Cost of capital is often a contentious issue in utility ratemaking. This is due, in part, to the inexact nature of the tools available to financial analysts and the considerable room for divergent...
Breaking the Gridlock
A proposal to remove the bottlenecks on grid investment.
with stronger transmission ties. The connected load for the load-serving entities remains constant at 8,000 MW. The change in generation reserve requirements and production costs that follow upgrades to the transmission corridors is indicated and explained below.
The regions in the hypothetical example started with weak inter-regional ties. When these ties were strengthened, 3,000 MW of local generation were “displaced.” Costs came down while the reliability index was maintained at the previous level (one day of shortage in 10 years). In reality, stronger transmission ties “enabled” low-cost generation to compete in local markets, and the ability to share reserves during peak loads and outages allowed individual regions to cut installed capacity while maintaining the same level of reliability. This exact scenario prompted utilities to build strong tie lines with their neighbors in the 1950s and 1960s, thereby saving substantial amounts of money, in terms of generation investments, by building transmission tie-lines with their neighbors. In today’s market environment, the weak tie-lines indeed would show congestion and accompanying congestion costs. However, any attempt to upgrade these corridors would be seen by local generation as competition. To a local generator, any proposed transmission upgrade of tie lines would probably be more of a threat than would the addition of a neighboring generating plant.
A mechanism that works for transmission investments is a market-based bilateral arrangement for transmission that competes with generation and demand-side solutions. In the words of former FERC Commissioner Don Santa, “As long as the proposed transmission facility places downward pressure on the price of market-based solution to high prices at a node, from a public policy perspective why should the regulator care whether the economic rent is being collected by a generator, a demand-side operator or a transmission provider?”3 FERC recognized this paradigm in the case of TransEnergie’s Cross Sound Cable project.
It is worthwhile to examine the Cross Sound Cable model. In this model, the load-serving entity (LSE)—Long Island Power Authority (LIPA)—purchased long-term transmission capacity rights on a high-voltage direct current (HVDC) cable into Long Island. New York has a locational capacity market (LICAP), and the price of a megawatt of capacity in Long Island is significantly higher than the price of a megawatt of capacity in upstate New York. The extra capacity and energy provided by this cable allowed LIPA to meet its capacity requirements and import lower-cost energy from New England. In this case, FERC allowed a market-based bilateral arrangement for transmission that competed with generation and demand-side options. The success of this model allowed LIPA to go for the next round of competitive bidding between generation and transmission options that resulted in the selection of a second cable project into Long Island (Neptune Project). Both transmission cables selected by LIPA are HVDC cables. HVDC cables are controllable so that the flow into Long Island can be controlled. However the same construct may be used for the more common alternating current (AC) upgrade where incremental transfer capability (which has a value in the LICAP market) can be used as a basis of a long-term bilateral financial contract.