Failing the Market-Power Test:
How FERC's ruling could affect wholesale power markets.
The July ruling from the Federal Energy Regulatory Commission (FERC) on market-based rates, enacting two new market tests utilities must pass if they want to enter into wholesale power transactions at market rates, caught the attention of industry players. Those two tests-the pivotal-supplier test and the wholesale market-share test-stirred much debate and triggered several hearings and open forums. FERC generally stuck to its guns, adding a few minor provisions and a clause that allow companies that fail the market tests either to make their case in front of FERC or pass the delivered-price test. However, large investor-owned utilities (IOUs) that are outside of independent system operators (ISOs) and that don't belong to a control area with other members of similar size may as well book a ticket to Washington, D.C., if they want to sell power at market rates, because our analysis, developed here at Energy Velocity, shows that FERC is going to have a busy year.
The Pivotal-Supplier Test
The pivotal-supplier test is designed to ensure that no single company's capacity is essential to meet wholesale load. The test is simple: If the applicant's uncommitted capacity is greater than the market's net uncommitted capacity, the company fails the test. Table 1 contains a detailed description of the pivotal-supplier test. Net uncommitted capacity is the sum of all participants' uncommitted capacity less the market wholesale load. If the applicant's uncommitted capacity is greater than the market net uncommitted capacity then it is assumed that at some point the applicant will be in a position to control the market price, and the applicant fails the test.
Energy Velocity applied this test under two different conditions. The first did not include the control area's interconnected capacity; the second did. In the first analysis, only 11 of 136 companies failed the test. All those that failed were in control areas with peaks under 6,000 MW and had not experienced significant investment from independent power producers in the past few years. The second analysis included interconnected capacity, and no companies failed. This is partly a result of the recent overbuild and partly because most control areas are fairly well connected to their neighboring control areas.
Wholesale Market-Share Analysis
The wholesale market-share test is designed to measure an applicant's market power. Once again, the test is simple: If the applicant's uncommitted capacity is greater than or equal to 20 percent of the total market uncommitted capacity, the applicant fails. Figure 2 contains a detailed description of the wholesale market-share test. The base definition for supply in this test is the same as in the pivotal-supplier test, except that capacity is reduced to account for planned outages and low water years for hydro units. Planned outages need to be considered, because for this test, FERC defines native load as the minimum load in any season.
We also applied this test twice. The first analysis did not include the control area interconnected capacity; the second included first-tier interconnections. In the first run, only 69 out of 136 IOUs passed the test. In the second, 3 additional IOUs passed the test. That left 64 companies to either complete the optional delivered price test or proceed directly to mitigation in an effort to rebut FERC's presumption of market power. Of the companies that passed the test, 51 are in an ISO and 21 are not. Most of these 21 companies fall into one of three categories: They don't own any capacity of their own, they are a small company in a bigger company's control area, or their control area includes more than one significant player.
The Power of the ISO
None of the companies that belong to an ISO failed; additionally, all of the non-ISO companies that passed belong to a control area that diminishes their market position (such as Michigan Electric Coordinated System). While it's likely that some of the high passing ratios in the ISOs were caused by requirements that utilities sell their capacity before joining the ISO (as happened in California, Texas, and New England), ISOs are also one of the few places where a large amount of capacity can be absorbed in an effort to pass a 20-percent market-share test.
It's no secret that FERC wants all U.S. utilities to join an ISO or RTO, and this ruling may well encourage many IOUs to do just that. In fact, as soon as FERC ruled on the new market-based rates tests, American Electric Power (AEP), one of the named utilities in that ruling, moved aggressively toward membership in the PJM RTO. We examined what PJM will look like with the addition of AEP and determined that AEP would pass the market-share test if it joins PJM. In fact, when combined with PJM, AEP nearly passes the test without including any interconnected capacity because of the quantity of capacity installed in the PJM RTO. If AEP does join PJM, the PJM RTO will be large enough to absorb any other market participant without concern for market-share issues. This will provide a market that can offer safe harbor even to very large players like Southern and Entergy without challenging FERC's definition of market power. Now that Com Ed has joined PJM, there aren't even geographic boundaries that would keep participants from joining PJM. FERC appears to be using the carrot and the stick approach to encourage companies to join an RTO.
Power Market Impact
What will this ruling do to utility earnings? Some have referred to this ruling as a "death sentence" for the utility industry, and our analysis does indeed show that there's much at risk. We analyzed FERC's Electric Quarterly Report data for the first two quarters of 2004 and evaluated the possible impact on these transactions of enforcing a cost-plus-10-percent requirement for power transactions within the applicants' control area. The total dollars transacted in the first half of 2004 by power marketing organizations affiliated with companies that failed the market share test was more than $1.92 billion. Again, this number represents only market-based rate activity inside of a company's own control area.
FERC stated that "for applications by sellers with no generation assets in the ground that are affiliated with generation asset-owning utilities, we will continue to evaluate the affiliate generation owner's market power when evaluating whether to grant market based rate authority for the power marketer." Energy Velocity interprets this statement as implying that FERC would use different standards when evaluating a marketer's position in a control area where it owns capacity versus control areas where it does not. Another interpretation is that if the marketer's affiliates have market power in any market, then that marketer's ability to transact at market-based rates would be denied in every market. If the latter interpretation is used, the dollars at risk are significantly higher than those that we identified here at Energy Velocity.
The transactions that occurred in the first half of 2004 happened at an average rate of $23.76/MWh. To understand the impact of mandating cost-based transactions, we analyzed the system lambda data for 2002 (the most recent complete year of data available for these companies). The average lambda was $16.66/MWh for the first half of 2002, which implies a cost-based rate of $18.33 (if you in-clude a cost-plus adder of 10 percent). This difference suggests a market reduction of 23 percent, or nearly $440 million, for only half a year of transactions. Higher gas prices in 2004 would undoubtedly drive a lower market reduction if 2004 lambda data were available.
Any way you look at it, the FERC ruling denying IOUs the ability to transact at market-based rates is going to impact earnings for at least 64 such utilities-unless, perhaps, they join an ISO. Seemingly, the deck is stacked against non-ISO members-their choice is either to fall in line with FERC's definition of who can sell power at market rates, or to forgo transactions at market-based pricing. After all, what's a few hundred million dollars of earnings among friends?
The inputs for this test as defined by FERC are native load, wholesale load, applicant capacity, market uncommitted capacity, and net uncommitted capacity.
Native load is calculated by taking the month in which the single-hour peak occurred and averaging the daily peaks that occurred in that month. Wholesale load is computed by taking the single-hour peak and subtracting native load. Applicant's uncommitted capacity and market uncommitted capacity equal nameplate capacity plus firm and contract purchases minus operating reserves, native load, and long term non-requirement firm sales. Uncommitted capacity includes the applicant's capacity, all other capacity in the control area, and the lesser of first tier interconnected capacity and simultaneous import capability from that interconnected control area. In the event that the applicant owns capacity in an interconnected control area, the company's remote capacity is allocated transmission capability before any competing capacity. Net uncommitted supply is equal to the total uncommitted capacity in the control area and the first tier interconnects minus the wholesale load.
The applicant passes the test if its uncommitted capacity is less than the net uncommitted capacity.
Wholesale Market-Share Analysis
The inputs for this test as defined by FERC are native load, applicant uncommitted capacity, and market uncommitted capacity.
Native load is defined as the minimum peak day for each of four peak seasons: summer (June, July, August), fall (September, October, November), winter (December, January, February), and spring (March, April, May). Applicant uncommitted capacity and market uncommitted capacity are defined the same as in the pivotal-supplier test, except that hydro nameplate capacity is reduced by the lowest capacity factor in the past five years, and capacity values are reduced by planned outages for the season.
The applicant passes the test if the applicant's uncommitted capacity is less than 20 percent of the market's uncommitted capacity.
Our Method of Analysis
In applying the pivotal-supplier test, Energy Velocity included the following assumptions in its analysis. We used the hourly load data from FERC Form 714 to drive our native and wholesale load analysis. Our control area definition also came from the 714 form. We used 15 percent as our operating reserve. Since insufficient data are available from public sources to account for firm purchases and sales by the applicant in the month for which the test applies, that information was omitted. Requirement sales have been accounted for as they are reflected in the hourly load data. We also substituted total transfer capability between control areas for simultaneous import capability. In each case, the test applied by Energy Velocity should be easier to pass than the tests as defined by FERC. In the case of firm purchases and sales, 2003 FERC Form 1 filings show long-term firm purchases far outweighed long-term firm sales by IOUs. In the case of interconnected capacity, the total transfer capability between control areas will be somewhat higher than the simultaneous interconnect, which again would make it easier for an applicant to pass the test.
In the market-power test, we used the same assumptions as in the pivotal-supplier test, with the exception of applying hydro capacity and planned outages as described in Figure 2. As in the market-power test, the limitations of available public data make the tests easier to pass than FERC's definition of the test. In aggregate, these methodological differences are unlikely to affect the outcome. Fewer than 10 companies were within a range of 5 percent of the 20 percent market-power threshold, and they were split evenly above and below the threshold.
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