GE Energy Consulting and the New York Power Authority agree to a license arrangement allowing NYPA to use GE’s MAPS software to perform high-fidelity nodal...
Energy Technology: Winner Take All
in this scenario, aside from consumers who are plagued by periodic outages and the associated rate impacts, may be distribution-focused utilities, including players such as Consolidated Edison, Pepco, and Northeast Utilities. A world in which the value of reliability continues to increase, while the cost of self-providing enhanced reliability decreases thanks to innovations in distributed resources, could lead to growing competition to wires companies' "natural monopoly."
Distributed generation poses four primary threats to the existing distribution utility business model. First, distributed generation results in the loss of revenue under traditional tariff structures; the customer simply is purchasing fewer kilowatt-hour or fewer distribution services. Second, more substantial market capture by distributed generation can create a new class of stranded asset within the distribution system-grid capacity no longer needed. Third, the ability of distributed generation to enter more rapidly than centralized generation or transmission upgrades can partially strand new capacity additions. Fourth, the combination of the first three threats can create a "death cycle" in which the higher prices to remaining customers induce more of them to leave this system, creating a self-reinforcing cycle of ever-increasing unit prices.
Even modest revenue losses have substantial impacts on profit. The problem for utilities is that their high unit gross margins (revenues less cost of goods sold) are volume needed to cover largely fixed operating and depreciation costs. Hence, they are highly vulnerable to volume losses, as evidenced by their earnings' strong sensitivity to weather (see Figure1). 1
The Supply-Side Response Path
The under-investment in the U.S. transmission grid, especially relative to the increased demands being placed on it (see Figure 2), and the role of regulatory shortcomings in this neglect are the subject of endless discussion. The most commonly cited problems include: lack of adequate price information to signal the need for investment, controversy over the allocation of the costs of transmission investment, overlapping or poorly defined regulatory jurisdiction, a lack of mandatory reliability standards, excessive red-tape and complexity in transmission siting, and uncertainty over what regulators will demand next. This summer's blackout appears to create the potential for legislators to grapple with at least some of these topics. Combined with favorable tax treatments and lucrative guaranteed rates of return, the path could be clear for accelerated investment in the grid.
Just maintaining the historical capacity relationship norms of 201 MW-miles/MW demand throughout the next decade would requires the construction of 26,600 GW-miles, compared with planned construction of only 6,200 GW-miles. 2 If new construction maintained current levels of transmission capacity, investments would total an estimated $56 billion. This is equal to the current book value of transmission assets and about half of the $105 billion investment forecast for new generation capacity over the 10-year period. Putting aside the question of who will pay for this, the impact on power costs will depend on how the cost of the increased capacity (at about 1,500-1,800/kW) will compare to savings through reduced transmission losses (1 to 2 percent, say some experts) as well as improved dispatch efficiency.
We envisage four potential sets of winners in this scenario. First