REGULATORY MATTERS

As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies, including the prices that Idaho Power is authorized to charge for its electric service. These approvals are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition.

Regulatory Assets and Liabilities

Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, except for the cost of removal (which represents the cost of removing future electric assets). The following table presents a summary of Idaho Power’s regulatory assets and liabilities (in thousands of dollars):



		As of December 31, 2013
	Remaining Amortization Period	Earning a Return⁽¹⁾		Not Earning a Return		Total as of December 31,
Description	Remaining Amortization Period	Earning a Return⁽¹⁾		Not Earning a Return		2013		2012
Regulatory Assets:
Income taxes		$	—	$	710,482	$	710,482	$	677,795
Unfunded postretirement benefits⁽²⁾		—		116,583		116,583		308,850
Pension expense deferrals⁽³⁾		45,521		29,587		75,108		64,995
Energy efficiency program costs⁽³⁾		3,694		—		3,694		17,085
Power supply costs⁽³⁾	Varies	91,477		—		91,477		60,680
Fixed cost adjustment⁽³⁾	2014-2015	19,526		—		19,526		13,418
Asset retirement obligations⁽⁴⁾		—		18,026		18,026		15,411
Mark-to-market liabilities⁽⁵⁾		—		1,629		1,629		1,055
Other	2014-2021	1,992		1,554		3,546		3,749
Total		$	162,210	$	877,861	$	1,040,071	$	1,163,038
Regulatory Liabilities:
Income taxes		$	—	$	55,017	$	55,017	$	55,085
Removal costs⁽⁴⁾		—		173,974		173,974		168,651
Investment tax credits		—		79,121		79,121		79,897
Deferred revenue-AFUDC⁽⁶⁾		38,508		20,483		58,991		45,673
Energy efficiency program costs⁽³⁾		6,686		—		6,686		4,130
Power supply costs⁽³⁾	Varies	24		—		24		17,778
Settlement agreement sharing mechanism⁽³⁾	2014-2015	7,602		—		7,602		7,151
Mark-to-market assets⁽⁵⁾		—		1,672		1,672		4,579
Other		2,493		977		3,470		2,695
Total		$	55,313	$	331,244	$	386,557	$	385,639

⁽¹⁾ Earning a return includes either interest or a return on the investment as a component of rate base at the allowed rate of return.

⁽²⁾ Represents the unfunded obligation of Idaho Power’s pension and postretirement benefit plans, which are discussed in Note 11.

⁽³⁾ These items are discussed in more detail in this Note 3.

⁽⁴⁾ Asset retirement obligations and removal costs are discussed in Note 13.

⁽⁵⁾ Mark-to-market assets and liabilities are discussed in Note 16.

⁽⁶⁾ As part of its January 30, 2009 general rate case order, the IPUC allowed Idaho Power to recover AFUDC for the HCC relicensing asset even though the relicensing process is not yet complete and the relicensing asset has not been placed in service. Idaho Power has collected revenue in the Idaho jurisdiction for these relicensing costs, but is deferring revenue recognition of the amounts collected until the license is issued and the asset is placed in service under the new license.

Idaho Power’s regulatory assets and liabilities are amortized over the period in which they are reflected in customer rates. In the event that recovery of Idaho Power’s costs through rates becomes unlikely or uncertain, regulatory accounting would no longer apply to some or all of Idaho Power’s operations and the items above may represent stranded investments. If not allowed full recovery of these items, Idaho Power would be required to write off the applicable portion, which could have a materially adverse financial impact.

Power Cost Adjustment Mechanisms and Deferred Power Supply Costs

In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment (PCA) mechanisms address the volatility of power supply costs and provide for annual adjustments to the rates charged to its retail customers. The PCA mechanisms compare Idaho Power's actual and forecast net power supply costs (primarily fuel and purchased power less off-system sales) against net power supply costs currently being recovered in retail rates. Under the PCA mechanisms, certain differences between actual net power supply costs incurred by Idaho Power and the costs included in retail rates are recorded as a deferred charge or credit on the balance sheets for future recovery or refund through retail rates. The power supply costs deferred primarily result from changes in wholesale market prices and transaction volumes, fuel prices, changes in contracted power purchase prices and volumes (including PURPA power purchases), and the levels of Idaho Power's own hydroelectric and thermal generation.

Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual PCA adjustments consist of (a) a forecast component, based on a forecast of net power supply costs in the coming year as compared to net power supply costs included 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. The Idaho PCA mechanism also includes:


•	a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and shareholders (5 percent), with the exceptions of expenses associated with PURPA power purchases and demand response incentive payments, which are allocated 100 percent to customers; and


•	a load change adjustment rate, which is intended to ensure that power supply expense fluctuations resulting solely from load changes do not distort the results of the mechanism.

The table below summarizes the three most recent Idaho PCA rate adjustments.



Effective Date	$ Change (millions)			Notes
June 1, 2013	$	140.4		The 2013 Idaho PCA rates are offset by $7.2 million of Idaho revenue-sharing related to 2012 financial results pursuant to an IPUC order issued in 2012 under regulatory settlement agreements approved in January 2010 and December 2011. The $140.4 million increase in PCA rates includes the $19.9 million reduction in the revenue sharing amount (described below) from $27.1 million for the 2012-2013 PCA to $7.2 million for the 2013-2014 PCA.
June 1, 2012	$	43.0		The PCA rate increase was offset by $27.1 million to be shared with customers pursuant to the revenue sharing order described below, resulting in a net rate increase of $15.9 million for these orders.
June 1, 2011	$	(40.4	)	The reduction to Idaho PCA rates was net of $10.0 million of Idaho Power’s energy efficiency rider deferral balance that the IPUC authorized for recovery in Idaho Power’s Idaho PCA rates.

Oregon Jurisdiction Power Cost Adjustment Mechanism: Idaho Power’s power cost recovery mechanism in Oregon has two components: an annual power cost update (APCU) and a power cost adjustment mechanism (PCAM). The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same period. Under the PCAM, Idaho Power is subject to a portion of the business risk or benefit associated with this deviation through application of an asymmetrical deadband (or range of deviations) within which Idaho Power absorbs cost increases or decreases. For deviations in actual power supply costs outside of the deadband, the PCAM provides for 90/10 sharing of costs and benefits between customers and Idaho Power. However, collection by Idaho Power will occur only to the extent that Idaho Power’s actual return on equity (ROE) for the year is no greater than 100 basis points below Idaho Power’s last authorized ROE. A refund to customers will occur only to the extent that Idaho Power’s actual ROE for that year is no less than 100 basis points above Idaho Power’s last authorized ROE. Oregon jurisdiction power supply cost changes under the APCU and PCAM during each of 2013, 2012, and 2011 are summarized in the table that follows.



Year and Mechanism		APCU or PCAM Adjustment
2013 PCAM		Idaho Power estimates that actual net power supply costs were within the deadband, which would result in no deferral.
2013 APCU		A rate increase of $2.9 million annually took effect June 1, 2013.
2012 PCAM		Actual net power supply costs were within the deadband, resulting in no deferral.
2012 APCU		A rate increase of $1.8 million annually took effect June 1, 2012.
2011 PCAM		Actual net power supply costs were below the deadband, which would have resulted in a $1.5 million accrual of expense. However, Oregon-jurisdiction earnings were below the ROE threshold described above, resulting in no accrual.
2011 APCU		A rate decrease of $0.9 million annually took effect June 1, 2011.

Idaho Regulatory Matters

2011 Idaho General Rate Case Settlement: On June 1, 2011, Idaho Power filed a general rate case with the IPUC requesting approximately $82.6 million in additional Idaho jurisdiction annual revenues for collection through base rates. On September 23, 2011, Idaho Power, the IPUC Staff, and other interested parties filed a settlement stipulation with the IPUC resolving most of the key contested issues in the Idaho general rate case. The settlement stipulation, approved by the IPUC in December 2011, provided for a 7.86 percent authorized overall rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The approved settlement stipulation resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues, effective January 1, 2012. Neither the settlement stipulation nor the associated IPUC order specified an authorized rate of return on equity or imposed a moratorium on Idaho Power's filing a general rate case at a future date.

Idaho Power's Idaho jurisdiction base rates were again reset effective in July 2012, following completion of the Langley Gulch power plant, as described below.

January 2010 Idaho Settlement Agreement: In January 2010, the IPUC approved a settlement agreement among Idaho Power, the IPUC Staff, several of Idaho Power’s customers, and other interested parties. Significant elements of the settlement agreement included:


•	a specified distribution of the reduction in the 2010 PCA that would reduce customer rates, provide up to a $25 million general increase in annual base rates, and reset base power supply costs for the PCA, effective with the June 1, 2010 PCA rate change;


•	a provision to share with Idaho customers 50 percent of any Idaho-jurisdiction earnings in excess of a 10.5 percent return on year-end equity in the Idaho jurisdiction (Idaho ROE) in any calendar year from 2009 through 2011; and


•	a provision to allow the additional amortization of accumulated deferred investment tax credits (ADITC) if Idaho Power's Idaho-jurisdiction rate of return on year-end equity (Idaho ROE) is below 9.5 percent in any calendar year from 2009 through 2011.

Because Idaho Power’s actual Idaho ROE was between 9.5 and 10.5 percent in 2009 and 2010, the sharing and amortization provisions of the January 2010 settlement agreement were not triggered. However, recognition of income tax benefits in 2011 had a significant impact on Idaho Power's actual Idaho ROE and contributed to the triggering of the sharing mechanism for 2011. In accordance with the terms of the settlement agreement, Idaho Power recorded a $27.1 million reduction in revenue and recorded an associated regulatory liability in 2011, reflecting 50 percent of Idaho Power's 2011 Idaho-jurisdiction earnings above a 10.5 percent Idaho ROE to be shared with Idaho customers.

December 2011 Idaho Settlement Agreement: The sharing and ADITC amortization provisions of the January 2010 settlement agreement terminated on December 31, 2011. On December 27, 2011, the IPUC issued an order, separate from the general rate case proceeding, approving a settlement agreement extending, with modifications, some of the provisions of the January 2010 settlement agreement. The settlement agreement provided that:


•	if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 is less than 9.5 percent, then Idaho Power may amortize up to a total of $45 million of additional ADITC to help achieve a minimum 9.5 percent Idaho ROE in the applicable year;

•

if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.0 percent, the amount of Idaho Power's Idaho-jurisdiction earnings exceeding a 10.0 percent and up to and including a 10.5 percent Idaho ROE for the applicable year would be shared equally between Idaho Power and its Idaho customers in the form of a rate reduction to become effective at the time of the subsequent year's PCA adjustment; 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 75 percent to Idaho Power's Idaho customers as a reduction to the pension regulatory asset and 25 percent to Idaho Power.

The December 2011 settlement agreement provides that the return on year-end equity thresholds (9.5 percent, 10.0 percent, and 10.5 percent) will be 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. In consideration for the authority to amortize additional ADITC described above, the December 2011 settlement agreement provided that Idaho Power would allocate to customers as a reduction to the pension regulatory asset 75 percent of Idaho Power's own share of 2011 Idaho jurisdictional earnings over a 10.5 percent Idaho ROE.

Revenue Sharing Under January 2010 and December 2011 Idaho Settlement Agreements: The amounts Idaho Power recorded in each of 2011, 2012, and 2013 for revenue sharing under the January 2010 and December 2011 Idaho regulatory settlements described above were as follows (in millions):



Year	Recorded as Refunds to Customers	Recorded as a Pre-tax Charge to Pension Expense
2013	$7.6	$16.5
2012	$7.2	$14.6
2011	$27.1	$20.3

Cost Recovery for Langley Gulch Power Plant: 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 natural gas-fired power plant, which became commercially available in June 2012. 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 June 29, 2012, the IPUC issued an order 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.

Defined Benefit Pension Plan Contribution Recovery: Idaho Power has made substantial contributions to its defined benefit pension plan in recent years. Idaho Power defers its Idaho-jurisdiction pension expense as a regulatory asset until recovered from Idaho customers. As of December 31, 2013, Idaho Power's deferral balance associated with the Idaho jurisdiction was $72.6 million. Deferred pension costs are expected to be amortized to expense to match the revenues received when contributions are recovered through rates. Idaho Power only records a carrying charge on the unrecovered balance of cash contributions. In light of the substantial prior and expected future contributions, in March 2011 Idaho Power filed an application with the IPUC requesting an increase in the amount included in base rates for recovery of the Idaho-jurisdiction portion of Idaho Power's cash contributions to its defined benefit pension plan from the then-current amount of $5.4 million to approximately $17.1 million annually. On May 19, 2011, the IPUC approved Idaho Power’s application, with new rates effective on June 1, 2011.

Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (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. The amount of the FCA recovery is capped at no more than 3 percent of base revenue, with any excess deferred for collection in a subsequent year. The following table summarizes FCA amounts approved for collection in the prior three FCA years:



FCA Year	Period rates in effect	Annual Amount (in millions)⁽¹⁾
2012	June 1, 2013-May 31, 2014	$8.9
2011	June 1, 2012-May 31, 2013	$10.3
2010	June 1, 2011-May 31, 2012	$9.3

⁽¹⁾ The amount shown represents the total FCA deferred amount. The amount of the change in

the FCA amount for a year is calculated as the difference between the subject year's annual

FCA amount and the prior year's FCA amount.

The deferral for the 2013 FCA was $15.4 million which, pending approval by the IPUC, will be recovered between June 1, 2014 and May 31, 2015.

Energy Efficiency and Demand Response Programs: Idaho Power has implemented and/or manages a wide range of opportunities for its customers to participate in energy efficiency and demand response programs. Typically, a majority of energy efficiency activities are funded through a rider mechanism on customer bills. 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. In the 2012 PCA filing, $14.7 million of certain demand response program costs were shifted from the rider mechanism to the PCA mechanism, as these costs are closely related to and directly impact the other power supply costs collected through the PCA. The December 2011 IPUC general rate case settlement order described above reset Idaho Power's energy efficiency rider rate at 4.0 percent of the sum of the monthly billed charges for the base rate components, a reduction from the 4.75 percent rider amount in effect prior to that date.

On April 3, 2013, Idaho Power filed an application with the IPUC requesting an order finding Idaho Power's 2012 expenditures of $25.9 million in energy efficiency rider funds, $6.0 million in custom efficiency program incentives in a regulatory asset account, and $14.5 million of demand response program incentives included in the 2013 PCA, as prudently incurred demand-side management program expenses. On December 20, 2013, the IPUC issued an order finding all but $0.3 million of such expenses as prudently incurred, though the IPUC's order does provide Idaho Power with an opportunity to re-present $0.2 million of that amount for subsequent reconsideration. A previous order of the IPUC approved as prudently incurred $42.5 million of 2011 expenditures. As of December 31, 2013, the Idaho energy efficiency rider balance was a regulatory liability of $6.7 million. Separately, on June 12, 2013, the IPUC issued an order authorizing Idaho Power to recover custom efficiency program incentive payments, including the then-current regulatory account balance of $14.3 million, as well as subsequent custom efficiency program incentive payments, through the Idaho energy efficiency rider mechanism. As a result of the order, Idaho Power recognized the balance as other revenue and energy efficiency program expenses in 2013.

Certificate of Public Convenience and Necessity for Jim Bridger Plant Upgrades: On June 28, 2013, Idaho Power filed an application with the IPUC requesting that the IPUC issue a Certificate of Public Convenience and Necessity (CPCN) related to selective catalytic reduction (SCR) investments planned for Jim Bridger coal-fired plant units 3 and 4. Idaho Power's CPCN application requested that the IPUC provide Idaho Power with authorization and a binding commitment to provide rate base treatment for Idaho Power's share of the SCR investment in the amount of approximately $130 million (including AFUDC). Filing of the CPCN was intended to allow the IPUC to review the prudence of the investment in SCR prior to Idaho Power's incurring the bulk of the associated costs. On December 2, 2013, the IPUC issued an order granting Idaho Power's application for a CPCN. The IPUC, however, denied the company's additional request for early binding ratemaking treatment. The IPUC's order also requires that Idaho Power submit quarterly reports updating the IPUC on any changes to environmental policy or regulations until such time as the upgrades are in service, and that the company return to the IPUC if viable alternatives to the SCR upgrades become available.

Cost Recovery for Cessation of Boardman Coal-Fired Operations: 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 results in increased revenue requirements for Idaho Power related to accelerated depreciation expense, additional plant investments, and decommissioning costs. 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 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 December 31, 2013, Idaho Power's net book value in the Boardman plant was $21.2 million.

Idaho Depreciation Rate Filings: Idaho Power's advanced metering infrastructure (AMI) project provides the means to automatically retrieve and store energy consumption information, eliminating manual meter reading expense. Commencing June 1, 2009, the IPUC approved a rate increase, coincident with a related increase in depreciation expense, 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-jurisdiction base rates to reflect the revised depreciation rates. On May 31, 2012, the IPUC issued an order approving a settlement stipulation providing for a $1.3 million annual decrease in Idaho-jurisdiction base rates, effective June 1, 2012.

Oregon Regulatory Matters

2011 Oregon General Rate Case: On July 29, 2011, Idaho Power filed a general rate case and proposed rate schedules with the OPUC. 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, which the OPUC approved on February 23, 2012. 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. New rates in conformity with the settlement stipulation were effective March 1, 2012.

Cost Recovery for Langley Gulch Power Plant: On September 20, 2012, the OPUC issued an order approving an approximately $3.0 million increase in annual Oregon jurisdiction base rates, effective October 1, 2012, for inclusion of the Langley Gulch power plant in Idaho Power's Oregon rate base.

Federal Regulatory Matters - Open Access Transmission Tariff Rates

In 2006, Idaho Power moved from a fixed rate to 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. Idaho Power's OATT rates submitted to the FERC in Idaho Power's four most recent annual OATT Final Informational Filings were as follows:



Applicable Period	OATT Rate (per kW-year)
October 1, 2013 to September 30, 2014	$	22.80
October 1, 2012 to September 30, 2013	$	21.32
October 1, 2011 to September 30, 2012	$	19.79
October 1, 2010 to September 30, 2011	$	19.60

Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $118.2 million, which represents Idaho Power's net cost of providing OATT-based transmission service.