Market-Power Tests: A review of FERC’s market-based rate (MBR) screens, from theory to application.
John R. Morris is a principal and leads the energy practice at Economists Inc., an economic consulting firm in Washington, D.C. He formerly worked in the Bureau of Economics of the Federal Trade Commission. Contact him at email@example.com.
On April 14, 2004, the Federal Energy Regulatory Commission (FERC) adopted new “interim” market-power screens for electric utility application and maintenance of authority to sell electric power at market-based rates (MBR).1 Since then, FERC has heard and ruled on requests for rehearing, provided a schedule for utilities to file updated market-power studies, and ruled on many applications. It is, therefore, now appropriate to examine the screens in light of FERC’s actual application.
FERC ordered two new screens: Pivotal Supplier Analysis (PSA) and Wholesale Market Share Analysis (WMSA). In the PSA, the commission examines whether the generation owned by the applicant is necessary to serve wholesale demand within a control area. The commission first calculates the total generation capacity for an area. This is the total of generation in the control area plus the potential imports.2
From this total, the commission subtracts out a native-load obligation proxy, firm contractual commitments, and operating reserves.3 The result gives the uncommitted capacity. Net uncommitted capacity is calculated by subtracting a wholesale load proxy from uncommitted capacity. Net uncommitted capacity is compared with the applicant’s uncommitted capacity within the area. When the applicant’s uncommitted capacity is less than net uncommitted capacity, then all wholesale demand could be served without energy from the applicant, and the applicant passes the PSA screen. When the applicant’s uncommitted capacity is greater than the net uncommitted capacity, then the applicant fails the PSA screen.
In the WMSA, the commission examines whether the generation owned by the applicant is 20 percent or more of the uncommitted capacity in each of the four seasons. The commission first calculates the total generation capacity for an area, as in the PSA. From this total, the commission subtracts out planned outages and deratings, a native-load obligation proxy, firm contractual commitments, and operating reserves.4 FERC then calculates the applicant’s share by dividing the applicant’s uncommitted capacity by the total uncommitted capacity. When the applicant’s share is less than 20 percent, the applicant passes the WMSA screen. When the applicant’s share of uncommitted capacity is 20 percent or more, then the applicant fails the WMSA screen.
FERC presumes that an applicant does not have market power when it passes both the PSA and WMSA screens. Whenever applicants have failed either of the screens, the commission has ordered a refund proceeding to decide if the applicant must sell at cost-based rates. FERC has not yet articulated what would overcome the market-power presumption.
In some respects the new screens are an improvement over FERC’s previous screen, the Supply Margin Assessment, or SMA. The SMA was similar to the PSA, but it did not account for retail-load obligations. The flaw was that it did not account for the native-load commitments to produce electric power. For an analysis of wholesale markets, it is irrelevant that a utility’s generation is necessary to serve the total load in an area when the utility already has committed to supply a substantial share of the retail loads. Quite simply, the SMA totally was indefensible in court, and FERC never issued an order where it presumed that a utility had market power because the utility failed the SMA screen. Instead, FERC accepted filings that passed the SMA screen and waited more than two years to issue its April 14, 2004, order describing its new interim screens.
The PSA avoids the flaw of the SMA by subtracting a native load proxy from the applicant’s capacity and by comparing uncommitted capacity to the wholesale-load proxy. Instead of being a screen in which most vertically integrated investor-owned utilities fail, most applicants pass the screen. The reason is that most utilities are not necessary to serve the wholesale loads (other than the applicant’s) in a control area. Either other generation sources within the control area, imports, or a combination are sufficient to meet the wholesale demand available for competition.
Two other changes constitute improvements over the SMA. One is the exemption for generation installed after the transmission open-access rules were adopted on July 9, 1996. The essence of market power is restricting production to obtain higher market prices on the remaining production. Installing new capacity that will recover its costs only if it operates is the antithesis of market power. It is a pro-competitive activity that reduces prices and makes buyers better off. Hence, it is reasonable, even desirable, to give new generation a pass on the market-power screens. The practical import is that most owners of such generation make a simple filing that states when the generation was built and shows that the applicant does not have transmission market power, cannot erect barriers to entry, and adheres to the commission’s codes of conduct.
Another improvement is the requirement that a generation owner in a regional transmission organization (RTO) must file the assessment. Under the SMA, utilities in RTOs with commission-approved market power monitoring and mitigation did not need to submit an SMA. This was curious because the SMA was not applied in RTO markets where many suppliers do not have retail-load obligations and are more likely to have market power, and it was applied in traditional markets where suppliers had retail load obligations that mitigate wholesale market power. But now all utilities with generation installed before July 9, 1996, must file a market-power study.
Moreover, FERC has shown that it actually may consider the import of such filings. In one recent case, FERC limited market-rate authority to sales into the organized RTO markets and did not allow bilateral sales at market-based rates.5 FERC appears to have abandoned its prior reasoning that if short-term markets are competitive, then longer-term markets also must be competitive.6 But since that underlying reasoning is correct, perhaps FERC now is hedging its bets that its market monitoring and mitigation programs actually are effective at mitigating market power.
The WMSA has replaced the SMA as an assessment designed to fail transmission-owning utilities located outside of centrally-dispatched RTOs (see sidebar “Designed for Failures”). The bias of the WMSA is highlighted by the case of Tampa Electric Co. Tampa has no wholesale customers connected to its transmission system; therefore, it has no customers on its system over which it could exercise market power even if it did have market power on its system. Tampa serves two small municipal customers with less than 25-MW total peak load on neighboring Florida Power Corp.’s transmission system, an area in which Tampa easily passes the WMSA. The contracts were cost-based and approved by FERC. But these customers dynamically are scheduled into Tampa’s control area, where Tampa failed the WMSA despite available imports being more than 40 times the wholesale load. Tampa now finds itself (as of this writing) in a Section 206 refund proceeding for its control area even though the only customers “in” the area have only 25 MW of load, could be served by many alternative suppliers, and are connected to a transmission system where Tampa passes the WMSA.
FERC declares that recent decisions regarding Avista and Idaho Power are examples that the WMSA is not designed for utilities to fail.7 Avista is an atypical case. Its control area has sufficient transfer capability to supply the control-area load completely from generation outside of the control area, and it owns only about one-half of the generation inside of the control area. Given the facts, Avista rightfully passes the market-share screens.
Idaho Power’s case is not such a simple matter. It passes the WMSA for its control area not so much because it has substantial transfer capability, but because of how utilities are allowed to treat hydroelectric capacity in the analysis. For most generation, FERC now is insisting on using “nameplate” capacity.8 But for hydroelectric capacity, applicants can use average production levels for the past-five years.9
This makes sense for run-of-river hydroelectric generation. But much of the hydroelectric generation in the West has significant pondage, so that utilities can use a substantial percentage of capacity during peak periods and substantially less during off-peak periods. In the case of Idaho Power, the effect of using the average production levels is that Idaho Power had no uncommitted capacity in the summer and very little in other seasons. If nameplate capacity were used instead, there is a significant likelihood that Idaho Power would have failed the WMSA in its own control area.
Simple adjustments also would result in Idaho Power failing market-power screens in the Sierra Pacific control area. Under the WSMA, exports from Idaho Power to Sierra Pacific are allocated based upon the uncommitted capacity in the first-tier control areas. First-tier control areas for Sierra Pacific include PacifiCorp East, Bonneville Power Administration, Los Angeles Department of Water & Power, California ISO, and Idaho Power. Given this group of control areas and the amount of generation in these areas, Idaho Power had a trivial share of imports and was credited with only 5 to 10 MW of them. But this method ignores the fact that California could transfer to Sierra Pacific only 92 MW of its 51,000 MW of generation capacity, while Idaho Power’s control area could export 475 MW of its 2,200 MW of generation. Whereas Idaho Power had only about 3 percent of the first-tier uncommitted capacity, its control area could export about 33 percent of Sierra Pacific’s simultaneous import capability. If the actual ability to export to Sierra Pacific were used instead of assuming that all first-tier capacity had equal ability to reach Sierra Pacific, Idaho Power likely would fail a 20 percent screen in the Sierra Pacific control area.
Moreover, the WMSA cannot screen for market-power problems for which it purports to screen. One of the alleged purposes of the WMSA is that it “may indicate the presence of the ability to facilitate coordinated interaction with other sellers.”10 But the WMSA is incapable of providing a screen for the likelihood of coordinated interaction (i.e., interdependent actions of a few sellers to raise prices above competitive levels), because the WMSA only looks at one seller. A seller that fails the screen with a 20 percent share and faces 16 equal-sized sellers as competitors is very unlikely to be involved in coordinated interaction, whereas a seller that passes the screen with a 19 percent share and has only one competitor with an 81 percent share may be likely to be involved in coordinated interaction. If FERC desires a screen for the likelihood of coordinated interaction, it needs to consider information about the number and sizes of competitors.
When interested parties raise objections to the WMSA, FERC responds that the PSA and WMSA represent a “balanced” approach to screening. The July 8 order on rehearing uses the word “balance” nine times to describe or defend its approach. But an approach that routinely identifies a likelihood of market power where none exists and fails to identify market power that does exist is not balanced; it is arbitrary and capricious. Like the SMA, the WMSA is indefensible on both theoretical and empirical grounds. It needs to be replaced.
Some facets of complying with the PSA and WMSA have less to do with the substance of finding or not finding market power, and more to do with filing requirements. For example, FERC has been pedantic about using nameplate capacity for the PSA and WMSA. Nameplate capacity is the design capacity for a generation unit that is typically recorded when the generation is installed, and it is seldom changed. Utilities also report summer capacities and winter capacities, reflecting the actual ability to generate electricity during the summer and winter seasons. These capacities are much more likely to be updated as capacities change over time as a unit ages or is upgraded.
FERC-accepted filings using alternative capacity measures in a number of cases.11 The commission addressed the issue of alternative measures in Dayton Power & Light. Dayton used summer capacity because “complete nameplate rating data are unavailable.” The commission accepted the “simplifying assumption” of using summer ratings because Dayton became part of the PJM RTO, and PJM determines seasonal ratings.12 Yet, within a week, FERC staff requested that TransCanada Hydro-Northeast resubmit its filing in part because Trans-Canada used essentially the same data as Dayton. The use of nameplate capacity resulted in TransCanada capacity declining by about 10 percent because about one-half of the facilities had “nameplate” capacities 20 percent less than both the summer and winter ratings determined by ISO New England. The use of summer (or winter) capacity would provide better information. TransCanada’s updated filing was clearly a case of form over substance as TransCanada’s original filing passed the PSA by more than 6,000 MW and its market shares were below 7 percent. Any reasonable measurement of capacities would result in TransCanada passing the screens.
Another facet in the “ugly” category is the use of the delivered-price test. If an applicant fails the screens, the applicant may submit a delivered-price test.13 In the delivered-price test, applicants also consider the cost of generation in addition to capacities and transmission constraints. FERC requires applicants to file results for economic capacity, which does not consider native-load obligations, and available economic capacity, which subtracts out native-load obligations. Entergy took FERC at its word and submitted a delivered-price test; Entergy failed the economic-capacity screens but passed the available economic-capacity screens.
Because native-load obligations are equivalent to commitments to produce electricity for retail loads, only the available economic-capacity results are relevant for examining competition in wholesale markets in areas with traditional retail obligations like Entergy’s. Yet FERC ignored these results and still ordered a refund proceeding. Given the result, it is unlikely that many more utilities will submit a delivered-price test.
The delivered-price test, however, may be forced upon utilities as an added expense. When utilities have failed the WMSA, FERC has ordered them to provide a delivered-price test or provide for mitigation.14 But in many cases, the delivered-price test would provide little or no additional useful information for the relevant issues. For example, a delivered price test for the Tampa Electric control area would provide no useful information on whether its municipal customers connected to the Florida Power Corp. transmission system have sufficient alternatives so that Tampa must offer competitive prices to maintain the business. Given that one of the two customers already has selected an alternative supplier at the expiration of the Tampa contract, It is clear that Tampa must offer competitive prices to keep the business. The requirement to submit a delivered-price test before FERC will examine the real competitive issues, is nothing more than a penalty on utilities that fail the initial screens.
Another area that belongs in the “ugly” category concerns historical sales. FERC stated that it would consider historical sales evidence for applicants that fail either the PSA or WMSA.15 A number of utilities have failed the WMSA and provided historical sales evidence.16 To date, FERC has not accepted any such evidence. It seems reasonable that in cases where: (1) utilities provide such evidence; (2) explain how it indicates that the utility has no market power; and (3) no intervener claims that the utility has market power, then no further analysis should be needed.
The first step is to change the mindset that most vertically integrated utilities outside of an RTO should fail the screen. If FERC regulation sufficiently has mitigated transmission market power, which FERC requires for market-rate authority, then these utilities should not be inherently suspect in a market-power screen. The screening method should focus on the issues at hand rather than whether a utility is or is not part of an RTO with centralized dispatch and market power mitigation.
Second, FERC needs to abandon its old rate-case mentality. Whether it is the old hub-and-spoke method, the SMA, the PSA, or the WMSA, FERC appears stuck in an old rate-case mentality where the utility submits data and crunches some numbers, FERC staff checks the numbers, and some magical result appears. Such methods are unlikely to work because market power analysis is so fact specific and the facts vary so widely.
Instead, FERC needs to adopt an analytical approach that answers a series of questions. Instead of one or two screens, FERC should think of several successive screens. If the applicant passes at one level, it need not continue to subsequent levels. At some point, one can conclude that details are sufficiently complex so that a more detailed factual inquiry is necessary before FERC could conclude that market-based rates would result in rates comparable to, or below, traditional cost-based rates. But FERC should limit that detailed inquiry to the relatively small number of cases where wholesale market power may be a concern.
1. AEP Power Marketing, et al., 107 FERC ¶61,018 (2004) (April 14 order), order on reh’g, 108 FERC ¶61,026 (2004) (July 8 order).
2. Potential imports are the lesser of simultaneous import capability into the control area and the uncommitted capacity in surrounding control areas.
3. The native-load obligation proxy is equal to the average daily peak hourly load during the month of the annual peak hourly load.
4. For the WMSA, the native-load obligation proxy is the load during the lowest daily peak hour during the season.
5. Wisconsin Electric Power Co., Docket No. ER98-855-002, Order Accepting Updated Market Power Analysis and Revised Market-Based Rate Tariff, March 25, 2005, at P 20.
6. AEP Power Marketing, et al., 97 FERC ¶61,219, at 61,972 (2001).
7. “Mixed Results for Traditional Utilities In and Out of RTOs in Latest Market Power Tests,” INSIDE FERC, March 7, 2005, at P 5.
8. April 14 order, at P 95.
9. April 14 order, at P 126.
10. April 14 order, at P 72.
11. NorthPoint Energy Solutions Inc., 109 FERC ¶61,178 (2004) (Use of FERC Form 714 capacity); Dominion Energy New England Inc., et al., 109 FERC ¶61,262 (2004) (Use of summer capacities from ISO New England as reported in FERC Form 714); Consolidated Water Power Co., 109 FERC ¶61,278 (2004) (Use of FERC Form 714 capacity).
12. Dayton Power and Light Co. and DPL Energy LLC, 109 FERC ¶61,268, at P 9 (2004).
13. April 14 order, at PP 105-112.
14. For example, The Empire District Electric Co., 110 FERC ¶61,214 (2005); Pinnacle West Capital Corp. et al., 109 FERC ¶61,295 (2004); Westar Energy Inc. et al., 110 FERC ¶61,316 (2005); and Tampa Electric Co. et al., 110 FERC ¶61,206 (2005). These orders are consistent with paragraph 105 of the April 14 order, which states that an applicant that fails a screen and “chooses not to proceed directly to mitigation … must present a more thorough analysis using the Commission’s Delivered Price Test.”
15. April 14 order, at P 102, 112.
16. See, for example, Duke Power, a division of Duke Power Corp., et. al., 109 FERC ¶61,270, at PP 11-13, 30 (2004).
FERC's Market Power Screen
Designed for Failures
It is relatively easy to show that the Wholesale Market Share Analysis (WMSA) was designed to fail for traditional vertically integrated utilities. Utilities must have enough generation sources to meet peak loads in each season; therefore, let P be equal to the seasonal peak load and be a proxy for the available generation. Uncommitted capacity is equal to P less the peak on the minimum load day, which can be represented by mP, where m is the minimum peak divided by the seasonal peak. Finally, given the instructions in Appendix E of the April 14, 2004, order, simultaneous import capability can be no more than the seasonal peak load, P. It follows that a reasonable proxy for the applicant's wholesale market share in its control area is W=(P-mP)/(P-mP+P). To pass the WMSA, it can be shown that m must be less than 75 percent. As far as I am aware, only Minnesota Power meets this condition.
There are only two ways to avoid failure of the WMSA. One is to have hydroelectric generation. Under the WMSA, hydroelectric generation is derated to average production levels, which results in uncommitted capacity falling below P-mP. The other is to have a low share of generation and loads within the control area, like Avista Corp. But few vertically integrated utilities have a sufficiently low share of generation within their own control area to pass the WMSA.-JM
WMSA's Bad Math: 10 x 10 = 200
When the uncommitted capacity for a control area is less than the simultaneous import capability (SIC), the WMSA inflates the relevant market shares of suppliers outside of the control area. Consider a situation in which a control area has 500 MW of SIC, 250 MW of uncommitted capacity (including supplies from imports), 10 suppliers outside of the control area, and each of the 10 suppliers has 60 MW of uncommitted capacity. Each supplier would be allocated 50 MW of the SIC. This is calculated by multiplying each supplier's share of uncommitted capacity outside of the control area, 10 percent, by the 500 MW of SIC. The allocation of 50 MW is divided by the control area uncommitted capacity of 250 MW, to give a share of 20 percent for each of the 10 suppliers. Therefore, the total market share of 10 suppliers with 10 percent of potential supplies is 200 percent (see table 1). This inflation of market shares occurs in several control areas, including Avista, Idaho Power, PacifiCorp West, and Reedy Creek.-JM
Second-Tier Control Areas
Paragraph 94 of the April 14, 2004, order requests that applicants limit their import supplies to first-tier markets, whereas Appendix E appears to allow for imports from second-tier markets. Whether it is appropriate to include supplies from second-tier markets is ultimately an empirical question. To examine the question, I examined wholesale purchases recorded in FERC Form 1 for a sample of utilities and classified the source as being from the utility control area, first-tier control areas, second-tier control areas or beyond, or unknown. Out of a sample of 25 utilities, 18 purchased more than 20 percent and 10 purchased more than 50 percent of their imports from second-tier utilities. The leading second-tier purchasers are listed here. From these data, it appears reasonable to include second-tier sources for applicants that are not in RTOs.-JM