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Capacity Planning: The Good, the Bad, and the Ugly
Market-Power Tests: A review of FERC’s market-based rate (MBR) screens, from theory to application.
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