Putting U.S. "Market Power"
Tests Into Perspective

For an integrated utility in the power generation business, the issue of market power is critical. When utilities were regulated solely under cost-based (cost-of-service) rates, such concerns were moot, but this issue has become paramount as competitive wholesale markets have grown. In recent years, the U.S. Federal Energy Regulatory Commission (FERC) has struggled to find the best ways to determine whether a wholesale supply applicant (e.g., a utility or an independent power provider (IPP)) could benefit from its generation portfolio by influencing the wholesale price of power in the market—thus affecting customers—and if so, what to do about it. This determination is vital, since a FERC finding of market power would indicate that a utility would need to correct that situation by selling capacity; changing its wholesale, market-based rates (MBR) to cost-based rates; or undertaking other mitigation approaches.

PDF Version of Article   This article was published in the Spring/Summer 2005 issue of Perspectives. Please refer to our Terms of Use policy regarding acceptable use of content on the ICF International Web site.

Is it easy to determine whether wholesale market power exists? No. FERC has made several attempts to identify and mitigate the potential for generation market power since MBR was first introduced in 1989. For example, in November 2001, FERC replaced its “hub-and-spoke” method with the Supply Margin Analysis (SMA) after realizing the former method’s limitations. The SMA used a market share benchmark (which the previous test had not) of 20 percent or more in each relevant market. Also, the SMA took transmission constraints into account, allowing FERC to more precisely estimate the amount of generation that could compete with the utility and establishing a threshold to determine whether its supply was pivotal in the market.

However, the SMA had its shortcomings. It did not consider that generation dedicated to native load (end-use utility customers) and other wholesale commitments could not influence market prices, and it did not allow utilities to challenge FERC if they failed the market power test. Thus, in April 2004, FERC replaced the SMA with two interim, indicative screens. The screens are “interim” because FERC established a proceeding to conduct a comprehensive review of its test. Unlike the SMA, they are "indicative" because they give applicants a chance to rebut a market power finding.

For example, in the Uncommitted Pivotal Supplier (UPS) analysis, FERC considers native load and other firm contracts in calculating its uncommitted capacity at peak times. FERC replaced the SMA’s use of total transfer capability (TTC) with simultaneous import capability to better measure the effect of transmission limitations on generation imports. In the Uncommitted Market Share (UMS) analysis, FERC evaluates the applicant’s share of the seasonal uncommitted capacity. FERC believes that, taken together, these screens give a reasonable indication of whether an applicant may possess market power. Failure in either screen creates a “rebuttable presumption” of market power in generation. Several utilities (e.g., Entergy, Southern, and AEP) failed one or both of these tests. In its recent application to acquire PSEG, Exelon has acknowledged that it will fail these tests and has offered to sell power plants or sign contracts to sell the output of 5,500 megawatts of generation. This approach could be an important indicator of how FERC intends to apply its market power screens.

If the utility challenges the test findings of potential market power, it can submit more detailed data using a "delivered price test" (DPT) to illustrate that it has not exercised such influence in actual practice. The DPT incorporates capacity that can be delivered at a price less than or equal to 105 percent of the market price into the destination market, and is applied in two prongs—one looking at "economic capacity" (EC) and the other at "available economic capacity" (AEC). EC includes all capacity for suppliers who can compete in the market using the 105 percent threshold if simultaneous import capability is available, while AEC excludes the supplier’s native load and other firm commitments. If FERC remains unconvinced by the rebuttal, the commission may require utilities to adopt the mitigation procedures mentioned above. Figure 1 describes the overall process.

To date, more than 100 entities have made filings under the interim tests, a number of which have been accepted; some filings have triggered rate reviews (206 filings). To maintain MBR, utilities like Entergy will continue to walk the tightrope of allaying FERC’s concerns while satisfying native load obligations. The interim screens and the DPT are not perfect either—FERC may need to define the appropriate product and geographic markets (e.g., products may include capacity, spinning reserves, regulations, etc.).

Moreover, focusing on only annual, seasonal, or aggregate load can be misleading, since each hour represents a product market with a unique supply curve. Similarly, using the utility control area— or regional transmission organizations (RTO)—as the default geographic market may be inappropriate, and “commercially significant transmission constraints” could more accurately outline the relevant market. Many of these shortcomings could be addressed through the use of detailed market analysis, using state-of-the-art generation and transmission models.

Finally, FERC’s market power assessments include more than just generation—they also intend to include transmission tests, assessments of affiliate abuse, and barriers to entry. Recognizing these issues, FERC has recently opened a new docket (RM04-7-000) to consider how to mesh all four prongs of its market power evaluation. The results of this review will inevitably affect power companies for years to come.

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