An estimated $900 billion of direct infrastructure investment will be required by electric utilities over the next 15 years, and $750 million already is in place. Nukes, renewables, low-carbon...
Neptune and the Northeast
could bring to the table.
Neptune and the Northeast
What a merchant transmission line
could bring to the table .
It' s been a couple of busy weeks in the transmission arena back at the Federal Energy Regulatory Commission (FERC).
On July 12, it herded the transmission owners into a big corral, where New England, New York, and PJM independent system operators would join forces to create a single, super-RTO (regional transmission organization). Then, two weeks later on July 25, it set the proposed Neptune transmission project loose in that corral. The sponsors of the Neptune project, known formally as the Neptune Regional Transmission System, would build a 4800-megawatt high-voltage direct current (DC) transmission network, connecting Atlantic Canada with NEPOOL, the New York Power Pool, and PJM.
BY CONNECTING GENERATORS IN RELATIVE REMOTE AREAS WITH LOAD IN RELATIVE CONGESTED URBAN AREAS, THE NEPTUNE PROJECT WOULD FORM THE BACKBONE FOR AN EMERGING NORTHEAST RTO. FERC's order directs the Neptune project to work with a future Northeast RTO to ensure that the RTO's tariff would be designed in a manner that would accommodate the Neptune project' s financing needs. That is an important statement. It is directed not just at the Neptune project, but also at the parties creating the Northeastern RTO. As FERC explained in its July 12 order calling for a Northeast RTO, "our long-term competitive goals are better served by RTO expansion plans that allow for third-party participation as well as merchant projects outside the plan." It ordered PJM to revise its procedures "to include in its process that third parties may participate in constructing and owning new transmission facilities."
Thus, the regulatory doors have swung open to merchant transmission. Can the Neptune project meet the challenge?
CONSIDER NEW YORK CITY. WHILE IT MAY WELL BE POSSIBLE TO SHOE-HORN ONE OR TWO NEW 1000-MW POWER PLANTS INTO THE CITY, and to re-power one or two existing plants, in the long run a new paradigm has to be found.
In fact, several years of location-based marginal pricing experience in PJM and the New York Power Pool provide ample evidence of the existence of an urban price premium for electricity. During the period from June 1, 2000, to May 31, 2001, the average price in Zone J was more than $20 higher than that of the PSE&G zone just across the Hudson River.
Regarding the urban premium, New York and Boston now represent mixed gas/oil markets with lots of old and inefficient generating units - hence the high clearing prices in energy markets. Over time, most of the oil-fired capacity will be phased out, and a few new combined-cycle natural gas turbines (CCGTs) will be installed. But neither city is likely to be the home of surplus electricity generating capacity. Relatively tight capacity markets means enduring urban premiums for energy and capacity, compared to surrounding suburban and rural areas.
BY CONTRAST, NOVA SCOTIA GENERATORS CAN ACCESS EX-TARIFF SCOTIAN SHELF GAS, FOR AN ADVANTAGE OF UP TO $10/MWH. New Brunswick has excess existing hydro, coal, orimulsion, and nuclear power in the summer, which will usually be cheaper than