Papers

Excerpt from the introduction:

The New York Independent System Operator (“NYISO”) asked Analysis Group to conduct a study that would measure the costs and benefits associated with various aspects of the restructuring of the wholesale power market in New York. Our economic study focuses on certain key changes in operational performance of the power system during the initial years following the start-up of the NYISO. NYISO began operation at the end of 1999, as part of the larger process to restructure the electric industry in New York State. At the wholesale level, restructuring included both changes in the institutions responsible for grid operation and in the dispatch and market rules implemented by the NYISO, as well as major changes in the ownership of generation assets. These combined changes – especially the new market rules that paid generators market clearing prices – created strong profit incentives for improving operational performance of power plants. We look at the effect of these changes. There were many other changes in the industry as well, not all of which are amenable to quantitative assessment. To assess these larger changes in the economic environment, we examine broad measurable changes in wholesale power market performance, although we do not suggest that we have examined all factors comprehensively. Our spotlight focuses on the effects of changes in power plant dispatch rules and practices, and in incentives for improvement performance of generating units.

The Commission identified the key role of RTOs in supporting competitive electricity markets. No matter what the name or governance structure, there must be an organization responsible for key coordination activities needed to make a market work. This is not an option, and the market cannot solve the problem of market design. Hence the most important part of the Commission's Millennium Order is the description of a workable framework for competitive electricity markets. A competitive electricity market can be the vehicle for pursuing the public interest, but only if the market structure addresses the particular characteristics of the electricity system with its complex mix of essential facilities and large network externalities. The central design requirement is easy access to a coordinated spot market. There are certain critical functions that must be provided by the system operator. When these functions are organized within the framework of a bid-based, securityconstrained economic dispatch with locational pricing, the tools are available to deal with the most important network complexities that otherwise confound electricity markets. Once done, many of the other problems in the electric network would either disappear or would be greatly simplified.

The Commission raised many important questions for consideration in this inquiry. Presumably the extensive and difficult issues cannot be disposed of within the constraints of a two day public conference, even accompanied by a few pages of comments. Hence, my approach is to emphasize the conference as neither the beginning nor the end of the conversation, but as a major milestone in the effort to move forward with the development of open access and competitive electricity markets. Relatively few of the Commission’s explicit or implied questions lend themselves to a single answer. Much has been learned in the development of open access and the design of new market institutions, and tradeoffs among various objectives are, to a degree, inevitable. However, the realities of the electricity system impose certain constraints and consistency requirements that serve to narrow the choices that the Commission can or should make.

Here I respond to the request for supplemental comments addressing the Commission’s questions about transmission pricing and other issues discussed at the two day session of April 15-16, 1998.

Hogan, William. Electricity Market Design and Structure: Avoiding the Separation Fallacy. Comments submitted to FERC, Docket No. RM01-12-000. 12 March 2002. 7 pages.

In April of 1996, the Federal Energy Regulatory Commission (FERC) adopted its initial rules to support competition in the wholesale electricity market. The FERC called for open access and non-discriminatory transmission services. Public utilities would be required to file tariffs which would allow others to have equal access to the transmission grid. In addition, the rule emphasized a standard embraced by FERC which would require all transmission owning utilities to provide all actual or potential transmission users with "comparable" service on the transmission grid. Subsequent to its initial notice of a proposed rulemaking, commonly known as the Mega-NOPR, the concept of creating an independent system operator (ISO) arose as an approach to providing non-discriminatory access to the transmission grid. In its order, the FERC included a discussion of the emerging initiatives to create independent system operators, but stopped short of making an ISO mandatory. However, the FERC advanced a set of principles which extended the discussion.4 Coupled with the growing number of proposals for an ISO, there is an increased interest in the associated governance issues.

The notion of an ISO offers an alternative that advances the FERC view of restructuring and could alleviate many of the difficult problems in providing open transmission access as part of the restructuring of the electricity market. There are significant advantages in this approach. There is wide recognition that there must be a system operator coordinating use of the transmission system. That this system operator should also be independent of the existing transmission owning utilities and other market participants is attractive in its simplicity in achieving equal treatment of all market entities. Hence, the easy-to-state but hard-to-enforce principle of comparability would be transformed into an easier to enforce principle of nondiscrimination. However, the precise goals, criteria and options for the ISO are not well understood or well posed. The tension is clear: the ISO should be independent but also responsive; stable but also flexible; limited but also substantial. The scope of responsibility, rules for operations and decisions on who should decide define an agenda of important details that are being examined or overlooked, decided explicitly or adopted implicitly in intense parallel conversations in different regions of the country. An investigation of the governance, scope and rules for the ISO presents an opportunity to unify seemingly independent conversations that are or should be about the same thing, namely how to deal with the special characteristics of electric networks in order to support a competitive electricity market.

The purpose of this background paper is to provide an overview of the basic governance discussion and illustrate the range of proposals that are under development in various regions and electricity markets.

Just before the April conversion to the use of locational marginal cost prices, the PJM system produced data that address two questions. Is transmission congestion insignificant? Are there only a few zones with meaningfully different prices?

Federal Energy Regulatory Commission. Order Granting Petition for Declaratory Order (SeTrans RTO). 10 October 2002. FERC Order, 45 pages.

Excerpt from the Executive Summary:

As part of electricity restructuring in the United States, there is broad interest in the concept of an independent transmission company (ITC) that would operate as a standalone, for-profit transmission business. The Federal Energy Regulatory Commission has encouraged ITCs by offering to consider incentive rate mechanisms in conjunction with Regional Transmission Organizations that meet the requirements of Order 2000. However, the appropriate role of an ITC within the RTO framework remains unsettled. Some proposals would have the transmission company (Transco) be the RTO and perform all of its functions, even market operations. Hybrid proposals would have the Transco control some of the RTO functions but delegate the activities associated with market operations to a third party. This paper describes a third model, a marketcompatible ITC that would neither be the RTO nor assume the RTO’s public interest functions.

The for-profit nature of a monopoly Transco and its claimed ability to make efficient tradeoffs across market operations, system control, grid management and investment give the Transco its initial appeal. On closer inspection, however, the implications of these tradeoffs for market participants and concerns about leaving the RTO’s public interest functions distorted by the Transco’s private interests create a need to ensure independence for both system and market operations, so that functions necessary for an efficient market are performed in an unbiased manner.

Fortunately, the concerns with the pure Transco model do not foreclose a viable approach with for-profit ITCs that operate in conjunction with a separate and independent RTO. An ITC could complement the RTO but not be the RTO. It would respond to the market’s price signals to pursue market-driven grid investments, but it would not run the RTO markets. This ITC would be compatible with the Eastern markets that use coordinated spot markets, locational marginal pricing (LMP) and financial transmission rights (FTRs). Separating an ITC’s ownership/investment functions from the independent RTO’s system/market operation functions would allow both to pursue their respective objectives, but with the ITC free to aggressively pursue its private interests without concerns about biasing the market. It would then be simpler to ensure independent RTO governance and a focus on the limited but essential tasks that the RTO must perform. Within this open architecture, multiple transmission owners, both private and public, traditional utility transmission owners and ITCs, could then be accommodated without requiring the RTO to be the monopoly grid owner.

Federal Energy Regulatory Commission. Declaratory Order on Regional Transmission Organization (WestConnect RTO). 10 October 2002. FERC Order, 77 pages.

For years, utilities, regulators, and economists have discussed the possibility of opening access to the electric transmission grid. It is now well past the time to cut the Gordian knot in impasse over the debate, and to raise the key strategic question of whether utility owned transmission facilities belong in the ratebase paid for by native-load ratepayers. The question is complex, but requires public discussion and debate as we move inexorably to more competitive bulk power markets. The issue is best approached from three different perspectives: 

• Who should bear the risk of residual revenue respon-
sibility for transmission assets?

• Are actual costs and uses reflected in the allocation of responsibilities for transmission revenues?

• How can transmission pricing be used to reduce the likelihood of anti-competitive behavior by those entities owning both generation and trasmission.