T&D

Breaking the Renewables Log Jam

Issue 6 and Volume 85.

by Larry F. Eisenstat and Cortney Madea

Currently, 24 states have renewable portfolio standards (RPS) which, in general, require retail electricity providers to have a minimum percentage of renewable resources in their supply portfolios. Unfortunately, though, the energy from such resources, particularly wind and geothermal projects, is often difficult to deliver due to their remote locations or relatively small size. Wind speed is not necessarily highest next to existing transmission, and upgrades usually aren’t justified by relatively small projects. The problem, then, is how best to tailor interconnection policies to accommodate the entry of such “location-constrained” resources as are necessary to meet state or regional RPS requirements.

The largest obstacle to interconnecting renewable resources is the cost of the necessary facilities. Under FERC Order 2003, generators must initially fund the network upgrades necessary to interconnect to the grid in exchange for transmission credits or financial rights. But as FERC recently acknowledged, “[l]ocation constrained resources present unique challenges not faced by other resources and . . . are not adequately addressed in the Commission’s current interconnection policies.” [California Independent System Operator Corporation, 119 FERC ¶ 61,061, P 64 (April 19, 2007).] In particular, the cost responsibility for major new transmission facilities faced by first-in-line renewable developers, if not outright prohibitive, can lead to continual queue reshuffling and lost opportunities for developing otherwise viable projects. Indeed, several regional transmission providers are intent on eliminating such obstructions.

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For example, California requires that 20 percent of the state’s electricity demand be met from renewable energy by 2010. Acknowledging the barrier posed by high interconnection costs, the California Independent System Operator (CAISO) sought and obtained FERC approval to include (or “roll-in”) the costs of those interconnection facilities required by location-constrained resources in the revenue requirement of the transmission owner charged with their construction; i.e., to charge an interconnecting generator only its pro rata share of the facilities’ total costs, and to charge system customers the costs of any unsubscribed portion of these facilities.

Similarly, certain load-serving entities (LSEs) in the Midwest Independent Transmission System Operator (MISO) are required to procure as much as 25 percent of their electricity requirements from renewable resources by 2020. As a consequence, MISO is developing a mechanism that, rather than allocating all the transmission upgrade costs solely to the first renewable generator wishing to interconnect, would allocate these costs, over time, to all those renewable generators connecting to the same facilities. Specifically, the upgrade’s sponsors (e.g., LSEs, transmission owners, etc.) initially would finance the upgrades and renewable generators would pay their share of the annual payments at such time as they go commercial.

Texas, on the other hand, has adopted a much more comprehensive legislative and regulatory approach. In 2005, the Texas Legislature established a target of 10,000 MW of installed renewable capacity by 2025, and directed the Public Utility Commission of Texas (Texas Commission) to (1) designate competitive renewable energy zones (CREZs) in areas with sufficient renewable energy resources and suitable land area to develop renewable resources, and (2) develop a plan to construct the transmission necessary to deliver the targeted level of renewable resources in each CREZ. The costs of these transmission projects will be borne by the transmission providers and each renewable project in the given CREZ will be required to post collateral of 10 percent of its pro rata share of the estimated capital cost of the transmission improvements. The Texas Commission has since established the CREZs and target capacity levels, and anticipates issuing construction permits by summer 2009.

Only time will tell which of these approaches best facilitates renewable energy development. One way or the other, though, if a state requires a given percentage of renewables, the transmission system must be planned to ensure that this directive in fact will be met. Surely the task of developing the policy changes and regulatory rules necessary to accomplish this is no less imperative than the policy objective that lead to the adoption of an RPS in the first place.

Authors

Larry F. Eisenstat is head of the energy practice and Cortney Madea is an energy associate with Dickstein Shapiro LLP. They can be reached at [email protected] dicksteinshapiro.com and [email protected], respectively.