RTOs – The Centerpiece of Electric Industry Restructuring by Chris Trayhorn, Publisher of mThink Blue Book, January 15, 2002 Electric industry restructuring and its consequences seized the headlines in 2001. When deregulation was first introduced to state and federal regulators in the early 1990s, few imagined that the road to restructuring would turn into such a roller coaster ride. Over the past year, blackouts in California and other states kicked off the summer, then appeared to subside. Electricity prices skyrocketed on the spot market. Market uncertainty continues as the economy slows. When the huge energy price spikes and blackouts that had been predicted for the hottest summer months failed to materialize and prices eased, the attempts to resolve transmission issues were still continuing. While at first electric industry restructuring appeared to be a way to offer lower rates to consumers and less regulation for generators and utilities, it has profited only some and bankrupted others. It has now become a political hot potato. Many entrepreneurs and investors, who were looking to profit from new generation construction are now on unsure footing. Independent power companies have witnessed their stock valuations and public images decline. At the center of these issues is the development of an organizational structure for transmission facilities. Transmission is the key element of the structural changes being developed. Yet, new transmission investment has been slowed by the uncertainty surrounding rates of return and investment capital recovery. Whether the for-profit model or the not -for-profit model works better is also uncertain. In this climate, the push to create four Regional Transmission Organizations (RTOs) nationwide is clearly the new direction at the changing Federal Energy Regulatory Commission. This overview chronicles recent milestones of electric industry restructuring related to Regional Transmission Organizations and relates them to the present trends in order to bring the reader up to date. Even more dramatic change is likely in the near future as the FERC is reconstituted under a new administration — the new chairman of the FERC is in place and we await the appointment of another commissioner by President Bush. Depending upon that selection, we may see policy revisions regarding the specific nuances of transmission structure. Will a consensus form about the new FERC directives to create four giant RTOs? As of this writing, the question remains unanswered. In the last years of the 20th Century, American corporations generally — and energy companies in particular — strove to improve efficiency by taking advantage of economies of scale. Service unbundling and deregulation initiatives spawned new market entrants, some of whom recombined in an effort to remain viable in a competitive environment. Some got it right, some failed and others are still searching for solutions. At the same time that traditional utilities became more comfortable thinking “outside the box,” consumers, regulators, and non-traditional service providers had to cope with the consequences of inconsistent pro-competitive policies. These consequences included how to regulate conduct among affiliates, ensure fair and reliable system management, determine consumer electric rates, minimize rate aberrations and maximize reliability in abnormal (and often unpredictable) situations, recognize environmental necessities, and whether and how to recover costs associated with inefficient assets in the newly restructured market. By 1999, it was apparent to both the regulators and the regulated that the newly emerging “system,” such as it was, had holes. Reliability was less secure than it should be. Letting the invisible hand of the markets determine the need for services and the prices to be charged for them was nice in theory, but there was not yet a solution to the problem of an imperfect market functioning imperfectly. The Evolution of the Solution The solution proffered by the FERC was Order No. 2000, which promoted the creation of geographically vast Regional Transmission Organizations while trying mightily not to recreate existing efforts to allow independent management and operation of the North American power grid. Order No. 2000 had its precursor in Order No. 888. Order No. 888-A and its electronic information sidekick, Order No. 889-A, were issued in March 1997. On June 30, 2000, the U.S. Court of Appeals for the D.C. Circuit affirmed Order Nos. 888 and 889 in all important respects (Transmission Access Policy Study Group, et al. v. FERC, No. 97-1715). On February 26, 2001, the U.S. Supreme Court granted certiorari to review the D.C. Circuit’s decision. Nine state commissions claimed that Order No. 888 exceeded the FERC’s jurisdiction under the Federal Power Act (FPA) by extending it to the transmission portion of unbundled retail electricity transactions. Enron Power Marketing contended that the commission should have extended the requirements of Order No. 888 to bundled retail transmission sales. The cases were consolidated for oral argument. (New York, et al. v. FERC, et al., No. 00-568; Enron Power Marketing Inc. v. FERC, No. 00-809). Certainly this appeal could greatly impact the FERC’s restructuring policies, as could numerous legislative initiatives currently in Congress. The Notice of Intent Following up on comments made in discussion of market activity in California and the Midwest during the summer of 1998, the FERC issued a Notice of Intent in November 1998 to consult with the states about establishing RTOs under §202(a) of the FPA. (Regional Transmission Organizations, Docket No. RM99-2-000, FERC Stats. & Regs. 35,534). Section 202(a) is part of the interconnection and coordination portion under the FPA, authorization for which was granted to the Federal Power Commission when the statute was enacted in 1935, transferred to the Secretary upon creation of the Department of Energy in 1977, and back to the FERC on October 1, 1998. Although its precise meaning has never been ruled on, §202(a) “empowers” and “directs” the commission “to divide the country into regional districts for the voluntary interconnection and coordination of facilities,” following notice to the commission of each state in which such district is located. The FERC’s consultative process with the states examined the following questions, among others: 1. What criteria and policy considerations should be used to establish the boundaries for effective RTOs? 2. What factors make it appropriate for a utility to belong in a specific region? 3. What is the appropriate role of the states in the formation and governance of RTOs? These important issues remain unresolved. The Notice of Proposed Rulemaking On May 13, 1999, the FERC issued a NOPR on RTOs that adopted the general principle that transmission should operate independently of generation on a regional basis (Regional Transmission Organizations, Docket No. RM99-2-000, 87 FERC 61,173). The NOPR did not propose to dictate the business form of the organization nor the boundaries within which RTOs could operate, and the FERC clearly wanted to accommodate existing ISOs and RTGs. The FERC also characterized its initiative as “voluntary” but believed that well-developed RTOs could alleviate a number of real and potential shortcomings in present markets. These benefits include improved grid reliability and market performance, more efficient grid management, removing opportunities for discriminatory transmission practices, and facilitating a lighter governmental regulatory role. The Final Rule on RTOs On December 20, 1999, the FERC issued a Final Rule on RTOs (Regional Transmission Organizations, Docket No. RM99-2-000, 89 FERC 61,285). Like the NOPR, the Final Rule took a “voluntary” approach to RTO participation, but the FERC made clear that this approach does not preclude taking action to require RTO participation as a remedy for undue discrimination or the exercise of market power. Order No. 2000 required all public utilities that own, operate or control interstate transmission facilities to file RTO proposals by October 15, 2000 or, alternatively, to describe any efforts made by the utility to participate in an RTO, the reasons for not participating, any obstacles to participation and any plans for further work toward participation. With minor exceptions, the utilities submitted their filings and many entities have made substantial progress to fulfill the FERC’s mandate. Order No. 2000 adopted a flexible approach to RTOs, permitting non-profit ISOs and for-profit transcos, combinations of the two, or other as yet undetermined approaches. It adopts the principle of open architecture, so that an RTO may evolve over time. However, all RTOs must embrace the four core characteristics and the eight key functions that are discussed below. The Order provided guidance on flexible rate-making options for RTOs that address congestion pricing and performance-based regulation and is the “Bible” of transmission philosophy today. Under Order No. 2000, all RTOs must possess the following four characteristics: Independence RTOs must be independent of market participants. A “market participant” is defined as any entity that, directly or through an affiliate, sells or brokers electricity or provides transmission or ancillary services to the RTO, unless the commission finds that the entity does not have economic or commercial interests that would affect the RTO. This definition, which is used as a starting point for establishing limits on ownership and standards for independent decision-making or governance, is narrower than the NOPR proposed because buyers of electricity are not automatically included (see §35.4(b)(2)). Order No. 2000-A revised the definition to remove specific references to entities that provide transmission service to an RTO. Order 2000 distinguished between “active” and “passive” ownership interests, depending on the ability to control RTO operations. For “active” owners, the de minimis “safe harbor” in the NOPR was increased to five percent; however, all active voting interests, with limited exceptions, must be terminated within five years. Passive ownership interests in RTOs can continue indefinitely if they can be shown to be truly passive. Order No. 2000 modified somewhat the proposed requirement that the RTO have the exclusive authority to file tariff changes under §205 of the FPA. While the RTO has the independent and exclusive right to make §205 filings that apply to the rates, terms and conditions of service over the facilities that it controls and operates, transmission owners retain certain §205 rights with respect to the level of revenue requirement that they receive from the RTO (and which the RTO will collect from transmission customers through the RTO’s rates). Thus, a transmission owner may have a tariff on file that affects the level of the RTO’s revenue requirement, but the transmission owner is not permitted to file tariff changes that will affect the RTO’s services to transmission customers. Scope and Regional Configuration RTOs must serve a region of sufficient scope and configuration to permit the RTO to maintain reliability, effectively perform its required functions and support efficient and non-discriminatory power markets. The commission did not attempt to draw RTO boundaries. If faced with multiple RTO proposals for a region, the FERC would have to determine which would best meet their objectives. In making a determination, the FERC would look to regional configuration factors, i.e., the RTO’s ability to make accurate, reliable ATC determinations; resolve loop flow issues; manage congestion; offer service at non-pancaked rates; improve operations (e.g., a single OASIS operator over an area of sufficient regional scope will better allocate scarcity, promote simplicity and one-stop shopping, and lower costs); and plan and coordinate transmission expansion. In evaluating boundaries, the FERC considered the extent to which the proposed boundaries facilitate performing essential RTO functions and achieving RTO goals; encompass a contiguous geographic area; encompass a highly interconnected portion of the grid; deter the exercise of market power; recognize existing trading patterns; take existing regional boundaries into account (e.g., NERC regions); encompass existing regional transmission entities; encompass existing control areas; and consider international boundaries. All or most of the transmission facilities in a region must be included in the RTO. Operational Authority The RTO must be the security coordinator for the region it serves. As such, the RTO has responsibility for performing load-flow and stability studies to anticipate, identify and address security problems; exchanging security information with local and regional entities; monitoring real-time operating characteristics such as reserve availability, power flows, interchange schedules, system frequency and generation adequacy; and directing actions to maintain reliability, including firm load-shedding. An RTO may contract out security coordinator responsibilities to an independent coordinator. The FERC allowed flexibility as to how operational authority is accomplished and did not require the RTO to operate a single control area for its region. Short-term Reliability The RTO must have exclusive authority to maintain short-term reliability of the grid it operates, including exclusive authority for receiving, confirming and implementing all interchange schedules and the right to order redispatch if necessary for reliable operation of transmission facilities. The phrase “short-term” is intended to cover transmission reliability responsibilities short of grid capacity enhancement and includes all time periods necessary for the RTO to satisfy its reliability responsibilities up to the planning horizon. An RTO that operates transmission facilities owned by others must have authority to approve all requests for scheduled outages but is not required to have authority over proposed generation maintenance schedules nor to establish facility ratings. All RTOs must also be prepared to perform the following eight functions: Tariff Administration and Design The RTO must be the sole provider of transmission service and sole administrator of its own open access tariff. It must have sole authority over the facilities it controls, to evaluate and approve or deny all requests for transmission service and to approve requests for new interconnections. Congestion Management The RTO must ensure the development and operation of congestion management mechanisms. Responsibility for operating these market mechanisms must reside either with the RTO or with an entity that is unaffiliated with any market participant. The RTO must have an effective congestion management protocol from “day one” of operations, but has one year to implement a market mechanism. Parallel Path Flows The RTO should implement procedures to address parallel path flow issues within its region and with other regions on the date of initial operation. It will have three years to implement measures to address parallel path flows between regions. Ancillary Services The RTO must serve as the provider of last resort of all required ancillary services, which must be included in the RTO-administered tariff. Since the RTO is not required to be a single control area operator, the FERC concluded that it cannot require an RTO that owns no generation to be a supplier of ancillary services, as the NOPR had proposed. An RTO can fulfill its ancillary services obligations through a variety of mechanisms, including contractual arrangements, indirect or direct control of specified generation facilities, or market mechanisms. Market participants must have the option of either self-supplying or acquiring ancillary services from third parties. The RTO must have authority to decide the minimum required amounts of each ancillary service and, if necessary, the locations where these services must be provided. All facilities that provide ancillary services must be subject to direct or indirect operational control by the RTO. The RTO must also ensure that customers have access to a real-time balancing market that is developed and operated either by the RTO or by another entity unaffiliated with any market participant. Even if the RTO is not a control area operator, the FERC expects it to have sufficient operational authority to ensure that a real-time balancing market can be implemented. OASIS Upon commencement of service, the RTO must be the single OASIS administrator for all transmission facilities under its control and must independently calculate total transmission capability and available transmission capability. The RTO has flexibility to contract out OASIS responsibilities to another independent entity if justified. The FERC recognizes that standardized communications protocols and business practices will be needed to promote trade across RTO boundaries. Market Monitoring The RTO must provide for objective market monitoring. However, the FERC recognizes that different market monitoring plans will be appropriate for different RTOs. Standards include a design that ensures there is objective information about the markets that the RTO operates or administers and a vehicle to propose appropriate action regarding any opportunities for efficiency improvement, market design flaws or abuses of market power. The monitoring plan must also evaluate the behavior of market participants to determine whether their behavior adversely affects the ability of the RTO to provide reliable, efficient, nondiscriminatory transmission service. It must also periodically assess whether behavior in other markets in the RTO’s region affect operations, as well as how RTO operations affect the efficiency of markets operated by others. Planning and Expansion The RTO must be responsible for planning and directing necessary transmission expansions and upgrades to provide efficient, reliable, nondiscriminatory service and to coordinate such efforts with the appropriate state authorities. Specifically, this function includes: market-based operations and investments for alleviating congestion, accommodating efforts by state regulatory commissions to create multi-state agreements that review and approve new transmission facilities and coordinate with existing RTG programs where necessary, and if the RTO is initially unable to satisfy this function, to file a plan with the FERC listing milestones that will ensure the RTO meets the overall planning and expansion requirements within three years of commencing initial operations. The RTO should have the ultimate planning and expansion responsibility so that investments will not work at cross-purposes which could adversely affect reliability. However, the emphasis in Order No. 2000 is a coordinated approach, and where feasible, the RTO should encourage market approaches to relieving congestion. Interregional Coordination Order No. 2000 adds the explicit requirement that RTOs must develop mechanisms to coordinate their activities with other regions (whether or not those regions have RTOs) and must explain how the RTO will ensure the integration of reliability and market interface practices among regions. In addition to the minimum functions and characteristics, the FERC required RTOs to have open architecture, so that they will be able to evolve over time and will be flexible enough to improve their organizations. Open architecture will permit RTOs to evolve in the following ways: it will allow basic changes in RTO organizational form to reflect changes in utility ownership and revised corporate structure; it will accommodate changes in the geographical scope of RTOs; it ensures that future developments to provide market support (e.g., formation of a power exchange) are not foreclosed; it accommodates operational needs; and it is necessary to accommodate technological changes and permit design modification to keep pace with technology. Order No. 2000 states that it is critical for RTOs to develop rate-making practices that eliminate regional rate pancaking, manage congestion, internalize parallel path flows, deal effectively and fairly with non-participating transmission-owning utilities, and provide incentives for transmission-owning utilities to efficiently operate and invest in their systems. In §35.34(e)(2), innovative transmission rate treatment is defined as any of the following: (1) a transmission rate moratorium, which may include proposals based on formerly bundled retail rates; (2) rates of return that consider risk premiums and account for demonstrated adjustments in risk, or do not vary with capital structure; (3) non-traditional depreciation schedules for new transmission investment; (4) transmission rates based on leveled recovery of capital costs; (5) transmission rates that combine incremental cost pricing for new transmission facilities with an embedded-cost access fee for existing transmission facilities; or (6) performance-based transmission rates, which may include such factors as (i) a method for calculating initial transmission rates (including price caps and any provisions for discounting, (ii) a mechanism for adjusting initial rates, which may be derived from or based on external factors or indices or a specific performance measure, (iii) time periods for determining initial rates, and (iv) costs to be excluded from performance-based rates. Order No. 2000-A The FERC issued its rehearing order on Order No. 2000 on February 25, 2000 (Regional Transmission Organizations, Docket No. RM99-2-001, 90 FERC 61,201). Order No. 2000-A reaffirmed the core elements of Order No. 2000 and clarified a number of issues, including concerns about the requirement that the RTO have exclusive and independent authority to propose rates, terms and conditions of transmission service over the facilities it operates. The order also amended the regulatory text in three respects: It revised the definition of market participant in §35.34(b)(2) to remove specific references to entities that provide transmission service to an RTO, added §35.34(j)(1)(iv) to codify the requirement for audits with respect to the independence characteristic, and revised §35.34(d)(4) to require RTO proposals to include an explanation of efforts made to include cooperatively owned entities in addition to public power entities. Transco and RTO Formation Efforts —The Freight Train of FERC Directives At its July 11, 2001 meeting, the FERC announced its preference for four large RTOs — one each for the Northeast, Southeast, Midwest and West. The large-area RTO approach is one that over the last several years was championed by Commissioner William Massey but appeared to have negligible support until action was taken on the PJM, New York and New England proposals by the FERC this summer. Since PJM appears to be more advanced than the others in satisfying the RTO characteristics and functions of Order No. 2000, the commission expects it to serve as a platform for development of a Northeast-wide RTO. At the same time, the commission expects that the best practices of each system will be incorporated into the new emerging organization. Commissioner Linda Breathitt viewed the directive to form four specific RTOs as a “dramatic departure” from the approach taken in Order No. 2000 and dissented on this issue in all of the RTO orders approved at the July 11 meeting. Separate orders initiated mediation on a 45-day schedule, under the direction of two administrative law judges. Participants in the PJM, PJM West, New York and New England RTOs were directed to participate in the Northeast discussions, and state commissions and Canadian entities were encouraged to do so (Regional Transmission Organizations, Docket No. RT01-99-000, 96 FERC 61,065). Parties to the Southwest Power Pool, Entergy, Southern and GridSouth RTO proceedings were directed to participate in the Southeast RTO discussions, and GridFlorida parties were invited to do so. State commissions and public entities such as the Tennessee Valley Authority and Santee Cooper were urged to be present (Regional Transmission Organizations, Docket No. RT01-100-000, 96 FERC 61,066). The judges issued their reports in late September and summarized them at the October 24, 2001 FERC meeting. Although both proceedings showed some progress on regional accommodations, both reports evidenced persistent difficulties with the large-scale approach that a four-RTO environment entails. These include the weighting of regional influences in the governance structure minimizing the cost-shifting effects of the switch to RTOs, development of the technical capabilities to replace multiple independent system operators with a single RTO, and how RTO proposals that have been “rejected” in favor of larger-scale operations (New York and New England are examples) can recover their substantial organizational and development costs. Other stumbling blocks included whether Congressional pressure could be used to delimit or require RTOs, and an argument before the Supreme Court over the FERC’s jurisdiction to mandate unbundling and the possible anticompetitive effects of large-scale transmission management. By late September, it was apparent that the December 15, 2001 RTO implementation date was overly optimistic. Instead, the new FERC chairman recommended the date should be used as the deadline for jurisdictional utilities to elect to join an approved RTO or have all market-based rate privileges of any corporate affiliate prospectively revoked, following an investigation under §206 of the FPA. It also appears that no mergers will be approved for entities that do not agree to become part of an operational RTO. However, since it appears that an RTO participant will be subjected to little market power analysis or none at all, whereas the analysis for non-participants will be significantly strengthened. So the choice whether to join an RTO may be limited. Since then, the commission has embarked on two parallel tracks to address issues concerning RTO structure, organization and operation. The first is directed toward getting RTOs operational. The Midwest, Northeast and Southeast RTOs were to be acted upon by November 2001. The chairman observed that it’s time for Desert Star and RTO West to “marry up.” However, keeping California operations separate from the rest of the western United States has support because of some of its restructuring problems. In Opinion No. 453, issued October 11, the FERC moved the Midwest ISO closer to RTO operational status by acting on rate-related issues that predate Order No. 2000, and praised the Midwest ISO for its substantial progress. The second track encompasses substantive operational issues and is intended to give clearer guidance about how the functions and characteristics requirements of Order No. 2000 are to be satisfied. To this end, the FERC held a series of RTO workshops during the week of October 15, focusing on core issues such as congestion management, cost recovery, market monitoring, transmission planning, business and reliability standards, and the nature of transmission rights. State regulators and other experts were encouraged to participate. A rulemaking under §206 of the FPA on market design and structure was expected to follow. Chairman Wood leans strongly toward market design standardization, while Commissioner Massey favors treating new market design rules as a rebuttable presumption that may be superceded by something that provides even greater flexibility for market participants. The answers will emerge throughout 2002 as RTOs take shape. Filed under: White Papers Tagged under: Utilities About the Author Chris Trayhorn, Publisher of mThink Blue Book Chris Trayhorn is the Chairman of the Performance Marketing Industry Blue Ribbon Panel and the CEO of mThink.com, a leading online and content marketing agency. He has founded four successful marketing companies in London and San Francisco in the last 15 years, and is currently the founder and publisher of Revenue+Performance magazine, the magazine of the performance marketing industry since 2002.