20141016press release.pdf

Case No. IPC-E-13-22, Order No. 33150
Contact: Gene Fadness [phone], 890-2712
www.puc.idaho.gov

Commission adopts updated costs wind developers pay
for integrating wind generation onto Idaho Power’s system

BOISE (Oct. 16, 2014) – State regulators have adopted updated rates to be charged wind
developers who sell energy to Idaho Power Company to account for the utility’s expense of
integrating the wind onto its distribution and transmission system. The commission also
approved a new method for calculating the wind integration charge.

“We find that the current mechanism for recovery of integration costs has resulted in under-
collection of the actual costs required to integrate wind onto Idaho Power’s system,” the Idaho
Public Utilities Commission said. That is not in the best interest of Idaho Power ratepayers
because expense to integrate wind that is not paid by wind developers is borne by customers.

In seeking the updated rates, Idaho Power said its ability to integrate wind into its system was
nearing its limit. The utility has about 678 megawatts of wind capacity on its system now, 505
MW of that coming online since 2010. The integration rate has not been updated since 2007.

The intermittency of wind forces Idaho Power to modify its system operations to ensure
transmission grid reliability. The utility must provide reserves from other resources -- such as
hydro or natural gas -- that can increase or decrease generation on short notice to offset
changes in wind generation. The effect of having to use other resources as operating reserve
restricts those same resources from being economically dispatched to their fullest capability,
resulting in higher power supply costs passed on to customers. The federal Public Utility
Regulatory Policies Act (PURPA) requires Idaho Power to buy the wind from qualifying
renewable energy projects.

Under the previous method, the wind integration charge was calculated by using a percentage
of the avoided-cost rate set by the commission. The avoided-cost rate is the rate paid to
renewable energy developers based on the cost the utility avoids by not having to generate the
power itself or buy it from another source. However, Idaho Power claimed that basing the
integration charge on the avoided-cost rate has no relation to the actual costs of the additional
reserves needed to integrate variable resources on its system.

Under the new method approved by the commission, wind developers will pay a tariff rate that
is not based on a percentage of avoided-cost. Instead, the rate is established in a tariff that
increases as the utility’s overall wind penetration level increases because costs increase as
more wind is added to the system. However, an increase to the integration rate when wind
generation hits specific thresholds is applied only to new projects as they sign on. The rate each
developer pays is determined at the signing of the contract so that developers have certainty as
to what they will pay over the term of what is typically a 20-year contract.

For example, at the utility’s current wind penetration level of between 600 MW and 700 MW, a
developer of a project that signs in 2014 would pay an integration rate of $11.99 per megawatt-
hour. For a non-levelized contract, that rate increases to $21.03 per MWh through the
contract’s end at 2033. The integration rate increases for new projects for every 100 MW of
additional wind penetration up to 1,100 MW.

Intervenors representing the Renewable Northwest Project and the American Wind Energy
Association said Idaho Power’s proposal results in rates that are too high because the method it
uses to calculate its reserve requirement to accommodate wind results in a reserve three times
greater than necessary. The intervenors said the utility is not using actual wind integration
expense to calculate the integration rate, but instead is using costs associated with having to re-
sell surplus wind energy that PURPA compels Idaho Power to buy even when the wind is not
needed.

The commission said the intervenors are not taking into account other costs the utility incurs
because of PURPA’s must-buy requirements. “We find that if a utility incurs additional
operational costs as a result of having to balance intermittent, must-take PURPA generation,
those costs are reasonably classified as integration costs,” the commission said. “It is also in
accord with this commission’s position that PURPA transactions should not harm ratepayers.”

The commission’s final order and other documents related to this case are on the commission’s
Website at www.puc.idaho.gov. Click on “Open Cases,” under the Electric heading and scroll
down to Case No. IPC-E-13-22. Petitions for reconsideration must be filed with the commission
by no later than Oct. 31.

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