EU Energy Policy Blog

As power engineers and economists have known for a long-time, the transmission grid is essential to the operation of well-functioning electric power markets. Yet, grid expansion in several regions has been nil or slow. By reviewing the main prescriptions from academic literature and comparing them with case studies from over 16 jurisdictions we find that unless the governance structure is appropriate and specific incentives are provided, grid expansion proves elusive.

Electric transmission capacity appears to be lacking in most markets. In the United States, following the August 2003 blackout that affected most of the Eastern part of the country, the Department of Energy has launched several studies, including a National Electric Transmission Congestion Study, that found congestion problems in many of the fast-growing, economically active areas of the United States. Specifically, it identified two critical congestion areas (the Atlantic coastal area from metropolitan New York southward through Northern Virginia, and Southern California), and four congestion areas of concern: New England, the Phoenix – Tucson area, the Seattle – Portland area, and the San Francisco Bay area.

In Europe, the grid congestion appears to be primarily — but not only at the borders between countries. According to the Commission’s inquiry the interconnectors from Slovakia to Hungary, Germany to Denmark, the Netherlands to Belgium, and France to Switzerland were congested in all hours during the first five months of 2005. Anecdotal evidence also suggests within-country congestion, around Nice and in Brittany in France, and in Italy.

Before going further, it is critical to describe the reality of transmission constraints and grid expansion, and possibly dispel some misconceptions. Policy-makers sometime view a transmission constraint as a limit on the “size” of the wire, i.e., if one attempts to increase the flow on the line beyond the limit, it immediately melts down. Therefore relieving a transmission constraint means building a larger — or a new — wire, thus (1) investing a large sum (in the order of hundreds of millions of dollar), and (2) overcoming and/or accommodating significant environmental constraints.

This turns out to represent only a small fraction of transmission constraints and their relief procedures. In most systems, most constraints are created by operating practices, i.e., the applications of safe operating rules, in particular reliability rules: the capacity on one line is limited by the maximum flow that it could safely carry in a set of pre-specified contingencies, for example should another component of the system fail. For example, the High Voltage Direct Current (HVDC) line linking the province of Québec in Canada to Boston in the United States has a thermal rating of 2,000 MW (i.e., it will not start melting down until 2,000 MW flow through). However, it is usually operated at no more than 1,300 MW. The maximum admissible flow is limited by the capacity of a circuit East of Philadelphia, a few hundred miles south, to withstand the power flow that would result should then HVDC line fail.

The capacity of an existing transmission interface can be increased by changes in operating procedures and investment on the existing network, as well as development of new lines. For example, the main transmission constraint in the state of New York occurs at the Marcy substation, where cheap, clean electric power from Canada is restricted on its way to New York City. The solution does not involve building new lines, instead installing a sophisticated high-power switch in the substation yard (Fairley,2001). Similarly, following deregulation, a constraint developed at Ferrybridge B in England and Wales that cost hundreds of million of pounds annually. The solution was simply to add a mobile capacitor bank to temporarily relieve the constraint, while a more permanent (and still inexpensive) solution was found.

This clarification is critical, as it leads to a mindset shift: the objective for policy-makers is to design institutions that will develop and implement a wide variety of solutions, ranging from changes in operating procedures to targeted investments to some large scale investments, and not only large, capital-intensive investments.

Let’s now turn to the review of theoretical prescriptions and empirical evidence. The academic literature offers four strong prescriptions:

1. The transmission grid is essential to the functioning of power markets. Pre-restructuring of the power industry, the grid’s main role was to improve reliability and reduce the cost of meeting demand. Post-restructuring, the grid also serves to increase competition among generators.

2. Full vertical unbundling (by which we mean separation of the ownership and operations of transmission assets from generation and sales) facilitates optimal expansion of the grid. Since the configuration of the grid impacts profits of generators, an integrated electricity generator/transmitter face mixed incentives when contemplating an expansion of the transmission grid: he takes into account the impact of the expansion on its transmission and generations profits.

3. Regulatory contracts can be structured to induce an independent transmission company to expand the grid “optimally”. Various authors have proposed such regulatory contracts.

4. Merchant transmission (i.e., transmission projects financed by independent entrepreneurs and remunerated by their market value) does not provide for optimal grid expansion, mostly (but not solely) due misaligned incentives: a for-profit transmission developer selects the magnitude of the expansion to maximize the (ex post) value of the asset, which does not generally coincide with the socially desirable expansion).

Empirical evidence presented appears to confirm these prescriptions. In a recent paper we examine 16 jurisdictions having restructured their power industry in recent years. A jurisdiction can be a country (e.g., Norway, France, Italy, Argentina), a state/province (e.g., Texas, New York, California), or multiple states/provinces (e.g., England and Wales, New England, the Pennsylvania-New Jersey-Maryland Interconnection (PJM)). In a few instances, these jurisdictions have clear regulatory oversight, while in most cases, regulatory relationships are layered (e.g., multiple state Public Utilities Commissions and the Federal Energy Regulatory Commission (FERC) for PJM).

We first classify the institutional arrangements according to two dimensions that we find pertinent for grid expansion: (1) the degree of vertical unbundling, since this emerges a clear prescription from the literature, and (2) the strength of incentives for grid expansion. We then determine the extent and quality of grid expansion for each jurisdiction, as measured by a reduction in the cost of congestion. The results are presented on the figure below:

The empirical evidence collected in this study appears consistent with theoretical prescriptions: creation of an independent transmission company subject to strong grid expansion incentives lead to congestion alleviation (e.g., England and Wales).

On the other hand, the Independent System Operator (ISO) model pursued in the United States, where operation but not ownership of the grid is vertically unbundled, does not appear to have performed well. This is consistent with “theoretical” predictions: transmission asset owners in the ISO model face mixed incentives for expansion resulting from limited vertical unbundling of the assets. Perhaps less obviously, we observe that vertical unbundling alone does not appear sufficient to ensure congestion alleviation, but that targeted incentives must be provided.

Thomas-Olivier Léautier and Véronique Thelen, University of Toulouse

This entry was posted on Sunday, January 27th, 2008 at 10:14 pm and is filed under Electricity, English. You can follow any responses to this entry through the RSS 2.0 feed. You can leave a response, or trackback from your own site.