PJM would dictate grid expansion, even if not needed for reliability, and then push the cost of the upgrades on those who use them the most.
Chairman Pat Wood and his...
for reliability, and those that are motivated by economics," Schnitzer says.
Schnitzer and SeTrans would put these two categories of grid assets into different buckets, A and B. Bucket B, the reliability category, would fall under a familiar regulatory structure:
When questioned, Schnitzer explained that SeTrans would include in "reliability transmission" any grid assets required to meet recognized reliability criteria so that all "firm resources" within the RTO (meaning generators classed as "network resources," excluding generators treated as "energy-only") would be able to serve load:
But all other transmission then falls into Bucket A-the privately funded "economic" category-as Schnitzer explained further:
"Everything else, then, by definition, is for economics. … Someone wants to try and get lower delivered prices. Someone wants to try and get higher prices at their node. Someone wants to get more 'out' or 'through' service."
Under the SeTrans vision, private enterprise takes the lead in grid expansion. The RTOs and ITPs play only a residual role. They step in with public money only where the market has failed to attract the necessary investment.
Incentives for Private Funding?
Dividing the grid into separate buckets-public and private-assumes that the private financiers of Bucket A will receive congestion revenue rights as compensation (CRRs, also known as financial transmission right, or FTRs). Yet some experts wonder whether such compensation will prove incentive enough to encourage grid expansion. One such expert is Chuck Meyer, vice president of marketing and sales at Bonneville Power Administration. He argues that CRRs will fall short, forcing FERC to award transmission rate credits to private grid builders, as is done under some aspects of FERC's generation interconnection policy.
The issue invites a comparison between participant funding and the traditional method of socializing grid expansion through traditional embedded-cost, rolled-in rates.
Rich Bayless, director of interconnected systems at PacifiCorp, tells of a study conducted out West that looked at two alternatives to bring cheaper power to Colorado and Montana. Option A would expand the grid to gain access to low-priced but remote renewable energy and coal-fired power. Option B would build more gas-fired generators close to load, to avoid grid investment. How would participant funding affect each decision?
According to the study, Option A would produce net gen savings of $7 per megawatt-hour (MWh) across the entire customer base, after paying for a roll-in of grid expansion costs. But if you financed the grid construction privately, assigning the cost only to the coal-fired plants and windmill operators, you would add $5/MWh to the price of the generation and lose the competitive advantage over the close-in gas turbines. So the merchant coal and wind plants would have no incentive to build out transmission under a PTF model.
However, the grid expansion would also produce $1.4 billion in savings through avoided congestion. Spreading those credits among the 25,000 MW of new coal- and wind-fired generators would give them about $8/MWh. So, if those merchant coal and wind plants receive credits (CRRs) in exchange for participant funding, to allow them to capture the hedge value of the congestion savings, they (and ratepayers) would