Transmission Planning

ISO New England develops the nation’s first multistate long-term forecast of energy-efficiency savings.

With no single entity in charge, transmission planning has plagued projects that span multiple regions. A new framework offers a solution.

Allocating the costs of new transmission investments requires accurately assessing the value of those new lines, and identifying the primary beneficiaries. But formulaic approaches rely too much on the most easily quantified cost savings, and reject benefits that are dispersed across service areas—or that might change over the course of time. Brattle Group analysts J.P. Pfeifenberger and D. Hou explain that comprehensive valuation produces a more accurate picture.

Where wind integration has been most successful, state authorities developed and adopted basic transmission planning and cost allocation principles before FERC issued Order 1000. Experiences in Texas, California, and Hawaii demonstrate what it takes to overcome permitting and cost allocation barriers—namely, a coherent policy framework and close coordination among stakeholders.

To encourage billions of dollars of investment into America’s transmission grid over the next several decades, the Federal Energy Regulatory Commission (FERC) is restructuring its regulatory policies to bring market-based solutions into the framework for planning, construction, and operation of new transmission lines. The recent Order 1000 is the most dramatic example of this effort. But as FERC has learned before, one set of rules doesn’t serve the financial and commercial needs of all market participants.

Six years after Congress granted FERC “backstop” siting authority for electric transmission projects in the Energy Policy Act of 2005, the regulatory landscape is still evolving as a result of federal court decisions and new FERC orders. But despite a lack of certainty at the federal level, project sponsors have filed numerous applications at the state level for new transmission projects. Can these projects proceed without greater certainty at FERC?

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While it’s theoretically possible to keep the lights on with a much smaller reserve than the U.S. utility industry historically has maintained, the costs of doing so might be higher than some analyses suggest. As demand response plays a growing role on the grid—and as system planners reconsider reserve margins and reliability standards—quantitative risk analysis will guide resource adequacy decisions.

The case backlog of unprocessed electric reliability violations is growing out of control, threatening to “swamp” the industry — a sign, perhaps, that when Congress and FERC modernized the electric reliability regime to serve a more market-based industry structure, and for the first time gave enforcement authority to North American Reliability Corp. (NERC) as the nation’s official electric reliability czar, no one gave much thought, apparently, as to whether NERC’s very idea of what constitutes reliability might have needed modernizing as well.

The California ISO is going its own way with its proposal for transmission planning, virtually ignoring FERC’s proposed rules on transmission planning and cost allocation. California wants to bring method to the madness of developing transmission projects, and its approach has raised hackles in the industry. The dispute defines the battle over America’s most attractive market for rate-regulated investment.