"We view the [Entergy-ITC] transaction [as] an attempt to extract excess value."-Mississippi PSC
Dayton Power & Light control area outside of MISO). Piqua had signed a new contract with Cinergy at the start of 2002, extending the term of its full-requirements purchases. Previously, Piqua had to pay a transmission fee to both DP&L and Cinergy. (Its total cost for transmission from Cinergy was about $1,070/MW per month, or $2/MWh.) With the startup of MISO, Piqua expected that it would pay but one charge, saving money compared to the prior system of pancaked rates. Instead, as Rosenzweig learned from his interview with city officials, Piqua ended up paying transmission charges to both DP&L and MISO, since DP&L (a former Alliance company) was not joining MISO. The increase translated to a 4.5 percent increase in existing retail rates for Piqua residents.
Rosenzweig interviewed many other transmission customers, hearing many similar stories. FERC has cited this testimony as persuasive. It has formed a key element of the commission's decision to eliminate RTORs and utility specific T&O rates.
Operations and Dispatch: Merging the Markets
Another Cinergy witness, Dr. Richard Tabors, president of Tabors Caramanis & Associates, also appeared instrumental. His role was to convince FERC that if AEP was to join PJM, it would have to join all the way, with full participation in PJM's market structures, including LMP for congestion management.
Note, first of all, in order to overcome state objections, that AEP had proposed to join PJM only half-way; it would submit its grid assets to the functional control of PJM, and yield to the RTO on all other functions that FERC had defined as fundamental to RTOs in its Order 2000. Yet AEP would refrain from participating in PJM's day-ahead market and would not submit to PJM's centralized and security-constrained dispatch, nor PJM's LMP regime for market-based congestion management. Instead, it would rely on the non-market technique of TLRs to manage grid congestion. AEP had argued that when it had promised to join an RTO in exchange for FERC approval of its merger with CSW, it had envisioned such membership to include only those features described in Order 2000 as essential to RTOs. FERC had not yet announced its SMD, which listed LMP, day-ahead markets, and security-constrained dispatch as required elements of RTOs.
Responding to AEP's half-a-loaf proposal, Tabors had argued that AEP needed to be fully integrated immediately into PJM markets. RTOs, he said, should not be "hamstrung with a requirement to indefinitely depend upon an economically inefficient TLR interregional congestion management protocol for the AEP transmission system portion of the RTO's regions, while attempting to implement coordinated, LMP-based congestion management in the remainder of the surrounding regions."
Tabors, whose book, Spot Pricing of Electricity, documents the underlying mathematical theory of LMP-based electricity markets used in PJM, NY-ISO, and ISO-NE, told how LMP would prove superior to quantity-based rationing of transactions, which results from the TLR process. To support his conclusion, he discussed how various solutions for generation dispatch can affect power flows across a flowgate, as indicated by "sift factors described in the Interchange Distribution Calculator (IDC), developed by the North American Electric Reliability