The IEAB has reviewed Chapter 11 of the Draft 6th Power Plan. This chapter provides an excellent discussion of the relevant technical information about flexibility options for variable generation resources, especially wind generation. Chapter 11 says:
Historically, the cost of operating the power system to provide regulation and load following services received little attention. The effect of wind and other variable generation on the balancing authority’s control problem has raised awareness of the cost of providing these services. Improvements in operating procedures and business practices, described below, should help to hold down integration costs, but they will likely increase over time as more variable generation is added to the system.
This task and our review of this chapter are motivated by some concern in the region that the potential rate impacts of wind integration are being underestimated.
While Chapter 11 is an excellent coverage of the technical interrelationships which underlie the costs of integrating variable generation resources into the PNW system, it does not directly discuss these costs or rate impacts. Some information on wind integration costs is included elsewhere in the Power Plan, primarily in Appendix I and Appendix P.
Appendix I indicates that the modeling of costs and rates done for the 6th Power Plan did not actually estimate the costs of wind integration. Instead, the cost models used by Council staff relied on integration cost assumptions derived from integration cost studies by several western utilities (see appendix I, pages I-11 and I-12). Work by Council staff to better understand and model PNW wind integration costs is ongoing.
The IEAB suggests that the 6th Power Plan should include at least one paragraph but probably a section (not necessarily in Chapter 11) that discusses the quantitative cost and rate estimates from Appendices I and P, focusing on the costs of integrating variable generating resources, and a short summary of the estimated effect on power rates should be provided. Chapter 11 might reference a section on costs and rates that should appear somewhere in the main document, not just the appendices. It also might also be useful to discuss how power rates might change differently in different parts of the region.
At a minimum, the IEAB suggests providing a summary similar to the following:
Historically, the cost of operating the power system to provide regulation and load following services received little attention. The effect of wind and other variable generation on the balancing authority’s control problem has raised awareness of the cost of providing these services. Improvements in operating procedures and business practices, described below, should help to hold down integration costs, but they will likely increase over time as more variable generation is added to the system.An analysis of rates has been conducted that includes assumptions about integration costs. The analysis, in Appendix P, estimates average future power rates under a variety of scenarios. The annual rate of increase of real power rates is expected to range anywhere from 0.3 to 1.6 percent annually. The assumptions for wind integration costs included in these rates are shown in Appendix I, pages I-11-13. The going forward power system costs also include the cost of conservation and generating resource options, and in some futures, construction and operation.
The short summary of rate impacts might be something like this:
Wind integration costs for 2010 were assumed to be $8.85/MWh, rising to $10.90/MWh in 2024. At 0.9 to 1.1 cents per KWh these wind integration costs would be significant, but not overwhelming, relative to total rates of X to Y cents per KWh.
The discussion of integration costs raises a separate issue about the appropriate accounting frame for these costs. The Council is interested in costs from at least three perspectives – the cost of power, the cost of the fish and wildlife program (FWP), and the cost of wind integration. Clearly, these three are interrelated. The FWP imposes restrictions on flow, spill and peaking at the dams, which makes wind integration more difficult and costly. The question becomes – are the integration costs properly viewed as costs of the power system, or should they be viewed as costs of the FWP, much as spill costs are now treated as costs of the FWP? If at least part of the integration costs were viewed as FWP costs, this might shift attention to possible changes in the FWP that would enhance hydropower system flexibility and reduce integration costs – much the same way as the draft Plan now focuses on changes in power system management as a way to reduce integration costs. It would be appropriate to at least mention these topics somewhere in Chapter 11.
The IEAB applauds the ongoing work by Council staff and others to understand the issues raised by wind integration and to estimate its costs and rate impacts. At this time the IEAB has neither the budget nor the experience of working with power cost modeling to independently estimate these costs and impacts. However, the IEAB is ready if it becomes appropriate to offer its economic expertise to this effort.
