000, 84 FERC ¶ 61,231 (1998). The Alliance RTO proposal pending before the Commission contains a congestion management proposal similar to that initially proposed by the Midwest ISO, i.e. employing TLR procedures as the primary tool to manage congestion.
Great value exists in using pricing as an additional tool to manage congestion. This tool provides signals as to the economically efficient opportunities for system expansion and provides benefits by allocating non-firm capacity to the most highly valued use. While system expansion responses may not be immediate since construction of generation or new transmission lines takes time, the market would nonetheless benefit from the information provided via a congestion pricing mechanism. Buses which are consistently constrained will appear on congestion pricing charts at prices consistently higher than system average market prices. Such information signals market participants and others on the best locations to build new generation or identifies where transmission upgrades should be located. The Commission should require RTOs to develop congestion pricing systems in addition to other congestion management mechanisms which operate on redispatch or curtailment procedures. However, whether congestion costs should actually be charged to load serving entities is another issue, and one which should be decided in the context of specific proposals or in the context of any additional inquiry initiated with respect to power exchanges and power markets as discussed in Section II of these Comments.

The Commission proposes in the NOPR that RTOs should develop measures to adjust for and, where possible, to internalize the effects of parallel path / loop flows. NASUCA agrees that RTOs provide a valuable tool for managing such flows. First, by providing the RTO with coordination and control over the transmission systems of numerous companies throughout a wide region, the RTOs will be able to effectively account for and internalize the incidental energy which flows between interconnected systems. RTOs also serve as a convenient regional mechanism to address parallel path/loop flow between RTOs through inter-agency coordination. As discussed earlier in Section IV, Subsection B (3) of these comments, the necessity for managing parallel path / loop flows provides a sound justification to mandate inter-RTO coordination. As the NOPR suggests, such coordination has the potential to improve economic efficiency, reduce costs, and improve reliability.

Market participants should have the option of self-supplying ancillary services, or the option of acquiring such services from third parties, subject to Commission and RTO rules. Ancillary services can be obtained from various types of generating units. Just as the intent behind Order No. 888 and various state retail choice programs is to recognize that the market for generation services has become increasingly competitive with the advent of new technology, so should the Commission now recognize the possibilities for competition among ancillary services. Choice among alternative providers of such services will allow market participants to minimize ancillary service costs, to the benefit of consumers. However, such services should not be priced at market rates until the Commission determines through an evidentiary process that sufficient competition exists in the provision of such services.
The Commission should mandate that RTOs have responsibility to ensure the adequate provision of ancillary services. Such services are vital for maintaining system reliability. Where competitive markets for ancillary services do not currently exist, RTOs must have the authority to order generation owners within the respective RTO boundaries to provide such services, as appropriate. In other words, an RTO should be able to ensure adequacy of ancillary services by reliance, at least initially, on the traditional providers of such services until sufficient competition exists within the market.
The discussion of ancillary services necessarily raises the issue of managing energy imbalances. The Commission should require RTOs to develop mechanisms to ensure that all transmission customers have equal access to a real-time energy balancing mechanism. The forms this mechanism and the mechanisms for creating competitive ancillary service markets should take will depend on the nature of the energy and capacity markets in the RTO’s territory. Such issues may entail the development of power exchanges or other types of power markets managed either by the RTO or by other entities. The independent nature of RTOs provide a unique advantage over other entities in managing such markets considering the need for transparency in market prices, and the need for trust in the non-discriminatory administration of such markets. As noted in Section II above, these issues should not hold up expeditious issuance of a final RTO rule, but should instead be the subject of a future Notice of Inquiry ("NOI"). Nonetheless, the Commission should go forward with this NOPR and insist that RTOs begin to investigate other tools for managing ancillary services and energy imbalances.

NASUCA supports the Commission’s proposal that each RTO be the single OASIS site administrator for the transmission systems subject to its regional control and that each RTO independently calculate Total Transfer Capacity ("TTC") and Available Transfer Capacity ("ATC"). These functions clearly impact commercial transactions within competitive energy markets and should be performed by an entity independent of market participants. In addition, administration of the capacity benefit margin ("CBM") mechanism should be a required function of RTOs if CBM requirements are enforced within the RTO. This is necessary because methods of calculating CBM reduce otherwise available capacity at interties with other RTOs and systems, thereby affecting ATC calculations.
The data and the methodologies for calculating the capacity benefit margin, ATC, and TTC should be transparent and internally consistent. This will allow concerned parties to check the calculations and even to estimate calculations of these quantities for the future, even though the results will be extremely time-dependent. A uniform methodology for calculating CBM, to be used by all RTOs, would foster the Commission’s goals of promoting competitive energy markets since all market participants would understand the rules.
Transparency should enhance trust that the market is truly competitive and operates on a level playing field for all market participants. In its July 28, 1999 "Order Clarifying Methodology for Computing Available Transmission Capability," Docket No. EL99-46-000, 88 FERC ¶ 61,099 (1999), the Commission recognized the importance of requiring greater transparency with respect to procedures for how CBM is determined. The Commission further directed NERC to develop a standardized methodology for such calculations. These developments are consistent with our recommendations regarding the calculation of CBM, ATC, and TTC and the Commission should incorporate the requirements in the CBM Order into the final rule in this proceeding.

In Order 888, the Commission unbundled electric transmission and generation functions and authorized the creation of ISOs to operate the interconnected transmission facilities of electric distribution companies in order to foster a robust, competitive market for electricity and provide all customers access to competitively priced generation. Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities and Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 75 FERC ¶ 61,080 (1996); order denying reh’g, Order No. 888-A, 78 FERC ¶ 61,220 (1997); order denying reh’g, Order No. 888-B, 81 FERC ¶ 61,248 (1997). The goals of Order 888, however, may be frustrated if market power abuses occur. Appropriately structured RTOs will provide assurance that market power abuses do not occur by applying the RTO’s Open Access Transmission Tariff in controlling the operation of the transmission facilities, as discussed above, on a non-discriminatory basis. However, RTOs must also provide a strong market monitoring function so as to detect and deter any market power abuses.
Market power is generally defined as the ability of a market participant or group of participants to raise prices above competitive levels, or to restrict output below levels of demand in order to raise prices for a sustained period of time. Strategic bidding and capacity withholding can be used to exercise market power. The following characteristics of the electricity markets allow for the potential for market participants to exercise market power:

RTOs are the appropriate entities to monitor market power because they are independent from any market participant and can objectively perform the market monitoring function. In addition, RTOs will collect much of the data necessary to perform this function in the course of fulfilling their other functions.
In performing a market monitoring function, RTOs should (1) monitor and report on issues pertaining to the operation of the bulk power market, capacity markets, transmission rights markets, ancillary services markets, and any other potentially competitive markets; (2) evaluate the operation of such markets to detect either design flaws in the rules or procedures of the RTO; and (3) enforce the RTO’s rules.

To monitor the operation of the various markets, RTOs should use a combination of standard, traditional market power measurement techniques, and new innovative analyses of market participant behavior and price trends. Market power is traditionally measured in terms of market concentration using the Herfindahl-Hirschman Index ("HHI"). The HHI assumes that the greater a given company’s market share, the greater its ability to manipulate prices. However, traditional market power concentration analysis alone is an insufficient measure to determine whether market power abuses are occurring within a particular electric market. Moreover, the price effects of market power can be high even if the HHI is low.
The electricity marketplace is dynamic, and factors other than market concentration may allow a market participant to exert market power. For example, constraints on the transmission system can create sub-markets, quickly altering the local supply-demand balance. In addition, market conditions can vary appreciably from one hour to the next because electricity is a real-time commodity (produced and consumed simultaneously). Therefore, to monitor the operation of the various markets, it is incumbent upon RTOs to develop baselines in order to conduct a comprehensive analysis of market participant behavior, price data, and cost data.
In order to instill confidence in the market participants that the RTO is able to effectively perform the market monitoring function, RTOs should make the indicies and screens they use to analyze the operation of the various markets publicly available. Recognizing the commercially sensitive nature of much of the data that RTOs will need to collect to perform the monitoring function, two types of indicies may be necessary. One set of indicies would include commercially sensitive, participant-specific data and would only be used internally by the RTO. The other set of indicies would describe broad market measures based on average and typical data rather than participant-specific data. Additionally, the RTO should periodically review the indicies and screens and revise them as necessary to keep pace with changes in the various markets. Market participants, state and federal regulatory agencies, and state consumer advocates should be allowed to participate in the development and periodic review of the indicies and screens the RTO will use to monitor the operation of the markets.
To further create trust in RTOs’ ability to effectively and objectively monitor the market, RTOs should periodically issue reports describing the state of the markets that it is monitoring, items under investigation by the RTO, and any results from completed investigations. The RTO should provide a copy of this report on a confidential basis to federal and state regulatory authorities as well as state consumer advocate offices. This information is necessary for the regulatory agencies and the state consumer advocates to independently assess whether additional investigation is merited. Ultimately, if the RTO determines that a market participant has abused its market power, the RTO should bring the abuse to the attention of an appropriate governmental agency, such as the Commission, Department of Justice, state attorney generals’ offices, and/or state public utility commissions.

In addition to monitoring the operation of the competitive markets for the exercise of market power, RTOs should evaluate whether its own rules or procedures need to be modified to prevent market participants from abusing market power. RTO rules, for example, may contain loopholes that allow market participants to withhold generation capacity, causing the market price for generation capacity to increase. If the RTO identifies such loopholes in conducting its monitoring function, it should instigate a collaborative process to determine what modifications or additional rules are necessary.

RTOs should establish mechanisms to enforce compliance with their rules and procedures. These enforcement mechanisms should be established in a collaborative process involving all market participants, regulatory agencies, and consumer advocates. RTOs would then use these enforcement mechanisms when they identify violations of the RTO rules and procedures in carrying out their market monitoring function.
Sanctions and other penalties would be appropriate enforcement mechanisms. The sanctions and penalties should be large enough to be an effective deterrent; however, a for-profit RTO must not be given any profit incentive to impose unjustified penalties. Instead, all revenue derived from sanctions and penalties should be allocated in a way that benefits customers. After all, the purpose of the market monitoring function is to ensure that discrimination does not occur and that competitive prices are maintained. Thus, the RTO is performing a monitoring function on consumers’ behalf.
Another possible enforcement mechanism would be a rule that would allow the RTO to enter a mandatory default bid in order to prevent capacity withholding. Currently, NEPOOL and PJM have such rules.
RTOs should not be given authority to require a market participant to divest generation assets. While divestiture of generation assets may be an effective means to reduce the potential exercise of vertical and horizontal market power, divestiture authority should lie only with judicial and regulatory bodies. However, while RTOs should not have divestiture authority, they should include recommendations regarding divestiture in any market monitoring reports where appropriate as judicial and regulatory bodies may find the recommendations useful.

In order to accomplish the Commission’s goal of forming RTOs to foster greater competition in wholesale and retail energy markets, the Commission must ensure that the guiding principles established for the RTOs’ market monitoring functions are strong, clear and transparent. Thus, the Commission should require RTOs to go beyond the bare bones proposals in the RTO NOPR in order to have the RTOs take a more proactive approach to monitoring for abuse of market power, flaws in the RTOs’ rules and procedures, and violations of RTO rules and procedures. While state and federal government agencies invested with enforcing anti-trust laws will work diligently to remedy market power abuses in the electric utility industry, the tools historically used by these agencies to perform their functions may not translate well to an industry in which has historically been regulated as a monopoly. The metric commonly used by these agencies to indicate the acceptability of utility proposals, the Hirschman-Herfendahl Index (HHI), may be an inadequate predictor of the potential price impacts of market power in the electric utility industry. Consequently, RTOs must have strong market monitoring functions and the Commission should, in the final rule, provide guidance as to the types of standards and processes which will satisfy such principles.

On pages 199-203 of the NOPR, the Commission addresses the possibility of incentive pricing for transmission owners as a means of encouraging them to turn over operational control of their assets to RTOs. 64 Fed. Reg. at 31431 (Slip Op. at 199-203). The Commission should reject the use of incentive pricing for this purpose. First, the Commission should require all transmission owners, especially investor-owned utilities, to turn over operational control of their transmission systems to RTOs. Such mandates could be accomplished through use of the Commission’s statutory authority under Sections 202(a), 203, 205, 206 and 210 of the Federal Power Act. Sections 203, 205 and 206 in particular offer the Commission the option to condition the grant of certain privileges, such as market based rate authority and merger approval with requirements to join RTOs. For those utilities whom the Commission has already granted merger approval conditioned on compliance with a mandate to join an ISO, the grant of incentive rates to join an RTO merely provide windfall profits at consumer expense without achieving any benefit not otherwise already available.
Additionally, many economic and financial reasons exist which should be sufficient to incent utilities to join RTOs. These utilities will have greater access to competitive markets through RTO operations than they do under the current regulatory structure. With the advent of retail choice, utilities will be anxious to sell their stranded generation capacity in someone else’s formerly sacrosanct service territory. As noted above, the formation of RTOs facilitates that end result. Financial rewards to incent behavior which is in a utility’s self-interest at the outset is unjust, unreasonable and unacceptable.
Aside from being unnecessary, incentives for turning over operational control of transmission assets to RTOs would be unjust and unreasonable because they would not be cost-based, would provide more than a just and reasonable return, and would send inaccurate price signals. Also, transmission owners who transfer control of their assets to an RTO do not incur any additional risk or expense that merits additional compensation. The cost of the compensation would be borne primarily by consumers.
Some of the specific incentives mentioned on pages 201-202 of the NOPR present other problems in addition to those mentioned above. 64 Fed. Reg. at 31431 (Slip op. at 201-202). One of the specific incentives is the upward revaluation of transmission assets based on replacement cost or acquisition cost. This incentive is proposed to apply in the case of the creation of a Transco which purchases these assets from existing transmission owners, or in the case of an existing transmission owner seeking an increase in rates due to use of a different method of depreciation. Revaluation in either situation, however, would create a series of major problems. First, the implicit incentive would have to be enormous in the case of many transmission assets, i.e. much larger than any amount that might be necessary to convince the owners to turn over control to RTOs. Replacement cost is far larger than original cost, less depreciation, in many cases because the investment costs of most existing systems have already been substantially depreciated, and thus recovered from ratepayers, and because rights of way have become more difficult and expensive to obtain over time.
Second, if the Commission allowed transmission rates that recovered the acquisition premiums of transmission assets, there could be a nationwide sell-off of transmission assets at inflated prices. The prices could be inflated because purchasers would perceive some probability of recovering acquisition premium through rates. The resulting massive change in the ownership of transmission assets could precipitate chaos in the collaborative process of establishing Transcos or RTOs, and also in the operation of those assets just when the already challenging transition to RTOs is occurring. The additional complication arises if RTOs seek to purchase such assets and evolve into for-profit Transcos.
If the Commission allowed even a single transmission owner to upwardly revalue its transmission rate base, other transmission owners would refuse to turn over control of their transmission assets until the Commission granted them similar treatment. To avoid the problems associated with upwardly revaluing the transmission assets in the rate bases of their owners, the Commission should adhere to a strict policy of allowing no transmission assets to be valued higher than original cost less depreciation.
Similarly, the Commission must not allow accelerated depreciation of transmission assets. In addition to being unnecessary, unjust, and unreasonable, as discussed above, accelerated depreciation shares two of the particular faults of the upward revaluation of transmission rate base. First, accelerated depreciation would be, in some cases, a far larger incentive than may be necessary to promote participation, even in the absence of a participation mandate. Second, as noted above, if the Commission allowed accelerated depreciation for even one transmission owner, others would refuse to turn over operational control of their transmission assets to RTOs until granted similar treatment.
Finally, such financial incentives could hinder rather than foster competitive energy markets. Any premiums authorized, particularly premiums recovered through depreciation, return adjustments or acquisition adjustments, would only serve to increase transmission rates. Suppliers of generation would clearly prefer to locate in or sell into RTOs without such premiums in transmission rates.
If the Commission determines that it needs to encourage transmission owners to transfer operational contral of their transmission assets to an RTO, the Commission should explore other means, rather than financial incentives, to accomplish this goal of participation. For example, the Commission should determine whether market-based rate authority should appropriately be denied in the absence of participation in a fully functioning RTO. In addition, the Commission should determine whether merger approval should be withheld without participation of the merged entity in a fully functioning RTO. Through these and other methods, the Commission could encourage and achieve participation (or discourage non-participation) without unjustly raising transmission rates through unnecessary financial incentives.
NASUCA urges the Commission to reject the policy of providing incentives for RTO participation, require such participation by investor owned utilities and encourage such participation by other entities such a public power agencies discussed below.

C. Issue G: Public Power Participation in RTOs
The benefits of implementing RTOs may be diminished to the extent that some transmission assets are not fully integrated into the systems operated by RTOs. NASUCA strongly supports the Commission’s objective "to encourage all of the Nation’s transmission grid to be under the control of RTOs that have the minimum characteristics and functions adopted in the Final Rule." 64 Fed. Reg. at 31432 (Slip Op. at 208). Therefore, NASUCA recommends that any Commission requirement compelling participation by investor owned utilities in RTOS should include relevant public entities to the extent permitted by law. Where such public entities are not participating in an RTO, FERC should encourage them to join an RTO or should require them to work with the RTOs in their region to coordinate operational, tariff pricing, and planning functions. Coordinated operation of such public facilities is essential if the RTO is to have functional control over all transmission facilities within its borders.

VI. Conclusion

NASUCA thanks the Commission for this opportunity to comment on the important issues regarding the development of Regional Transmission Organizations. NASUCA looks forward to continuing to work with the Commission and other interested parties in the development of RTOs and other critical initiatives in order to assure that the benefits of competitive generation markets are shared by all consumers.
Respectfully submitted,
National Association for State Utility
Consumer Advocates
Suite 550
1133 15^th Street, N.W.
Washington, D.C. 20005
(202) 727-3908
54137

National Association of State Utility Consumer Advocates
8380 Colesville Road, Suite 101, Silver Spring, MD  20910
Phone: (301) 589-6313 Fax: 589-6380
e-mail: nasuca@nasuca.org