REGULATORY MATTERS

IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Included below is a summary of Idaho Power's regulatory assets and liabilities, as well as a discussion of notable regulatory matters.

Regulatory Assets and Liabilities

The application of accounting principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. 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, or represent amounts collected in advance of incurring an expense. The following table presents a summary of Idaho Power’s regulatory assets and liabilities (in thousands of dollars):



		As of December 31, 2015
	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		2015		2014
Regulatory Assets:
Income taxes		$	—	$	875,027	$	875,027	$	802,188
Unfunded postretirement benefits⁽²⁾		—		251,762		251,762		264,548
Pension expense deferrals		62,642		23,148		85,790		63,644
Energy efficiency program costs⁽³⁾		4,482		—		4,482		4,690
Power supply costs⁽⁴⁾	Varies	47,220		—		47,220		59,189
Fixed cost adjustment⁽⁴⁾	2016-2017	36,820		—		36,820		23,737
Asset retirement obligations⁽⁵⁾		—		14,410		14,410		17,309
Mark-to-market liabilities⁽⁶⁾		—		4,973		4,973		3,961
Long-term service agreement⁽⁷⁾	2043	18,592		11,633		30,225		—
Other	2016-2021	1,096		2,620		3,716		3,121
Total		$	170,852	$	1,183,573	$	1,354,425	$	1,242,387
Regulatory Liabilities:
Income taxes		$	—	$	51,131	$	51,131	$	55,490
Removal costs⁽⁵⁾		—		183,505		183,505		180,063
Investment tax credits		—		79,655		79,655		79,163
Deferred revenue-AFUDC⁽⁸⁾		58,835		28,855		87,690		72,975
Energy efficiency program costs⁽³⁾		6,554		—		6,554		—
Power supply costs⁽⁴⁾		—		—		—		1
Settlement agreement sharing mechanism⁽⁴⁾	2016-2017	3,159		—		3,159		7,999
Mark-to-market assets⁽⁶⁾		—		405		405		1,880
Other		5,219		1,180		6,399		4,036
Total		$	73,767	$	344,731	$	418,498	$	401,607

⁽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⁾ The 2015 energy efficiency asset represents the Oregon jurisdiction balance and the liability represents the Idaho jurisdiction balance. Both jurisdiction's balances were assets at December 31, 2014.

⁽⁴⁾ These items are discussed in more detail in this Note 3.

⁽⁵⁾ Asset retirement obligations and removal costs are discussed in Note 13.

⁽⁶⁾ Mark-to-market assets and liabilities are discussed in Note 16.

⁽⁷⁾ A portion not earning a return as of December 31, 2015 will be eligible to earn a return as of January 1, 2018.

⁽⁸⁾Idaho Power is collecting revenue in the Idaho jurisdiction for AFUDC on HCC 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 typically 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 net power supply costs (primarily fuel and purchased power less off-system sales) against net power supply costs being recovered. Under the PCA mechanisms, certain differences between actual net power supply costs incurred by Idaho Power and the costs are recorded as a deferred charge or credit on the balance sheets for future recovery or refund. The power supply costs deferred primarily result from changes in contracted power purchase prices and volumes, changes in wholesale market prices and transaction volumes, fuel prices, and the levels of Idaho Power's own generation.

Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual PCA adjustment consists of (a) a forecast component, based on a forecast of net power supply costs in the coming year as compared with 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 sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales changes does not distort the results of the mechanism.

The table below summarizes the three most recent Idaho PCA rate adjustments, all of which also include non-PCA-related rate adjustments as ordered by the IPUC:



Effective Date	$ Change (millions)			Notes
June 1, 2015	$	(11.6	)	The net decrease in Idaho PCA rates included the application of (a) a customer rate credit of $8.0 million for sharing of revenues with customers for the year 2014 under the terms of the December 2011 settlement stipulation, and (b) $4.0 million of surplus Idaho energy efficiency rider funds.
June 1, 2014	$	(88.2	)	2014 PCA rates are net of (a) $20.0 million of surplus Idaho energy efficiency rider funds, and (b) $7.6 million of customer revenue sharing under a regulatory settlement stipulation. In addition, on June 1, 2014, there was an increase in base net power supply costs that shifted $99.3 million in power supply expenses from recovery via the PCA mechanism to recovery via base rates. The shifting of base net power supply costs is discussed in more detail below.
June 1, 2013	$	140.4		The 2013 PCA rate increase was net of $7.2 million of customer revenue sharing under regulatory settlement stipulations.

In March 2014, the IPUC issued an order approving Idaho Power's application requesting an increase of approximately $106 million in the normalized or "base level" net power supply expense on a total-system basis to be used to update base rates and in the determination of the PCA rate that became effective June 1, 2014. Approval of the order removed the Idaho-jurisdictional portion of those expenses (approximately $99 million) from collection via the Idaho PCA mechanism and instead results in collecting that portion through base rates.

In July 2014, the IPUC opened a docket pursuant to which Idaho Power, the IPUC Staff, and other interested parties further evaluated Idaho Power's application of the true-up component of the PCA mechanism and whether a deferral balance adjustment was appropriate. While the IPUC's docket was closed in August 2014 with no adjustment to the PCA true-up revenue amount, Idaho Power subsequently met with the IPUC Staff to explore approaches to increasing the accuracy of the actual cost recovery under the PCA mechanism. In May 2015, the IPUC approved a settlement stipulation that resulted in the replacement of the existing load-based adjustment used for determining the power cost deferrals under the PCA mechanism with a similar sales-based adjustment. The sales-based adjustment functions in the same manner as the previous load-based adjustment but measures deviations between Idaho-specific test year sales and actual Idaho sales rather than deviations between test year loads and actual loads. The approved settlement stipulation implemented the new methodology as of January 1, 2015.

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 Oregon-jurisdictional 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 2015, 2014, and 2013 are summarized in the table that follows:



Year and Mechanism		APCU or PCAM Adjustment
2015 PCAM		Actual net power supply costs were within the deadband, resulting in no deferral.
2015 APCU		A rate decrease of $0.7 million annually took effect June 1, 2015.
2014 PCAM		Actual net power supply costs were within the deadband, resulting in no deferral.
2014 APCU		A rate increase of $0.4 million annually took effect June 1, 2014.
2013 PCAM		Actual net power supply costs were within the deadband, resulting in no deferral.
2013 APCU		A rate increase of $2.9 million annually took effect June 1, 2013.

Notable Idaho Regulatory Matters

Idaho Base Rate Changes: Idaho base rates were most recently established in 2012, and adjusted in 2014. Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from IPUC approval of a settlement stipulation that provided for a 7.86 percent authorized overall rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues. Idaho base rates were subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant. In June 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. Neither the settlement stipulation nor the IPUC orders adjusting base rates specified an authorized rate of return on equity or imposed a moratorium on Idaho Power filing a general rate case at a future date.

As noted above in this Note 3, the IPUC also issued a March 2014 order approving Idaho Power's request for an increase in the normalized or "base level" net power supply expense to be used to update base rates and in the determination of the Idaho PCA rate that became effective June 1, 2014.

December 2011 Idaho Settlement Stipulation: In December 2011, the IPUC issued an order, separate from the general rate case proceeding, approving a settlement stipulation that provided as follows:


•	If Idaho Power's actual Idaho-jurisdiction return on year-end equity (Idaho ROE) for 2012, 2013, or 2014 was less than 9.5 percent, then Idaho Power may amortize up to a total of $45 million of additional accumulated deferred investment tax credits (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 exceeded 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 mechanism adjustment.


•	If Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeded 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.

As Idaho Power's Idaho ROE exceeded 10.5 percent for each of 2012, 2013, and 2014, Idaho Power did not amortize additional ADITC for those years, but instead shared a portion of its Idaho-jurisdiction earnings with Idaho customers. The amounts Idaho Power recorded in each of 2012, 2013, and 2014 for sharing with customers under the December 2011 Idaho regulatory settlement stipulation were as follows (in millions):



Year	Recorded as Refunds to Customers	Recorded as a Pre-tax Charge to Pension Expense
2014	$8.0	$16.7
2013	$7.6	$16.5
2012	$7.2	$14.6

October 2014 Idaho Settlement Stipulation: In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of the December 2011 Idaho settlement stipulation for the period from 2015 through 2019, or until the terms are otherwise modified or terminated by order of the IPUC or the full $45 million of additional ADITC contemplated by the settlement stipulation has been amortized. The provisions of the new settlement stipulation are as follows:


•	If Idaho Power's annual Idaho ROE in any year is less than 9.5 percent, then Idaho Power may amortize up to $25 million of additional ADITC to help achieve a 9.5 percent Idaho ROE for that year, and may amortize up to a total of $45 million of additional ADITC over the 2015 through 2019 period.


•	If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding a 10.0 percent Idaho ROE and up to and including a 10.5 percent Idaho ROE will be allocated 75 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's power cost adjustment and 25 percent to Idaho Power.

•

If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 50 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's power cost adjustment, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension expense deferral regulatory asset (to reduce the amount to be collected in the future from Idaho customers), and 25 percent to Idaho Power.


•	If the full $45 million of additional ADITC contemplated by the settlement stipulation has been amortized the sharing provisions would terminate.


•	In the event the IPUC approves a change to Idaho Power's Idaho-jurisdictional allowed return on equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, 2020, the Idaho ROE thresholds (9.5 percent, 10.0 percent, and 10.5 percent) will be adjusted prospectively.

Neither the settlement stipulation nor the associated IPUC order impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding during the term of the settlement stipulation.

Idaho Power recorded no additional ADITC amortization and a $3.2 million provision against current revenue for sharing with customers for 2015 under the October 2014 Idaho settlement stipulation, as its Idaho ROE for 2015 was above 10.0 percent.

Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (FCA) mechanism is designed to remove Idaho Power’s financial 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 mechanism is adjusted each year to collect, or refund, the difference between the authorized fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year. The annual change in 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)
2014	June 1, 2015-May 31, 2016	$16.9
2013	June 1, 2014-May 31, 2015	$14.9
2012	June 1, 2013-May 31, 2014	$8.9

In July 2014, the IPUC opened a docket to allow Idaho Power, the IPUC Staff, and other interested parties to further evaluate the IPUC Staff's concerns regarding the application of the FCA mechanism (including weather-normalization, customer count methodology, rate adjustment cap, and cross-subsidization issues) and whether the FCA is effectively removing Idaho Power's disincentive to aggressively pursue energy efficiency programs. In May 2015, the IPUC approved a settlement stipulation that modified the FCA mechanism by replacing weather-normalized billed sales with actual billed sales in the calculation of the FCA, applicable for the entirety of calendar year 2015 and thereafter, and reflected in FCA charges effective June 1, 2016.

Notable Oregon Regulatory Matters

Oregon Base Rate Changes: Oregon base rates were most recently established in a general rate case in 2012. In February 2012, the OPUC issued an order approving a settlement stipulation that 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. Subsequently, in September 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

Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily 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, 2015 to September 30, 2016	$	23.43
October 1, 2014 to September 30, 2015	$	22.48
October 1, 2013 to September 30, 2014	$	22.80
October 1, 2012 to September 30, 2013	$	21.29

Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $121.3 million, which represents the OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.