The application of accounting principles related to regulated operations sometimes results in Idaho Power recording some expenses and revenues in a different period than when an unregulated enterprise would record those 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.


		As of December 31, 2022
	Remaining Amortization Period	Earning a Return(1)		Not Earning a Return		Total as of December 31,
Description						2022		2021
Regulatory Assets:
Income taxes(2)		$	—	$	739,689	$	739,689	$	721,276
Unfunded postretirement benefits(3)		—		70,254		70,254		315,011
Pension expense deferrals(4)		220,648		28,855		249,503		234,437
Energy efficiency program costs(5)		3,767		—		3,767		7,622
Power supply costs(6)	2023-2024	145,321		(16,012)		129,309		33,529
Fixed cost adjustment(6)	2023-2024	24,859		17,042		41,901		54,944
North Valmy plant settlements(6)	2023-2028	90,747		—		90,747		97,852
Jim Bridger plant settlement(6)	2023-2030	76,392		4,139		80,531		—
Asset retirement obligations(7)		—		28,780		28,780		22,585
Wildfire Mitigation Plan deferral(6)		—		27,078		27,078		6,075
Long-term service agreement	2023-2043	13,363		8,751		22,114		23,273
Other	2023-2056	2,790		15,498		18,288		17,050
Total		$	577,887	$	924,074	$	1,501,961	$	1,533,654
Regulatory Liabilities:
Income taxes(8)		$	—	$	94,946	$	94,946	$	96,880
Depreciation-related excess deferred income taxes(9)		158,634		—		158,634		170,039
Removal costs(7)		—		180,087		180,087		184,670
Investment tax credits		—		115,285		115,285		109,460
Deferred revenue-AFUDC(10)		159,001		48,527		207,528		187,717
Energy efficiency program costs(5)		154		—		154		—

Settlement agreement sharing mechanism(6)	2023	—		—		—		569
Mark-to-market liabilities		—		59,544		59,544		8,581
Tax reform accrual for future amortization(11)		—		32,793		32,793		24,522
Other		6,553		5,077		11,630		10,496
Total		$	324,342	$	536,259	$	860,601	$	792,934

(4) Idaho Power records a regulatory asset for the difference between net periodic pension cost and pension cost considered for rate-making purposes relating to Idaho Power's defined benefit pension plan. In its Idaho jurisdiction, Idaho Power’s inclusion of pension costs for the establishment of retail rates is based upon contributions made to the pension plan. This regulatory asset account represents the difference between cumulative cash contributions and amounts collected in rates. Deferred costs are amortized into expense as the amounts are provided for in Idaho retail revenues.

(9) In 2017, income tax reform reduced deferred income tax assets and liabilities. For depreciation-related temporary differences under the normalized tax accounting method, the resulting excess deferred taxes will flow back to customers ratably over the remaining regulatory lives of Idaho Power's plant assets under the alternative method provided in the statute.

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

In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment mechanisms address the volatility of power supply costs and provide for annual adjustments to the rates charged to its retail customers. The power cost adjustment mechanisms compare Idaho Power's actual net power supply costs (primarily fuel and purchased power less wholesale energy sales) against net power supply costs being recovered in Idaho Power's retail rates. Under the power cost adjustment mechanisms, certain differences between actual net power supply costs incurred by Idaho Power and costs being recovered in retail rates 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 the levels of Idaho Power's own hydroelectric generation, changes in contracted power purchase prices and volumes, changes in wholesale market prices and transaction volumes, and changes in fuel prices.

Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual power cost adjustment (PCA) 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 balancing component that trues up the difference between the previous year’s actual net power supply costs and the costs collected in the previous year's forecast component. The latter component ensures that, over time, the actual collection or refund of net power supply costs matches the amounts authorized. The PCA mechanism includes:

•a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (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


Effective Date	$ Change (millions)		Notes
June 1, 2022	$	94.9	The $94.9 million increase in PCA rates reflects a forecasted reduction in low-cost hydroelectric generation as well as higher costs associated with market energy prices and natural gas prices. The rate also reflects $0.6 million of 2021 earnings shared with customers under the May 2018 Idaho Tax Reform Settlement Stipulation described below.
June 1, 2021	$	39.1	The net increase in PCA rates reflects a forecasted reduction in low-cost hydroelectric generation as well as higher costs associated with forecasted PURPA power purchases. The net increase in PCA revenues also reflects a smaller credit to customers through the true-up component.
June 1, 2020	$	58.7	The $58.7 million increase in PCA rates reflects a return to a more normal level of power supply costs as wholesale market energy prices came down from unusually high levels in the previous year's PCA and a forecasted reduction in low-cost hydropower generation.

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. Actual 2022 Oregon-jurisdiction power supply costs exceeded the amount recovered through the APCU, resulting in a $1.1 million deferral of costs for future recovery. Oregon jurisdiction power supply cost changes during 2021 and 2020 did not have a material impact on the companies' financial statements.

January 2012 and June 2014 Idaho Base Rate Adjustments: 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.

May 2018 Idaho Tax Reform Settlement Stipulation: In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent.

In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation provided an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future regulatory asset recoverable from Idaho customers. The May 2018 Idaho Tax Reform Settlement Stipulation also provided for the indefinite extension, with modifications, of a previous settlement stipulation beyond its termination date of December 31, 2019.

The May 2018 settlement stipulation provides Idaho Power the ability to earn a minimum Idaho-Jurisdiction return on year-end equity (Idaho ROE) of 9.4 percent by amortizing up to $25 million of additional ADITC in any calendar year, so long as the cumulative amount of additional accumulated deferred investment tax credits (ADITC) used does not exceed $45 million; however, Idaho Power may seek approval from the IPUC to replenish the total amount of additional ADITC it is permitted to amortize and if there are no remaining amounts of additional ADITC authorized to be amortized, the remainder of the revenue sharing provisions below would not be applicable until additional ADITC is replenished.

If Idaho Power’s annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding 10.0 percent and up to and including 10.5 percent will be allocated 80 percent to Idaho Power’s Idaho customers as a rate reduction to be effective at the time of the subsequent year’s PCA, and 20 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 55 percent to Idaho Power’s Idaho customers as a rate reduction to be effective at the time of the subsequent year’s PCA, 25 percent to Idaho Power’s Idaho customers in the form of a reduction to the pension regulatory asset balancing account (to reduce the amount to be collected in the future from Idaho customers) and 20 percent to Idaho Power.

In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding effective on or after January 1, 2020, the Idaho ROE thresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at 95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 80 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c) sharing with customers on an 80 percent basis but allocated 55 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent of the newly authorized Idaho ROE.

In 2022, Idaho Power recorded no provision against current revenue for sharing with customers or additional amortization of ADITC, as its full-year Idaho ROE was between 9.4 percent and 10.0 percent. In 2021, Idaho Power recorded a $0.6 million provision against current revenue for sharing with customers, as its Idaho ROE exceeded 10.0 percent. Accordingly, at December 31, 2022, the full $45 million of additional ADITC remained available for future use under the terms of the May 2018 Idaho Tax Reform Settlement Stipulation.

Valmy Base Rate Adjustment Settlement Stipulations: Idaho Power has settlement stipulations in place in Idaho and Oregon related to the planned early retirement of both units of its jointly-owned North Valmy coal-fired power plant. Idaho Power ceased coal-fired operations at unit 1 in 2019, as planned, and plans to cease coal-fired operations at unit 2 in 2025. Both commissions have approved this plan. The IPUC-approved settlement stipulation provides for (1) accelerated depreciation for the North Valmy plant to allow the coal-related plant assets to be fully depreciated and recovered by December 31, 2028, (2) Idaho Power to use prudent and commercially reasonable efforts to end its participation in coal-fired operations at North Valmy as described above, (3) a balancing account to track the incremental costs, benefits, and required regulatory accounting associated with ceasing participation in coal-fired operations at the North Valmy plant, and (4) increased customer rates related to the associated incremental annual levelized revenue requirement. If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval.

Jim Bridger Power Plant Rate Base Adjustment and Recovery: In June 2022, the IPUC issued an order approving, with modifications, Idaho Power’s amended application requesting authorization to (1) accelerate depreciation for the Jim Bridger plant to allow the coal-related plant assets to be fully depreciated and recovered by December 31, 2030, (2) establish a balancing account to track the incremental costs, benefits, and required regulatory accounting associated with ceasing participation in coal-fired operations at the Jim Bridger plant, and (3) increase customer rates related to the associated incremental annual levelized revenue requirement (Bridger Order).

The Bridger Order allows for regulatory accounting entries and establishes balancing accounts (recorded as regulatory assets or liabilities on Idaho Power’s and IDACORP’s consolidated balance sheets) to track differences between amounts recovered in rates and actual incremental costs and benefits associated with Idaho Power’s cessation of coal-fired operations at the Jim Bridger plant. The incremental costs and benefits include the revenue requirement associated with the incremental Jim Bridger plant coal-related investments made from 2012 through the end of 2020, forecasted coal-related investments, and near-term decommissioning costs, offset by other operations and maintenance (O&M) cost savings. The Bridger Order deemed all coal-related investments at the Jim Bridger plant from 2012 through 2020 to be prudent for recovery. In the Bridger Order, the IPUC reduced Idaho Power's requested rate increase from 2.1 percent in its amended filing to 1.5 percent, a reduction from a requested $27.1 million to $18.8 million annually. The Bridger Order provides that any uncollected amount resulting from the reduction in the rate increase will be recorded in the balancing account for future recovery with no carrying charge. Idaho Power anticipates making future filings with the IPUC that may result in periodic adjustments to rates to true up variances between revenue collections and actual revenue requirement amounts.

The Bridger Order allows Idaho Power to earn a return on and recover through 2030 the net book value of coal-related assets at the Jim Bridger plant as of December 31, 2020, as well as forecasted coal-related investments, which resulted in Idaho Power's deferral of certain depreciation expense during the full year of 2022. The deferral and impacts of the Bridger Order resulted in an increase in net income for 2022 of approximately $20 million.

Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (FCA) mechanism, applicable to Idaho residential and small commercial customers, is designed to remove a portion of 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 (kWh) charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is included in the variable kWh charge, which may result in over-collection or under-collection of fixed costs. To return over-collection to customers or to collect under-collection from customers, the FCA mechanism allows Idaho Power to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the year. The IPUC has discretion to cap the annual increase in the FCA recovery at 3 percent of base revenue, with any excess deferred for collection in a subsequent year.

Wildfire Mitigation Cost Recovery: In June 2021, the IPUC authorized Idaho Power to defer for future amortization incremental O&M and depreciation expense for certain capital investments necessary to implement Idaho Power's Wildfire Mitigation Plan (WMP). The IPUC also authorized Idaho Power to record these deferred expenses as a regulatory asset until Idaho Power can request amortization of the deferred costs in a future IPUC proceeding, at which time the IPUC will have the opportunity to review actual costs and determine the amount of prudently incurred costs that Idaho Power can recover through retail rates. In its 2021 application with the IPUC, Idaho Power projected spending approximately $47 million in incremental wildfire mitigation-related O&M and roughly $35 million in wildfire mitigation system-hardening incremental capital expenditures over a five-year period. The IPUC authorized a deferral period of five years, or until rates go into effect from Idaho Power's next general rate case, whichever is first. As of December 31, 2022, Idaho Power's deferral of Idaho-jurisdiction costs related to the WMP was $27.1 million.

During the 2021 and 2022 wildfire seasons, Idaho Power identified needs for expanded mitigation measures by gaining additional insights and knowledge on wildfires and wildfire mitigation activities. In October 2022, Idaho Power filed an updated WMP with the IPUC along with an application requesting authorization to defer an estimated $16 million of newly identified incremental costs expected to be incurred between 2022 and 2025 associated with expanded wildfire mitigation efforts. As of the date of this report, the application with the IPUC is pending.

Oregon Base Rate Changes: Oregon base rates were most recently established in a general rate case in 2012. In February 2012, the Public Utility Commission of Oregon (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. Additionally, in October 2020, the OPUC approved an increase in Oregon customer rates of $0.4 million annually associated with amortization of deferred Langley Gulch power plant revenue requirement variances, effective November 1, 2020, through October 31, 2024.

In May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018 through May 31, 2020, related to income tax reform. In May 2020, the OPUC issued an order to approve the quantification of $1.5 million in annualized Oregon jurisdictional benefits associated with federal and state income tax changes resulting from tax reform and adjusting customer rates to reflect this amount, effective June 1, 2020, until its next general rate case or other proceeding where the tax-related revenue requirement components are reflected in rates.