The marriage between Exelon and PSEG would create the largest electric utility in the United States. The policy implications could loom even larger, however. Standing at risk is nothing less than...
Bad Day at Black Oak
Beware even the best of attempts at apportioning grid rights and costs.
100 MW (the total exceeding the line’s capacity), with one request scoring a 40 percent DFAX and the other only 20 percent, PJM will prorate the first request down to 37.5 (30 x 100/200 x 1/0.40), and the second to 75 (30 x 100/200 x 1/0.20).
This method also means that with a line capacity of 180 MW, and two competing ARR requests—one for 10 MW, with an 80 percent DFAX, and the second ARR 50 times bigger, at 500 MW with a 40 percent DFAX—PJM will cut the first request by half (from 10 MW to 4.41 MW), while cutting the second by less than one-twelfth (from 500 MW to 441.18 MW).
Chambersburg cries foul: Why cut its ARR request by a half, when its 20-MW flow marks only a small share of the 2,400-MW capacity of the Black Oak line? Surely it argues, it must be that other, much larger LSEs—perhaps in the higher-priced and populous eastern zones of PJM — are exerting a greater impact on the scarce resource. Chambersburg argues, in essence, that just as PJM assigns responsibility for mandated grid upgrades through its RTEP process on the basis of the grid impacts exerted by entire pricing zones (based roughly on utility service territories), so also it should prorate ARR nominations in the same way. By contrast, PJM’s method, says Chambersburg, will always discriminate against LSEs with small flows and load requirements in geographic locations that force them to rely disproportionately on congested lines.
In fact, here is what is happening: PJM’s ARR allocation method does not compare the treatment of differing geographic zones or corporate entities, as might occur in a traditional investigation of rate discrimination by a state public utility commission. Rather, its method seeks fairness among transactions. It assures the fewest curtailments of ARR nominations across the entire system, and thus the maximum amount of commerce and the maximum amount of hedged congestion revenue. In this way, it represents a complete reversal of traditional notions of rate making.
Upgrades: Planet Neptune?
In an ironic twist, PJM’s recommended allocations of cost responsibility to individual LSEs for transmission upgrades approved by the PJM board of managers as part of the RTO’s most recent RTEP iteration, as per its report of July 21, have raised objections opposite to those of the Chambersburg case. In essence, opponents say that PJM’s allocation method is too primitive, that it focuses too much on company and zonal impacts, while ignoring broader impacts on region-wide commerce that can be perceived only by taking a much broader view.
For example, several parties object the fact that PJM nets the DFAX calculation, combining and netting all counterbalancing needs or benefits within TO-specific territories and zones, thus masking their effects. In particular, the Old Dominion Electric Co-op notes that by modeling the system only at peak, when west-to-east flows are greatest (ignoring the other 8,759 hours of the year), PJM adopts a “snapshot” view that ignores broader trends, and instead searches only for the “straw that broke the camel’s back.” This use of the DFAX method,