An interview with key executives of Duke-American Transmission Co.: Phillip Grigsby, president, and Randy Satterfield, executive vice president. Both also sit on DATC's Board of Managers.
IRP Meets RPS
New green mandates force portfolio planners to re-think their models.
management, and contract options. However, the 2006 IRP included 23 zones and 34 interties. There were 62 existing resources with 96 existing contracts. PacifiCorp considered more than 80 potential resources, over 40 potential contract purchases, and seven transmission expansion options ( see http://www.pacificorp.com/Article/Article23848.html).
Utilities that operate in multiple states or regions face added complexities when evaluating where to build resources—particularly renewable resources such as wind and solar, which require extensive site analysis.
A typical RPS requirement might specify 15 percent of a utility’s generated power must come from renewable resources. However, some RPS may require specific technologies. For example, Colorado, Nevada, Delaware, and Pennsylvania all state specific percentages of the total generating capacity that must be met by solar technologies. Other states may mandate a specific renewable capacity target (for example, Texas defines a specific capacity of 5,880 MW). Massachusetts, on the other hand, specifies the required renewable percentage as only applying to new resources, while Minnesota specifies a separate percentage that applies just to Xcel Energy. All of these variations increase the scope and complexity of the IRP.
In preparing a multi-state IRP, resource planners must be able to accurately capture and analyze complex variations such as:
• The total renewable percentage requirement by state or area;
• Secondary requirements for specific technologies ( e.g., percent wind or solar);
• The ability to specify a particular required capacity (MW) of renewable resources (either in aggregate or by technology);
• Separate percentage requirements for a specific company;
• Setting generator contributions only on new generation; and
• Recognizing that only renewable generation contributes towards the minimum RPS percentage requirement; even though additional resources may be required to meet the overall IRP goals.
Resource planners also need to keep in mind the prospects for national RPS requirements. In December 2007, the Senate removed a federal RPS provision from the Renewable Fuels, Consumer Protection, and Energy Efficiency Act of 2007. While the Edison Electric Institute (EEI) and Southern utilities were against national RPS, other stakeholders have been pushing to include national RPS in proposed bills.
In 2009, the United States will have a new president. Whoever wins the election strongly will influence the development of any national RPS. Sen. John McCain voted against a 10 percent national RPS standard in 2005, and Sen. Barack Obama supports achieving a 25 percent level by 2025.
If a national RPS moves forward, it could require every provider in the nation to source between 15 and 20 percent of its power from renewables. A key uncertainty is whether a national RPS would contain any trading mechanisms to help parties achieve their targets.
The effect of a national RPS on the IRP process is that it would supersede some state requirements, but other states still would have more stringent requirements ( e.g., Oregon and Illinois). IRP processes within those states must continue to account for area and regional-level requirements.
So how do some of these regulatory realities and uncertainties affect IRP processes? First, the timing of state and national RPS