Resource Planning After the Crash

How to update yesterday's IRP model to account for tomorrow's risk profile.

 

The process we know today as integrated resource planning (IRP) got its start back in the 1980s, when regulators first came to grips with nuclear plant cost overruns and urged utilities in effect to hedge that risk-to give equal weight to conservation, "negawatts," and demand-side management (DSM) as sources of new electric capacity.

Times Have Changed, Even If IRP Hasn't

Today's utilities face a bevy of new risks in this post-Enron, post-crash, post-blackout world. This litany of new dangers includes such risks as: (1) gas price spikes; (2) thin and illiquid trading; (3) suppliers with poor credit; (4) boom-and-bust cycles; and (5) merchant power bankruptcies. And this new set of risks demands a fresh look at traditional IRP.

In the standard IRP approach, utilities first develop a long-range load forecast. Then they evaluate their existing supply-side resources and prospects for DSM to determine uncommitted needs. Lastly, they select among competing supply- and demand-side programs that appear most viable and economic, develop alternative portfolios, and test those portfolios against selected scenarios to see which portfolio will best satisfy a set of economic, regulatory, and environmental mandates.

The tools most typically used in this traditional IRP involve forecasting, shaping, and characterization of load, plus price forecasting for power and fuels. Other tools are used to model power plant dispatch.

However, the standard IRP process was not designed to efficiently address a host of new factors, such as: