XML 48 R20.htm IDEA: XBRL DOCUMENT
v3.24.0.1

REGULATORY MATTERS: | 12 Months Ended
--- | ---
Dec. 31, 2023
Regulated Operations [Abstract] |
Regulatory Matters | 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 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. The following table presents a summary of Idaho Power’s regulatory assets and liabilities (in thousands of dollars):
|  |  |  | As of December 31, 2023 |  |  |  |
|  | Remaining Amortization Period |  | Earning a Return(1) |  | Not Earning a Return |  | Total as of December 31,
Description |  |  |  |  | 2023 |  | 2022
Regulatory Assets: |  |  |  |  |  |  |  |  |  |
Income taxes(2) |  |  |  | $ | — |  |  | $ | 774,672 |  |  | $ | 774,672 |  |  | $ | 739,689 |
Unfunded postretirement benefits(3) |  |  |  | — |  |  | 87,318 |  |  | 87,318 |  |  | 70,254 |
Pension expense deferrals(4) |  |  |  | 253,744 |  |  | 1,500 |  |  | 255,244 |  |  | 249,503 |
Energy efficiency program costs(5) |  |  |  | — |  |  | — |  |  | — |  |  | 3,767 |
Power supply costs(6) |  | 2024-2025 |  | 134,816 |  |  | (19,291) |  |  | 115,525 |  |  | 129,309 |
Fixed cost adjustment(6) |  | 2024-2025 |  | 36,037 |  |  | 15,248 |  |  | 51,285 |  |  | 41,901 |
North Valmy plant settlements(6) |  | 2024-2028 |  | 82,917 |  |  | — |  |  | 82,917 |  |  | 90,747 |
Jim Bridger plant settlement(6) |  | 2024-2030 |  | 108,376 |  |  | 15,256 |  |  | 123,632 |  |  | 80,531 |
Wildfire Mitigation Plan deferral(6) |  |  |  | — |  |  | 51,329 |  |  | 51,329 |  |  | 27,078 |
Asset retirement obligations(7) |  |  |  | — |  |  | 35,270 |  |  | 35,270 |  |  | 28,780 |
Long-term service agreement |  | 2024-2043 |  | 12,679 |  |  | 8,276 |  |  | 20,955 |  |  | 22,114 |
Other |  | 2024-2056 |  | 2,330 |  |  | 52,573 |  |  | 54,903 |  |  | 18,288 |
Total |  |  |  | $ | 630,899 |  |  | $ | 1,022,151 |  |  | $ | 1,653,050 |  |  | $ | 1,501,961 |
Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |
Income taxes(8) |  |  |  | $ | — |  |  | $ | 108,641 |  |  | $ | 108,641 |  |  | $ | 94,946 |
Depreciation-related excess deferred income taxes(9) |  |  |  | 147,950 |  |  | — |  |  | 147,950 |  |  | 158,634 |
Removal costs(7) |  |  |  | — |  |  | 175,369 |  |  | 175,369 |  |  | 180,087 |
Investment tax credits |  |  |  | — |  |  | 165,479 |  |  | 165,479 |  |  | 115,285 |
Deferred revenue-AFUDC(10) |  |  |  | 177,884 |  |  | 50,787 |  |  | 228,671 |  |  | 207,528 |
Energy efficiency program costs(5) |  |  |  | 1,507 |  |  | — |  |  | 1,507 |  |  | 154 |
Power supply costs(6) |  |  |  | 1,240 |  |  | — |  |  | 1,240 |  |  | — |
Mark-to-market liabilities |  |  |  | — |  |  | 88 |  |  | 88 |  |  | 59,544 |
Tax reform accrual for future amortization(11) |  |  |  | — |  |  | 40,891 |  |  | 40,891 |  |  | 32,793 |
Other |  |  |  | 8,383 |  |  | 4,334 |  |  | 12,717 |  |  | 11,630 |
Total |  |  |  | $ | 336,964 |  |  | $ | 545,589 |  |  | $ | 882,553 |  |  | $ | 860,601 |
(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. The interest rate on deferral accounts is published annually by the IPUC and OPUC. The applicable rates for 2023 were 2% and 4.5%, respectively. (2) Represents flow-through income tax accounting differences which have a corresponding deferred tax liability disclosed in Note 2 - "Income Taxes." (3) Represents the unfunded obligation of Idaho Power’s pension and postretirement benefit plans, which are discussed in Note 11 - "Benefit Plans." (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. (5) The energy efficiency asset and liability represent the separate Idaho and Oregon jurisdiction balances at December 31, 2022, and December 31, 2023, respectively. During 2023, the balances changed from an asset to a liability in the Idaho jurisdiction. (6) This item is discussed in more detail in this Note 3 - "Regulatory Matters." (7) Asset retirement obligations and removal costs are discussed in Note 13 - "Asset Retirement Obligations (ARO)." (8) Represents the tax gross-up related to the depreciation-related excess deferred income taxes and investment tax credits included in this table and has a corresponding deferred tax asset disclosed in Note 2 - "Income Taxes." (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. (10) 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. (11) Represents amount accrued under the May 2018 Idaho tax reform settlement stipulation (described below) for the future amortization of existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers. 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 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 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 •a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales volume changes does not distort the results of the mechanism. The Idaho deferral period or Idaho-jurisdiction PCA year runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. In May 2023, the IPUC approved recovery of an incremental $200.2 million of Idaho-jurisdiction PCA revenues, but directed Idaho Power to spread recovery of the $190.2 million deferral balance component of the PCA over a two-year period from June 1, 2023 to May 31, 2025, resulting in a total PCA increase of $105.1 million, effective for the PCA collection period from June 1, 2023 to May 31, 2024. The order deferred collection of $95.1 million of deferred PCA costs to the subsequent annual PCA collection period from June 1, 2024, to May 31, 2025. The net increase in PCA revenues reflects higher market energy and natural gas prices, combined with lower-than-expected hydropower generation and limited coal supply in the prior April 2022 to March 2023 PCA period. The net increase also reflects an expectation of continued elevated market energy and natural gas prices in the April 2023 to March 2024 forecast period. The table below summarizes the three most recent Idaho-jurisdiction PCA rate adjustments, which also include non-PCA-related rate adjustments as ordered by the IPUC:
Effective Date |  | $ Change (millions) |  | Notes
June 1, 2023 |  | $ | 105.1 |  |  | The $105.1 million increase in PCA rates reflects higher market energy and natural gas prices, combined with lower-than-expected low-cost hydropower generation and limited coal supply. The increased rate also reflects an expectation of continued elevated market energy prices and natural gas prices in the forecast period.
June 1, 2022 |  | $ | 94.9 |  |  | The increase in PCA rates reflected 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 reflected $0.6 million of 2021 earnings shared with customers under the 2018 Settlement Stipulation described below.
June 1, 2021 |  | $ | 39.1 |  |  | The net increase in PCA rates reflected a forecasted reduction in low-cost hydroelectric generation as well as higher costs associated with forecasted PURPA power purchases. The net increase in PCA rates also reflected a smaller credit to customers through the true-up component.
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 2023 Oregon-jurisdiction power supply costs were less than the amount recovered through the APCU, resulting in a $0.9 million refund due to customers, while in 2022, Oregon jurisdiction power supply cost exceeded the amount recovered through the APCU, resulting in a $1.1 million deferral of costs for future recovery. Variances during 2023 and 2022 did not have a material impact on the companies' financial statements. Idaho Power's annual June 1 APCU rate changes were $7.7 million, $4.0 million, and $2.4 million in 2023, 2022, and 2021, respectively. Notable Idaho Base Rate Adjustments Idaho base rates were most recently established through a general rate case in 2023, with rate changes effective January 1, 2024. Previously, base rates were established in a general rate case in 2012 and adjusted in 2014, 2017, 2018, and 2019. 2023 Idaho General Rate Case: In June 2023, Idaho Power filed a general rate case with the IPUC. In December 2023, the IPUC issued an order approving a settlement stipulation among parties (2023 Settlement Stipulation) settling the general rate case. The Order and the 2023 Settlement Stipulation contains the following significant terms, among other items: •Idaho Power will implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by $54.7 million, or 4.25 percent, effective January 1, 2024. The $54.7 million of additional annual revenue is net of an Idaho-jurisdiction PCA rate decrease of $168.3 million and a reduction to annual energy efficiency rider collection of $3.5 million, each of which was transferred into base rates; •A 9.6 percent return on equity and a 7.247 percent authorized rate of return based on a non-specified cost of debt and capital structure, applied to an Idaho-jurisdictional rate base of approximately $3.8 billion; •Modifications to the Idaho-jurisdiction PCA including establishment of a new level of base net power supply expense of $484.9 million, which includes the transfer of $168.3 million from current PCA rates to base rates; •Modifications to the energy efficiency rider to support the transfer of $3.5 million of energy efficiency labor-related cost collection from the annual energy efficiency rider into base rates, warranting a decrease in the energy efficiency rider rate from 3.1 percent to 2.35 percent; •Modifications to the Idaho-jurisdiction FCA mechanism to support Idaho Power’s rate designs and to reflect updated fixed costs; •Continued deferral of incremental vegetation management and insurance costs, as measured from 2022 actual costs, through the earlier of Idaho Power’s next Idaho general rate case or 2025; •An annual $18 million increase in collection of Idaho Power’s regulatory asset associated with its defined benefit pension plan contributions; •Modifications to Idaho Power’s ADITC and revenue sharing mechanism beginning in 2024 to (1) include an additional amount of investment tax credits equal to the incremental investment tax credits generated from Idaho Power’s investment in 2023 battery storage projects; (2) remove the existing $25 million annual cap on the amount of accelerated amortization of ADITCs; (3) establish a minimum specified Idaho ROE of 9.12 percent for additional amortization of ADITCs; (4) establish a 9.6 percent Idaho ROE as the threshold for revenue sharing of Idaho-jurisdiction earnings between Idaho Power and Idaho customers; and (5) implement all revenue sharing through the PCA rather than a portion offsetting customer-funded pension obligations; •Agreement that Idaho Power’s capital expenditures through year-end 2022 were prudently incurred; •Deferral and amortization of annual differences between certain periodic maintenance costs at Idaho Power’s natural gas-fired power plants; and •A residential price modernization plan and updated rate designs. Under the modified ADITC and Revenue Sharing mechanism, if Idaho Power's annual Idaho ROE in any year exceeds 9.6 percent, the amount of earnings exceeding 9.6 percent will be allocated 80.0 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 20.0 percent to Idaho Power. In 2023, Idaho Power recorded no amortization of ADITC. Accordingly, at December 31, 2023, the full amount of ADITC remained available for future use under the terms of the 2023 Settlement Stipulation and the 2018 Settlement Stipulation described below. May 2018 Idaho Tax Reform Settlement Stipulation: In May 2018, the IPUC issued an order approving a settlement stipulation (2018 Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the 2018 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 2018 Settlement Stipulation also provided for the indefinite extension, with modifications, of a previous 2014 settlement stipulation beyond its termination date of December 31, 2019, with modified terms related to the ADITC and revenue sharing mechanism that became effective January 1, 2020. The 2018 Settlement Stipulation provided Idaho Power the ability to earn a minimum Idaho ROE of 9.4 percent by amortizing up to $25 million of additional ADITC in any calendar year. If Idaho Power’s annual Idaho ROE in any year exceeded 10.0 percent, the amount of earnings exceeding 10.0 percent and up to and including 10.5 percent would 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. Idaho Power’s ADITC and revenue sharing mechanism was modified by the 2023 Settlement Stipulation. North Valmy Base Rate Adjustment Settlement Stipulations: Idaho Power has settlement stipulations in place in Idaho and Oregon related to the planned end of its participation in coal-fired operations of both units of its jointly-owned North Valmy power plant. Idaho Power ceased coal-fired operations at unit 1 in 2019, as planned, and these settlement stipulations provide for Idaho Power to cease coal-fired operations at unit 2 in 2025. 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 plan at the time of the Bridger Order to cease its participation in coal-fired operations at the Jim Bridger plant by the end of 2028. 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 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. The uncollected amounts tracked in this balancing account were included for recovery in the 2023 Settlement Stipulation. 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. Other Notable Idaho Regulatory Matters Fixed Cost Adjustment: The 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 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. In May 2023, the IPUC issued an order approving a $10.1 million decrease in recovery from the FCA from $35.2 million to $25.1 million for the 2022 FCA deferral, with new rates effective for the period from June 1, 2023, to May 31, 2024. Beginning with the 2024 FCA deferral, the 2023 Settlement Stipulation updates the authorized fixed-cost recovery amount per customer and modifies parts of the FCA mechanism to support Idaho Power's proposed rate designs, as noted above. 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)
2022 |  | June 1, 2023-May 31, 2024 |  | $25.1
2021 |  | June 1, 2022-May 31, 2023 |  | $35.2
2020 |  | June 1, 2021-May 31, 2022 |  | $38.3
Wildfire Mitigation Cost Recovery: In June 2021 and March 2023, the IPUC issued orders authorizing Idaho Power to defer for future amortization incremental O&M and depreciation expense for certain capital investments necessary to implement Idaho Power's WMP. As of December 31, 2023, Idaho Power’s deferral balance of Idaho-jurisdiction costs related to the WMP was $51.3 million. As a result of the 2023 Settlement Stipulation, Idaho Power will recover and amortize its WMP deferral balance through 2022 of $26.7 million, beginning January 1, 2024. 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. 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. The OPUC has also approved settlement stipulations that provide for the accelerated cost recovery of jointly-owned North Valmy unit 1 through 2019 and unit 2 through 2025. The net rate impact of the Oregon settlement stipulations is immaterial. In December 2023, Idaho Power filed a general rate case with the OPUC. The filing was based on a 2024 test year and requested an overall annual rate increase of $10.7 million, or 19.28 percent. The filing requested, among other items, a 10.4 percent authorized rate of return on equity and an approximate $188.9 million Oregon-jurisdiction retail rate base. The $188.9 million of rate base excludes rate base associated with Idaho Power's jointly-owned North Valmy coal facilities, the costs of which are recovered under the separate rate mechanism noted above. In its application, Idaho Power proposed a capitalization structure of 49 percent long-term debt and 51 percent common stock equity. Idaho Power included an average cost of debt of 5.104 percent and an overall cost of capital of 7.807 percent. If approved by the OPUC, new rates for Oregon-jurisdiction customers would become effective in October 2024 or later. 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 actual financial and operational data Idaho Power files with the FERC and allows Idaho Power to recover costs associated with its transmission system. 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, 2023 to September 30, 2024 |  | $ | 30.74 |
October 1, 2022 to September 30, 2023 |  | $ | 31.42 |
October 1, 2021 to September 30, 2022 |  | $ | 31.19 |
October 1, 2020 to September 30, 2021 |  | $ | 29.95 |
Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $135.7 million, which represents the OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.

X
- Definition The entire disclosure for public utilities. + References Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef -Topic 980 -Name Accounting Standards Codification -Publisher FASB -URI https://asc.fasb.org//980/tableOfContent + Details
Name: | us-gaap_PublicUtilitiesDisclosureTextBlock
Namespace Prefix: | us-gaap_
Data Type: | dtr-types:textBlockItemType
Balance Type: | na
Period Type: | duration

X
- References No definition available. + Details
Name: | us-gaap_RegulatedOperationsAbstract
Namespace Prefix: | us-gaap_
Data Type: | xbrli:stringItemType
Balance Type: | na
Period Type: | duration