REGULATORY MATTERS

Recent and Pending Idaho Regulatory Matters

Idaho General Rate Case Settlement

On June 1, 2011, Idaho Power filed a general rate case and proposed rate schedules with the IPUC, Case No. IPC-E-11-08. On September 23, 2011, Idaho Power, the IPUC Staff, and other interested parties publicly filed a settlement stipulation with the IPUC resolving most of the key contested issues in the Idaho general rate case. On December 30, 2011, the IPUC issued an order approving the settlement stipulation. The settlement stipulation provides for a 7.86 percent authorized rate of return on an Idaho-jurisdictional rate base of approximately $2.36 billion. The approved settlement stipulation resulted in a $34.0 million overall increase in Idaho Power's annual Idaho jurisdictional base rate revenues, effective January 1, 2012. While both are final, neither the order nor the settlement stipulation specified an authorized rate of return on equity.

Settlement Stipulation -- Investment Tax Credits and Idaho Sharing Mechanism

On January 13, 2010, the IPUC approved a rate settlement agreement among Idaho Power, several of Idaho Power's customers, the IPUC Staff, and other parties. The settlement agreement provided for (a) the use of additional ADITC to help achieve a minimum 9.5 percent rate of return on year-end equity in the Idaho jurisdiction (Idaho ROE), and (b) an equal sharing between Idaho Power and its customers of Idaho jurisdiction earnings exceeding a 10.5 percent Idaho ROE. The sharing and ADITC amortization provisions of the January 2010 settlement agreement terminated on December 31, 2011.

On November 2, 2011, Idaho Power filed an application with the IPUC requesting an extension of the two elements of the January 2010 settlement agreement described above. On December 27, 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that provides as follows:


•	if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 is less than 9.5 percent, then Idaho Power may amortize additional ADITC to help achieve a minimum 9.5 percent Idaho ROE in the applicable year. Idaho Power would be permitted to amortize additional ADITC in an aggregate amount up to $45 million over the three-year period, but could use no more than $25 million in 2012;


•	if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.0 percent, the amount of Idaho Power's Idaho jurisdictional earnings exceeding a 10.0 percent but less than a 10.5 percent Idaho ROE for the applicable year would be shared equally between Idaho Power and its Idaho customers; and


•	if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.5 percent, the amount of Idaho Power's Idaho jurisdictional earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 25 percent to Idaho Power and 75 percent to benefit Idaho customers through an offset in the pension balancing account.

The settlement stipulation provides that the Idaho ROE thresholds (9.5 percent, 10.0 percent, and 10.5 percent) will be automatically adjusted prospectively in the event the IPUC approves a change to Idaho Power's authorized return on equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, 2015. The automatic adjustments would be as follows: (a) the 9.5 percent Idaho ROE trigger in the settlement stipulation would be replaced by the percentage equal to 95 percent of the new authorized rate of return on equity; (b) the 10.0 percent Idaho ROE trigger in the settlement stipulation would be re-established at the new authorized rate of return on equity; and (c) the 10.5 percent Idaho ROE trigger in the settlement stipulation would be replaced by the percentage equal to 105 percent of the new authorized rate of return on equity.

Revenue-Sharing Order Under January 2010 and December 2011 Settlement Agreements

On March 2, 2012, Idaho Power filed an application with the IPUC requesting authority to share revenues with customers based on year-end 2011 financial results, in accordance with the terms of settlement agreements executed in January 2010 and December 2011 described above. Idaho Power's revenue-sharing arrangements had two components: (1) a power cost adjustment mechanism component, which reduced net rates by $27.1 million effective June 1, 2012, and (2) a pension balancing account component, which resulted in a $20.3 million net reduction to Idaho Power's pension regulatory asset (reducing Idaho customers' future obligation). Idaho Power recorded the $27.1 million revenue reduction as a regulatory liability, and the $20.3 million pension regulatory asset reduction, in 2011. On May 31, 2012, the IPUC approved Idaho Power's March 2, 2012 application requesting a corresponding adjustment to Idaho-jurisdiction rates, effective for the period from June 1, 2012 to May 31, 2013.

Annual Power Cost Adjustment Mechanism Filing

Idaho Power has power cost adjustment (PCA) mechanisms in its Idaho and Oregon jurisdictions that address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers. In the Idaho jurisdiction, the annual PCA adjustments are based on (a) a forecast component, based on a forecast of net power supply costs in the coming year as compared to net power supply costs in base rates, and (b) a true-up component, based on the difference between the previous year’s actual net power supply costs and the previous year’s forecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or refund of authorized true-up dollars matches the amounts authorized. On May 31, 2012, the IPUC issued an order approving Idaho Power's April 13, 2012 application requesting a $43.0 million increase to Idaho PCA rates, effective for the period from June 1, 2012 to May 31, 2013. The PCA rate increase was offset by $27.1 million to be shared with customers pursuant to the revenue sharing order described above, resulting in a net rate increase of $15.9 million for these orders. By comparison, the PCA rates in effect from June 1, 2011 to May 31, 2012 were based on a May 31, 2011 IPUC order approving Idaho Power's requested $40.4 million Idaho PCA rate decrease.

Fixed Cost Adjustment Filings

The fixed cost adjustment (FCA) began as a pilot program for Idaho Power’s Idaho residential and small general service customers, running from 2007 through 2009. The FCA is designed to remove Idaho Power’s disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. The FCA is adjusted each year to collect, or refund, the difference between the allowed fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year.

On April 29, 2010, the IPUC approved a two-year extension of the FCA pilot program, retroactively effective from January 1, 2010 through December 31, 2011. On October 19, 2011, Idaho Power filed an application with the IPUC requesting that the FCA pilot program become permanent for residential and small general service customer classes effective January 1, 2012. On March 30, 2012, the IPUC issued an order approving the FCA as a permanent program. The order also maintained the existing 3 percent cap on the FCA adjustment. The IPUC noted in its order, however, that the FCA does not isolate or identify changes in cost recovery associated solely with Idaho Power's energy efficiency programs, and instead responds to all changes in load. While the IPUC rejected the IPUC Staff's proposal that FCA results be shared 50 percent with customers, the IPUC's order directed Idaho Power to file with the IPUC a proposal to adjust the FCA to address specified factors. Proceedings relating to a potential change to the FCA mechanism are ongoing.

On March 2, 2012, Idaho Power filed an application with the IPUC requesting an order authorizing Idaho Power to increase the annual FCA collection to $10.3 million, a $1.2 million increase in FCA rates, for the period from June 1, 2012 to May 31, 2013. On May 8, 2012, the IPUC issued an order approving Idaho Power's application as filed.

Langley Gulch Power Plant Cost Recovery Filing - Idaho

On September 1, 2009, Idaho Power received pre-approval from the IPUC to include $396.6 million of construction costs in Idaho Power’s rate base when the Langley Gulch natural gas-fired power plant achieved commercial operation. On March 2, 2012, Idaho Power filed an application with the IPUC requesting an increase in annual Idaho-jurisdiction base rates of $59.9 million for recovery of Idaho Power's investment and associated costs for the Langley Gulch power plant. Idaho Power's application stated that its estimated investment in the plant through June 2012 was approximately $398 million. After the impact of depreciation, deferred income taxes, amounts currently included in rates, and an Idaho-jurisdictional cost allocation, Idaho Power's application requested a $336.7 million increase in Idaho jurisdiction rate base. Idaho Power's requested base rate increase was based on an overall rate of return of 7.86 percent, as authorized by a prior IPUC order. On May 30, 2012, the IPUC Staff recommended to the IPUC that the $59.9 million increase in annual Idaho-jurisdiction base rates requested by Idaho Power be reduced to $58.1 million. The plant became commercially available on June 29, 2012. On that date, the IPUC issued an order consistent with the IPUC Staff's recommendation, approving a $58.1 million increase in annual Idaho-jurisdiction base rates, effective July 1, 2012. The order also provided for a $335.9 million increase in Idaho rate base.

Inclusion of the Langley Gulch power plant in Idaho Power's power supply portfolio resulted in a change in Idaho Power's power supply cost assumptions. Accordingly, in the Langley Gulch order the IPUC updated Idaho Power's load-change adjustment rate (LCAR) to $17.64 per MWh, effective July 1, 2012. The LCAR is intended to eliminate recovery of power supply expenses already collected in rates associated with load changes resulting from changing weather conditions, a growing customer base, or changing customer use patterns. The LCAR adjusts power supply cost recovery within the Idaho-jurisdiction PCA formula upwards or downwards for differences between actual load and the load used in calculating base rates. The settlement stipulation that became effective January 1, 2012 provided for a LCAR of $18.16 per MWh, effective January 1, 2012, compared to the rate of $19.67 per MWh in effect prior to that date.

Energy Efficiency and Demand Response Programs

Idaho Power manages a wide range of opportunities for its customers to participate in energy efficiency and demand response programs. On March 15, 2012, Idaho Power filed an application with the IPUC requesting an order designating Idaho Power's 2011 demand-side management expenditures of $42.6 million as prudently incurred. Of Idaho Power's 2011 demand-side management expenditures, approximately $36 million was funded through a rider mechanism on customer bills and approximately $7 million was recorded as a regulatory asset. As of the date of this report, a determination of prudence and order from the IPUC is pending. As of June 30, 2012, the Idaho portion of the energy efficiency rider balance was a regulatory asset of $1.6 million. Idaho Power's previous application filed in March 2011, which was approved by the IPUC in August 2011, designated Idaho Power's 2010 Idaho energy efficiency rider expenditures of approximately $42 million as prudently incurred expenses. Typically, a majority of energy efficiency activities are funded through a rider mechanism on customer bills. Per an IPUC order, program expenditures are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no impact on earnings. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or obligation to customers.

Cost Recovery for Cessation of Boardman Coal-Fired Operations - Idaho

In December 2010, the Oregon Environmental Quality Commission approved a plan to cease coal-fired operations at the Boardman power plant not later than December 31, 2020. The plan for a 2020 shutdown of coal-fired operations at the Boardman plant results in increased revenue requirements for Idaho Power related to accelerated depreciation expense, additional plant investments, and decommissioning costs. As a result, in response to an application filed by Idaho Power, on February 15, 2012 the IPUC issued an order accepting Idaho Power's regulatory accounting and cost recovery plan associated with the early plant shut-down and approving the establishment of a balancing account whereby incremental costs and benefits associated with the early shut-down will be tracked for recovery in a subsequent proceeding. On February 15, 2012, Idaho Power filed an application with the IPUC requesting a $1.6 million annual increase in Idaho-jurisdiction base rates to recover the incremental Idaho jurisdictional levelized annual revenue deficiency associated with early shut-down. On May 17, 2012, the IPUC issued an order approving a $1.5 million annual increase in Idaho-jurisdiction base rates, with new rates effective June 1, 2012. As of June 30, 2012, Idaho Power's net book value in the Boardman plant was $22.1 million.

Idaho Depreciation Rate Filings

The advanced metering infrastructure (AMI) project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. Commencing June 1, 2009, the IPUC approved a rate increase, allowing Idaho Power to recover the three-year accelerated depreciation of the existing non-AMI metering equipment and to begin earning a return on its AMI investment. On April 27, 2012, the IPUC approved Idaho Power's February 15, 2012 application requesting approval of a $10.6 million decrease in rates for specified customer classes, effective June 1, 2012, as a result of the removal of accelerated depreciation expense associated with non-AMI metering equipment.

In connection with a depreciation study authorized by Idaho Power and conducted by a third party, on February 15, 2012, Idaho Power filed an application with the IPUC seeking to institute revised depreciation rates for electric plant-in-service, based upon updated service life estimates and net salvage percentages for all plant assets, and adjust Idaho-jurisdictional base rates to reflect the revised depreciation rates. Idaho Power's application requested a $2.7 million increase in Idaho-jurisdictional base rates. On May 31, 2012, the IPUC issued an order approving a settlement stipulation agreed to by Idaho Power, the IPUC Staff, and a large industrial customer of Idaho Power, which provided for a $1.3 million annual decrease in Idaho-jurisdiction base rates, effective June 1, 2012.

Recent and Pending Oregon Regulatory Matters

Oregon General Rate Case Filing

On July 29, 2011, Idaho Power filed a general rate case and proposed rate schedules with the OPUC, Case No. UE 233. The filing requested a $5.8 million increase in annual Oregon jurisdictional revenues and an authorized rate of return on equity of 10.5 percent, with an Oregon retail rate base of approximately $121.9 million. Idaho Power, the OPUC Staff, and other interested parties executed and filed a partial settlement stipulation with the OPUC on February 1, 2012, resolving all matters in the general rate case other than the prudence of costs associated with pollution control investments at the Jim Bridger coal-fired power plant. The settlement stipulation provided for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. On February 23, 2012, the OPUC issued an order adopting the settlement stipulation. New rates in conformity with the settlement stipulation went into effect on March 1, 2012. The OPUC is conducting a second phase of the proceedings to address the prudence of Idaho Power's pollution control investments at the Jim Bridger plant.

Langley Gulch Power Plant Cost Recovery Filing - Oregon

On March 9, 2012, Idaho Power filed an application with the OPUC requesting an annual increase in Oregon-jurisdictional revenues of $3.0 million for inclusion of the Langley Gulch power plant in Idaho Power's rate base. A scheduling order issued by the OPUC provides for an OPUC decision by January 2013 and inclusion in rates by March 2013. In June 2012, the OPUC issued an order allowing Idaho Power to defer the annual $3.0 million of revenues associated with the Langley Gulch power plant for a twelve month period beginning July 1, 2012.

Federal Open Access Transmission Tariff Rate

Idaho Power uses a formula rate for transmission service provided under its open access transmission tariff (OATT), which allows transmission rates to be updated annually based on financial and operational data Idaho Power files with the FERC. On June 1, 2012, Idaho Power posted its 2012 transmission rate draft informational filing reflecting an OATT rate of $21.32 per kW-year, to be effective for the period from October 1, 2012 to September 30, 2013. Idaho Power's filing was based on its net annual transmission revenue requirement of $108.4 million. The OATT rate in effect from October 1, 2011 to September 30, 2012 is $19.79 per kW-year.