The Changing Structure of the Electric Power Industry 2000: An Update

While congressional assent is necessary for many of the reforms to the electric power industry, Congress has granted the Federal Energy Regulatory Commission (FERC) authority to make regulations in a number of areas. The purpose of this chapter is twofold. First, it highlights FERC initiatives to promote competitive wholesale power markets over approximately the past 20 years, which have become progressively broader in scope in recent years. Second, it highlights FERC's initiatives in promoting an efficient and reliable power transmission system.⁽¹⁾ The two areas--promoting competitive wholesale power markets and an efficient power transmission system--are interrelated goals. Having fully competitive power markets depends on creating an efficient, well operating transmission system.

As mentioned in Chapter 3, the power transmission system is one of three major components of the electric power industry; the others are power generation and distribution. The transmission system provides the capability to move electrical power over long distances, producing significant benefits to electric utilities and to electricity customers. One benefit is that large efficient power plants can be built far from where the power is used, and the transmission system or systems can deliver power from those plants to many customers over a broad area at a relatively low cost. This capability was one of the reasons that utilities built large centralized power plants, which now provide most of the Nation's power generation capacity.

Another benefit of today's transmission system is that it provides wholesale electricity customers an opportunity to purchase less expensive power from alternative suppliers such as power marketers or independent power producers. This opportunity, which did not exist until the passage of the Energy Policy Act of 1992 (EPACT), and later expanded in 1996 by FERC's Order 888, is the foundation for creating competitive wholesale power markets.

As the electric power industry becomes more competitive, many of the changes taking place involve the regulation, operation, and control of the transmission system. FERC, the agency responsible for regulating interstate energy commerce and the transmission grid, is at the forefront of these changes. Its objective is to make the power generation sector more competitive by fostering wholesale power markets, and to make the Nation's transmission system more efficient.

FERC has long believed that competition in electric power generation could result in lower electricity prices and improved services for wholesale and retail electricity customers. Beginning approximately in the mid-1980s, FERC has issued numerous Orders, Policy Statements, or case rulings designed to promote competition in wholesale power markets and to improve operation of the transmission system. (Table 9 presents a chronological summary of these documents.) FERC's objectives center on five broad functions:

Introducing Market-Based Rates for Wholesale Power Sales
In a regulated environment, wholesale and retail electricity power prices are calculated based on a utility's embedded costs plus a negotiated rate of return on their investments. Because this method ensures that the utility will cover its costs of operation, this method does not have appropriate incentives to motivate a utility to fully evaluate all the risks of an investment. If a utility invests in what turns out to be an uneconomical project, it can still add the costs of the investment to the price it charges for electricity. Thus, the risks and economic consequences of a poor investment are passed to the electricity customer. Another limitation is that the cost-based pricing concept is the antithesis of the objective of promoting competitive wholesale power markets.

To overcome the limitations of cost-based pricing, in the mid-1980s FERC considered 31 applications to use market-based pricing for wholesale transactions, although only a few applications were approved. However, by the mid-1990s, FERC had approved the use of market-based rates for more than 100 power suppliers, and substantial growth in their use had begun.

Currently, 866 companies are eligible to sell wholesale power at market-based rates, including 389 independent power producers, 271 affiliated power marketers and producers, and 206 investor-owned utilities (IOUs) and other utilities (Table 10). Affiliated companies must comply with standards of conduct designed to eliminate abuses and reciprocal dealing between the public utility and its affiliated power marketer.⁽²⁾

The use of market-based prices started with bilateral transactions, where buyers and sellers negotiated a price. Since then, a few centralized power markets have been created where a power supplier sells through a power exchange, and wholesale electricity prices are based on the market conditions at the exchange. Centralized power markets have begun in New England; New York; Pennsylvania, New Jersey, Maryland (PJM) region; and California. More are likely to open during the coming years. Without blanket approval to sell power at market-based rates, these competitive centralized markets could not exist.

Providing Nondiscriminatory Access to the Transmission System
Historically, many vertically integrated utilities did not allow independent power suppliers to use their transmission systems. If they were ordered to provide access, the integrated utilities would favor power from their own plants over the independent supplier when the transmission lines became congested. In some instances, the utility would withhold certain types of important transmission services. These practices stymied the growth of competitive power generation markets because they limited the extent to which independent power suppliers could provide service to electricity customers.

EPACT's passage gave FERC broad authority to order transmission-owning utilities to wheel power for wholesale power transactions, and it helped to relieve some of the barriers to using the transmission system. Wheeling occurs when a transmission-owning utility allows another utility or independent power producer to move (or wheel) power over its transmission lines. Although FERC's wheeling authority facilitated creation of competitive wholesale electricity markets, wheeling requests were evaluated on a case-by-case basis, which was sometimes slow and cumbersome. Also, disparities still persisted in the comprehensiveness and quality of transmission services provided by transmission owners to other users. To address disparities in service, in 1994 FERC established a "comparability standard" stating that transmission-owning utilities should offer other transmission users access to their transmission systems on the same basis and under the same conditions as they use the transmission systems to service their own electricity customers. FERC also applied the comparability standard case-by-case; when a utility requested approval for market-based rates or approval to merge with another utility, FERC would specify that the utility must incorporate the comparability standard into its transmission tariff as a condition for approval.

Even with more wheeling authority and implementation of the comparability standard on a case-by-case basis, open non-discriminatory transmission access still did not exist universally. In April 1996 FERC took action to correct the lack of universal access by issuing Order 888. At that time, Order 888 was considered the most far-reaching and ambitious project undertaken by FERC to eliminate deterrents to competition in the electric power industry. Order 888 had two basic goals: (1) to eliminate anti-competitive practices and undue discrimination in transmission services through a universally applied open access transmission tariff, and (2) to ensure the recovery of stranded costs a utility might accrue in the transition to competitive markets.

With respect to the first goal, FERC imposed a blanket requirement that all transmission-owning utilities under its jurisdiction must file an open access transmission tariff specifying the terms and conditions for using their transmission systems. The comparability standard was one of the required conditions of the transmission tariff. One significant advantage of a universal transmission tariff was that it eliminated FERC's time-consuming case-by-case evaluation of wheeling requests. Instead, rights, terms, and conditions to wheel power were predefined in the tariff and a company could respond immediately to opportunities in short-term markets that previously were not available to them in a timely manner. Access to the transmission system in a timely manner is essential for a competitive short-term power market to function properly.

Another equally important component of Order 888 was the requirement for transmission owners to functionally unbundle their activities. Functional unbundling required the transmission owner to take transmission service under the same tariff as other transmission users (comparability standard); to separate rates for wholesale generation, transmission, and ancillary services; and to rely on the same electronic information network that its transmission customers rely on to obtain information about prices and available capacity of the transmission system. Essentially, the idea of functional unbundling was to avoid favoritism and discriminatory practices within a vertically integrated utility by separating its transmission services functions from other business activities in the company.

Order 888 covered other transmission tariff issues such as pricing of transmission services, the application of market-based rates for power sold from new capacity, and other items. (Table 11 provides a summary of the major provisions of Order 888 with respect to open transmission access.) Since issuance of Order 888, all utilities have filed their open access tariffs, and Order 888 is now history. In retrospect, Order 888 represented FERC's first broad sweeping effort to eliminate discriminatory and unfair practices in the management and control of the transmission system.

Table 11. Major Provisions of FERC Order 888 on Open Access
Functional Unbundling A utility's uses of its own transmission system for the purpose of engaging in wholesale sales and purchases must be separated from other activities. Corporate unbundling is not required. Utilities must take transmission services (including ancillary services) under the same tariff of general applicability as do others. Utilities must state separate rates for wholesale generation, transmission, and ancillary services. Utilities must rely upon the same electronic information network that its transmission customers rely upon to obtain transmission information.	Reciprocity Transmission customers of jurisdictional utilities who take service under the open access tariff and who own, control, or operate transmission facilities must, in turn, provide open access service to the transmitting utility. This includes municipally owned entities and RUS cooperatives.
	Services to be Provided A public utility must offer transmission services that it is reasonably capable of providing, not just those services that it currently provides to itself and others. Six ancillary services must be included in the open access tariff: Scheduling, system control, and dispatch Reactive supply and voltage control from generation sources Regulation and frequency response Energy imbalance Operating reserve--spinning reserve Operating reserve--supplemental reserve. The transmission customer must purchase the first two services from the transmission provider.
Nondiscriminatory Open Access Tariff Requirement By July 9, 1996, jurisdictional utilities that own or control transmission must have filed a single open access tariff that offers both network, load-based services and point-to-point, contract-based services, including ancillary services, to eligible customers comparable to the service they provide themselves at the wholesale level. The rule provides a single pro forma tariff that sets forth minimum conditions for both network and point-to-point services and nonprice terms and conditions for providing those services and ancillary services.
Pools and Holding Companies Jurisdictional utilities who are members of tight or loose power pools must file either an individual pro forma tariff or a joint pool-wide pro forma tariff by July 9, 1996. They are not required to take service for pool transactions under that tariff, but are required to file a joint pool-wide tariff no later than December 31, 1996, and begin to take service under that tariff for all pool transactions by that same date. By that date, they must also restructure their ongoing operations and open membership to nonutilities. Public utility holding companies not subject to tight or loose pool requirements are required to file a single system-wide pro forma tariff permitting transmission service across the entire holding company by July 9, 1996. All bilateral economy energy coordination contracts executed before the effective date of this rule must be modified to require unbundling of any economy energy transaction occurring after December 31, 1996.	Pricing The rule does not prescribe rates for network, point-to-point, or ancillary services. Instead, utilities may charge current rates or apply for new transmission rates. Utilities can propose to recover opportunity costs and expansion costs. Crediting for customers' transmission facilities will be permitted on a case-by-case basis. Proposed pricing must conform with FERC's Transmission Pricing Policy Statement.
	Contract Reform The rule does not void any existing requirements contracts. The functional unbundling requirement applies only to transmission services under new requirements contracts, new coordination contracts, and new transactions under existing coordination contracts. Parties to requirements contracts executed on or before July 11, 1994, may seek modification of such contracts on a case-by-case basis, even if they contain a Mobile-Sierra clause. FERC, however, does not take contract modification lightly and parties seeking to modify contracts will have a heavy burden to demonstrate the need for it.
Customer Eligibility Any entity engaged in wholesale purchases or sales of energy or retail purchases is an eligible customer.	Market-Based Rates Utilities seeking market-based rates for sale of electricity at wholesale from new capacity are no longer required to demonstrate lack of market power in generation. New capacity is that for which construction has commenced on or after the effective date of this rule. For existing generation, FERC will continue its case-by-case approach that includes an analysis of generation market power in first- and second-tier markets.
Source: Adapted from "FERC Finalizes Electric Industry Restructuring Rule," Public Utility Topics (Philadelphia, PA: Coopers & Lybrand, L.L.P., June/July 1996), No. 96-2, p. 4.

Developing Guidelines for Recovery of Stranded Costs
The second goal of Order 888 was to ensure that electric utilities are able to recover their sunk costs in a competitive industry. These sunk costs are called stranded costs, or transition costs, and they represent a utility's capital investments that are unrecoverable because of the transition to competition. The rationale for allowing stranded cost recovery is that utilities have invested billions of dollars in facilities under a regulatory regime that allowed cost recovery of all prudent investments. To gain support and cooperation for a successful transition to a competitive industry, and to be consistent with the past decisions, FERC believed it was critical that utilities recover these costs. At the same time, FERC recognized that recovery of stranded costs may delay some of the benefits of competitive power markets.

FERC's Order 888 spelled out under what general conditions a utility is entitled to recover its stranded costs and from whom. As far as entitlements, Order 888 specified that cost recovery at the wholesale level is limited to situations where there is a link between the use of FERC's required open access transmission tariff and the loss of wholesale power customers. FERC went further to specify that recovery of wholesale stranded costs should be assigned to the departing customer. At the retail level, FERC determined that States should have primary jurisdiction over cost recovery resulting from retail competition, although it would entertain requests to recover costs resulting from retail competition when a State does not have the authority.

FERC's concerns for the recovery of wholesale stranded costs may have been overestimated. Since Order 888 was issued, FERC has on record seven stranded costs cases. Moreover, as of April 2000, it had not received a filing for wholesale stranded cost recovery in more than a year and a half.⁽³⁾ The overwhelming majority of stranded costs awards have been in States that have implemented retail competition. Chapter 8 contains a discussion of stranded costs resulting from States introducing retail competition.

Promoting Transparency of Information About the Bulk Power Transmission System
To follow through with non-discriminatory access to the transmission system, timely and accurate day-to-day information about transmission must be unrestricted and public to all transmission users. To implement this concept, in 1996 FERC issued Order 889 requiring all IOUs to participate in the Open Access Same-Time Information System (OASIS).

The OASIS is an interactive Internet-based database containing information on available transmission capacity, capacity reservations, ancillary services, and transmission prices. The underlying idea of the OASIS is to create an interactive computerized market for transmission-related products and services which is accessible by all qualified users of the transmission system. In that role, the OASIS facilitates the functioning of competitive power markets.

The OASIS became operational in January 1997. Currently, 23 OASIS nodes are on the Internet, and approximately 166 transmission owners participate by providing information about their transmission facilities. Initially the OASIS had operational problems traceable to a lack of common data elements and business practices. This condition made it difficult to compare data between nodes, and to conduct business over multiple nodes. Recently, OASIS developers have adopted a common set of Business Practice Standards to improve the interaction between transmissions providers and customers over the OASIS.⁽⁴⁾ Implementation of these standards should move the OASIS further along in becoming a useful tool in support of a competitive industry.

Promoting Development of Regional Transmission Organizations
Promoting regional transmission organizations (RTOs) is the last of FERC's major objectives discussed in this chapter. It arguably can be called FERC's most significant and, to some extent, most tumultuous activity undertaken in its effort to create a more competitive and efficient industry.

The concept of regional organizations in the electric power industry has existed for some time. Many regional entities have been created for planning, coordination, or system reliability functions. The most visible are the 10 Regional Reliability Councils that develop standards and procedures to maintain the reliability of the Nation's power system. Some industry observers have noted that perhaps there are too many regional entities, and that regional decision-making authority and responsibility sometimes becomes blurred.

RTOs refer to the idea of organizing the operation, control, and possible ownership of the transmission grid into independent companies or organizations; the process of forming RTOs is also referred to as grid regionalization.⁽⁵⁾ Regional control of the transmission grid has many coordination and efficiency advantages over the current balkanized configuration where each vertically integrated utility operates and controls its own transmission facilities.

FERC's effort to foster grid regionalization consists of three progressively ambitious initiatives. In 1993 FERC issued a policy statement recommending that transmission owners, transmission customers, and other interested parties form regional transmission groups (RTGs) to coordinate transmission planning and expansion on a regional and inter-regional basis (Table 9). A few RTGs were established, but their role has been limited. Although effective for planning purposes, these organizations were usually not vested with appropriate decision-making authority needed to address transmission issues affecting an entire region.

In its next initiative, FERC used a stronger and more ambitious approach to grid regionalization. In Order 888, FERC encouraged the formation of independent system operators (ISOs), whereby utilities would transfer operating control of their transmission facilities to the ISO. Ownership of the facilities would remain with the utility. Utility participation in an ISO was voluntary.

By encouraging ISO formation, FERC underscored its belief in the importance of unbundling power generation and marketing from operation and control of the transmission grid. An ISO with no economic interest in marketing and selling power could administer fairly the open access transmission tariff and eliminate discriminatory practices, and at the same time achieve the efficiency benefits from regional control of the grid.⁽⁶⁾ Since Order 888 was issued, six ISOs have been formed and five of them are now operating. (The status of these ISOs is discussed later.)

Remaining Impediments to Competitive Power Markets After Order 888
Even with five ISOs operating and open access transmission tariffs in place, the development of wholesale power markets across the nation has been slow, and obstacles to competition still remain. Three major obstacles have been mentioned. First, since Order 888 was issued the Commission has received many complaints of transmission owners discriminating against independent power companies. Further, the Commission noted that an increase in the number of market participants and transactions in wholesale markets has made discriminatory behavior with regard to transmission access more subtle and more difficult to identify.⁽⁷⁾ Second, the Commission observed that electric utilities' implementation of functional unbundling has not produced sufficient separation between operating the transmission system and marketing and selling power, and that this lack of separation contributes to discriminatory behavior. Third, grid regionalization through ISOs has occurred in some areas of the country, but was not implemented in other areas. Although creation of an ISO was voluntary, expectations were that more regions would seek to realize the benefits of grid regionalization and would participate in forming ISOs.

In addition to these obstacles, an increase in market participants and trading over the past few years, and changes to electricity trading patterns has made system reliability more difficult to maintain which impedes creating fully competitive power markets. The North American Electric Reliability Council (NERC) reported that, "[in recent years] the adequacy of the bulk power transmission system has been challenged to support the movement of power in unprecedented amounts and in unexpected directions."⁽⁸⁾ This view is supported by a U.S. Department of Energy Task Force noting that "there is a critical need to be sure that reliability is not taken for granted as the industry restructures, and thus does not fall through the cracks."⁽⁹⁾

Not only has maintaining reliability become more difficult, other obstacles to competitive markets have emerged. Transmission congestion has increased, but current procedures for relieving congestion are antiquated and sometimes unfair. As FERC points out, "current transmission loading relief (TLR) procedures [for relieving congestion] are cumbersome, inefficient, and disruptive to power markets because they rely exclusively on physical measures of [electricity] flows with no attempt to assess the relative costs and benefits of alternative congestion management techniques." Another problem is that planning for transmission expansion is more difficult than in the past because of more uncertainty in the industry. Responsibilities for transmission expansion are not always clear, the motivation for construction of new facilities is changing, and cost recovery after construction may be more risky than in the past. Finally, the current method of transmission pricing is antiquated given the new competitive environment. In most of the United States, the transmission customer pays separate additive access charges every time the power crosses the boundary of a transmission owner. This practice is referred to as pancaked pricing, which has the effect of raising the cost of transmission and reducing the geographic size of competitive power markets.

Order 2000 and Grid Regionalization
FERC's third initiative to grid regionalization, which is currently being implemented, is perhaps its most ambitious effort. In December 1999, FERC issued Order 2000, calling for the voluntary creation of RTOs throughout the United States. FERC had noted that all of the Nation's transmission systems should be brought under regional control and perhaps regional ownership in order to eliminate the remaining discriminatory practices, meet the increasing demands placed on the transmission system, and achieve fully competitive wholesale power markets. If FERC's implementation of Order 2000 is successful, the transmission system will go from a system owned and controlled mostly by vertically integrated electric utilities to a system owned and/or controlled by a few, but uncertain number of, unaffiliated RTOs.

With this formidable undertaking, the Commission again believes a voluntary approach will be successful because (1) many vertically integrated utilities recognize the benefits of an RTO, (2) Order 2000 provides clear rules and guidance for utilities to follow in forming an RTO, (3) to facilitate cooperation, the Commission established a collaborative process for RTO development, and (4) Order 2000 provides ratemaking incentives for companies who assume the risks of a transition to a new corporate structure. (Table 12 contains a summary of the major components of Order 2000.)

Table 12. Summary of Major Provisions of the Federal Energy Regulatory Commission's Order 2000 Final Rule Establishing Regional Transmission Organizations
Filing Requirements and Deadlines Each public utility that owns, operates, or controls interstate transmission facilities (except those already participating in an approved regional transmission entity) must file by October 15, 2000, a proposal to participate in a regional transmission organization (RTO) that will be operational by December 15, 2001, or they must file, by the same date, a description of efforts to participate in an RTO, obstacles to participation, and plans and a timetable for future efforts. Each public utility that is a member of an existing transmission entity that conforms with the 11 ISO principles contained in Order 888 must file by January 15, 2001, a description that explains the extent to which the transmission entity in which it participates meets the minimum characteristics and functions of an RTO, and how it proposes to modify the entity to become an RTO, or a description of efforts, obstacles, and plans to conform to an RTO's minimum characteristics and functions. All RTOs will implement their minimum functions according to the following schedule: Congestion management function by December 15, 2002 Parallel path flow coordination function by December 15, 2004 Transmission planning and expansion function by December 15, 2004 Other minimum functions will be implemented by startup.
Minimum Characteristics of a Regional Transmission Organization 1. Independence: The RTO must be independent of market participants. Independence can be achieved by meeting three conditions: (1) the RTO, its employees, and any non-stakeholder director must not have any financial interest in any market participants, (2) the RTO must have a decision-making process independent of control by any market participant, and (3) the RTO must have exclusive authority under Section 205 of the Federal Power Act to file changes to its transmission tariff. 2. Scope and Regional Configuration: The RTO's region must be of sufficient scope and configuration to perform effectively its required function and to support efficient and nondiscriminatory power markets. FERC will evaluate the configuration or boundaries of the RTO according to the extent it meets nine criteria: Facilitates performing essential RTO functions Encompasses one contiguous geographic area Encompasses a highly interconnected portion of the grid Deters the exercise of market power Recognizes existing trading patterns Takes into account existing regional boundaries (e.g., NERC regions) Encompasses existing regional transmission entities Encompasses existing control areas Takes into account international boundaries. 3. Operational Authority: The RTO must have operational authority for all transmission facilities under its control, and it also must be the security coordinator for the region. The security coordinator ensures the real-time operating reliability of the power systems. 4. Short-Term Reliability: The RTO must have exclusive authority for maintaining the short-term reliability of the transmission grid under its control. Short-term is intended to include all time periods necessary for the RTO to satisfy its reliability responsibilities up to the planning horizon.
Minimum Functions of a Regional Transmission Organization 1. Tariff Administration and Design: The RTO will be the sole administrator of its own tariff and, therefore, it will be the sole decision-making authority on provision of transmission service including the decision to establish new interconnections. 2. Congestion Management: The RTO will ensure the development of market mechanisms to manage transmission congestion. These mechanisms should provide price signals to transmission customers regarding the consequences of their transmission usage decisions. 3. Parallel Path Flow: The RTO must implement procedures within 3 years of start-up to address the problems associated with interregional parallel path flow and implement procedures immediately for regional parallel path flow. Parallel path flow refers to the fact that electricity flows over transmission lines according to the laws of physics. Because of these laws, the power generated in one region may flow over the transmission lines of another region, inadvertently affecting the ability of the other region to move power. 4. Ancillary Services: The RTO must serve as the provider of last resort for all ancillary services as required in Order 888. The RTO should promote creation of competitive markets for procurement of these services. 5. Open Access Same-Time Information System (OASIS) and Capability Calculations: The RTO should act as a single OASIS node. The data elements of total transmission capability and available transmission capability, which are stored on the OASIS and used by potential transmission customers, will be calculated by the RTO, or if provided by the transmission owner, verified by the RTO. 6. Market Monitoring: The RTO will submit to FERC a market monitoring plan that (1) ensures that there is objective information about the markets, (2) contains procedures for proposing efficiency improvements, market flaws, and market power, and (3) contains procedures to evaluate the behavior of market participants. 7. Planning and Expansion: The RTO must develop a planning and expansion proposal that (1) encourages market-motivated operating and investment actions for preventing and relieving congestion, (2) accommodates efforts by State regulatory commissions to create multi-state agreements to review and approve new transmission facilities and coordinates with existing regional transmission groups, and (3) files a plan with milestones showing that the RTO will meet its planning and expansion requirements no later than 3 years after start-up. 8. Interregional Coordination: The RTO will develop mechanisms to ensure the integration of reliability practices within an interconnection and market interface practices among regions.
Open Architecture Open architecture refers to the idea that RTOs should be designed so that improvements in their structure, operating rules, and other activities can evolve over time.
Policy for an RTO's Transmission Rates FERC believes that effective transmission rates are essential in promoting economic efficiency in the generation and transmission sectors, and are an important factor to the success of the RTO as a stand-alone transmission business. FERC has approval responsibility for an RTO's transmission rate schedule. According to FERC policy, effective transmission rates will address the following issues: Eliminate Pancake Pricing: Pancake pricing occurs when a transmission customer is charged separate access charges for each utility service territory crossed by the transmission customer's power transaction. Pancaking increases the price of electricity and it discourages competition in the generation sector. By combining transmission systems under one RTO, a wider area served by a single rate can be designed. Reciprocal Waiving of Access Charges Between RTOs: FERC encourages the RTOs to waive transmission access charges for transactions that cross RTO borders. This increases the size of the competitive trading area beyond the RTO border. Uniform Access Charges: FERC encouraged that an RTO establish one uniform access charge for all transmission customers. However, they recognized that this approach may result in cost shifting (i.e., low-cost transmission providers would see a rate increase, and high cost providers a rate decrease). As a temporary solution, FERC will allow a single rate, but that rate will vary based on where the customer is located. Congestion Pricing: Congestion pricing is closely related to congestion management in that effective pricing of congestion problems provides the appropriate price signals to build additional transmission lines or power generation plants in order to eliminate congestion. Service to Transmission-Owning Utilities that do not Participate in an RTO: FERC intends to permit an RTO to propose rates, terms, and conditions of transmission service that recognize the participatory status of transmission customers. In other words, a transmission customer who is also a transmission provider in the region that chose not to join the RTO, will have a different transmission tariff than other customers. Performance-Based Regulation: Performance-based regulation (PBR) represents the concept of offering financial incentives to lower rates or costs. Under PBR, good performance can be rewarded with higher profits and poor performance can be penalized in some manner. As an alternative to cost-based regulation, FERC encourages the RTO to develop PBR proposals, although submission of a proposal is voluntary. Other RTO Transmission Rate Reforms: To encourage investment in transmission facilities and efficiency in operation, FERC indicated that it would consider other innovative transmission pricing proposals such as a higher return on equity than previously allowed, levelized rates, or accelerated depreciation and incremental pricing for new transmission investments. Additional Ratemaking Issues: This section of Order 2000 contained a wide range of comments on ratemaking issues not specifically addressed in the notice of proposed rulemakiing. These comments cover issues ranging from alternative ratemaking methods to issues dealing with how to incorporate incentives to promote environmentally benign resources. Filing Procedures for Innovative Rate Proposals: FERC will evaluate innovative rate proposals based on how the proposed rate treatment would help achieve the goals of an RTO. Rate moratoria or returns on equity that do not vary according to the RTO capital structure may not be included in the RTO's rate structure after January 1, 2005.
Other Issues In Order 2000, FERC identified nine issues, other than the ones discussed above, which may have an impact on the structure, completeness, regulation, and design of RTOs. 1. Public Power and Cooperative Participation in RTOs: FERC expects public power entities to participate in the formation of RTOs, but it is aware public power entities face several obstacles. The Internal Revenue Service Codes may prevent facilities financed by tax-exempt debt from wheeling privately owned power, or they may prevent transfer of operational control of transmission facilities financed by tax-exempt debt to a for-profit transmission company. State and local government laws may prevent public power entities from participating in RTOs. The lack of participation of public power entities may negate some of the effectiveness and expected benefits of RTOs. 2. Participation by Canadian and Mexican Entities: FERC opined that Mexican and Canadian participation in an RTO would be beneficial. 3. Existing Transmission Contracts: FERC indicated that it will examine, case-by-case, how to handle existing contractual arrangements when forming an RTO. For example, one issue may involve how to handle pancaked rates in existing contracts for others when transmission-owning utilities design a non-pancaked rate for their own transactions. 4. Power Exchanges: FERC will leave it to each region to determine a need for a power exchange, and if the RTO should operate the exchange should there be a need. 5. Effects on Retail Markets and Retail Access: FERC opined that formation of an RTO will not affect the ability of States to implement retail markets and competition. In Order 2000, FERC noted that experience with the independent system operators (ISOs) indicates that an RTO could be a benefit to States that are implementing retail competition. 6. Effects on States with Low-Cost Generation: Some States are concerned that an RTO would result in local utilities selling their low-cost power to other States. FERC asserted that an RTO will provide access to future low-cost generation plants and that new low-cost generation plants will be attracted to regions with an RTO because of dependable and nondiscriminatory access to the transmission system. 7. States' Role With Regard to RTOs: FERC believes that States have an important role to play, but they chose not to specify what role in Order 2000. 8. Accounting Issues: FERC will require that RTOs conform to the Uniform System of Accounts, but they also indicated that changes in the industry require them to re-examine existing accounting and related reporting requirements. 9. Market Design Lessons: FERC envisions that bid-based markets for wholesale electric power will be a central feature in many RTO proposals. Although bid-based markets for electric power do not now represent the dominant method for buying and selling electricity, this method is expected to grow. In Order 2000, FERC summarizes lessons learned from its analysis and approval of bid-based markets for four independent system operators. As these and other power markets mature, additional information on how to design and operate power markets will develop. Multiple Product Markets: Efficiency of a multi-product market operating in the same time period is maximized when arbitrage opportunities reflected in the bids are exhausted. That is, it is efficient when, after the RTO's market has cleared, no market participant would have preferred to be in another of the RTO's markets. Physical Feasibility: Transaction in the market should be physically feasible. Access to Real-Time Balancing Market: Real-time balancing refers to the moment-to-moment matching of loads and generation on a system-wide basis. A real-time balancing market should be available to all grid users for purposes of settling their individual imbalances. Market Participation: Markets are more efficient with a broad participation. Demand-Side Bidding: The current wholesale power markets do not offer customer demand-side bidding, only power suppliers bid into the markets. However, demand-side bidding, to the extent it is practical, is desirable to make electricity supply and prices more responsive to competitive markets. Bidding Rules: The market should allow generators to make bids that approximate their costs. Transaction Costs and Risks: Transaction costs should be low and participation in the market should involve no unnecessary risk. Price Recalculations: Market clearing prices should minimize electricity price recalculations. Multi-Settlement Markets: Multi-settlement markets may involve a day-ahead market and a real-time market. If the day-ahead market bids are needed for reliability, these bids need to be physically binding and may be subject to penalties for failing to adhere to the bid. Preventing Abusive Market Power: FERC highlights three items which will help to lessen the potential for market power: (1) have fewer restrictions on importing power into the region, (2) have less segmentation of geographic markets for the same product, and (3) stop allowing market participants to change bids before they complete the financial settlement. Bid changing can be used as signaling to facilitate collusive behavior. Market Information and Marketing Monitoring: Market clearing prices and quantities should be transparent so that market participants can assess the market and plan their business efficiently. Prices and Cost Averaging: Transmission and congestion prices based on average costs may distort power production, power consumption, and investment decisions. More innovative pricing methods are needed.
Collaborative Process: FERC asserted its commitment to hold regional workshops to assist in the voluntary formation of RTOs. Five workshops were held in March and April 2000.
Sources: Federal Energy Regulatory Commission, "Regional Transmission Organizations, Order No. 2000," 18 CFR Part 35 (December 20, 1999); L.S. Hyman, What's Inside FERC's Transmission Policy: A Guide To Order 2000 (Vienna, VA: Public Utilities Reports, January 2000).

Potential Benefits of Regional Transmission Organizations Through Order 2000
By eliminating the balkanized control of the transmission grid, regionalization has the potential to increase significantly the overall operating efficiency of the industry system. Many industry analysts believe that combining the control of individual transmission systems under one regional organization with a wide regional scope can lead to improvements in transmission pricing, improved management of congestion, improved information relevant to promoting competition in power markets, better management of parallel path flow problems, improved reliability management, and as noted above, the elimination of remaining discriminatory practices concerning access to the transmission system services. The term potential is a key word because regionalized control of the Nation's transmission grid, as proposed in Order 2000, is a new and unproven concept. These potential benefits, some of which were alluded to in the above discussion, are covered below in more detail.

Eliminate remaining opportunities for discriminatory transmission practices: As organizations completely independent from power production and sales, RTOs will sever the economic incentives between power marketing and control of the transmission system. Without the economic incentive, the reasons for discriminatory practices should be eliminated. Functional unbundling required in Order 888 did not eliminate economic incentives, and was not completely effective in eliminating discriminatory practices.

Improve calculations of available transmission capacity: Available transmission capacity (ATC) is a measure of the amount of transmission capacity that is available to transmit power over the grid at a particular time. Market participants use this information to make short-term decisions to purchase or sell power. ATC is difficult to calculate due to constantly changing conditions and the complexity of the electrical network. The difficulty is compounded in a balkanized network where each utility calculates its own ATC. An RTO with regional scope will have better information on conditions of the network than an individual utility; with better information, more accurate estimates of ATC will be available to transmission users. Also, FERC has pointed out that many complaints have been filed claiming that transmission providers are calculating ATC to favor their own generators, which is a form of discrimination. An independent RTO will eliminate this behavior.

Improve management of parallel path flow and system reliability: The interconnection of the transmission grid makes management a difficult and challenging task. One of the biggest problems is managing parallel path flow (also called loop flow). Parallel path flow refers to the fact that electricity flows across an electrical path between source and destination according to the laws of physics, meaning that some power may flow over the lines of adjoining transmission systems inadvertently affecting the ability of the other region to move power. This cross-over can create compensation disputes among the affected transmission owners. It also impacts system reliability if a parallel path flow overloads a transmission line and decisions must be made to reduce (curtail) output from a particular generator or in a particular area. An RTO with access to regionwide information on transmission network conditions, with regionwide power scheduling authority, and with more efficient pricing of congestion can better manage parallel path flows and reduce the incidence of power curtailment.

Improve transmission pricing methods: Pricing of transmission services is one of the most important issues in restructuring the Nation's transmission system. Historically, FERC has based its approach to transmission prices on the rolled-in average historic costs of the transmitting utility. This method was largely developed for requirements service where the wholesale customer's load was dispersed throughout the utility's service territory and integrated generation and transmission facilities are used. The result has been a "postage stamp" rate. Postage stamp rates have important limitations, particularly in providing price signals to transmission users. Such rates may not reflect the cost of scarcity when there is a bottleneck on the grid, the costs of expanding capacity to remove such a bottleneck, or the costs of transmitting power over long distances.

In addition to the potential inefficiencies, each transmission owner had its own rate structure which worked when the industry was totally regulated and wholesale electricity markets were relatively small or nonexistent and electricity trading was infrequent. Competitive wholesale power markets require more efficient and equitable pricing methods that eliminate the possibility of pancaked pricing which can double or triple the price of the transaction, making it more difficult for electricity suppliers that have to cross multi-transmission boundaries to be cost competitive. Under Order 2000, RTOs will be required to design pricing methods that eliminate pancaked prices. Also, Order 2000 encourages RTO applicants to consider innovative transmission pricing methods such as performance-based ratemaking (PBR), or levelized rates, to replace the inefficient transmission pricing methods currently used.

Improve management of transmission congestion: Transmission congestion occurs when a transmission line reaches its transmitting capacity and additional power from a specific generator cannot be dispatched as needed. Congestion is caused by generation or power grid outages, increases in energy demand, loop flow problems, or a combination of these factors.

In the past, transmission owners had responsibility for the management of congestion on their transmission systems. Usually, adequate transmission facilities existed to support the flow of electricity within each transmission owner's system; however, when congestion occurred, the common approach was to curtail power to relieve the congestion. In a competitive environment, administrative curtailment is no longer an acceptable technique for congestion management. By not evaluating the costs of congestion, administrative curtailment provides no price signals or economic incentives to reduce congestion, and in that respect it is incompatible with competitive markets. In Order 2000, the Commission requires that an RTO develop mechanisms that measure congestion costs and that market participants are made aware of the cost consequences of their transmission usage decision. FERC leaves it up to the RTO to design a congestion pricing method to suit its needs.

Improve reliability of the transmission grid: Because an RTO typically covers a larger region, it enhances coordination among key players during system emergencies. Additionally, it can better coordinate or schedule generation and transmission outages and the sharing of ancillary services. An independent RTO can conduct more objective reliability studies of the system than others who may have vested interests in certain outcomes.

Major Issues in Forming a Regional Transmission Organization
Creating RTOs nationwide is a formidable task, and many difficult issues must be addressed. In addition to the problems unique to each region of the country, there are also generic problems applicable to all regions. Three important generic issues are the RTO's size, organizational structure, and transmission grid coverage.

Determining the appropriate size of an RTO: The Commission did not prescribe boundaries for an RTO, but notes that a region sized appropriately will be sufficient to permit the RTO to effectively perform its required functions and to support efficient and nondiscriminatory power markets. The Commission specified regional configuration factors to evaluate the appropriateness of the proposed RTO's configuration. The region configuration should be large enough so that the RTO can make accurate and reliable ATC calculations, resolve loop flow issues internally within the region, manage congestion effectively, offer non-pancaked transmission rates, effectively operate one OASIS site, and conduct transmission planning and expansion effectively. The specific boundaries of an RTO will be evaluated using nine criteria (Table 12, Minimum Characteristic 2).

A reading of Order 2000 requirements with respect to the appropriate size of an RTO makes clear a few points. FERC does not have any apparent preconceived notion of the appropriate size of an RTO, only that determining the right size will involve evaluating many factors. One size does not fit all regions, so different configurations are likely. To maximize the benefits of an RTO, it appears that the larger the region covered by the RTO the better, to a point. Technical factors, as well as managerial, economic, and political factors need to be evaluated to determine an optimal size.

Determining the appropriate ownership structure of an RTO: One of the most important factors in determining the appropriate ownership structure for an RTO is its ability to achieve independence from market participants.⁽¹⁰⁾ FERC commented in Order 888 that "the principle of independence is the bedrock upon which the ISO must be built and that this principle must apply to all RTOs, whether they are ISOs, transmission companies (Transcos), or variants of these two models. Order 2000 enumerates three conditions for independence: (1) the RTO's employees and any nonstakeholder directors must not have any financial interest in any market participants; (2) the RTO must have a decision-making process that is independent of control by any market participant or class of participants; and (3) the RTO must have exclusive and independent authority to file changes to its transmission tariff with the Commission under section 205 of the Federal Power Act.

The effect of ownership on an RTO's independence depends on which ownership model is used. The two basic models are the ISO model and transmission company (Transco) model. With the ISOs that are currently operating, ownership of the transmission facilities remained with the vertically integrated electric utility, but operating control of the facilities was transferred to the ISO. These ISOs operate as nonprofit and nonshare companies and their independence from market participants is established through representation and voting privileges of its governing board.

The Transco is an independent, self-sustaining, profit-making transmission company. Under this model, the Transco owns the transmission facilities and the issue of independence concerns ownership of the company itself. The Commission noted that it will permit market participants to retain limited active ownership (up to 5 percent for a single market participant and 15 percent for a class of market participants) in the RTO during a 5-year transition period. Active ownership refers to ownership of voting securities that gives the owner the ability to influence or control an RTO's operating and investment decisions. An active ownership interest will terminate after 5 years.

In Order 2000, FERC has noted its openness to consider any type of ownership and governance structure as long as the RTO's design meets the minimum characteristics requirement of Order 2000. FERC has stated that "it is important that we provide current transmission owners with flexibility in deciding how they will relinquish ownership or control of their transmission facilities to an RTO." Flexibility in ownership allows for regional differences.

Avoiding gaps in regional coverage of the transmission grid: For an RTO to realize its full potential, its must have control and authority over the entire transmission grid in the region. Gaps or breaks in continuity of coverage of the grid undermine the RTO's effectiveness and the achievement of the benefits it can provide.

Because joining an RTO is voluntary, some utilities may decide not to participate. IOUs choosing not to participate are required to file reasons and obstacles for not participating. This procedure should invoke a dialogue with FERC and provide a mechanism to overcome obstacles to participation. Because IOUs are jurisdictional utilities, FERC also has some leverage in convincing IOUs to participate.

On the other hand, federally owned and other public power and cooperative utilities are non-jurisdictional utilities; they have no filing requirements under Order 2000 and FERC has no apparent leverage in obtaining their participation. Because these utilities own approximately 30 percent of the Nation's power grid, the potential exists for substantial gaps in regional coverage. For example, in the northwest and southeast regions of the United States, federally owned utilities are major providers of electricity with substantial ownership in transmission facilities. RTO formation in those regions may be impractical without their participation.

In Order 2000, FERC encourages non-jurisdictional utility participation, but also recognizes that municipally owned utilities face numerous regulatory and legal obstacles. The Internal Revenue Code has private use restrictions on the transmission facilities of municipally owned utilities financed by tax-exempt bonds. State and local government limitations, such as prohibitions on participating in stock-owning entities and other restrictions, may also impede full participation. FERC, through the collaborative process, seeks solutions to these problems, but the outcome is uncertain.

Although FERC has encouraged formation of independent RTOs, development of them has been sporadic; most of the Nation's transmission grid is not under control of an independent RTO. Five ISOs have formed over the past 2 years and are now operating--California ISO; Pennsylvania, New Jersey, Maryland (PJM) ISO; ISO New England; New York ISO; and ERCOT ISO (Figure 27). The Midwest ISO has received regulatory approval and much of its operating infrastructure has been assembled; it should take operating control of the transmission grid in the near future.

Several factors have contributed to the current set of approved ISOs. PJM, New England, and New York ISOs were created from existing tight power pools. A tight power pool functions as one control area. Unlike ISOs, power pools did not have control of transmission facilities, they were not independent from transmission owners, and they did not administer a regional open access transmission tariff. According to Order 2000, "it appears that the principal motivation for these tight power pools forming ISOs was to establish a single system-wide transmission tariff as required by Order 888." In contrast, State legislation that opened California's electric industry to retail competition required the formation of the California ISO. The Public Utility Commission of Texas created the ERCOT ISO. Originally, the Midwest ISO consisted of voluntary members. Subsequent to its initial formation, electric utilities in Illinois and Wisconsin have joined the Midwest ISO because of State legislation requiring either utility participation in an ISO or divestiture of their transmission assets.

A comparison of the six ISOs show many similarities, although many of the implementation details are different (Table 13). All of the ISOs are nonprofit organizations. Four of the ISOs operate as a single control area; ERCOT and the Midwest ISO have multiple control areas within their regions.

Table 13. Selected Information on Independent System Operators
	California ISO	ERCOT Texas ISO	ISO New England	MidWest ISO (MISO)	New York ISO	Pennsylvania, New Jersey, Maryland (PJM)-ISO
Operating Date	March 31, 1998	August 1996	1997	Approved 1998. Not yet operating	1999	April 1998
States Covered	California	Texas	Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, Vermont	Illinois, Indiana, Kentucky, Missouri, Ohio, Maryland, Pennsylvania, Virginia, West Virginia, Wisconsin	New York, New Jersey	Delaware, New Jersey, Maryland, Pennsylvania, Washington, DC, Virginia
Number of Transmission Owners	3	16	15	13	8	10
Type of Organization	Nonprofit	Nonprofit	Nonprofit	Nonprofit	Nonprofit	Nonprofit
Board of Directors	24 members representing 13 stakeholder classes	18 members representing 6 stakeholder classes	10 independent members	8 independent members	10 independent members	8 independent members
Control Areas	Single	Multiple	Single	Multiple	Single	Single
Transmission Rights Program	Under development	None	Under development	Undecided	Transmission congestion contracts	Fixed transmission rights
Transmission Congestion Management	Price based ^a	Priority based	Priority based	Priority based	Price based	Price based
Transmission Access Charges ^b (Method to Meet Revenue Requirements)	Charge is based on the embedded cost of the transmission owner serving the customer	System-wide (postage stamp) charge	Charge is based on the embedded cost of the transmission owner serving the customer	Charge is based on the embedded cost of the transmission owner serving the customer	Charge is based on the embedded cost of the transmission owner serving the customer	Charge is based on the embedded cost of the transmission owner serving the customer
Ancillary Services	ISO procures if not provided	ISO coordinates	ISO can provide	ISO will arrange for services	ISO can provide	ISO provides or coordinates
Transmission Planning	ISO leads coordinated process	ISO coordinates	NEPOOL has lead role	ISO develops plan with transmission owners	ISO is an active participant	ISO prepares plan
Operation of a Centralized Power Market	Separate from ISO	None	Combined with ISO	None	Combined with ISO	Combined with ISO
Type of Centralized Power Markets	The California power exchange manages the day-ahead and hour-ahead markets. The ISO manages the ancillary services, real-time imbalance, and congestion markets.	NoneOne residual day-ahead market (only the difference between participant's energy resources and obligations can be bidded); All transactions are priced at ex-post energy clearing price.	NoneDay-ahead and real-time market; both ISO settled; additional bids can be submited and non-accepted bids resubmitted (hour-ahead bids) up to 90 minutes before dispatch hour in the real-time market.	One real-time joint market for energy and reserves; generators submit hourly bids for their resources once daily; these resources are used by the ISO for energy and reserves.
^aPrice based means that the ISO calculates the costs of congestion and allocates these costs to the appropriate transmission user. Priority based means that the ISO curtails power generation based on a predetermined curtailment plan. ^bAll of the ISOs will be phasing in one system-wide transmission access charge. Sources: L.D. Kinsch, "Pricing the Grid: Comparing Transmission Rates of the U.S. ISO," Public Utilities Fortnightly (February 15, 2000). Energy Information Administration, The Changing Structure of the Electric Power Industry: Selected Issues 1998, DOE/EIA-0562(98) (Washington, DC, July 1998), pp. 34-35.

With the exception of the ERCOT ISO, all other ISOs have developed a single access charge to the ISO-controlled transmission systems, based on the costs of the transmission owner serving the customer. Access charges are used to recover the transmission owner's embedded transmission system costs, and are calculated based on dollar per megawatthour of transmission system usage. Under this system, the transmission customer pays only one access charge regardless of the number of individual transmission systems crossed in the ISO-controlled grid, so pancaked charges have been eliminated. Most of the ISOs are moving toward development of one uniform access charge for the entire ISO-controlled grid.

Three of the ISOs (California, PJM, and New York) use bid prices to manage transmission congestion in their region. In general, the power generators submit voluntary bids to reduce output and relieve congestion, and the ISO uses the bids to calculate the costs (or price) of transmission congestion. The costs are assigned to the appropriate transmission user. This technique places a value on congestion and it provides a basis for economic decision-making. Managing transmission congestion using energy prices is a relatively new and innovative application, and it is likely that RTOs now being formed will experiment with these new techniques.

Four of the regions--California, PJM, New York, and New England--have established centralized markets for buying and selling energy in their respective regions. In California, the California Power Exchange, which is a separate organization from the California ISO, runs their energy market. Operation of the energy markets and the ISO are combined in the other regions. These centralized markets are new, and the rules of operation will likely evolve as more operating experience is acquired.

With respect to meeting the requirements of Order 2000, ISOs have until January 1, 2001, to submit a filing to FERC specifying their plans for forming an RTO. None of the existing ISOs have announced publicly their specific compliance plans. It is unlikely that the existing organizational structure of these ISOs will satisfy all of the minimum characteristics and minimum functions required of an RTO (Table 12), so one can expect to see changes in the ISO organizational structures and functions over the coming years. Electric utilities not currently members of an ISO have to file plans to form an RTO by October 1, 2000. In some regions, progress toward compliance with Order 2000 has been made as demonstrated by the following examples.

The most significant announcement was the planned merger between the Midwest ISO and the Mid-Continent Area Power Pool (MAPP). This arrangement has the potential of creating one RTO from east of the Rocky Mountains up to the border of the PJM ISO (Figure 27).

The Southwest Power Pool (SPP) has filed with FERC seeking formal recognition as an ISO. It also requested that the Commission recognize that it satisfies minimum requirements for an RTO. In May 2000, FERC ruled that SPP's proposal does not have the operational authority, independence, and other requirements to qualify as an RTO.

In June 1999, the Alliance Companies, consisting of five large IOUs located in Michigan, Ohio, and Virginia, filed with FERC an application to transfer their transmission facilities to a Transco. FERC conditionally approved the transfer of ownership and the general framework of the Transco as meeting the requirements of an ISO subject to certain revisions. In May 2000, FERC ruled that the Alliance Transco does not meet the independence requirements of an RTO.

Recently, FERC accepted the creation of Mountain West as an Independent System Administrator (ISA) and conditionally approved the transfer of transmission facilities belonging to Nevada Power and Sierra Power to the ISA. FERC did not evaluate Mountain West under its ISO or RTO principles. Mountain West is considered an interim step in a broader regional transition plan in the western region.

In response to FERC's Order 2000, nine transmission-owning utilities are working together to form the Northwest RTO.

Coinciding with FERC's promotion and approvals of market-based rates for the sale of electricity, the industry has experienced a significant change in the way power is sold. Most noticeable is the emergence of centralized power markets where electricity suppliers submit bids to sell power in regional markets. The market operator evaluates the bids and selects the most economical bid to meet energy demand in the region. Four centralized power markets are now operating--California PX, New York ISO, ISO New England, and PJM-ISO (Figure 28). Of the four operating markets, the California Power Exchange may be the most active because California's three major electric utilities were until recently required by State law to sell all of their power through the exchange. Participation in the other power markets is voluntary and currently most of the power in these regions is sold through bilateral arrangements between buyer and seller. This may change as buyers and sellers gain more experience with centralized power markets.

To support bilateral power trading, numerous electricity trading hubs have emerged over the past few years. A hub is a location on the power grid representing a delivery point where power is sold and ownership changes hands. Potentially, each control area on the power grid could become a trading hub, but a few hubs account for the bulk of power trading (Figure 28). Of the 10 major trading hubs, five of them are located in the western United States, four in the midwest, and one in the east.

Part of the reason that these major trading hubs have emerged is because the New York Mercantile Exchange (NYMEX) and the Chicago Board of Trade (CBOT) have developed and sponsored electricity futures contracts to facilitate trading at these hubs. A futures contract is a common risk management tool used in agricultural, metal, and energy commodities markets. One of the main purposes of a futures contract is to eliminate the risk of price changes. For example, a power marketer entering into a contract to sell power at a predetermined price at the California Oregon Border (COB) runs the risk that the price it must pay for electricity will increase before the power is delivered. However, the power marketer can hedge its risk by buying electricity futures that match the quantity and timing of the original power contract. NYMEX has created electricity futures contracts for the Cinergy, COB, Entergy, Palo Verde, and PJM trading hubs. CBOT has created electricity futures contracts for the Commonwealth Edison and Tennessee Valley Authority trading hubs.

Market power is the ability of an electricity supplier to raise prices profitably above competitive levels and maintain those prices for a significant time. Electricity suppliers exercising market power force consumers to pay higher electricity prices than they would pay in a competitive market.

Market power exists in two forms--horizontal and vertical. Vertical market power may occur when a firm controls two related activities. In the electric power industry, one firm controlling both electricity generation and transmission has the potential to exercise vertical market power. Separating control of electricity generation from control of the transmission system (via ISOs and RTOs) is designed to eliminate the potential for vertical market power. Horizontal market power is more difficult to eliminate. Horizontal market power may occur when a firm controls a significant share of the market. In the electric power generation business, one firm controlling a significant share of electric generation capacity in a particular region has the potential to exercise horizontal market power. ⁽¹¹⁾

FERC and State regulators are interested in seeing that market power abuses do not undermine the potential benefits of competitive markets. To meet this objective, FERC requires ISOs and RTOs to monitor bulk power markets for abuses and design flaws, and to report market anomalies to FERC and other effected regulatory authorities. This market monitoring function is critical, particularly now as new competitive bulk power markets develop across the country.

A report prepared recently by the California ISO's Department of Market Analysis demonstrates the crucial role of market monitoring.⁽¹²⁾ The report documents that recent spikes in California's electricity prices over this summer were attributable, in part, to some electricity suppliers exercising market power. The report noted that "the presence of market power can be verified by bid prices significantly over the variable costs of many suppliers in the ISO's market."

Price spikes in wholesale power markets in California and New York have prompted FERC to conduct an investigation of all electric bulk power markets to determine whether they are working efficiently and, if not, the causes of the problems. Their report is scheduled to be completed November 1, 2000.

By providing the capability to move power over long distances, the transmission system is an integral component of the Nation's electric power industry. Nondiscriminatory access to the transmission system for all electricity suppliers is critical to creating competitive power markets. For more than a decade, FERC has been pushing for the development of competitive wholesale power markets and opening the transmission system to all qualified users. Since the late 1980s, FERC has approved more than 850 applications from electric utilities, power marketers, and independent power producers to use market-based rates to sell power competitively in wholesale markets. In 1996, the Commission issued Order 888, which opened the transmission system to all qualified power producers and marketers. Prior to Order 888, independent power producers and power marketers had difficulty accessing the transmission grid to deliver power.

Over the past few years, FERC has also encouraged regionalization of the transmission grid whereby vertically integrated electric utilities transfer control of their transmission facilities to an independent transmission organization. Independent means generally that the transmission organization does not have an economic interest in buying or selling electricity. The independence from the electricity market helps to ensure fair and comparable access to the transmission grid. In addition, regionalization of control of the transmission grid promotes improved operating efficiency, simplified and more efficient transmission pricing, and improved reliability.

In an ambitious move to promote regional control of the transmission system, FERC recently issued Order 2000 encouraging all electric utilities to transfer control and/or ownership of their transmission facilities to an independent RTO. Utilities that are not currently a member of an existing regional organization are required to submit plans to join an RTO by October 2000; utilities that are members of an existing regional organization are required to submit their plans to join an RTO by January 2001. It is possible that compliance with Order 2000 will reduce the ownership and control of the Nation's transmission grid to a handful of independent transmission companies over the next few years, but there is much uncertainty about the ultimate effects of Order 2000.

Both this chapter and the preceding chapter have discussed restructuring activities at the Federal level. The following chapter examines the roles of the States.

1. The transmission system is an interconnected group of lines and equipment for the movement or transfer of electric energy between points of supply and points where it is transformed for delivery to customers or is delivered to other electric systems.

2. D.F. Santa, "Analytical Flaws and Practical Pitfalls: Reconsidering FERC's Merchant Affiliate Rules," The Electricity Journal, Vol. 11, No. 9 (November 1998).

3. Personal conversation with the Federal Energy Regulatory Commission, April 3, 2000.

4. Federal Energy Regulatory Commission, "Open Access Same-Time Information System and Standards of Conduct-Order 638," (February 25, 2000).

5. Regional Transmission Organizations (RTOs) have also been called power pools, regional transmission groups (RTGs), and independent system operators (ISOs). They are all similar in that they represent a grouping of transmission facilities owned by different electric utilities to achieve common objectives. Their missions, scope of responsibilities, and objectives, however, were different.

6. The intent of FERC's functional unbundling requirement, specified in Order 888 and discussed above, was to accomplish the same thing without the need for separate organizations.

7. Federal Energy Regulatory Commission, "Notice of Proposed Rulemaking , Regional Transmission Organization," RM99-2-000 (May 13, 1999).

8. North American Electric Reliability Council, "Reliability Assessment 1998-2007" (September 1998).

9. Secretary of Energy Advisory Board's (SEAB) Task Force on Electric System Reliability, "Maintaining Reliability in a Competitive U.S. Electric Industry" (September 29, 1998).

10. A definition of "market participant" was problematic, and FERC, after considering extensive comments, concluded that market participants is an entity whose economic or commercial interest is likely to be affected by an RTO's decision and actions. The Regulatory Text, Part 35, Chapter I, Title 18 CFR, 35.34(b2) contains a full definition of "market participant."

11. A detailed discussion of horizontal market power and its effects on competition can be found in a report prepared by the U.S. Department of Energy, Office of Economic, Electricity, and Natural Gas Analysis, "Horizontal Market Power in Restructured Electricity Markets," DOE/PO-0060 (Washington, DC, March 2000).

12. California ISO, Department of Market Analysis, "Report on California Energy Market Issues and Performance: May-June 2000" (August 2000).