Idaho Public Utilities Commission

Case No. IPC-E-08-19, Order No. 30715

January 16, 2009

Contact: Gene Fadness (208) 334-0339, 890-2712



Commission adopts changes to PCA calculations


The Idaho Public Utilities Commission has approved changes in the way the annual Power Cost Adjustment (PCA) is calculated in hopes of decreasing the volatility in the rate adjustment, which can be either a one-year surcharge on customer bills or a one-year credit.


The normal costs for supplying power to customers are recovered in a utility’s base rates. However, a utility may incur higher than normal costs from unusual circumstances, such as low-water conditions or higher than anticipated market conditions. In those circumstances, the commission approved a PCA process that enables Idaho utilities to recover higher than normal costs. Revenues from a PCA surcharge are used only to pay the increased power costs and do not increase company earnings.


The PCA becomes effective June 1 every year. Because water conditions have been lower than normal and the market more volatile, customers have experienced wide variations in the PCA in recent years. The 2008 PCA was an average 10.7 percent increase for customers. In 2007, the surcharge was an average 14.5 percent increase. However, in 2006, there was an average 19.34 percent credit or decrease to customer rates.


To address the fluctuations in the PCA, the commission directed Idaho Power Co., commission staff and representative of customer groups to participate in workshops. Customer groups participating included those representing commission staff, Idaho Power, irrigation customers, industrial customers, Micron and the U.S. Department of Energy. The workshops resulted in a settlement agreed to by all parties and later approved by the commission.


Major components of the agreement include:


1) Since the 1992 inception of the PCA, 10 percent of the power supply costs above base rates were absorbed by the company and customers paid the remaining 90 percent in the form of the surcharge. Conversely, during those years when there was a credit, Idaho Power got 10 percent of the savings and customers received 90 percent.


The settlement adopted by the commission changes that sharing mechanism to require customers to pay 95 percent of above-normal power supply expense. During years when there is a credit, customers would get 95 percent of the savings. The sharing mechanism was put in place to incent the company to make wise decisions when purchasing energy because the company would be responsible for 10 percent of the costs of those decisions. However, since 1992, the volatility in power supply expense scenarios has increased from about $100 million to $330 million. The settlement proposes, and the commission agrees, that with a 95/5 share, the company’s risk and possible loss would be about the same proportionately as it was under the 90/10 share. “We do find that power supply cost volatility has increased significantly since the PCA was implemented, and that with increased volatility , a sharing percentage of 5 percent still provides strong incentive for the company to make prudent power purchases,” the commission said.


A further reason for the change to 95/5 is that after the 2000-01 Western energy crisis, the commission directed Idaho Power to develop a risk management policy that provides less discretion to Idaho Power when making its energy sales and purchases.


2) The settlement also adopts changes in the Load Growth Adjustment Rate, or LGAR. The LGAR acknowledges that Idaho Power’s revenues will increase between rate cases due to customer growth and changes in customer use. About $31.40 per megawatt-hour was subtracted from power supply expense to account for that growth. The settlement’s new methodology recognizes that the company also incurs additional power supply costs to serve new load between rate cases and has no opportunity to collect those costs. Therefore, the settlement reduces the LGAR to $28.14 per MWh.


3) A third component of the settlement makes changes to the formula for determining forecasted power supply expenses. The former methodology created unreasonably large true-ups between forecasted power supply costs and actual costs. The new method is designed to reduce that difference.


4) A fourth component allows Idaho Power to include third-party transmission expense in the PCA not already included in base rates. During 2007, third-party transmission costs were about $13 million. “We find that third-party transmission costs are incurred in conjunction with market purchase and sales and should be tracked through the PCA, like other variable power supply costs,” the commission said.