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H.R. 3406, The Electric Supply and Transmission Act of 2001
Subcommittee on Energy and Air Quality
The Honorable Patrick Wood
Summary of Testimony The electric utility industry continues to move toward the goal endorsed in the 1992 Energy Policy Act of a competitive wholesale electricity market. However, the uncertainty of the lengthy transition is harming infrastructure investment and reliability and raising Americans' electricity bills unnecessarily. It is time to finish the job. Successful completion of the transition requires a balancing of short-term and long-term considerations. In the short-term, we must ensure that the transmission grid is operated more efficiently and fairly, and is expanded when appropriate. Regional transmission organizations (RTOs) are the key here, and the Commission is aggressively encouraging formation of large, well-structured RTOs. To help, Congress should allow the Commission to require RTOs where it finds RTOs to be in the public interest. We also must eliminate unnecessary barriers and delays to the entry of new generation. The Commission is working to standardize procedures and agreements for interconnecting new generation, to help new players and technologies get on-line faster. We must facilitate the development of more market-based demand reduction programs. FERC and the state commissions have taken steps to foster such programs, and must work together to elicit the full potential of demand reduction efficiencies. And we must take steps to ensure that the type of market problems experienced in California do not recur there or elsewhere. The Commission is working with industry participants to design balanced, effective market rules that treat all market players fairly and provide clarity and certainty across all wholesale electric markets. Next year we will begin a generic proceeding to identify the best tools for identifying generation market power and, in the meantime, we have already improved our analytical method for determining whether a generator may have market power. Taking these steps will give investors the certainty they need to make long-term commitments to new electrical infrastructure, ultimately allowing us to achieve the kind of competitive wholesale markets envisioned by the 1992 Energy Policy Act. And the infrastructure choices will be dictated by the market, not by government. While the Commission is moving ahead aggressively, additional legislation will help us achieve Congress' goal of effective wholesale competition faster. Thus, I support the Commission-related provisions of Chairman Barton's proposed legislation, but with certain modifications discussed below. Testimony I. Introduction Mr. Chairman and Members of the Subcommittee: Good afternoon. Thank you for the opportunity to speak today on the Chairman's proposed legislation, H.R. 3406, to restructure the electric utility industry to full, effective wholesale competition. This industry has changed substantially in the years since Congress enacted the Energy Policy Act of 1992, moving closer to the Congressional goal of a competitive wholesale electricity market. However, the transition is not complete. Infrastructure investment suffers from the uncertainty of this long transition. Reliability is being tested and customers are being deprived of the financial savings and other benefits of a competitive marketplace. It is time to finish the job. Today, I will describe briefly the significant actions taken by the Commission in recent months to do just that, and the efforts planned by the Commission in the future. I will identify those areas in which legislation could facilitate the Commission's efforts. Finally, I will discuss other significant aspects of the Chairman's proposed legislation and suggest certain modifications to the legislation. My key point today is that successful completion of the industry's transition requires a balancing of short-term and long-term considerations. In the short term, we must take steps to ensure that the transmission grid is operated more efficiently and fairly, and is expanded when appropriate. We must eliminate unnecessary barriers to entry of new generation, big or small. We must facilitate the development of more market-based demand reduction programs. And we must take steps to ensure that the type of market problems experienced in California do not recur there or elsewhere by establishing clear, fair, balanced market rules. Taking these steps in the short term will give investors the certainty they need to make long-term commitments to new electrical infrastructure. Over the long term, this commitment to sound infrastructure and sound market rules ultimately will allow us to achieve the kind of competitive wholesale markets envisioned by the Energy Policy Act - with choices dictated by the market, not by government. Some argue that the short-term steps envisioned by the Commission will chill infrastructure investments, not encourage them. I disagree. People will not invest in generation where they believe transmission owners will operate the grid unfairly, delay interconnections of new generation or fail to expand the grid as needed. Similarly, markets characterized by a pattern of extreme price turmoil and the risk of further governmental restrictions will not provide the certainty needed by investors. The short-term steps described below will encourage the future stability of the markets, reduce or eliminate the risk of crisis-driven governmental interventions and, thus, give investors the confidence to commit billions of dollars to building the infrastructure our nation needs. II. Regional Transmission Organizations (RTOs) Electric power markets are regional in nature. For that reason, the Commission has been promoting the formation and development of a small number of RTOs. These institutions, once formed, will assure reliable minute-by-minute grid operations, optimize fair use of the "electric highway" by all users, plan for the future transmission needs of the region and help long-term supply stay ahead of long-term demand. Two years ago, the Commission decided to move forward with RTO formation on a voluntary basis. Although that has been a more tortuous path than originally intended, it is drawing to a close with utilities in all regions of the country coalescing around organizations of appropriate scope, governance and configuration. But if any party challenges this progress in courts, then Congress should make clear its intent that these organizations are its preference. This will save the industry years in the courts, ensure customers get the billions of dollars of savings that a competitive power market can deliver during that time, and most importantly, rebuild to secure and reliable levels a bedrock industry that has suffered inadequate investment in the past decade. Recently, the Commission clarified its policies and plans on RTOs. In an order issued last month, the Commission indicated that it intends to complete the RTO effort on two parallel tracks. The first track will be to resolve issues on scope and governance in pending cases; the second track will be a rulemaking to standardize the market design for public utilities, to be implemented by RTOs. The Commission has also begun forming state-federal regional panels as a structured forum for constructive dialogue with state commissions on RTO development. We hope to expand these panels in the future to discuss other joint concerns. The Commission is updating cost-benefit studies on RTOs (with input on the analysis from a diverse panel of state commissioners) and will establish in future orders the timelines for continuing RTO progress in each region. We expect to address the RTO structure in the large Midwestern region of the country at our December meeting. In establishing the characteristics and functions of RTOs and the procedures for obtaining Commission approval of an RTO, the Commission relies on sections 205 and 206 of the Federal Power Act. These sections are the Commission's fundamental authority for ensuring that the rates, terms and conditions of transmission in interstate commerce by public utilities are just, reasonable and not unduly discriminatory or preferential. In addition, the Commission has relied on its authority under section 203 of the Federal Power Act to review proposed transfers of operational control over jurisdictional transmission facilities. While some may question the Commission's as-yet-unexercised authority to require the formation of RTOs, there is no legitimate debate about the Commission's authority to oversee voluntarily-formed RTOs. I strongly support the formation of RTOs. RTOs will provide significant benefits to electric utility customers across our Nation. I believe the best legislative approach at this time would be for Congress to adopt a provision permitting the Commission to require RTOs where it finds such RTOs to be in the public interest. This simple step would avoid problems that could arise if Congress codifies extensive and cumbersome procedures for formation of RTOs and detailed standards for those RTOs; it also would allow the Commission to adapt the RTO procedures and standards appropriately over time, as circumstances change. Section 202 of the Chairman's proposed legislation would codify more prescriptive procedures. Section 202 would require all "transmitting utilities" (a term that includes both investor-owned utilities and public power/electric power cooperative utilities) to participate in an RTO. A utility not in a Commission-approved RTO upon enactment of the bill must submit an application to form or join an RTO. If the Commission finds the application does not meet the standards specified in the bill, the Commission, in consultation with affected State authorities, must propose modifications. The Commission cannot mandate formation of, or participation in, an RTO except under these provisions. If an applicant asks, the Commission must hold an evidentiary hearing on the proposed modifications. Subsequently, the utility has a right to seek appellate review, during which time the Commission's order is stayed. If the court finds the Commission's decision is supported by a preponderance of the evidence, the court must uphold the Commission's decision. Otherwise, the Commission must order the utility to participate in its proposed RTO without modification. If Congress decides to proceed with the more elaborate process laid out in Section 202, I have specific concerns about aspects of the provision. First, I do not support giving a single RTO applicant the unilateral right to require an "evidentiary" (trial-type) hearing instead of "paper" hearings. While evidentiary hearings may be appropriate in certain cases, most cases can be fairly resolved much more quickly based on paper submissions and non-trial type procedures. Further, because the provision requires a "stay" of a Commission RTO order pending court review, and a Commission order likely would address one application filed on behalf of all the participants in the region, this provision could allow a single applicant to stall the creation of an RTO and an effective wholesale market for many years, raising costs for other applicants and all regional electricity consumers. Formation of workable wholesale markets will be more likely and swift without these provisions. Second, I do not support the requirement for a "preponderance" of the evidence instead of "substantial" evidence supporting the Commission's decisions. The "substantial evidence" test has been the basis for court review under the Federal Power Act since 1935, and I see no reason why a different standard is now needed for this one category of cases. Third, I see no reason for the provision resembling "baseball-type" arbitration, under which the Commission either must prevail in court or accept without modification the utility's proposal. Judicial review of Commission decisions sometimes yields a remand to the Commission for a fuller explanation or more fact-finding, and I see no reason to preclude that option here. In general, having RTO formation dependent upon only transmission-owning applicants, rather than all wholesale market players, leads to a less balanced and robust marketplace. A successful wholesale market model must have strong stakeholder participation and oversight at its core. Section 202 also specifies the standards for RTOs. These standards are drawn partly from the Commission's Order No. 2000. While it might be appropriate to codify some general standards (such as the basic independence requirement), other standards and the details of implemention are not appropriate to legislate. As market circumstances and structures change, and as the Commission gains experience with market behavior, the Commission needs the flexibility to adapt its rules over time to ensure that markets remain robust and customers' interests are safeguarded; a rigid, legislative codification of standards could preclude this flexibility. If Congress does codify such standards, certain elements of section 202's standards raise other concerns. For example, the bill requires a proposed RTO to have "sufficient generation within the RTO's boundaries to serve the load within such boundaries." While I agree that this is desirable, exceptions may be appropriate in certain circumstances, and section 202 should allow exceptions deemed appropriate by the Commission. The bill allows each public utility in an RTO to file "original or amended rates concerning transmission service on such utility's facilities." This is contrary to the Commission's requirement in Order No. 2000 that the RTO have the exclusive right to make rate filings related to the rates, terms and conditions of transmission services it provides to transmission customers in the region. While the Commission found that transmission owners have the right to file to recover from the RTO their own revenue requirements, it also found that it would be contrary to the basic RTO independence requirement if transmission owners could control the RTO's rate filings. I note that section 3 of the bill would define a "market participant" as "any entity that generates, sells, or aggregates electric power (other than State-ordered transition or default service) that is transmitted on the transmission system operated by a regional transmission organization." As above, I do not believe Congress should legislate a definition of "market participant," since such a definition may need to be changed over time as we gain experience with market behavior and new types of market institutions and activities (for instance, it excludes energy service companies that could aggregate demand and "negawatts" and offer price-responsive demand opportunities in wholesale and retail electric markets). Further, with respect to the specific definition in section 3, I disagree with the provision on State-ordered transition or default service. This provision appears to assume that, unlike other market participants, utilities providing such services are economically indifferent to the grid's operation because their profits or growth potential will not depend on the cost of their power supplies. Depending on the terms under which they provide this service, however, utilities may have the same economic incentive as other market participants to benefit from grid operations that provide them preferential access to low cost supplies. If Congress does legislate a definition, a better approach to defining "market participant" is the definition adopted by the Commission in Order No. 2000, which includes:
18 CFR 35.34 (b)(2) (2001). This approach is more flexible than the bill's assumption that providers of State-ordered transition or default service always lack economic or commercial interests that would be significantly affected by the RTO's actions or decisions. Finally, three other provisions raise concerns. First, the legislation would require the Commission to accept a cost/benefit analysis submitted by an applicant to support its proposed scope and configuration, unless the Commission finds the scope and configuration does not meet the statutory requirements by a preponderance of the evidence. Cost-benefit analyses are easily susceptible to manipulation of assumptions and data to achieve a desired result, so any analysis should be tested and verified rather than automatically accepted. Second, the standard for the Commission's findings should be "substantial evidence," not a preponderance. Third, the legislation would preclude the Commission from requiring any change to the governance or scope of an RTO finally approved without condition before the law's enactment. This provision would prevent the Commission from responding to changed circumstances warranting modifications in the RTO's governance or scope. III. Interconnections The current lack of standardized interconnection agreements and procedures means that every new generator can be forced to expend time and money negotiating the terms and conditions of an interconnection arrangement, before it can have any certainty about its ability to deliver power to the grid. This uncertainty is a significant barrier to entry for new generation. To remedy this problem, on October 25, 2001, the Commission issued an Advance Notice of Proposed Rulemaking (ANOPR) requesting comments on a standardized generator interconnection agreement and procedures. The ANOPR strongly encouraged interested parties to pursue consensus on the issues and presented a model that was used successfully in Texas as a strawman to facilitate the process. Parties must file this Friday a document describing the consensus views and any remaining disagreements; any additional comments are due by December 21, 2001. I understand that industry is reaching consensus on many issues in the ANOPR process but that they may request a brief extension of time to complete their negotiations. I assure you that I will be receptive to a brief extension if it is evident that progress is being acheived toward a consensual resolution of these issues. The Commission expects to use the outcome of the ANOPR as the starting point for a rulemaking to standardize interconnection protocols. This rulemaking will clarify and simplify the procedures for interconnecting new generation, thus promoting competition and benefitting customers. The Commission has held that interconnection is a component of transmission service. Thus, the Commission's authority to standardize interconnection protocols derives from sections 205 and 206 of the Federal Power Act, under which the Commission oversees the rates, terms and conditions of jurisdictional transmission service. Section 101 of the Chairman's proposed legislation establishes requirements for interconnections with distribution or transmission facilities. Section 101 addresses the generator's right to interconnect and its duty to pay interconnection costs, the availability of backup power and the rates, terms and conditions for such power. The Commission is required to promulgate the technical standards for interconnections. The Commission is also required to establish the process and procedures for interconnection with transmission facilities. A transmitting utility or regional transmission organization is exempted from the Commission-established process and procedures upon showing that "substantially comparable interconnection procedures and agreements have previously been filed with and approved by the Commission for interconnection with that entity." But this exemption provision would nullify the benefits of standardization by forcing the Commission and utilities to litigate over which "substantially comparable" non-standard provisions are acceptable and exempt from the standard, and keep non-standard agreements in place for years. As stated above, standardization of rules and procedures for interconnecting all new generation and expansions of existing generation is a good policy, both for traditional power plants and for small-scale distributed generation. This is a high priority goal for the Commission. Standardization will help minimize the costs and barriers to entry for new and expanded generation, which is critical to a robust competitive marketplace and the realization of lower electricity costs for end users. As written, Section 101 may be overly prescriptive and impede the Commission's ability to adapt its approach as the industry changes over time. A more general approach may be preferable. If the current approach is retained, I suggest another change in Section 101, pertaining to the right to backup power for generators interconnecting with distribution facilities unless the local distribution utility allows open access to its facilities. In this context, open access is defined as access "that is not unduly discriminatory or preferential." However, the Commission found in establishing wholesale open access to public utilities' transmission facilities that the lack of a published tariff of rates, terms and conditions was a significant obstacle to service. The Commission required public utilities to provide open access transmission service by tariff. Accordingly, I believe a local distribution utility must offer open access service by tariff before it can be relieved of its duty to provide backup power. IV. Test for Generation Market Power Since beginning to grant market-based rates (rate deregulation) to public utilities in the 1980s, the Commission primarily focused on the applicant and employed a "hub-and-spoke" analysis to determine whether an individual entity and its affiliates have generation market power. In a hub-and-spoke analysis the applicant computes its market share of generation in a particular market. While the Commission did not use a "bright line" test, it looked to a benchmark for generation market power of whether a seller had a market share of 20 percent or less in each market. In public deliberations shortly after I joined the Commission this summer, which were informed in part by our experiences in California, my colleagues and I questioned the usefulness of the hub-and-spoke test as a tool to identify the potential for the exercise of harmful market power. After reviewing the issue over the summer, the Commission instructed our staff at an Open Meeting on September 26th to refine the hub-and-spoke test on an interim basis for future applications and for current certificate holders' three-year updates, while contemplating a rulemaking to address the issue on a more permanent basis. The revised test, the Supply Margin Assessment (SMA), improves upon the hub-and-spoke in two critical ways. First, unlike the hub-and-spoke, the SMA excludes from the analysis of the relevant market those sellers who are physically precluded from participating in that market by transmission constraints. Second, instead of deriving an overall market share, the SMA determines whether any part of a seller's capacity is "pivotal," i.e., must be used to meet the market's peak demand. For example, if peak demand in a market is 100 megawatts, total capacity in the market (including the applicant's) is 120 megawatts and the applicant owns 60 of the 120 megawatts, the seller's capacity is pivotal because at least 40 megawatts of the seller's capacity is needed to meet peak demand. By contrast, a seller with only 15 megawatts would not be pivotal because peak demand in the market could be met fully by other suppliers. A company that fails the SMA screen is subject to mitigation to ensure that the company does not exercise market power by withholding its capacity from the market. Under this mitigation, the company must offer for sale, a day in advance, any short-term capacity which is not already committed for sale or use by the company. The price for any such sales is based on a "split-the-savings" approach which divides the economic benefits of the transaction equally between the seller and buyer. This test is administratively preferable to the more intensive cost-of-service based calculation traditionally used, for example, to set retail rates in regulated states. The company must also post offers to sell long-term energy products (in addition to the daily products noted above). This mitigation is carefully tailored to apply only to the extent necessary. For example, mitigation applies only in the specific market where the utility has market power, and the utility (and its affiliates) are still allowed to sell at market-based rates in any areas where they do not possess market power. The mitigation applies only to capacity that is not committed a day in advance ("spot" sales), and does not affect a utility's authorization to sell its capacity under long-term contracts. Finally, the SMA does not apply to sales in an RTO or an Independent System Operator (ISO) with Commission-approved market monitoring and mitigation. The Commission soon will initiate a generic proceeding to consider long-term changes to its analysis for generation market power. In the meantime, the SMA and its carefully-crafted mitigation are a substantial improvement on the prior approach, while continuing to allow sellers to compete freely in markets where they lack generation market power. I would note that the interim SMA market power screen is subject to rehearing, and the Commission will consider carefully any requests for rehearing. Apart from these efforts, the Commission recently proposed a new condition on its authorization of market-based rates for electricity producers. Under this proposal, a seller would be subject to refunds or other appropriate remedies if it engages in anti-competitive behavior or exercises market power. This condition would be triggered only when the seller engages in inappropriate conduct, not when market problems are caused by poor market rules or other generic dysfunctions. The Commission adopted a similar condition to help address the market problems in California and the Western United States, and is now proposing to extend the condition to public utilities elsewhere. The Commission is receiving public comments on this proposal and will fully consider the comments before making a final decision. V. Reliability Section 301 of the Chairman's proposed legislation provides for Commission certification of an electric reliability organization (ERO) to develop and enforce reliability standards applicable to all users, owners and operators of the bulk power system. The bill specifies the criteria for the ERO. The ERO would be required to file its proposed reliability standards with the Commission, and the Commission would need to act on those proposals within specified time periods. The ERO and the Commission would have to rebuttably presume that a proposal from a regional entity for a reliability standard applicable on an interconnection-wide basis is just, reasonable, not unduly discriminatory or preferential and in the public interest. The ERO would have authority to enforce its standards, subject to Commission review. Section 301's approach to reliability is a step in the right direction. Although I have not seen problems with the current voluntary process, parties inform me that federal legislation is needed to ensure the enforceability of the reliability standards. While some technical clarifications or modifications to the proposed language might be useful, as a general matter section 301 takes a reasonable and efficient approach to this problem. VI. Transmission Jurisdiction A. Open Access "Separate but equal" transmission is inherently unequal. Transmission of electric power is interstate commerce and should be fairly recognized as such. And all users of transmission service should be treated equally, provided they pay for it. One need look no further than Chairman Barton's home state to observe the positive impact that having clear rules from a single regulator has had on needed investment and expansion of the grid. Section 201 of the Chairman's proposed legislation would allow the Commission to require all public utilities and transmitting utilities to offer open access transmission services. In recent years, open access transmission services by public utilities have increased competition in wholesale power markets significantly. Extending this requirement to the large portion of the grid owned or operated by transmitting utilities that are not public utilities will further increase competition. I believe this can be done in a manner that respects the historic independence of certain public power utilities while ensuring that a consistent approach is applied to all users of the interstate grid, to further wholesale electric competition and benefit all electricity customers. I support Section 201 but suggest minor changes. First, for reasons explained above, section 201 should be clarified to provide that the Commission can require open access transmission services by tariff, and can require such tariffs to be on file with the Commission so that potential transmission customers have available for public inspection, in a centralized place (the Commission), all open access services being offered and the rates, terms and conditions of such services. Second, section 201 would require the Commission to ensure that the rates charged for open access services by a transmitting utility other than a public utility are comparable to the rates the utility charges itself. The Commission would be given authority to review and remand the rates for revision where necessary, but would not have the authority to modify the rates directly. The Commission could be given the authority to modify the rates where necessary, to prevent any delay in the establishment of rates in compliance with section 201. B. Stranded Costs Section 201 also would require the Commission to authorize recovery of wholesale stranded costs caused by a "municipalization," and specifies precisely how the Commission should determine the "reasonable expectation period" for purposes of calculating the stranded costs. I am concerned about the latter provision, and believe that the calculation of stranded costs should be left to the Commission's discretion based on all relevant circumstances in a particular case. The Federal Power Act does not prescribe how to calculate stranded costs except in requiring that rates must be just, reasonable and not unduly discriminatory or preferential. This statutory approach should not be changed. C. Transmission Siting Section 402 would allow the Commission to authorize construction or modification of transmission facilities if it makes each of three findings: (1) the relevant State lacks authority to approve the action, has withheld or delayed approval for more than a year or has conditioned its approval such that the action is economically infeasible; (2) the facilities being authorized will be used for transmission of electric energy in interstate commerce; and (3) the action is consistent with the public interest, as proposed or conditioned. A FERC backstop such as this may well be the best decision, but there are others that could work. Since these siting issues are largely regional, the RTO could be the backstop instead of FERC. This keeps the relevant determinations of need, environmental issues and landowner concerns closer to the affected citizens. Or, it may be enough to simply require states to make final decisions (pro or con) within a fixed time-frame. Some states specifically require that a transmission line approval by that state be shown to provide direct benefits to the citizens of that state. This sort of provision may make it difficult for a state to approve routing of a line that has significant regional benefits but not specific local benefits. VII. Other Issues A. Investigations, Refunds and Penalties Section 702 of the proposed bill expands section 206 of the Federal Power Act to allow the Commission to order refunds not only by public utilities but also by other entities that provide transmission service or power to a public utility. Section 703 expands the criminal penalties authorized under section 316 of the Federal Power Act. Section 703 also broadens section 316A of the Federal Power Act so that civil penalties are authorized for violations of any provision under Part II of the Federal Power Act, instead of only sections 211, 212, 213 or 214. These provisions are helpful changes to the Federal Power Act. The recent problems in wholesale markets in California and the Western United States demonstrated the need for such changes. B. PUHCA Sections 111-125 of the Chairman's proposed legislation repeal the Public Utility Holding Company Act of 1935 (PUHCA) and replace it with increased access by the Commission and state regulators to certain books and records. This is appropriate. PUHCA was enacted primarily to undo harms caused by certain holding company structures that no longer exist. In the 65 years since PUHCA was enacted, utility regulation has increased substantially under the Federal Power Act (including oversight of corporate restructurings such as electric utility mergers, discussed below), federal securities laws and state laws, all of which ensure that customers are fully protected. C. PURPA Sections 131-134 of the Chairman's proposed legislation repeal prospectively the mandatory purchase obligation in the Public Utility Regulatory Policies Act of 1978 (PURPA). As indicated in the bill's proposed findings, PURPA's "forced sale" requirement is no longer necessary to promote competition, in light of the availability of open access transmission, and more often serves to distort competitive outcomes. Thus, I agree that Congress should repeal PURPA but "grandfather" existing PURPA contracts. To provide a smoother transition for parties which made investments under the expectations created by PURPA, it may be appropriate to limit its repeal to those states where all generation entities have the ability to sell their output to the widest possible range of customers. D. Mergers Section 141 would repeal section 203 of the Federal Power Act, the authority under which the Commission reviews proposed mergers and other dispositions of public utility facilities. This provision may not be in the public interest. The Commission deals with the electric utility industry on a daily basis and much more closely than the federal antitrust agencies. Thus, the Commission is better able to identify and remedy any harmful effects of mergers and other dispositions. Our efforts do not duplicate those actually being performed today by other merger reviewing agencies. The Commission has used its section 203 authority as intended by Congress to ensure that mergers and other dispositions are consistent with the public interest. Also, in recent years, the Commission has acted quickly on merger applications, almost always within 90 days after receiving public comments on a proposed merger. In addition, it may be a good idea to clarify the Commission's authority to review mergers involving only generation facilities and mergers of holding companies with electric utility subsidiaries. The increasing amount of competition in power generation markets makes this more than an academic question. But, to be fair, there are other, less blunt tools that the Commission has to address generation market power. VIII. Conclusion The electric utility industry has come far since the enactment of the 1992 Energy Policy Act. The Commission is moving ahead aggressively to achieve that legislation's vision of fully competitive wholesale markets. Additional legislation will help us get there faster. I support the Commission-related provisions of Chairman Barton's proposed legislation, with the modifications described above. This legislation will help all electric customers realize greater benefits from wholesale competition.
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