Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

NOTES TO FINANCIAL STATEMENTS

Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement.
Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock.
For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Commission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof.
Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However, where material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred.
Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.

PACIFICORP

NOTES TO FINANCIAL STATEMENTS

(1) Organization and Operations

PacifiCorp is a United States ("U.S.") regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp is an indirect subsidiary of Berkshire Hathaway Energy Company ("BHE"), a holding company based in Des Moines, Iowa that has investments in subsidiaries principally engaged in energy businesses. BHE is a wholly owned subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

(2) Summary of Significant Accounting Policies

Basis of Presentation

These financial statements are prepared in accordance with the requirements of the Federal Energy Regulatory Commission ("FERC") as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America ("GAAP"). These notes include certain applicable disclosures required by GAAP adjusted to the FERC basis of presentation and include specific information requested by the FERC.

The following are the significant differences between the FERC accounting and reporting standards and GAAP.

Investments in Subsidiaries

In accordance with FERC Order No. AC11-132, PacifiCorp accounts for its investment in subsidiaries using the equity method for FERC reporting purposes rather than consolidating the assets, liabilities, revenues and expenses of subsidiaries as required by GAAP. GAAP requires that entities in which a company holds a controlling financial interest be consolidated. Also in accordance with FERC Order No. AC11-132, PacifiCorp does not eliminate intercompany profit on transactions with equity investees as would be required under GAAP. The accounting treatment described above has no effect on net income or the combined retained earnings of PacifiCorp and undistributed earnings of subsidiaries.

Costs of Removal

Estimated removal costs that are recovered through approved depreciation rates, but that do not meet the requirements of a legal asset retirement obligation ("ARO") are reflected in the cost of removal regulatory liability under GAAP and as accumulated provision for depreciation under the FERC accounting and reporting standards.

Income Taxes

Accumulated deferred income taxes are classified as net non-current assets or liabilities on the balance sheet for GAAP. Under the FERC accounting and reporting standards, accumulated deferred income taxes are classified as gross non-current assets and gross non-current liabilities. Additionally, there are certain presentational differences between FERC and GAAP for amounts related to unrecognized tax benefits associated with temporary differences in accordance with FERC guidance. For GAAP, unrecognized tax benefits associated with temporary differences are reflected as other liabilities while for FERC the income tax impact of uncertain tax positions associated with temporary differences are reflected in accumulated deferred income taxes.

Interest and penalties on income taxes for GAAP are classified as income tax expense. All such amounts are classified as interest income, interest expense and penalties under the FERC accounting and reporting standards.

Pensions and Postretirement Benefits Other Than Pensions

Pension and postretirement benefits other than pensions ("PBOP") are comprised of several different components of net periodic benefit costs. As required by GAAP, the service cost component is reported with other compensation costs arising from services rendered by employees, while the other components of net periodic benefit costs are presented outside of operating income. Additionally, only the service cost component of net periodic benefit costs is eligible for capitalization under GAAP. In accordance with FERC guidance, PacifiCorp continues to report the components of net periodic benefit costs for pension and PBOP on the statement of income and follows GAAP guidance to capitalize only the service cost component of net periodic benefit costs.

Reclassifications

Certain other reclassifications of balance sheet, income statement and cash flow amounts have been made in order to conform to the FERC basis of presentation. These reclassifications had no effect on net income.

Use of Estimates in Preparation of Financial Statements

The preparation of the financial statements in conformity with the FERC and GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; certain assumptions made in accounting for pension and other postretirement benefits; AROs; income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for loss contingencies and applicable insurance recoveries, including those related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") and a wildfire that began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California in July 2022 (the "2022 McKinney Fire"), referred to together as "the Wildfires" as discussed in Note 14. Actual results may differ from the estimates used in preparing the financial statements.

Accounting for the Effects of Certain Types of Regulation

PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, PacifiCorp defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in rates occur.

If it becomes no longer probable that the deferred costs or income will be included in future rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").

Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered when determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.

Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents included in other special funds consist substantially of funds representing vendor retention, nuclear decommissioning and custodial funds. A reconciliation of cash and cash equivalents and restricted cash equivalents as of December 31, 2025 and 2024 as presented on the Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Comparative Balance Sheets (in millions):


	2025		2024
Cash (131)	$	8	$	20
Other special funds (128)	22		16
Temporary cash investments (136)	54		21
Total cash and cash equivalents and restricted cash and cash equivalents	84		57

Investments

Available-for-sale securities are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. As of December 31, 2025 and 2024, PacifiCorp had no unrealized gains and losses on available-for-sale securities. Trading securities are carried at fair value with realized and unrealized gains and losses recognized in earnings.

Allowance for Credit Losses

Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination, and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on PacifiCorp's assessment of the collectability of amounts owed to PacifiCorp by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, PacifiCorp primarily utilizes credit loss history. However, PacifiCorp may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. The changes in the balance of the allowance for credit losses, which is included in accumulated provision for uncollectible accounts on the Comparative Balance Sheet, is summarized as follows for the years ended December 31 (in millions):


	2025		2024
Beginning balance	$	22	$	30
Charged to operating costs and expenses, net	33		26
Write-offs, net	(35)		(34)
Ending balance	$	20	$	22

Derivatives

PacifiCorp employs a number of different derivative contracts, which may include forwards, options, swaps and other agreements, to manage price risk for electricity, natural gas and other commodities and interest rate risk. Derivative contracts are recorded on the Comparative Balance Sheet as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.

Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or operations expenses on the Statement of Income.

For PacifiCorp's derivative contracts, the settled amount is generally included in rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in rates are recorded as regulatory liabilities or assets. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.

Inventories

Inventories consist mainly of materials, supplies and fuel stocks and are stated at the lower of average cost or net realizable value.

Net Utility Plant

General

Additions to utility plant are recorded at cost. PacifiCorp capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs, which include debt and equity allowance for funds used during construction ("AFUDC"). The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed.

Depreciation and amortization are generally computed on the straight-line method based on composite asset class lives prescribed by PacifiCorp's various regulatory authorities or over the assets' estimated useful lives. Depreciation studies are completed periodically to determine the appropriate composite asset class lives, net salvage and depreciation rates. These studies are reviewed and rates are ultimately approved by the various regulatory authorities. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either accumulated provision for depreciation or an ARO liability on the Comparative Balance Sheet, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated accumulated provision for depreciation or ARO liability is reduced.

Generally when PacifiCorp retires or sells a component of regulated utility plant, it charges the original cost, net of any proceeds from the disposition, to accumulated provision for depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.

Debt and equity AFUDC, which represents the estimated costs of debt and equity funds necessary to finance the construction of utility plant is capitalized as a component of utility plant, with offsetting credits to the Statement of Income. AFUDC is computed based on guidelines set forth by the FERC. After construction is completed, PacifiCorp is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.

Asset Retirement Obligations

PacifiCorp recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. PacifiCorp's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to utility plant, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in utility plant and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.

Impairment

PacifiCorp evaluates long-lived assets for impairment, including utility plant, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the appropriate FERC accounts are adjusted to write down the asset to the estimated fair value and any resulting impairment loss is reflected on the Statement of Income. The impacts of regulation are considered when evaluating the carrying value of regulated assets.

Leases

PacifiCorp has non-cancelable operating leases primarily for land, office space, office equipment, and generating facilities and finance leases consisting primarily of battery energy storage systems ("Energy Storage"), office buildings, natural gas pipeline facilities, and vehicles. These leases generally require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. PacifiCorp does not include options in its lease calculations unless there is a triggering event indicating PacifiCorp is reasonably certain to exercise the option. PacifiCorp's accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Right-of-use assets are evaluated for impairment in line with GAAP when a triggering event has occurred that might affect the value and use of the assets being leased.

PacifiCorp's leases of generating facilities generally are in the form of long-term purchases of electricity, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy, and the payments are generally considered variable lease payments as they are based on the amount of output. The lease payments associated with PacifiCorp's Energy Storage agreements are considered fixed because they are based on the guaranteed storage capacity.

PacifiCorp follows FERC accounting and reporting requirements and records operating and finance right-of-use assets in Account 101.1, Property under capital leases, and the current and noncurrent operating and finance lease liabilities in Account 243, Obligations under capital leases � Current and Account 227, Obligations under capital leases � Noncurrent, respectively.

Revenue Recognition

PacifiCorp uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which PacifiCorp expects to be entitled in exchange for those goods or services. PacifiCorp records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Statement of Income.

Substantially all of PacifiCorp's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission and distribution and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided.

Revenue recognized is equal to what PacifiCorp has the right to invoice as it corresponds directly with the value to the customer of PacifiCorp's performance to date and includes billed and unbilled amounts. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and classified in accordance with FERC accounting standards.

The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since the date of the last meter reading is estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Unbilled revenue is reversed in the following month and billed revenue is recorded based on the subsequent meter readings.

Unamortized Debt, Premiums, Discounts and Debt Issuance Costs

Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.

Income Taxes

Berkshire Hathaway includes PacifiCorp in its U.S. federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for income taxes has been computed on a stand-alone basis.

Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities associated with certain property-related basis differences and other various differences that PacifiCorp deems probable to be passed on to its customers in most state jurisdictions are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse or as otherwise approved by PacifiCorp's various regulatory commissions. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.

Investment tax credits are deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions.

PacifiCorp recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement.

Government Grants

From time to time, PacifiCorp enters into grant agreements with federal agencies, as well as agreements with third parties as a subrecipient of a federal grant, subjecting PacifiCorp to various federal compliance requirements. Most commonly these are cost share grants where PacifiCorp expenditures match the amount of grant proceeds. Grant proceeds most frequently support capital projects but are also used to cover operating costs. Grant proceeds received to reimburse capital project costs are applied as a direct offset to construction work-in-progress, ultimately serving to reduce PacifiCorp's investment in net utility plant. Grant proceeds received to reimburse operating costs are applied as an offset to operation expense.

Segment Information

PacifiCorp currently has one reportable segment, its regulated electric utility operations, which derives its revenue from regulated retail sales of electricity to residential, commercial, industrial and irrigation customers and from wholesale sales. PacifiCorp's chief operating decision maker ("CODM") is its Chief Executive Officer. The CODM uses net income, as reported on the Consolidated Statements of Operations in PacifiCorp's GAAP financial statements that are filed with the U.S. Securities and Exchange Commission ("Consolidated Statements of Operations"), and generally considers actual results versus historical results, budgets or forecasts, as well as unique risks and opportunities, when making decisions about the allocation of resources and capital. The segment expenses regularly provided to the CODM align with the captions presented on the Consolidated Statements of Operations. PacifiCorp's segment capital expenditures are reported on the Statement of Cash Flows as cash outflows for plant. PacifiCorp's segment assets are reported on the Comparative Balance Sheet as total assets.

New Accounting Pronouncements

In June 2023, the FERC issued Order No. 898, "Accounting and Reporting Treatments of Certain Renewable Energy Assets" which amends the Uniform System of Accounts for public utilities and licensees to create new accounts for wind, solar, and other renewable generating assets; to create a new functional class for energy storage accounts; to codify the accounting treatment of environmental credits; to create new accounts within existing functions for computer hardware, computer software, and communication equipment; and to amend the relevant FERC forms to accommodate these changes. PacifiCorp adopted this guidance on January 1, 2025 on a prospective basis.

In December 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2023-09, Income Taxes Topic 740, "Income Tax�Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. PacifiCorp adopted this guidance for the fiscal year beginning January 1, 2025, under the retrospective method. The adoption did not have a material impact on PacifiCorp's financial statements, but did expand the disclosures included within Notes to Financial Statements. Refer to Note 9 for expanded rate reconciliation disclosures and disaggregation of income taxes paid.

In November 2024, the FASB issued ASU No. 2024-03, Income Statement�Reporting Comprehensive Income�Expense Disaggregation Disclosures Subtopic 220-40, "Disaggregation of Income Statement Expenses" which addresses requests from investors for more detailed information about certain expenses and requires disclosure of the amounts of purchases of inventory, employee compensation, depreciation and intangible asset amortization included in each relevant expense caption presented on the income statement. This guidance, as clarified in ASU 2025-01, is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. PacifiCorp is currently evaluating the impact of adopting this guidance on its financial statements and disclosures included within Notes to Financial Statements.

In December 2025, the FASB issued ASU No. 2025-10, Government Grants Topic 832, "Accounting for Government Grants Received by Business Entities" which establishes accounting for government grants received by an entity, including guidance for a grant related to an asset and a grant related to income. This guidance also requires, consistent with current disclosure requirements, that an entity provide disclosures including the nature of the government grant received, the accounting policies used to account for the grant, and significant terms and conditions of the grant. This guidance is effective for interim and annual reporting periods beginning after December 15, 2028. Early adoption is permitted and can be applied using either a modified prospective approach, a modified retrospective approach or a retrospective approach. PacifiCorp is currently evaluating the impact of adopting this guidance on its financial statements and disclosures included within Notes to Financial Statements.

Subsequent Events

Refer to Note 18 for information associated with the future sale of certain PacifiCorp assets and liabilities associated with PacifiCorp's Washington operations.

PacifiCorp has evaluated the impact on its financial statements of events occurring after December 31, 2025 up to February 27, 2026, the date that PacifiCorp's GAAP financial statements were filed with the U.S. Securities and Exchange Commission and has updated such evaluation for disclosure purposes through April 14, 2026. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.

(3) Net Utility Plant

The average depreciation and amortization rate applied to depreciable utility plant was 3.3% and 3.2% for the years ended December 31, 2025 and 2024, respectively, including the impacts of accelerated depreciation totaling $87 million associated with Utah's share of certain coal-fueled units and depreciation related regulatory assets pursuant to the April 2025 Utah general rate case order. Existing regulatory deferrals associated with the Utah Sustainability and Transportation Plan ("STEP") were utilized to accelerate depreciation of these assets.

Government Grants

In November 2024, PacifiCorp accepted two cost share grants from the U.S. Department of Energy ("DOE") under the DOE's Grid Resilience and Innovation Partnerships ("GRIP") Program supported by the Infrastructure Investment and Jobs Act. The two GRIP grants will provide cash proceeds totaling approximately $150 million as cost reimbursements supporting PacifiCorp's investment in certain wildfire mitigation projects, such as system hardening for fire resistance and prevention and new substation infrastructure, and other investments in technologies that significantly enhance situational awareness to reduce or mitigate wildfires and improve electric grid flexibility, reliability and resiliency. The period of performance for both GRIP grants extends through September 2028 and 2029. No costs incurred after the period of performance will be eligible for reimbursement.

In conjunction with the two GRIP awards, the DOE and U.S. Department of Labor accepted PacifiCorp's request for a temporary exception regarding the Davis-Bacon Act weekly pay and certified payroll reporting requirements with which PacifiCorp is required to comply under the terms of the grants. The parties agreed to a curative plan that provides for a temporary means to achieve the goals of these requirements and allows PacifiCorp to have until April 1, 2026, to fully comply with these requirements.

In December 2024, PacifiCorp accepted four cost share grants from the DOE under the DOE's Hydroelectric Efficiency Improvement Incentive, supported by Section 243 of the Energy Policy Act of 2005. Expected grant proceeds for the hydroelectric grants total approximately $14 million as cost reimbursements to support PacifiCorp's efforts to improve efficiency and extend the life of its generating assets. The period of performance for the hydroelectric grants runs through March 2028.

In December 2025, PacifiCorp entered into three state grant agreements related to grid resiliency, which are intended to support activities focused on wildfire mitigation, outage prevention and overall grid?hardening measures. PacifiCorp participates in these programs as a subrecipient with the state agencies serving as the prime recipients of DOE grants. The total amount allocated to PacifiCorp for these grants is approximately $8 million. The period of performance extends through April 2030.

Previous DOE cost share grants primarily supported electric vehicle infrastructure programs and energy efficiency programs. The period of performance for the electric vehicle infrastructure grant ended December 2024, and was for total cash proceeds of $6 million. The energy efficiency grant was cancelled by the DOE in October 2025.

On January 20, 2025, U.S. federal executive order entitled Unleashing American Energy was issued requiring federal agencies to immediately pause disbursement of federal funds appropriated under the Inflation Reduction Act of 2022 and the Infrastructure Investment and Jobs Act, subject to respective agency review within 90 days of the date of the order of the agency's processes, policies and programs for issuing grants consistent with the policies stated in the executive order. The pause was lifted on federal funding disbursements in April 2025 and the invoice process resumed.

Various compliance requirements are associated with the DOE grants, including demonstration that the costs are allowable under the grants. In the event PacifiCorp fails to meet these requirements, it could be required to return funds to the DOE. No costs incurred after the period of performance for a specific grant will be eligible for reimbursement.

During the years ended December 31, 2025 and 2024, approximately $50 million and $11 million, respectively, of federal grant funds reduced additions to net utility plant on the Comparative Balance Sheet and approximately $18 million and $4 million, respectively, of federal grant funds reduced operation and maintenance expenses on the Statement of Income. Federal grant funds received prior to 2024 were insignificant.

(4) Jointly Owned Utility Facilities

Under joint facility ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly owned generation, transmission and distribution facilities. PacifiCorp accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Statement of Income include PacifiCorp's share of the expenses of these facilities.

The amounts shown in the table below represent PacifiCorp's share in each jointly owned facility included in net utility plant as of December 31, 2025 (dollars in millions):


	PacifiCorp Share	Facility in Service		Accumulated Depreciation and Amortization		Construction Work-in-Progress

Jim Bridger Nos. 1 - 4	67%	$	1,543	$	1,034	$	2
Hunter No. 1	94	510		275		11
Hunter No. 2	60	317		174		�
Wyodak	80	495		319		�
Colstrip Nos. 3 and 4	10	267		248		2
Hermiston	50	198		125		7
Craig Nos. 1 and 2	19	373		228		�
Hayden No. 1	25	77		62		�
Hayden No. 2	13	45		36		�
Transmission and distribution facilities	Various	963		368		554
Total		$	4,788	$	2,869	$	576

(5) Leases

The following table summarizes PacifiCorp's leases recorded on the Comparative Balance Sheet as of December 31 (in millions):


	2025		2024
Right-of-use assets:
Operating leases	$	10	$	11
Finance leases(1)	430		24
Total right-of-use assets	$	440	$	35

Lease liabilities:
Operating leases	$	10	$	11
Finance leases(1)	432		24
Total lease liabilities	$	442	$	35

(1) Includes amounts associated with an Energy Storage facility that reached commercial operation in December 2025 and for which the

associated costs will be subject to recovery as part of regulated net power costs and PacifiCorp's deferred net power cost mechanisms.

The following table summarizes PacifiCorp's lease costs for the years ended December 31 (in millions):


	2025			2024

Variable	$	33		$	35
Operating	3			4
Finance:
Amortization	5			1
Interest	3			2
Short-term	4			6
Total lease costs	$	48		$	48

Weighted-average remaining lease term (years):
Operating leases	12.7			12.0
Finance leases	20.3			7.3

Weighted-average discount rate:
Operating leases	3.8		%	3.8		%
Finance leases	6.1		%	7.8		%

Cash payments associated with operating and finance lease liabilities approximated lease cost for the years ended December 31, 2025 and 2024.

PacifiCorp has the following remaining lease commitments as of December 31, 2025 (in millions):


	Operating		Finance				Total
			PPAs/Energy Storage Agreement

					Other

2026	$	3	$	31	$	11	$	45
2027	2		31		10		43
2028	1		31		10		42
2029	1		31		10		42
2030	1		31		9		41
Thereafter	5		533		12		550
Total undiscounted lease payments	13		688		62		763
Less - amounts representing interest	(3)		(305)		(13)		(321)
Lease liabilities	$	10	$	383	$	49	$	442

Refer to Note 14 for information regarding Energy Storage facilities that have not reached commercial operation.

(6) Regulatory Matters

Regulatory Assets

Regulatory assets totaling approximately $991 million, primarily related to those for Employee benefit plans, Unrealized loss on derivative contracts and Asset retirement obligation, were not accruing interest or included in rate base earning a return on investment as of December 31, 2025. Most other regulatory assets accrue interest but are not included in rate base earning a return on investment. In general, regulatory assets associated with net utility plant are included in rate base and earn a return on investment.

(7) Short-term Debt and Credit Facilities

PacifiCorp has a $2.0 billion unsecured credit facility expiring in June 2028 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which supports PacifiCorp's commercial paper program and certain series of its tax-exempt bond obligations and provides for the issuance of a certain level of letters of credit, has a variable interest rate based on the Secured Overnight Financing Rate ("SOFR") or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities. In addition, PacifiCorp has a $900 million 364-day unsecured credit facility expiring in June 2026 which, similar to its other existing $2.0 billion credit facility provides for loans at variable interest rates based on the SOFR or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities.

The following table summarizes PacifiCorp's availability under its unsecured credit facility as of December 31 (in millions):


2025:
Credit facilities	$	2,900
Less:
Short-term debt	(1,000)
Net credit facilities	$	1,900

2024:
Credit facilities	$	2,900
Less:
Short-term debt	(240)
Tax-exempt bond support	(52)
Net credit facilities	$	2,608

As of December 31, 2025, PacifiCorp was in compliance with all financial covenants that affect access to capital.

As of December 31, 2025 and 2024, PacifiCorp had $1.0 billion and $240 million of short-term debt outstanding at a weighted average rate of 5.23% and 4.65%, respectively. The outstanding short-term debt as of December 31, 2025 was subsequently repaid in February 2026.

The credit facilities require that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter. As of December 31, 2025, PacifiCorp's debt to total capitalization ratio was 0.58 to 1.0.

The following table summarizes PacifiCorp's letter of credit capacity and availability under various arrangements as of December 31 (in millions):


	2025				2024
	Capacity		Availability		Capacity		Availability

Credit facility(1)	$	255	$	255	$	255	$	255
Bilateral letter of credit agreements(2)	963		949		488		454
Total capacity and availability	$	1,218	$	1,204	$	743	$	709

(1)Capacity is available under PacifiCorp's $2.0 billion revolving credit facility.

(2)Amounts outstanding were utilized in support of certain transactions required by third parties.

Refer to Note 14 for information regarding a letter of credit agreement entered into in April 2026, which will be available only for specific purposes and is subject to certain regulatory approvals as described therein.

(8) Long-term Debt

Senior Debt

PacifiCorp's senior debt generally includes provisions that allow PacifiCorp to redeem the first mortgage bonds in whole or in part at any time through the payment of a make-whole premium.

The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's mortgage. Approximately $42.4 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage as of December 31, 2025.

In February 2026, PacifiCorp issued $400 million of 4.25% First Mortgage Bonds due March 2029.

In March 2026, PacifiCorp issued $300 million of its 4.65% First Mortgage Bonds due April 2029, $550 million of its 5.10% First Mortgage Bonds due April 2031, $800 million of its 5.45% First Mortgage Bonds due April 2033 and $850 million of its 5.80% First Mortgage Bonds due April 2036, for a total of $2.5 billion.

Junior Subordinated Debt

In February 2026, PacifiCorp issued $1.1 billion of its 7.125% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due August 2056. PacifiCorp will pay interest on the junior subordinated notes at a rate of 7.125% through August 2031, subject to a reset every five years, not to reset below 7.125%.

Long-Term Debt

PacifiCorp currently has regulatory authority from the Oregon Public Utility Commission and the Idaho Public Utilities Commission to issue an additional $150 million of long-term debt. PacifiCorp must make a notice filing with the Washington Utilities and Transportation Commission prior to any future issuance. PacifiCorp currently has an effective shelf registration statement filed with the U.S. Securities and Exchange Commission to issue an indeterminate amount of first mortgage bonds and unsecured debt securities through July 2027.

Annual Repayments of Long-Term Debt

As of December 31, 2025, the annual repayments of long-term debt for the years beginning January 1, 2026 and thereafter, are as follows (in millions):



2026	$	100
2027	�
2028	�
2029	900
2030	400
Thereafter	12,850
Total	$	14,250
Unamortized discount	(34)
Total	$	14,216

(9) Income Taxes

Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return and BHE includes its subsidiaries in certain state income tax returns. Consistent with established regulatory practice, PacifiCorp's provision for federal and state income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. Income (loss) before income tax expense (benefit) as reported on the Statement of Income, is all domestic.

Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):


	2025		2024
Current:
Federal	$	(172)	$	(240)
State	14		8
Total	$	(158)	$	(232)

Deferred:
Federal	(55)		(5)
State	19		3
Total	$	(36)	$	(2)

Investment tax credits	(2)		(1)
Total income tax expense (benefit)	$	(196)	$	(235)

The following table presents income taxes paid (received), net of refunds, for the years ended December 31 (in millions):


	2025		2024
Jurisdiction:
Federal	$	(82)	$	(339)
State	9		(21)
Total(1)	$	(73)	$	(360)

(1) Substantially all income taxes paid or (received) by PacifiCorp are pursuant to a tax allocation agreement.

Income taxes paid (received), net of refunds exceeded five percent of total income taxes paid (received) in the following jurisdictions (in millions):


	2025		2024
State:
Oregon(1)	$	9	*

(1) All income taxes paid are pursuant to a tax allocation agreement.

* Jurisdiction below the threshold for the period presented

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income (loss) before income tax expense (benefit) is as follows for the years ended December 31:


	2025				2024
	Amount		Percent		Amount		Percent
U.S. federal statutory income tax rate	$	93	21.0	%	$	64	21.0	%
State and local income taxes, net of federal income tax(1)	26		5.8		8		2.7
Energy-related tax credits	(242)		(54.5)		(201)		(66.5)
Nontaxable or non-deductible items	(2)		(0.4)		(3)		(0.9)
Effects of ratemaking(2)	(71)		(15.9)		(103)		(33.9)
Effective income tax rate	$	(196)	(44.0)	%	$	(235)	(77.6)	%

(1) State taxes in Utah and Oregon made up the majority (greater than 50 percent) of the tax effect in this category.

(2) Effects of ratemaking is primarily attributable to activity associated with excess deferred income taxes.

Energy-related tax credits relate primarily to production tax credits ("PTC") earned by PacifiCorp's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.

The net deferred income tax liability consists of the following as of December 31 (in millions):


	2025		2024
Deferred income tax assets:
Regulatory liabilities	$	274	$	292
Employee benefits	48		49
State carryforwards	81		88
Loss contingencies	288		356
Asset retirement obligations	125		102
Other	103		81
Total deferred income tax assets	919		968
Valuation allowances	(16)		(11)
Total deferred income tax assets, net	903		957
Deferred income tax liabilities:
Property-related items	(3,546)		(3,457)
Regulatory assets	(628)		(716)
Other	(55)		(50)
Total deferred income tax liabilities	(4,229)		(4,223)
Net deferred income tax liability	$	(3,326)	$	(3,266)

The following table provides, without regard to valuation allowances, PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December 31, 2025 (in millions):


	State

Net operating loss carryforwards	$	1,481
Deferred income taxes on net operating loss carryforwards	$	65
Expiration dates	2026 - indefinite

Tax credit carryforwards	$	16
Expiration dates	2026 - indefinite

The U.S. Internal Revenue Service has closed or effectively settled its examination of PacifiCorp's income tax returns through December 31, 2013. The statute of limitations for PacifiCorp's income tax returns have expired for certain states through December 31, 2011 and December 31, 2013, and for other states through December 31, 2021, except for the impact of any federal audit adjustments.

(10) Employee Benefit Plans

PacifiCorp sponsors defined benefit pension and other postretirement benefit plans that cover certain of its employees, as well as a defined contribution 401(k) employee savings plan ("401(k) Plan"). In addition, PacifiCorp contributes to a joint trustee pension plan and a subsidiary previously contributed to a multiemployer pension plan for benefits offered to certain bargaining units.

Defined Benefit Plans

PacifiCorp's pension plans include non-contributory defined benefit pension plans, the PacifiCorp Retirement Plan ("Retirement Plan"), and the Supplemental Executive Retirement Plan ("SERP"). The Retirement Plan is closed to all non-union employees hired after January 1, 2008. All non-union Retirement Plan participants hired prior to January 1, 2008 that did not elect to receive equivalent fixed contributions to the 401(k) Plan effective January 1, 2009 earned benefits based on a cash balance formula through December 31, 2016. Effective January 1, 2017, non-union employee participants with a cash balance benefit in the Retirement Plan are no longer eligible to receive pay credits in their cash balance formula. In general for union employees, benefits under the Retirement Plan were frozen at various dates from December 31, 2007 through December 31, 2011 as they are now being provided with enhanced 401(k) Plan benefits. However, certain limited union Retirement Plan participants continue to earn benefits under the Retirement Plan based on the employee's years of service and a final average pay formula. The SERP was closed to new participants as of March 21, 2006 and froze future accruals for active participants as of December 31, 2014.

PacifiCorp's other postretirement benefit plan provides healthcare and life insurance benefits to eligible retirees.

Net Periodic Benefit Cost (Credit)

For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the first year in which they occur.

Net periodic benefit (credit) cost for the plans included the following components for the years ended December 31 (in millions):


	Pension				Other Postretirement
	2025		2024		2025		2024

Service cost	$	�	$	�	$	1	$	1
Interest cost	37		37		11		11
Expected return on plan assets	(45)		(47)		(13)		(14)

Net amortization	7		9		(3)		(2)
Net periodic benefit (credit) cost	$	(1)	$	(1)	$	(4)	$	(4)

Funded Status

The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):


	Pension				Other Postretirement
	2025		2024		2025		2024

Plan assets at fair value, beginning of year	$	728	$	764	$	267	$	271
Employer contributions(1)	4		4		�		�
Participant contributions	�		�		3		3
Actual return on plan assets	66		31		12		15

Benefits paid	(74)		(71)		(20)		(22)
Plan assets at fair value, end of year	$	724	$	728	$	262	$	267

(1)Pension amounts represent employer contributions to the SERP.

The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):


	Pension				Other Postretirement
	2025		2024		2025		2024

Benefit obligation, beginning of year	$	683	$	740	$	196	$	215
Service cost	�		�		1		1
Interest cost	37		37		11		11
Participant contributions	�		�		3		3
Actuarial loss (gain)	19		(23)		(2)		(12)

Benefits paid	(74)		(71)		(20)		(22)
Benefit obligation, end of year	$	665	$	683	$	189	$	196
Accumulated benefit obligation, end of year	$	665	$	683

The funded status of the plans and the amounts recognized on the Comparative Balance Sheet as of December 31 are as follows (in millions):


	Pension				Other Postretirement
	2025		2024		2025		2024

Plan assets at fair value, end of year	$	724	$	728	$	262	$	267
Less - Benefit obligation, end of year	665		683		189		196
Funded status	$	59	$	45	$	73	$	71

Amounts recognized on the Comparative Balance Sheet:
Other special funds (128)	$	96	$	83	$	73	$	71
Miscellaneous current and accrued liabilities (242)	(4)		(4)		�		�
Accumulated provision for pension and benefits (228.3)	(33)		(34)		�		�
Amounts recognized	$	59	$	45	$	73	$	71

The SERP has no plan assets; however, PacifiCorp has a Rabbi trust that holds corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERP. The cash surrender value of all of the policies included in the Rabbi trust, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $84 million and $76 million as of December 31, 2025 and 2024, respectively. These assets are not included in the plan assets in the above table, but are reflected primarily in other investments as of December 31, 2025 and 2024, respectively, on the Comparative Balance Sheet. The projected and accumulated benefit obligations for the SERP were $37 million and $38 million at December 31, 2025 and 2024, respectively.

As of December 31, 2025, the fair value of the plan assets for the Retirement Plan was in excess of both the projected benefit obligation and the accumulated benefit obligation.

Unrecognized Amounts

The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):


	Pension				Other Postretirement
	2025		2024		2025		2024

Net loss (gain)	$	250	$	258	$	(51)	$	(53)
Regulatory deferrals(1)	18		19		�		�
Total	$	268	$	277	$	(51)	$	(53)

(1)Pension amounts represent the unamortized portion of deferred settlement losses.

A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2025 and 2024 is as follows (in millions):


	Regulatory Asset		Accumulated Other Comprehensive Loss		Total
Pension
Balance, December 31, 2023	$	279	$	13	$	292
Net gain arising during the year	(5)		(1)		(6)
Net amortization	(9)		�		(9)

Total	(14)		(1)		(15)
Balance, December 31, 2024	265		12		277
Net (gain) loss arising during the year	(4)		2		(2)
Net amortization	(6)		(1)		(7)

Total	(10)		1		(9)
Balance, December 31, 2025	$	255	$	13	$	268

					Regulatory Liability
Other Postretirement
Balance, December 31, 2023					$	(42)
Net gain arising during the year					(13)
Net amortization					2
Total					(11)
Balance, December 31, 2024					(53)
Net gain arising during the year					(1)
Net amortization					3
Total					2
Balance, December 31, 2025					$	(51)

Plan Assumptions

Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:


	Pension				Other Postretirement
	2025		2024		2025		2024

Benefit obligations as of December 31:
Discount rate	5.50	%	5.80	%	5.50	%	5.75	%

Interest crediting rates for cash balance plan - non-union
2023	N/A		N/A		N/A		N/A
2024	N/A		5.98	%	N/A		N/A
2025	5.03	%	5.03	%	N/A		N/A
2026	4.36	%	5.03	%	N/A		N/A
2027	4.36	%	3.60	%	N/A		N/A
2028 and beyond	4.30	%	3.60	%	N/A		N/A

Interest crediting rates for cash balance plan - union
2023	N/A		N/A		N/A		N/A
2024	N/A		4.47	%	N/A		N/A
2025	4.04	%	4.04	%	N/A		N/A
2026	4.74	%	4.04	%	N/A		N/A
2027	4.74	%	3.10	%	N/A		N/A
2028 and beyond	3.70	%	3.10	%	N/A		N/A

Net periodic benefit cost for the years ended December 31:
Discount rate	5.80	%	5.20	%	5.75	%	5.20	%
Expected return on plan assets	5.90	%	5.90	%	4.42	%	4.87	%

In establishing its assumption as to the expected return on plan assets, PacifiCorp utilizes the asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets.

Contributions and Benefit Payments

Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $� million, respectively, during 2026. Funding to PacifiCorp's Retirement Plan trust is based upon the actuarially determined costs of the plan and the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 ("ERISA") and the Pension Protection Act of 2006, as amended. PacifiCorp considers contributing additional amounts from time to time in order to achieve certain funding levels specified under the Pension Protection Act of 2006. PacifiCorp evaluates a variety of factors, including funded status, income tax laws and regulatory requirements, in determining contributions to its other postretirement benefit plan.

The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2026 through 2030 and for the five years thereafter are summarized below (in millions):


	Projected Benefit Payments
	Pension		Other Postretirement

2026	$	73	$	20
2027	69		19
2028	65		19
2029	62		18
2030	59		17
2031-2035	255		75

Plan Assets

Investment Policy and Asset Allocations

PacifiCorp's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The plans retain outside investment consultants to advise on plan investments within the parameters outlined by the Berkshire Hathaway Energy Company Investment Committee. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments.

The target allocations (percentage of plan assets) for PacifiCorp's pension and other postretirement benefit plan assets are as follows as of December 31, 2025:


	Pension(1)	Other Postretirement(1)
	%	%
Debt securities(2)	50-80	76 - 95
Equity securities(2)	10-50	0 - 19
Other	0-10	0 - 5

(1)The trust in which the PacifiCorp Retirement Plan is invested includes a separate account that is used to fund benefits for the other postretirement benefit plan. In addition to this separate account, the assets for the other postretirement benefit plan are held in Voluntary Employees' Beneficiary Association ("VEBA") trusts, each of which has its own investment allocation strategies. Target allocations for the other postretirement benefit plan include the separate account of the Retirement Plan trust and the VEBA trusts.

(2)For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities.

Fair Value Measurements

The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit pension plan (in millions):


	Input Levels for Fair Value Measurements
	Level 1(1)		Level 2(1)		Level 3(1)		Total
As of December 31, 2025:
Cash equivalents	$	2	$	2	$	�	$	4
Debt securities:
U.S. government obligations	54		�		�		54
Corporate obligations	�		227		�		227
Municipal obligations	�		11		�		11
Agency, asset and mortgage-backed obligations	�		48		�		48
Equity securities:
U.S. companies	18		�		�		18
Total assets in the fair value hierarchy	$	74	$	288	$	�	362
Investment funds(2) measured at net asset value							341
Limited partnership interests(3) measured at net asset value							21
Investments at fair value							$	724

As of December 31, 2024:
Cash equivalents	$	�	$	3	$	�	$	3
Debt securities:
U.S. government obligations	59		�		�		59
Corporate obligations	�		229		�		229
Municipal obligations	�		13		�		13
Agency, asset and mortgage-backed obligations	�		52		�		52
Equity securities:
U.S. companies	65		�		�		65
Total assets in the fair value hierarchy	$	124	$	297	$	�	421
Investment funds(2) measured at net asset value							285
Limited partnership interests(3) measured at net asset value							22
Investments at fair value							$	728

(1)Refer to Note 13 for additional discussion regarding the three levels of the fair value hierarchy.

(2)Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 45% and 55%, respectively, for 2025 and 40% and 60%, respectively, for 2024, and are invested in U.S. and international securities of approximately 87% and 13%, respectively, for 2025 and 88% and 12%, respectively, for 2024.

(3)Limited partnership interests include several funds that invest primarily in real estate.

The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit other postretirement plan (in millions):


	Input Levels for Fair Value Measurements
	Level 1(1)		Level 2(1)		Level 3(1)		Total
As of December 31, 2025:
Cash equivalents	$	17	$	�	$	�	$	17
Debt securities:
U.S. government obligations	11		�		�		11
Corporate obligations	�		34		�		34
Municipal obligations	�		54		�		54
Agency, asset and mortgage-backed obligations	�		57		�		57
Total assets in the fair value hierarchy	$	28	$	145	$	�	173
Investment funds(2) measured at net asset value							89

Investments at fair value							$	262

As of December 31, 2024:
Cash equivalents	$	�	$	6	$	�	$	6
Debt securities:
U.S. government obligations	16		�		�		16
Corporate obligations	�		34		�		34
Municipal obligations	�		18		�		18
Agency, asset and mortgage-backed obligations	�		52		�		52
Equity securities:
U.S. companies	7		�		�		7
Total assets in the fair value hierarchy	$	23	$	110	$	�	133
Investment funds(2) measured at net asset value							134

Investments at fair value							$	267

(1)Refer to Note 13 for additional discussion regarding the three levels of the fair value hierarchy.

(2)Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 0% and 100%, respectively, for 2025 and 39% and 61%, respectively, for 2024, and are invested in U.S. and international securities of approximately 88% and 12%, respectively, for 2025 and 90% and 10%, respectively, for 2024.

For level 1 investments, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. For level 2 investments, the fair value is determined using pricing models based on observable market inputs. Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.

Multiemployer and Joint Trustee Pension Plans

PacifiCorp contributes to the PacifiCorp/IBEW Local 57 Retirement Trust Fund ("Local 57 Trust Fund") (plan number 001) and its subsidiary, Energy West Mining Company, previously contributed to the UMWA 1974 Pension Plan (plan number 002). Contributions to these pension plans are based on the terms of collective bargaining agreements.

As a result of the Utah Mine Disposition and UMWA labor settlement, PacifiCorp's subsidiary, Energy West Mining Company, triggered involuntary withdrawal from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceased performing work for the subsidiary. PacifiCorp recorded its estimate of the withdrawal obligation in December 2014 when withdrawal was considered probable and deferred the portion of the obligation considered probable of recovery to a regulatory asset. PacifiCorp has subsequently revised its estimate due to changes in facts and circumstances for a withdrawal occurring by July 2015. As communicated in a letter received in August 2016, the plan trustees determined a withdrawal liability of $115 million. Energy West Mining Company began making installment payments in November 2016 and has the option to elect a lump sum payment to settle the withdrawal obligation. In January 2024, the withdrawal liability was recalculated by the plan's actuary to be $80 million as a result of arbitration efforts regarding the interest rate used to compute the obligation. The ultimate amount paid by Energy West Mining Company to settle the obligation is dependent on a variety of factors, including the results of ongoing efforts with the plan trustees and the recent arbitration activities.

The Local 57 Trust Fund is a joint trustee plan such that the board of trustees is represented by an equal number of trustees from PacifiCorp and the union. The Local 57 Trust Fund was established pursuant to the provisions of the Taft-Hartley Act and although formed with the ability for other employers to participate in the plan, there are no other employers that participate in this plan.

The risk of participating in multiemployer pension plans generally differs from single-employer plans in that assets are pooled such that contributions by one employer may be used to provide benefits to employees of other participating employers and plan assets cannot revert to employers. If an employer ceases participation in the plan, the employer may be obligated to pay a withdrawal liability based on the participants' unfunded, vested benefits in the plan. If participating employers withdraw from a multiemployer plan, the unfunded obligations of the plan may be borne by the remaining participating employers.

The following table presents PacifiCorp's participation in individually significant joint trustee and multiemployer pension plans for the years ended December 31 (dollars in millions):


		Pension Protection Act of 2006 zone status or plan funded status percentage for plan years beginning July 1,				Contributions
Plan name	Employer Identification Number	2025	2024	Funding improvement plan	Surcharge imposed under Pension Protection Act of 2006	2025		2024		Year contributions to plan exceeded more than 5% of total contributions
Local 57 Trust Fund	87-0640888	At least 80%	At least 80%	None	None	$	4	$	5	2025, 2024

PacifiCorp's minimum contributions to the Local 57 Trust Fund are based on the amount of wages paid to employees covered by the Local 57 Trust Fund collective bargaining agreements, subject to ERISA minimum funding requirements. The collective bargaining agreements governing the Local 57 Trust Fund expire in 2028.

Defined Contribution Plan

PacifiCorp's 401(k) Plan covers substantially all employees. PacifiCorp's matching contributions are based on each participant's level of contribution and, as of January 1, 2024, all participants receive contributions based on eligible pre-tax annual compensation. Contributions cannot exceed the maximum allowable for tax purposes. PacifiCorp's contributions to the 401(k) Plan were $60 million and $55 million for the years ended December 31, 2025 and 2024, respectively.

(11) Asset Retirement Obligations

PacifiCorp estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.

PacifiCorp does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the financial statements other than those included in the accumulated provision for depreciation established via approved depreciation rates in accordance with accepted regulatory practices.

The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 31 (in millions):


	2025		2024

Beginning balance	$	427	$	356
Change in estimated costs	86		73
Additions	8		4
Retirements	(22)		(20)
Accretion	19		14
Ending balance	$	518	$	427

Certain of PacifiCorp's decommissioning and reclamation obligations relate to jointly owned facilities and mine sites. PacifiCorp is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, PacifiCorp may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. PacifiCorp's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities.

In May 2024, the United States Environmental Protection Agency published its final rule on legacy coal combustion residuals ("CCR") surface impoundments and CCR management units ("CCRMUs") in the Federal Register. CCRMUs include CCR surface impoundments and landfills closed before October 19, 2015 and inactive CCR landfills. The final rule contains three main components: (1) a definition for legacy CCR surface impoundments, which are inactive surface impoundments at inactive generating facilities that must adhere to the same regulations as inactive CCR impoundments at active generating facilities, barring location restrictions and liner design criteria, with customized compliance deadlines; (2) groundwater monitoring, corrective action, closure, and post closure care requirements for CCRMUs, which may be located at active generating facilities and inactive generating facilities with a legacy CCR surface impoundment; and (3) the owners and operators of inactive generating facilities must identify the presence of legacy CCR surface impoundments and comply with all rule requirements for surface impoundments; and the owners and operators of active generating facilities and inactive generating facilities with a legacy CCR surface impoundment must prepare Facility Evaluation Reports ("FERs") that identify and describe the CCRMUs and determine whether closure is required. In February 2026, the U.S. Environmental Protection Agency extended certain compliance deadlines with CCRMUs. Accordingly, and in a manner consistent with existing CCR rules, owners and operators must publish FERs on their CCR websites in two parts, within 12 months (Part 1) and 24 months (Part 2) of the final rule's effective date in February 2026. PacifiCorp is currently evaluating the final rule and does not anticipate identifying any legacy surface impoundments, but does anticipate identifying CCRMUs subject to the rule. Due to the number of site investigations warranted by this rule and the nature of engineering and other studies required at each site, PacifiCorp is unable to reasonably estimate the potential impact, which may be material, to its asset retirement obligations.

(12) Risk Management and Hedging Activities

PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.

PacifiCorp has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.

The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Comparative Balance Sheet (in millions):


	Current Assets		Long-term Assets		Current Liabilities		Long-term Liabilities		Total
As of December 31, 2025
Not designated as hedging contracts(1):
Commodity assets	$	5	$	�	$	4	$	1	$	10
Commodity liabilities	�		�		(119)		(28)		(147)
Total	5		�		(115)		(27)		(137)
Cash collateral receivable	�		�		67		4		71
Total derivatives - net basis	$	5	$	�	$	(48)	$	(23)	$	(66)

As of December 31, 2024
Not designated as hedging contracts(1):
Commodity assets	$	10	$	�	$	16	$	1	$	27
Commodity liabilities	(1)		�		(105)		(18)		(124)
Total	9		�		(89)		(17)		(97)
Cash collateral receivable	�		�		6		�		6
Total derivatives - net basis	$	9	$	�	$	(83)	$	(17)	$	(91)

(1)PacifiCorp's commodity derivatives are generally included in rates. As of December 31, 2025 a regulatory asset of $137 million was recorded related to the net derivative liability of $137 million. As of December 31, 2024 a regulatory asset of $97 million was recorded related to the net derivative liability of $97 million.

The following table reconciles the beginning and ending balances of PacifiCorp's net regulatory assets (liabilities) and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets (liabilities), as well as amounts reclassified to earnings for the years ended December 31 (in millions):


	2025		2024
Beginning balance	$	97	$	76
Changes in fair value recognized in regulatory assets	177		326
Net gains reclassified to operating revenue	26		18
Net (losses) reclassified to energy costs	(163)		(323)
Ending balance	$	137	$	97

Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of December 31 (in millions):


	Unit of Measure	2025	2024
Electricity sales, net	Megawatt hours	�	(1)
Natural gas purchases	Decatherms	147	124

Credit Risk

PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

Collateral and Contingent Features

In accordance with industry practice, certain wholesale energy agreements, including contracts for purchases, sales and transportation of electricity, natural gas and coal, some of which are accounted for as derivatives, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features"). These agreements and other agreements that do not refer to specified rating-dependent thresholds may provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2025, PacifiCorp's issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.

The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $145 million and $123 million as of December 31, 2025 and 2024, respectively, for which PacifiCorp had posted collateral of $71 million and $6 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of December 31, 2025 and 2024, PacifiCorp would have been required to post $69 million and $100 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.

PacifiCorp's collateral requirements associated with wholesale energy agreements could fluctuate considerably due to market price volatility; changes in credit ratings; changes in legislation or regulation or other factors; and if counterparties demand adequate assurance in the event of a material adverse change in PacifiCorp's creditworthiness.

(13) Fair Value Measurements

The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, other investments, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has various financial assets and liabilities that are measured at fair value on the financial statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

�Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the ability to access at the measurement date.

�Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

�Level 3 - Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including its own data.

The following table presents PacifiCorp's financial assets and liabilities recognized on the Comparative Balance Sheet and measured at fair value on a recurring basis (in millions):


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2025
Assets:
Commodity derivatives	$	�	$	10	$	�	$	(5)	$	5
Money market mutual funds	73		�		�		�		73
Investment funds	28		�		�		�		28
	$	101	$	10	$	�	$	(5)	$	106
Liabilities:
Commodity derivatives	$	�	$	(147)	$	�	$	76	$	(71)

As of December 31, 2024
Assets:
Commodity derivatives	$	�	$	27	$	�	$	(18)	$	9
Money market mutual funds	34		�		�		�		34
Investment funds	29		�		�		�		29
	$	63	$	27	$	�	$	(18)	$	72
Liabilities:
Commodity derivatives	$	�	$	(124)	$	�	$	24	$	(100)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $71 million and $6 million as of December 31, 2025 and 2024, respectively.

Derivative contracts are recorded on the Comparative Balance Sheet as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. A discounted cash flow valuation method was used to estimate fair value. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. Refer to Note 12 for further discussion regarding PacifiCorp's risk management and hedging activities.

PacifiCorp's investments in money market mutual funds and investment funds are stated at fair value. When available, PacifiCorp uses a readily observable quoted market price or net asset value of an identical security in an active market to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.

PacifiCorp's long-term debt is carried at cost on the Comparative Balance Sheet. The fair value of PacifiCorp's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt as of December 31 (in millions):


	2025				2024
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	14,216	$	13,005	$	13,666	$	12,580

(14) Commitments and Contingencies

Commitments

PacifiCorp has the following firm commitments that are not reflected on the Comparative Balance Sheet. Minimum payments as of December 31, 2025 are as follows (in millions):


	2026		2027		2028		2029		2030		2031 and Thereafter		Total
Contract type:
PPAs - commercially operable	$	235	$	194	$	197	$	196	$	197	$	1,558	$	2,577
PPAs and Energy Storage contracts -
non-commercially operable	70		128		128		128		128		1,972		2,554
Fuel contracts	716		640		598		596		315		100		2,965
Construction commitments	429		369		174		3		�		23		998
Transmission	134		129		126		102		70		358		919
Easements	16		16		17		17		17		549		632
Maintenance, service and
other contracts	178		150		108		55		27		93		611
Total commitments	$	1,778	$	1,626	$	1,348	$	1,097	$	754	$	4,653	$	11,256

PPAs - Commercially Operable

The table above reflects PPAs with expiration dates ranging from 2026 through 2052. As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-term purchases and exchange agreements. PacifiCorp has many long-term PPAs primarily with solar-, wind- or hydro-powered generating facilities that are not included in the table above due to there being no minimum payments generally due to being dependent on solar, wind and stream flow conditions. These PPAs generally range from 10 to 30 years in duration, with certain of the PPAs extending through 2055. Future payments associated with these PPAs are expected to be material. Certain PPAs qualify as leases as described in Note 2 and are also excluded from the table above. Refer to Note 5 for variable lease costs associated with these lease commitments.

Included in the minimum fixed annual payments for purchased electricity above are commitments to purchase electricity from several hydroelectric systems under long-term arrangements with public utility districts. These purchases are made on a "cost-of-service" basis for a stated percentage of system output and for a like percentage of system operating expenses and debt service. These costs are included in operations expenses on the Statement of Income. PacifiCorp is required to pay its portion of operating costs and its portion of the debt service, whether or not any electricity is produced. These arrangements accounted for less than 5% of PacifiCorp's 2025 and 2024 energy sources.

PPAs and Energy Storage Contracts - Non-Commercially Operable

PacifiCorp has agreements with facilities that have not achieved commercial operation, including PPAs primarily related to solar-, wind- or hydro-powered generating facilities, as well as Energy Storage agreements.

The table above reflects estimated capacity payments through 2046 for various Energy Storage agreements that are expected to reach commercial operation in 2026, and for which the accounting determination is pending.

Commitments associated with PPAs from primarily solar- and hydro-powered generating facilities are not included in the table above due to there being no minimum payments generally due to being dependent on solar and stream flow conditions. The PPAs generally range from 10 to 20 years in duration, some of which extend through 2046. Future payments associated with these PPAs are expected to be material.

To the extent these facilities do not achieve commercial operation, PacifiCorp has no obligation to the counterparties.

Fuel Contracts

PacifiCorp has "take or pay" coal and natural gas contracts that require minimum payments.

Construction Commitments

PacifiCorp's construction commitments included in the table above relate to firm commitments and include costs associated with certain generating plant, transmission, distribution and operations projects.

In June 2025, PacifiCorp became committed under the terms of a previously existing construction funding agreement with Idaho Power Company to support the development of the Boardman to Hemingway 300-mile, 500-kV transmission line (the "B2H Project"). Under this agreement, PacifiCorp is committed to contributing up to $460 million toward construction costs, representing PacifiCorp's share of the total estimated shared project costs of $843 million. B2H Project costs will also include costs directly incurred by PacifiCorp, a substantial portion of which have already been incurred. Refer to Item 4 of Important Changes in this Form No. 1 for information regarding the sale leaseback transaction associated with the B2H Project.

Transmission

PacifiCorp has contracts for the right to transmit electricity over other entities' transmission lines to facilitate delivery to PacifiCorp's customers.

Easements

PacifiCorp has easements for land on which certain of its assets, primarily wind-powered generating facilities, are located.

Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal, wildfire prevention and mitigation and other environmental matters that have the potential to impact its current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.

Lower Klamath Hydroelectric Project

PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which addressed disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA established a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal could occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the FERC license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"); and (4) ability for PacifiCorp to operate the facilities for the benefit of customers through commencement of dam removal.

In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four mainstem Klamath hydroelectric dams comprising the Lower Klamath Project (FERC Project No. 14803) from PacifiCorp to the KRRC. The KRRC filed an amended license surrender application for the Lower Klamath Project with FERC in November 2020. In November 2022, the FERC issued a license surrender order for the Lower Klamath Project, which was accepted by the KRRC and the States in December 2022, resulting in the transfer of the Lower Klamath Project dams. Although PacifiCorp no longer owned the Lower Klamath Project, PacifiCorp continued to operate the facilities under an operation and maintenance agreement with the KRRC until each facility was ready for removal. PacifiCorp's obligations under the operations and maintenance agreement terminated in January 2024, when PacifiCorp's customers no longer received generation benefits from the facilities. Removal of the Copco No. 2 facility was completed in November 2023, and removal of the remaining three dams (J.C. Boyle, Copco No. 1, and Iron Gate) was completed in October 2024. The KRRC has $450 million in funding available for dam removal and restoration; $200 million collected from PacifiCorp's Oregon and California customers and $250 million in California bond funds. PacifiCorp and the States have also agreed to equally share cost overruns that may occur above the initial $450 million in funding. Specifically, PacifiCorp and the States have agreed to equally fund an initial $45 million supplemental fund and equally share any additional costs above that amount to ensure dam removal and restoration is complete. In May 2024, the KRRC communicated to PacifiCorp and the States that it expects to require the $45 million of supplemental funds. As a result, PacifiCorp provided supplemental funding to the KRRC of approximately $11 million in October 2024 and approximately $2 million in July 2025, and expects to provide the remaining $2 million in 2026.

Hydroelectric Commitments

Certain of PacifiCorp's hydroelectric licenses and settlement agreements contain requirements for PacifiCorp to make certain capital and operating expenditures related to its hydroelectric facilities, which are estimated to be approximately $278 million over the next 10 years.

Legal Matters

PacifiCorp is party to a variety of legal actions, including litigation, arising out of the normal course of business, some of which assert claims for damages in substantial amounts and are described below. For certain legal actions, parties at times may seek to impose fines, penalties and other costs.

Pursuant to GAAP, a provision for a loss contingency is recorded when it is probable a liability is likely to occur and the amount of loss can be reasonably estimated. PacifiCorp evaluates the related range of reasonably estimated losses and records a loss based on its best estimate within that range or the lower end of the range if there is no better estimate.

Wildfires

A significant number of complaints and demands alleging similar claims related to the Wildfires have been filed in Oregon and California, including a class action complaint in Oregon associated with 2020 Wildfires for which certain jury verdicts were issued as described below. The plaintiffs seek damages for economic losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees. Several insurance carriers also filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned complaints. Additionally, PacifiCorp received correspondence from the U.S. and Oregon Departments of Justice regarding the potential recovery of certain costs and damages alleged to have occurred on federal and state lands in connection with certain of the 2020 Wildfires. In December 2024, the United States of America filed a complaint against PacifiCorp in conjunction with the correspondence from the U.S. Department of Justice. The civil cover sheet accompanying the complaint demands damages estimated to exceed $900 million. On February 20, 2026, the United States Attorney for the District of Oregon and the United States Attorney for the Eastern District of California approved a settlement agreement for $575 million between PacifiCorp and the United States of America resolving all known federal government complaints and demands associated with the Wildfires, including those associated with the 242, Archie Creek, Echo Mountain Complex, McKinney, Slater and South Obenchain fires. In accordance with the settlement agreement, PacifiCorp paid the $575 million in March 2026. PacifiCorp is actively cooperating with the Oregon Department of Justice on resolving the alleged claims.

Amounts sought in outstanding complaints and demands filed in Oregon and in certain demands made in California totaled approximately $50 billion, excluding any doubling or trebling of damages or punitive damages included in the complaints, and of which approximately $48 billion represents the economic and noneconomic damages sought in the James mass complaints described below, as amended. Oregon law provides for doubling of economic and property damages in the event the defendant is found to have acted with gross negligence, recklessness, willfulness or malice. Oregon law provides for trebling of damages associated with timber, shrubs and produce in the event the defendant is determined to have willfully and intentionally trespassed. Generally, the complaints filed in California do not specify damages sought and are excluded from this amount. For class actions, amounts specified by the plaintiffs in the complaints include amounts based on estimates of the potential class size, which ultimately may be significantly greater than estimated. Additionally, damages are not limited to the amounts specified in the initially filed complaints as plaintiffs are frequently allowed to amend their complaints to add additional damages and amounts awarded in a court proceeding may be significantly greater than the damages specified. However, plaintiffs included in the James mass complaints are required to amend their complaints to align the economic damages to the facts specific to their complaints rather than the common per plaintiff damages specified in the originally filed mass complaints. Refer to "James Trial Activity" below for information regarding damages awarded to date in the James case.

In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages from wildfires without the utility being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could be found liable for all damage.

Based on available information to date, losses have been and will likely continue to be incurred associated with the Wildfires. Final determinations of liability will only be made following the completion of comprehensive investigations, which may be or have been performed by various entities, including the U.S. Department of Agriculture Forest Service ("USFS"), the California Public Utilities Commission, the Oregon Department of Forestry ("ODF") and the Oregon Department of Justice, as well as litigation or similar processes, the outcome of which, if adverse, could, in the aggregate, have a material adverse effect on PacifiCorp's financial condition.

2020 Wildfires

In September 2020, a severe weather event with high winds, low humidity and warm temperatures contributed to several major wildfires, which resulted in real and personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon, burning over 500,000 acres in aggregate and include the Santiam Canyon, Beachie Creek, South Obenchain, Echo Mountain Complex, 242, Archie Creek, Slater and other fires. The Slater fire occurred in both Oregon and California. Third-party reports for these wildfires indicate over 2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities.

In May 2022, the USFS issued its report of investigation into the Archie Creek fire concluding that the probable cause of the fire was power lines owned and operated by PacifiCorp. The USFS report for the Archie Creek fire also states that evidence indicates failure of power line infrastructure. The USFS report of investigation into the Slater fire for the investigation period October 5, 2020, to December 8, 2020, concluded that the fire was caused by a downed power line owned and operated by PacifiCorp. The USFS report for the Slater fire also states that evidence indicates a tree fell onto the power line and that wind blew over the 137-foot tree with internal rot that showed no outward signs of distress and would not have been classified or identified as a hazard tree.

Settlements have been reached with substantially all individual plaintiffs, timber companies and insurance subrogation plaintiffs in both the Archie Creek and Slater fires. Additionally, PacifiCorp has settled all wrongful death claims and all federal government demands and complaints associated with the 2020 Wildfires.

In April 2023, the USFS issued its report of investigation into a wildland fire that began in the Opal Creek wilderness outside of the Santiam Canyon that was first reported on August 16, 2020 ("Beachie Creek Fire"), approximately three weeks prior to the September 2020 wind event described above. In March 2025, PacifiCorp received the ODF's final investigation report on the Santiam Canyon fires ("ODF's Report"), which concluded that embers from the pre-existing Beachie Creek Fire caused 12 fires within the Santiam Canyon. The ODF's Report also found that PacifiCorp's power lines did not contribute to the overall spread of fire into the Santiam Canyon even though its power lines ignited seven spot fires within the Santiam Canyon that were each suppressed.

The Beachie Creek fire that spread into the Santiam Canyon burned approximately 193,000 acres; the South Obenchain fire burned approximately 33,000 acres; the Echo Mountain Complex fire burned approximately 3,000 acres; and the 242 fire burned approximately 14,000 acres. The James cases described below are associated with the Beachie Creek (Santiam Canyon), South Obenchain, Echo Mountain Complex and 242 fires, which are four distinct fires located hundreds of miles apart.

The James Case

On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp, ("James") in Oregon Circuit Court in Multnomah County, Oregon ("Multnomah County Circuit Court Oregon"). The complaint was filed by Oregon residents and businesses who sought to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. In November 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Santiam Canyon, Echo Mountain Complex, South Obenchain and 242 fires, as well as to add claims for noneconomic damages. The amended complaint alleged that PacifiCorp's assets contributed to the Oregon wildfires occurring on or after September 7, 2020, and that PacifiCorp acted with gross negligence, among other things. The amended complaint seeks damages similar to those described above, including not less than $600 million of economic damages and in excess of $1 billion of noneconomic damages for the plaintiffs and the class. Since filing of the original class action complaint, numerous James class members have been named and damages specified in various complaints as described below. Additionally, numerous cases were consolidated into the original James complaint.

As of December 2025, various mass complaints against PacifiCorp naming 1,760 class members have been filed referencing the James case as the lead case with complaints for some of the plaintiffs subsequently dismissed. These James mass complaints make damages-only allegations with substantially all plaintiffs individually seeking $5 million of economic damages, $25 million of noneconomic damages and punitive damages equal to 0.25 times the amount of economic and noneconomic damages, as well as doubling of economic damages. As described below under "James Court Activity," plaintiffs included in the mass complaints are required to amend their complaints to align the economic damages to the facts specific to their complaints. Subsequently, additional complaints were filed against PacifiCorp referencing the James case and seeking per plaintiff damages similar to those of the mass complaints.

An additional approximately 1,500 plaintiffs were granted the ability not to be represented by James lead counsel, a small portion of which filed complaints seeking damages similar to those in the mass complaints. In November 2025, PacifiCorp settled with approximately 1,400 of these plaintiffs for $150 million.

As a result of dismissals for the mass complaints and the November 2025 settlement, James complaints for approximately 1,700 individual plaintiffs remain outstanding, substantially all of which are represented by lead counsel. PacifiCorp believes the magnitude of damages sought by the class members in the James mass complaints to be of remote likelihood of being awarded based on the amounts awarded in the jury verdicts described below under "James Trial Activity" that are being appealed.

James Trial Activity

In June 2023, a jury verdict was issued in the first James trial finding PacifiCorp's conduct grossly negligent, reckless and willful as to each of the 17 named plaintiffs and the entire class. The jury awarded economic and noneconomic damages. After the jury verdict, the Multnomah County Circuit Court Oregon doubled the economic damages, in accordance with Oregon law, and added punitive damages by applying a 0.25 multiplier to the awarded economic and noneconomic damages. PacifiCorp filed a motion with the Multnomah County Circuit Court Oregon requesting the court offset the damage awards by deducting insurance proceeds received by any of the plaintiffs. In January 2024, PacifiCorp filed a notice of appeal associated with the June 2023 verdict, including whether the case can proceed as a class action.

Subsequent to the June 2023 James verdict, numerous damages phase trials were held with separate jury verdicts issued and damages awarded for each on a basis consistent with the initial trial and relying on the liability determination in the June 2023 James verdict. PacifiCorp amended its January 2024 appeal of the June 2023 James verdict to include the jury verdicts for the first two damages phase trials. PacifiCorp has filed notices of appeal for the subsequent jury verdicts in the damages phase trials once limited judgments are entered and any post-trial motions filed. Refer to "James Court Activity" below regarding the filing of PacifiCorp's appellate briefs. The appeals process and further actions could take several years.

The James jury verdicts awarded various damages as follows (in millions):


	Number of Plaintiffs	Verdict / Limited Judgment Date	Damages(1)
James Trial Start Date			Doubled Economic		Non-economic		Punitive		Insurance Offset(2)		Net Damages		Appeal Notice Filed

Jury verdicts, limited judgments entered(3)
Initial James trial	17	June 2023 / January 2024	$	9	$	67	$	18	$	2	$	92	Yes
January 8, 2024	9	January 2024 / April 2024	12		56		16		4		80		Yes
February 26, 2024	10	March 2024 / June 2024	12		23		7		4		38		Yes
February 3, 2025	8	February 2025 / April 2025	8		32		9		4		45		Yes
March 24, 2025	7	March 2025 / June 2025	5		34		9		1		47		Yes
April 21, 2025	9	April 2025 / August 2025	5		11		3		1		18		Yes
May 12, 2025	10	May 2025 / July 2025	11		30		9		2		48		Yes
June 2, 2025	10	June 2025 / August 2025	8		28		8		1		43		Yes
July 7, 2025	11	July 2025 / September 2025	10		36		10		3		53		Yes
September 8, 2025	10	September 2025 / November 2025	11		63		17		3		88		Yes
October 6, 2025	8	October 2025 / December 2025	5		26		7		1		37		Yes
December 1, 2025	10	December 2025 / March 2026	10		39		11		3		57
February 2, 2026	2	February 2026 / March 2026	1		2		1		�		4
February 9, 2026	8	February 2026 / March 2026	5		36		10		1		50
Jury verdicts, limited judgments not yet entered
February 17, 2026	16	February 2026	2		242		61		�		305
February 23, 2026	13	March 2026	2		34		9		�		45
March 2, 2026	13	March 2026	6		54		14		1		73
March 23, 2026	16	March 2026	5		51		13		2		67
March 30, 2026	3	April 2026	3		31		8		1		41
	190		$	130	$	895	$	240	$	34	$	1,231

(1)For jury verdicts where the limited judgment has not yet been entered, the doubling of economic damages and the application of punitive damages are estimates.

(2)For jury verdicts where limited judgment has been entered, the court offset the awards by the amount of insurance proceeds received by any of the plaintiffs. For jury verdicts where the limited judgment has not yet been entered, the insurance offset is an estimate.

(3)For each limited judgment entered in the court, PacifiCorp has posted or expects to post a supersedeas bond, which stays any effort to seek payment of the judgments pending final resolution of any appeals. Under Oregon Revised Statutes 82.010, interest at a rate of 9% per annum will accrue on the judgments commencing at the date the judgments were entered until the entire money award is paid, amended or reversed by an appellate court. The supersedeas bond posted for the June 2023 James verdict covers three years of post-judgment interest while amounts posted for the subsequent verdicts cover two years of post-judgment interest.

Through April 2026, jury verdict awards averaged approximately $6 million per plaintiff, including insurance offset. Additional damages phase trials are scheduled to occur through 2028 as described below.

James Court Activity

In April 2025, PacifiCorp filed its appellate brief with the Oregon Court of Appeals in connection with its appeal of the June 2023 James verdict and the January and March 2024 James damages phase trial verdicts. In the appellate brief, PacifiCorp addresses numerous procedural and legal issues, including that the class certification is improper due to the plaintiffs being impacted by distinct fires with independent ignition points that were hundreds of miles apart; awarding of non-economic damages is not allowed under Oregon law; plaintiffs failed to prove that PacifiCorp caused harm to every class member; and jury instructions applied incorrect legal standards in assessing class-wide evidence and individual claims. Additionally, PacifiCorp incorporated the ODF's Report into its appellate brief. Various parties who are not party to the James case filed supportive amicus briefs with the court. Plaintiffs filed their combined answering and cross-appeal brief on August 21, 2025, after plaintiffs requested three delays from the Oregon Court of Appeals. PacifiCorp has filed additional appellate briefs and will continue to file individual appellate briefs in connection with appeals of each of the verdicts for additional James damages phase trials.

In November 2025, the Oregon Court of Appeals issued an order for expedited oral argument in response to PacifiCorp's October 2025 request to facilitate a more prompt decision from the court. As a result of the order, oral argument for the appeal was held on February 4, 2026. On April 8, 2026, the Oregon Court of Appeals issued an opinion reversing the June 2023 verdict and remanding to the Multnomah County Circuit Court Oregon for further proceedings. The opinion explained that the Multnomah County Circuit Court Oregon erred in giving its instruction to the jury that they could "assume that the evidence at the trial applies to all class members." The Oregon Court of Appeals further concluded that the erroneous jury instruction "was prejudicial to PacifiCorp" because it "gave rise to some likelihood that the jury reached an erroneous result." Because the Oregon Court of Appeals reversed and remanded on the instructional error, it did not address the majority of PacifiCorp�s other appealed issues. Finally, the Oregon Court of Appeals emphasized that the Multnomah County Circuit Court Oregon has the authority on remand to reconsider its class certification decision and reconsider whether a single class is appropriate in this case. On April 9, 2026, the Multnomah County Circuit Court Oregon ordered a stay of scheduled damages phase trials and all proceedings under Case Management Order No. 11 ("CMO No. 11"), except the ongoing damages phase trial started April 6, 2026 and mandatory mediation. The Multnomah County Circuit Court Oregon asked the parties to submit briefing on the merits, scope and duration of the stay in advance of a May 22, 2026, hearing.

Subsequent to the first two damages phase trials, nine damages phase trials were scheduled to be held in 2025 in accordance with the Multnomah County Circuit Court Oregon's October 2024 case management order, adjudicating the damages of approximately 10 plaintiffs per trial. In March 2025, PacifiCorp filed a motion to stay the additional damages phase trials scheduled under the October 2024 case management order in consideration of the ODF's Report, but the motion was denied in April 2025. Refer to "James Trial Activity" above for information regarding the damages phase trials held in 2025.

In July 2025, the Multnomah County Circuit Court Oregon issued CMO No. 11 in response to the May 2025 hearing that was held to evaluate the scheduling of additional damages phase trials. As ordered, CMO No. 11 proposes to schedule dozens of trials in 2026 and over 100 more in 2027 and 2028. Currently, approximately 1,500 plaintiffs are scheduled for trial under CMO No. 11, including substantially all of those included in the mass complaints described above and reflecting the impacts of settlements and dismissals. CMO No. 11 requires plaintiffs included in the mass complaints to amend their complaints alleging the specific facts that support their claims for economic damages within 180 days before the start of their respective trials. Additionally, CMO No. 11 requires mediation every other month.

In August 2025, PacifiCorp filed a motion with the Oregon Court of Appeals to stay the James damages phase trials addressed in CMO No. 11. In September 2025, the Appellate Commissioner of the Oregon Court of Appeals denied PacifiCorp's motion to stay, to which PacifiCorp filed a request for reconsideration of the stay denial with the Chief Judge of the Oregon Court of Appeals. In October 2025, the Oregon Court of Appeals issued an order denying PacifiCorp's request for reconsideration. In November 2025, PacifiCorp petitioned the Oregon Supreme Court to review the Oregon Court of Appeals' decisions. In December 2025, plaintiffs' counsel filed their opposition to the petition, and in March 2026, the Oregon Supreme Court denied PacifiCorp�s petition for review.

Potential Effects of James CMO No. 11

To stay payment of damages awarded by the limited judgments while on appeal, PacifiCorp is required to bond the judgments. As of the date of this filing, PacifiCorp has posted bonds totaling $719 million associated with the limited judgments entered to date for 129 plaintiffs. These bonding requirements will continue to apply to future judgments associated with the CMO No. 11 trials. As noted above, CMO No. 11 proposes to schedule dozens of trials in 2026 and over 100 more in 2027 and 2028, with trials currently scheduled for approximately 1,500 plaintiffs. Each trial is subject to and dependent on judicial resources and availability, which will be determined six weeks before each trial. The CMO No. 11 proposed schedule is likely to put significant strain on the Multnomah County Circuit Court system, and PacifiCorp believes this may challenge the court's ability to fulfill the schedule in CMO No. 11.

PacifiCorp's liquidity has been materially impacted and its credit ratings have been downgraded as a result of the litigation risk and estimated losses recorded to date associated with the Wildfires. Due to the volume of James damages phase trials scheduled under CMO No. 11 combined with the requirement to bond judgments for each verdict to stay payment of damages during the appeals process, PacifiCorp may be unable to obtain the necessary funding to meet its liquidity needs.

While bonding of judgments awarded in James verdicts to date have been supported by surety bonds, they can also be supported by posting letters of credit or cash. If the trial schedule and caseload progress as proposed in CMO No. 11 and the future limited judgments follow current trends, damages awarded in additional James jury verdicts could exceed PacifiCorp's available surety bond and letter of credit capacity, requiring cash bonding thereafter.

In April 2026, PacifiCorp entered into a letter of credit agreement under which letters of credit will be made available solely to provide collateral support for surety bonds issued pursuant to a corresponding surety arrangement for supersedeas undertakings to secure the performance and stay enforcement of trial court judgments entered against PacifiCorp relating to the James case described in Note 14 in Notes to the Financial Statements, in each case while such judgments remain pending appeal by PacifiCorp in the Oregon Court of Appeals or the Oregon Supreme Court. The letter of credit agreement provides for a two-year standby letter of credit facility for PacifiCorp in an aggregate stated amount of up to $2.55 billion and is subject to approval by the Oregon Public Utility Commission and the Idaho Public Utilities Commission and other customary conditions. These conditions must be satisfied on or before September 30, 2026. In conjunction with the letter of credit agreement, PacifiCorp entered into a committed surety facility set forth in a term sheet with an initial aggregate capacity of $2.55 billion, not to exceed availability under the letter of credit agreement, and related indemnity agreement under which the surety party is committed to issue surety bonds from time to time for PacifiCorp to secure the supersedeas undertakings described above. The surety facility must be fully secured by letters of credit. If 91 days prior to the applicable termination date of any letter of credit issued under the arrangements described above, any letter of credit obligations remain outstanding, PacifiCorp will be required to provide cash collateral to secure outstanding letter of credit obligations in an amount equal to 103 percent of such obligations.

PacifiCorp expects additional debt financings, including potential borrowings under its $2.0 billion credit facility to the extent available, or other sources of funding will be needed to provide liquidity to post cash for judgments. These bonding requirements could weaken PacifiCorp's credit metrics. Any further credit rating downgrade may result in the loss of surety bond and letter of credit capacity, trigger cash collateral calls for surety bonds posted and trigger cash collateral calls or other forms of security for wholesale energy agreements that contain credit risk-related contingent features or rights to demand adequate assurance in the event of a material adverse change in PacifiCorp's creditworthiness. Additionally, a downgrade of PacifiCorp's senior secured debt below investment grade would require new regulatory applications and approvals due to certain authorizations or exemptions currently in place with certain regulatory commissions for the issuance of securities. PacifiCorp may also be subject to borrowing limitations under its long-term debt covenants.

In the event of a downgrade below investment grade, PacifiCorp may be unable to secure sufficient debt financings or alternative funding sources to support ongoing operations, including the ability to absorb wholesale power volatility, pay suppliers and meet debt obligations, and such liquidity issues may impact transmission and generation development, purchasing power in the market, building and upgrading substations, connecting new customers, addressing outages and maintaining system resilience. Investors in PacifiCorp's first mortgage bonds may be unable to hold existing bonds or to invest in new bonds, and perceived risks associated with the Wildfires may limit PacifiCorp's ability to attract investors. At a minimum, the cost of any short- or long-term financing is expected to be higher as a result of the wildfire litigation risks and decline in PacifiCorp's credit ratings.

Litigation is inherently difficult to predict, and its potential financial impacts are therefore based on assumptions that will change. Furthermore, there may be judicial decisions and other events or circumstances that could improve or worsen the challenges PacifiCorp faces. PacifiCorp believes it will have sufficient liquidity to cover its operations and obligations beyond a year.

2022 McKinney Fire

According to the California Department of Forestry and Fire Protection, a wildfire began on July 29, 2022, in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California located in PacifiCorp's service territory, burning over 60,000 acres. Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged; 185 structures destroyed, including residences; 12 injuries; and four fatalities. The USFS issued a Wildland Fire Origin and Cause Supplemental Incident Report. The report concluded that a tree coming in contact with a power line is the probable cause of the 2022 McKinney Fire. Settlements have been reached with substantially all individual plaintiffs, timber companies and insurance subrogation plaintiffs in the 2022 McKinney Fire. Additionally, PacifiCorp has settled all wrongful death claims associated with the 2022 McKinney Fire and has settled with the federal government as described above.

Estimated Losses for and Settlements Associated with the Wildfires

Based on the facts and circumstances available to PacifiCorp through February 27, 2026, the date through which PacifiCorp has evaluated the impacts of events occurring after December 31, 2025 as indicated under "Subsequent Events", including (i) cause and origin investigations; (ii) ongoing settlement and mediation activities; (iii) other litigation matters and upcoming legal proceedings; and (iv) the status of the James case, PacifiCorp recorded cumulative estimated probable losses associated with the Wildfires of $2,853 million through December 31, 2025. PacifiCorp's cumulative accrual includes estimates of probable losses for fire suppression costs, real and personal property damages, natural resource damages and noneconomic damages such as personal injury damages and loss of life damages that it is reasonably able to estimate at this time and which is subject to change as additional relevant information becomes available. Any information associated with the Wildfires arising subsequent to February 27, 2026 will be considered in a future period.

Through December 31, 2025, PacifiCorp paid $1,692 million in settlements associated with the Wildfires, $53 million of which occurred in 2022. As a result of the settlements, various trials have been cancelled. In January through March 2026, PacifiCorp made additional settlement payments related to the Wildfires totaling $584 million, including the $575 million discussed above.

The following table presents changes in PacifiCorp's liability for estimated losses associated with the Wildfires for the years ended December 31 (in millions):


	2025		2024

Beginning balance	$	1,536	$	1,723
Accrued losses	100		346
Payments	(475)		(533)
Ending balance	$	1,161	$	1,536

As of December 31, 2025 and 2024, $734 million and $247 million, respectively, of PacifiCorp's liability for estimated losses associated with the Wildfires was included in Total Current and Accrued Liabilities on the Comparative Balance Sheet. The amounts reflected as current as of December 31, 2025 reflect amounts reasonably expected to be paid out within the next year based on settlements reached as well as ongoing settlement and mediation efforts. The remainder of PacifiCorp's liability for estimated losses associated with the Wildfires as of December 31, 2025 and 2024 was included in Total Other Noncurrent Liabilities on the Comparative Balance Sheet.

The following table presents changes in PacifiCorp's receivable for expected insurance recoveries associated with the Wildfires for the years ended December 31 (in millions):


	2025		2024

Beginning balance	$	98	$	499
Accruals	�		�
Payments received	(98)		(401)
Ending balance	$	�	$	98

As of December 31, 2025, PacifiCorp had received all expected insurance recoveries. As of December 31, 2024, PacifiCorp's receivable for expected insurance recoveries was included in Total Current and Accrued Assets on the Comparative Balance Sheet. No additional insurance recoveries beyond those received to date are expected to be available.

During the years ended December 31, 2025 and 2024, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $100 million and $346 million, respectively.

It is reasonably possible PacifiCorp will incur material additional losses beyond the amounts accrued for the Wildfires that could have a material adverse effect on PacifiCorp's financial condition. PacifiCorp is currently unable to reasonably estimate a specific range of possible additional losses that could be incurred due to the number of properties and parties involved, including claimants in the class to the James case, the variation in the types of properties and damages and the ultimate outcome of legal actions, including mediation, settlement negotiations, jury verdicts and the appeals process.

Guarantees

PacifiCorp has entered into guarantees as part of the normal course of business and the sale or transfer of certain assets. These guarantees are not expected to have a material impact on PacifiCorp's financial results.

(15) Preferred Stock

In the event of voluntary liquidation, all preferred stock was entitled to stated value or a specified preference amount per share plus accrued dividends. Upon involuntary liquidation, all preferred stock was entitled to stated value plus accrued dividends. Dividends on all preferred stock were cumulative. Holders also had the right to elect members to the PacifiCorp Board of Directors in the event dividends payable are in default in an amount equal to four full quarterly payments.

On February 10, 2025, PacifiCorp effected a one-for-ten thousand reverse stock split ("Reverse Stock Split") of its Serial Preferred Stock.

As a result of the Reverse Stock Split, every 10,000 shares of each of PacifiCorp's pre-reverse split Serial Preferred Stock were combined and reclassified into one share of Serial Preferred Stock, with a corresponding reduction in the number of authorized shares of Serial Preferred Stock from 3,500 thousand to 350 and change to stated value of $100 to $1,000,000 per share. No fractional shares were issued in connection with the Reverse Stock Split and shareholders who would have otherwise held a fractional share of Serial Preferred Stock received payment in cash. As a result, all issued and outstanding shares of PacifiCorp's preferred stock as of February 10, 2025, were held by PPW Holdings LLC.

On April 23, 2025, PacifiCorp repurchased the sole outstanding share of its 7.00% Serial Preferred Stock from PPW Holdings LLC, for a purchase price of $1,800,000.

(16) Common Shareholder's Equity

Through PPW Holdings LLC, BHE is the sole shareholder of PacifiCorp's common stock. The state regulatory orders that authorized BHE's acquisition of PacifiCorp contain restrictions on PacifiCorp's ability to pay dividends to the extent that they would reduce PacifiCorp's common equity below specified percentages of defined capitalization. As of December 31, 2025, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to PPW Holdings LLC or BHE without prior state regulatory approval to the extent that it would reduce PacifiCorp's common equity below 44.00% of its total capitalization, excluding short-term debt and current maturities of long-term debt. As of December 31, 2025, PacifiCorp's actual common equity percentage, as calculated under this measure, was 44.27%. BHE has indicated that it will suspend dividends for the next several years.

Certain of these commitments also indirectly limit PacifiCorp's capital structure by requiring the consolidated equity of PPW Holdings LLC to be no less than 44.00% of total consolidated PPW Holdings LLC capitalization, excluding short-term debt and current maturities of long-term debt. As of December 31, 2025, consolidated PPW Holdings LLC equity exceeded the threshold. As of April 2026, certain of these commitments were modified to indirectly limit PacifiCorp's capital structure by requiring the consolidated equity of PPW Holdings LLC as a percentage of total consolidated PPW Holdings LLC capitalization, excluding short-term debt and current maturities of long-term debt, to be no less than 40.00% for the Washington and Wyoming commitments and no less than 35% for the Oregon, Idaho and California commitments.

These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings LLC or BHE if PacifiCorp's senior unsecured debt rating is BBB- or lower by Standard & Poor's Rating Services and Baa3 or lower by Moody's Investor Service. As of December 31, 2025, PacifiCorp met this minimum required senior unsecured debt rating commitment.

PacifiCorp is also subject to a maximum debt-to-total capitalization percentage under various financing agreements as further discussed in Note 7.

(17) Supplemental Cash Flow Disclosures

The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):


	2025		2024
Supplemental disclosure of cash flow information:
Interest paid, net of amounts capitalized	$	664	$	527

Supplemental disclosure of non-cash investing and financing activities:
Accounts payable related to utility plant additions	$	776	$	773

(18) Subsequent Events

On February 15, 2026, PacifiCorp and Portland General Electric Company and an affiliate of Portland General Electric Company (together, the "PGE Entities") entered into an Asset Purchase and Service Area Transfer Agreement (the "Sale Agreement") to sell to the PGE Entities certain PacifiCorp assets and liabilities associated with PacifiCorp's Washington operations for a sales price of $1.9 billion in cash plus additional cash consideration for the value of specified assets delivered at closing, subject to customary purchase price adjustments (the "Transaction").

The Transaction assets and liabilities are associated with PacifiCorp's retail service area in Washington and include certain related distribution assets and infrastructure, as well as PacifiCorp's Chehalis combined cycle natural gas-fueled generating facility located in Chehalis, Washington, Goodnoe Hills wind-powered generating facility located in Goldendale, Washington, and Marengo wind-powered generating facility located in Dayton, Washington.

The Transaction has been approved by PacifiCorp's board of directors but is subject to customary closing conditions including (i) the expiration or termination of the waiting period and other required approvals under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and (ii) the receipt of all necessary approvals, waivers and rulings from the FERC and each of PacifiCorp's six state public utility commissions. The Transaction is expected to close in the first half of 2027.

The Sale Agreement contains certain termination rights, including if the Transaction is not consummated by August 15, 2027, (subject to a six month extension to the extent certain regulatory approvals have not been received as of such date), and provides that upon termination of the Sale Agreement under certain specified circumstances, the terminating party would be required to pay the other party a termination fee of $35 million.

PacifiCorp believes the carrying value of the assets and liabilities are less than fair value and therefore does not expect to record a loss as a result of the Transaction. PacifiCorp expects to continue to depreciate the property, plant and equipment included in the Transaction as it will continue to operate and serve PacifiCorp's customers through closing of the Transaction and the costs to operate such property, plant and equipment will continue to be recovered in PacifiCorp's retail rates. Certain regulatory asset, regulatory liability, asset retirement obligation and deferred income tax balances will also be impacted by the Transaction.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. Report data on a year-to-date basis.
Line No.	Item (a)	Unrealized Gains and Losses on Available-For-Sale Securities (b)	Minimum Pension Liability Adjustment (net amount) (c)	Foreign Currency Hedges (d)	Other Adjustments (e)	Other Cash Flow Hedges Interest Rate Swaps (f)	Other Cash Flow Hedges [Specify] (g)	Totals for each category of items recorded in Account 219 (h)	Net Income (Carried Forward from Page 116, Line 78) (i)	Total Comprehensive Income (j)
1	Balance of Account 219 at Beginning of Preceding Year				10,369,236			10,369,236
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income				568,833			568,833
3	Preceding Quarter/Year to Date Changes in Fair Value				685,146			685,146
4	Total (lines 2 and 3)				1,253,979			1,253,979	538,923,971	540,177,950
5	Balance of Account 219 at End of Preceding Quarter/Year				9,115,257			9,115,257
6	Balance of Account 219 at Beginning of Current Year				9,115,257			9,115,257
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income				501,075			501,075
8	Current Quarter/Year to Date Changes in Fair Value				1,371,205			1,371,205
9	Total (lines 7 and 8)				870,130			870,130	640,140,656	639,270,526
10	Balance of Account 219 at End of Current Quarter/Year				9,985,387			9,985,387

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.
Line No.	Classification (a)	Total Company For the Current Year/Quarter Ended (b)	Electric (c)	Gas (d)	Other (Specify) (e)	Other (Specify) (f)	Other (Specify) (g)	Common (h)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlantInServiceAbstract In Service
3	UtilityPlantInServiceClassified Plant in Service (Classified)	38,667,415,599	38,667,415,599
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	440,490,621	440,490,621
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	1,835,052,205	1,835,052,205
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	40,942,958,425	40,942,958,425
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	11,176,305	11,176,305
11	ConstructionWorkInProgress Construction Work in Progress	3,305,302,836	3,305,302,836
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	156,468,483	156,468,483
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	44,415,906,049	44,415,906,049
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	14,475,856,318	14,475,856,318
15	UtilityPlantNet Net Utility Plant (13 less 14)	29,940,049,731	29,940,049,731
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	14,134,417,268	14,134,417,268
19	AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService Amortization and Depletion of Producing Natural Gas Land and Land Rights
20	AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService Amortization of Underground Storage Land and Land Rights
21	AmortizationOfOtherUtilityPlantUtilityPlantInService Amortization of Other Utility Plant	195,982,270	195,982,270
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	14,330,399,538	14,330,399,538
23	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract Leased to Others
24	DepreciationUtilityPlantLeasedToOthers Depreciation
25	AmortizationAndDepletionUtilityPlantLeasedToOthers Amortization and Depletion
26	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers Total Leased to Others (24 & 25)
27	DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract Held for Future Use
28	DepreciationUtilityPlantHeldForFutureUse Depreciation
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	145,456,780	145,456,780
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	14,475,856,318	14,475,856,318

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing arrangements.
Line No.	Description of item (a)	Balance Beginning of Year (b)	Changes during Year Additions (c)	Changes during Year Amortization (d)	Changes during Year Other Reductions (Explain in a footnote) (e)	Balance End of Year (f)
1	Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1)
2	Fabrication
3	Nuclear Materials
4	Allowance for Funds Used during Construction
5	(Other Overhead Construction Costs, provide details in footnote)
6	SUBTOTAL (Total 2 thru 5)
7	Nuclear Fuel Materials and Assemblies
8	In Stock (120.2)
9	In Reactor (120.3)
10	SUBTOTAL (Total 8 & 9)
11	Spent Nuclear Fuel (120.4)
12	Nuclear Fuel Under Capital Leases (120.6)
13	(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5)
14	TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13)
15	Estimated Net Salvage Value of Nuclear Materials in Line 9
16	Estimated Net Salvage Value of Nuclear Materials in Line 11
17	Est Net Salvage Value of Nuclear Materials in Chemical Processing
18	Nuclear Materials held for Sale (157)
19	Uranium
20	Plutonium
21	Other (Provide details in footnote)
22	TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21)

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Report below the original cost of electric plant in service according to the prescribed accounts. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included in column (c) are entries for reversals of tentative distributions of the prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent�s plant actually in service at end of year. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date.
Line No.	Account (a)	Balance Beginning of Year (b)	Additions (c)	Retirements (d)	Adjustments (e)	Transfers (f)	Balance at End of Year (g)
1	1. INTANGIBLE PLANT
2	(301) Organization
3	(302) Franchise and Consents	188,284,309	301,999				188,586,308
4	(303) Miscellaneous Intangible Plant	991,563,606	2,069,197			(h) 788,013,531	205,619,272
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	1,179,847,915	2,371,196			788,013,531	394,205,580
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	91,714,952	97,343	1,026		(i) 41,195,596	50,615,673
9	(311) Structures and Improvements	1,059,352,414	6,384,827	48,443,823		(j) 8,656,304	1,008,637,114
10	(312) Boiler Plant Equipment	4,482,191,313	48,815,883	278,843,441		(k) 61,601,086	4,190,562,669
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	1,000,443,706	19,629,278	13,685,415		(l) 35,733,341	970,654,228
13	(315) Accessory Electric Equipment	430,520,921	2,375,069	40,309,547		(m) 8,555,197	384,031,246
13.1	(315.1) Computer Hardware		690,455	354,543		(n) 773,748	1,109,660
13.2	(315.2) Computer Software		182,426	509		(o) 40,912	222,829
13.3	(315.3) Communication Equipment		718,215	16,537		(p) 19,243,963	19,945,641
14	(316) Misc. Power Plant Equipment	34,556,190	239,780	82,127		(q) 1,351,533	33,362,310
15	(317) Asset Retirement Costs for Steam Production	197,725,618	4,841,753	99,565,215	2,280,061	(r) 5,846,630	94,875,465
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	7,296,505,114	83,975,029	481,302,183	2,280,061	142,881,064	6,754,016,835
17	B. Nuclear Production Plant
18	(320) Land and Land Rights
19	(321) Structures and Improvements
20	(322) Reactor Plant Equipment
21	(323) Turbogenerator Units
22	(324) Accessory Electric Equipment
22.1	(324.1) Computer Hardware
22.2	(324.2) Computer Software
22.3	(324.3) Communication Equipment
23	(325) Misc. Power Plant Equipment
24	(326) Asset Retirement Costs for Nuclear Production
25	TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26	C. Hydraulic Production Plant
27	(330) Land and Land Rights	37,846,884					37,846,884
28	(331) Structures and Improvements	327,687,134	17,752,767	4,071,132			341,368,769
29	(332) Reservoirs, Dams, and Waterways	527,996,177	21,163,719	198,589		7,381	548,968,688
30	(333) Water Wheels, Turbines, and Generators	132,496,503	10,827,123	1,133,355			142,190,271
31	(334) Accessory Electric Equipment	73,388,540	1,289,770	464,132			74,214,178
31.1	(334.1) Computer Hardware		149,023	141,520		(s) 180,262	187,765
31.2	(334.2) Computer Software		22,834	23,831		(t) 23,831	22,834
31.3	(334.3) Communication Equipment		446,372	15,887		(u) 15,305,010	15,735,495
32	(335) Misc. Power Plant Equipment	3,633,176	452,115	22,131			4,107,422
33	(336) Roads, Railroads, and Bridges	27,891,131	4,283,660	40,280			32,134,511
34	(337) Asset Retirement Costs for Hydraulic Production	1,049,713		1,049,713
35	TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)	1,131,989,258	56,387,383	7,116,308		15,516,484	1,196,776,817
35.1	D. Solar Production Plant
35.2	(338.1) Land and Land Rights					(v) 74,986	74,986
35.3	(338.2) Structures and Improvements		7,897			(w) 73,237	81,134
35.5	(338.4) Solar Panels					(x) 348,108	348,108
35.6	(338.5) Collector System					(y) 133,736	133,736
35.7	(338.6) Generator Step-up Transformers (GSU)
35.8	(338.7) Inverters		83,192			(z) 228,389	311,581
35.9	(338.8) Other Accessory Electrical Equipment		1,607			(aa) 635,526	637,133
35.10	(338.9) Computer Hardware
35.11	(338.10) Computer Software
35.12	(338.11) Communication Equipment					(ab) 83,073	83,073
35.13	(338.12) Miscellaneous Power Plant Equipment
35.14	(338.13) Asset Retirement Costs for Solar Production
35.15	TOTAL Solar Production Plant (Enter Total of lines 35.2 thru 35.14)		92,696			1,577,055	1,669,751
35.16	E. Wind Production Plant
35.17	(338.20) Land and Land Rights		2,968,990			(ac) 17,581,425	20,550,415
35.18	(338.21) Structures and Improvements		173,719,251	174,830		(ad) 384,876,311	558,420,732
35.20	(338.23) Wind Turbines		526,428,991	9,755,590		(ae) 2,408,023,379	2,924,696,780
35.21	(338.24) Wind Towers and Fixtures		177,092,890			(af) 682,743,482	859,836,372
35.23	(338.26) Collector System		103,647,308	55,800		(ag) 245,806,512	349,398,020
35.24	(338.27) Generator Step-up Transformers (GSU)		20,767,773	1,110,408		(ah) 37,867,619	57,524,984
35.25	(338.28) Inverters		10,341,867			(ai) 1,227,600	11,569,467
35.26	(338.29) Other Accessory Electrical Equipment		1,974,797	56,620		(aj) 11,966,823	13,885,000
35.27	(338.30) Computer Hardware		246,038	32,594		(ak) 556,427	769,871
35.28	(338.31) Computer Software		262,547			63,781	326,328
35.29	(338.32) Communication Equipment		987,771			(al) 2,477,816	3,465,587
35.30	(338.33) Miscellaneous Power Plant Equipment		3,866,983	170,586		(am) 15,035,035	18,731,432
35.31	(338.34) Asset Retirement Costs for Wind Production		8,301,877		242,649	(an) 50,231,045	58,290,273
35.32	TOTAL Wind Production Plant (Enter Total of lines 35.17 thru 35.31)		1,030,607,083	11,356,428	242,649	3,858,457,255	4,877,465,261
35.33	F. Other Renewable Production Plant
35.34	(339.1) Land and Land Rights					(ao) 41,195,596	41,195,596
35.35	(339.2) Structures and Improvements		102	35,757		(ap) 8,656,304	8,620,649
35.36	(339.3) Fuel Holders		317,523	65,734		(aq) 58,751,114	59,002,903
35.37	(339.4) Boilers					(ar) 2,604,945	2,604,945
35.39	(339.6) Generators					(as) 35,970,982	35,970,982
35.41	(339.8) Other Accessory Electrical Equipment			2,744		(at) 8,555,197	8,552,453
35.42	(339.9) Computer Hardware			83,179		(au) 88,230	5,051
35.43	(339.10) Computer Software					7,387	7,387
35.44	(339.11) Communication Equipment					(av) 1,020,418	1,020,418
35.45	(339.12) Miscellaneous Power Plant Equipment		17,810			(aw) 1,351,533	1,369,343
35.46	(339.13) Asset Retirement Costs for Other Renewable Production		155,819			(ax) 5,846,630	6,002,449
35.47	TOTAL Other Renewable Production Plant (Enter Total of lines 35.34 thru 35.46)		491,254	187,414		164,048,336	164,352,176
36	G. Other Production Plant
37	(340) Land and Land Rights	99,076,598				(ay) 59,818,964	39,257,634
38	(341) Structures and Improvements	279,661,794	1,137,840	8,451		(az) 104,112,240	176,678,943
39	(342) Fuel Holders, Products, and Accessories	16,439,353					16,439,353
40	(343) Prime Movers	4,262,619,909	101,234,994	37,626,395		(ba) 3,095,879,025	1,230,349,483
41	(344) Generators	689,019,218	6,703,959	775,910		(bb) 252,527,155	442,420,112
42	(345) Accessory Electric Equipment	467,869,400	391,755	122,955		(bc) 253,031,811	215,352,299
42.1	(345.1) Computer Hardware		164,083	194,901		(bd) 433,712	402,894
42.2	(345.2) Computer Software		15,307			(be) 7,816	23,123
42.3	(345.3) Communication Equipment		654,718			(bf) 2,648,247	3,302,965
43	(346) Misc. Power Plant Equipment	25,863,349				(bg) 12,885,472	12,977,877
44	(347) Asset Retirement Costs for Other Production	52,282,320	4,137,233			(bh) 50,231,045	6,188,508
45	TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)	5,892,831,941	114,439,889	38,482,702		3,825,395,937	2,143,393,191
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, 35.15, 35.32, 35.47, and 45)	(a) 14,321,326,313	1,285,993,334	538,445,035	2,522,710	71,322,129	(bt) 15,137,674,031
47	3. Transmission Plant
48	(350) Land and Land Rights	466,656,013	5,456,305	22,797			472,089,521
48.2	(351.1) Computer Hardware		409,123	81,473		(bi) 81,473	409,123
48.3	(351.2) Computer Software		11,851,575			(bj) 55,644,709	67,496,284
48.4	(351.3) Communication Equipment		9,380,641	1,158,407		(bk) 199,657,015	207,879,249
49	(352) Structures and Improvements	410,583,028	73,202,847	269,547			483,516,328
50	(353) Station Equipment	3,569,215,743	243,094,515	3,184,023		28,801,003	3,780,325,232
51	(354) Towers and Fixtures	2,604,486,114	41,662,642	72,584			2,646,076,172
52	(355) Poles and Fixtures	1,534,948,481	137,843,720	10,066,573			1,662,725,628
53	(356) Overhead Conductors and Devices	2,380,323,565	79,367,163	7,752,608			2,451,938,120
54	(357) Underground Conduit	3,933,553	21,576	17,516			3,937,613
55	(358) Underground Conductors and Devices	9,083,639					9,083,639
56	(359) Roads and Trails	12,141,468					12,141,468
57	(359.1) Asset Retirement Costs for Transmission Plant	3,127,183	306,308				3,433,491
58	TOTAL Transmission Plant (Enter Total of lines 48 thru 57)	(b) 10,994,498,787	602,596,415	22,625,528		226,582,194	(bu) 11,801,051,868
59	4. Distribution Plant
60	(360) Land and Land Rights	90,012,356	1,765,139			388,164	92,165,659
61	(361) Structures and Improvements	160,830,647	826,108	196,975		603	161,460,383
62	(362) Station Equipment	1,488,894,589	189,239,813	6,391,396		96,457	1,671,839,463
63.1	(363.1) Computer Hardware		990,965	1,470,647		(bl) 3,249,516	2,769,834
63.2	(363.2) Computer Software		5,115,108	1,991		(bm) 46,821,866	51,934,983
63.3	(363.3) Communication Equipment		24,953,125	1,275,073		(bn) 190,001,268	213,679,320
64	(364) Poles, Towers, and Fixtures	1,801,994,931	339,276,251	26,115,460			2,115,155,722
65	(365) Overhead Conductors and Devices	1,187,871,547	133,277,207	18,804,585			1,302,344,169
66	(366) Underground Conduit	556,723,935	44,949,624	3,278,503			598,395,056
67	(367) Underground Conductors and Devices	1,272,817,445	221,593,290	6,435,113			1,487,975,622
68	(368) Line Transformers	1,755,631,948	149,385,884	13,319,231			1,891,698,601
69	(369) Services	1,116,634,765	59,028,065	1,864,785			1,173,798,045
70	(370) Meters	324,384,078	15,909,541	6,516,690			333,776,929
71	(371) Installations on Customer Premises	9,000,581	182,235	56,017			9,126,799
72	(372) Leased Property on Customer Premises
73	(373) Street Lighting and Signal Systems	67,954,265	2,714,748	1,859,773			68,809,240
74	(374) Asset Retirement Costs for Distribution Plant	1,331,349					1,331,349
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	(c) 9,834,082,436	1,189,207,103	87,586,239		240,557,874	(bv) 11,176,261,174
76	5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77	(380) Land and Land Rights
78	(381) Structures and Improvements
79	(382) Computer Hardware
80	(383) Computer Software
81	(384) Communication Equipment
82	(385) Miscellaneous Regional Transmission and Market Operation Plant
83	(386) Asset Retirement Costs for Regional Transmission and Market Oper
84	TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
84.1	6. ENERGY STORAGE PLANT
84.2	(387.1) Land and Land Rights
84.3	(387.2) Structures and Improvements
84.4	(387.3) Energy Storage Equipment
84.6	(387.5) Collector System
84.7	(387.6) Generator Step-up Transformers (GSU)
84.8	(387.7) Inverters
84.9	(387.8) Computer Hardware
84.10	(387.9) Computer Software
84.11	(387.10) Communication Equipment
84.12	(387.11) Miscellaneous Energy Storage Equipment
84.13	(387.12) Asset Retirement Costs for Energy Storage
84.14	TOTAL Energy Storage Plant (Total lines 84.2 thru 84.13)
85	7. General Plant
86	(389) Land and Land Rights	27,860,964	479,591			12,703	28,327,852
87	(390) Structures and Improvements	353,876,609	1,084,927	263,377			354,698,159
88	(391) Office Furniture and Equipment	95,288,980	2,099,121	2,547,053		(bo) 69,432,156	25,408,892
89	(392) Transportation Equipment	182,412,038	11,975,846	8,051,561			186,336,323
90	(393) Stores Equipment	21,385,312	1,236,371	177,302		1,418,699	23,863,080
91	(394) Tools, Shop and Garage Equipment	71,341,843	4,035,368	1,426,444			73,950,767
92	(395) Laboratory Equipment	49,171,831	7,157,904	1,679,773			54,649,962
93	(396) Power Operated Equipment	224,800,161	315,188	12,757,106		1,418,699	210,939,544
94	(397.1) Computer Hardware		14,953,323	7,513,614		(bp) 64,056,187	71,495,896
94.1	(397.2) Computer Software		115,248,274	7,575,908		(bq) 685,499,873	793,172,239
94.2	(397.3) Communication Equipment	(d) 581,811,742	5,750,963	1,806,430		(br) 430,128,507	155,627,768
95	(398) Miscellaneous Equipment	12,899,172	449,279	348,474		55,899	12,944,078
96	SUBTOTAL (Enter Total of lines 86 thru 95)	1,620,848,652	164,786,155	44,147,042		249,926,795	1,991,414,560
97	(399) Other Tangible Property	(e) 1,822,901					(bw) 1,822,901
98	(399.1) Asset Retirement Costs for General Plant	37,690					37,690
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	(f) 1,622,709,243	164,786,155	44,147,042		249,926,795	(bx) 1,993,275,151
100	TOTAL (Accounts 101 and 106)	37,952,464,694	3,244,954,203	692,803,844	2,522,710	375,461	40,502,467,804
101	(102) Electric Plant Purchased (See Instr. 8)
102	(Less) (102) Electric Plant Sold (See Instr. 8)	184,656				(bs) 184,656
103	(103) Experimental Plant Unclassified
104	TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)	(g) 37,952,649,350	3,244,954,203	692,803,844	2,522,710	190,805	(by) 40,502,467,804

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: ProductionPlant

Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:

Account (a)

Ref. Line No. (Column)

Balance Beg. of Year (b)

TOTAL Production Plant

46 (b)

14,321,326,313

Less: (317) Asset Retirement Costs for Steam Production (1)

15 (b)

197,725,618

Less: (337) Asset Retirement Costs for Hydraulic Production (1)

34 (b)

1,049,713

Less: (338.34) Asset Retirement Costs for Wind Production (1)

35.31 (b)

�

Less: (339.13) Asset Retirement Costs for Other Renewable Production (1)

35.46 (b)

�

Less: (347) Asset Retirement Costs for Other Production (1)

44 (b)

52,282,320

Revised TOTAL Production Plant

14,070,268,662

(1) In accordance with 18 C.F.R. �35.18(a-c) a public utility that files a transmission rate schedule, tariff or service agreement under �35.12 or �35.13 and has recorded an asset retirement obligation on its books, but is not seeking recovery of the asset retirement costs in rates, must remove all asset-retirement-obligations-related cost components from the cost of service supporting its proposed rates.

(b) Concept: TransmissionPlant

Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:

Account (a)

Ref. Line No. (Column)

Balance Beg. of Year (b)

TOTAL Transmission Plant

58 (b)

10,994,498,787

Less: (359.1) Asset Retirement Costs for Transmission Plant (1)

57 (b)

3,127,183

Revised TOTAL Transmission Plant

10,991,371,604

Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:

Account (a)

Ref. Line No. (Column)

Balance Beg. of Year (b)

TOTAL Distribution Plant

75 (b)

9,834,082,436

Less: (374) Asset Retirement Costs for Distribution Plant (1)

74 (b)

1,331,349

Revised TOTAL Distribution Plant

9,832,751,087

(d) Concept: CommunicationEquipment

As a result of FERC Order No. 898, the beginning January 1, 2025 balance of what was previously FERC Account 397, Communication equipment, within the General Plant function has been presented in Account 397.3, Communication Equipment, with any transfers to functionalize the communication equipment outside of General Plant under FERC Order No. 898 presented in the Transfers column as indicated in footnote (h).

(e) Concept: OtherTangibleProperty

Account 399.21, Land owned in fee

(f) Concept: GeneralPlant

Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:

Account (a)

Ref. Line No. (Column)

Balance Beg. of Year (b)

TOTAL General Plant

99 (b)

1,622,709,243

Less: (399) Other Tangible Property (1)

97 (b)

1,822,901

Less: (399.1) Asset Retirement Costs for General Plant (2)

98 (b)

37,690

Revised TOTAL General Plant

1,620,848,652

(1) To adjust PacifiCorp's formula rate, per FERC Docket No. FA16-4-000 for mining assets related to production plant.

(2) In accordance with 18 C.F.R. �35.18(a-c) a public utility that files a transmission rate schedule, tariff or service agreement under �35.12 or �35.13 and has recorded an asset retirement obligation on its books, but is not seeking recovery of the asset retirement costs in rates, must remove all asset-retirement-obligations-related cost components from the cost of service supporting its proposed rates.

(g) Concept: ElectricPlantInService

Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:

Account (a)

Ref. Line No. (Column)

Balance Beg. of Year (b)

TOTAL Intangible Plant

5 (b)

1,179,847,915

Revised TOTAL Production Plant (1)

14,070,268,662

Revised TOTAL Transmission Plant (2)

10,991,371,604

Revised TOTAL Distribution Plant (3)

9,832,751,087

Revised TOTAL General Plant (4)

1,620,848,652

(102) Electric Plant Purchased

101 (b)

�

(Less) (102) Electric Plant Sold

102 (b)

(184,656)

(103) Experimental Plant Unclassified

103 (b)

�

Revised TOTAL Electric Plant in Service

37,694,903,264

(1) Refer to footnote on page 204, line no. 46, column (b)

(2) Refer to footnote on page 204, line no. 58, column (b)

(3) Refer to footnote on page 204, line no. 75, column (b)

(4) Refer to footnote on page 204, line no. 99, column (b)

(h) Concept: MiscellaneousIntangiblePlantTransfers


This footnote applies to all lines on Page 204 of this Form No. 1 that were impacted by the adoption of FERC Order No. 898 on January 1, 2025. Beginning January 1, 2025 balances that transferred between accounts as a result of the order and that are presented in the Transfers column were as follows:
FERC Account	FERC Account Description	Cost Transferred
303	Miscellaneous intangible plant	$	(774,018,491)
310	Land and land rights	(41,195,596)
311	Structures and improvements	(8,560,163)
312	Boiler plant equipment	(61,181,755)
314	Turbogenerator units	(35,970,982)
315	Accessory electric equipment	(8,555,197)
315.1	Computer hardware	603,945
315.2	Computer software	47,987
315.3	Communication equipment	18,768,392
316	Miscellaneous power plant equipment	(1,351,533)
317	Asset retirement costs for steam prod plant	(5,846,630)
334.1	Computer hardware	164,004
334.2	Computer software	23,831
334.3	Communication equipment	14,246,699
338.1	Land and land rights	74,986
338.2	Structures and improvements	73,237


338.4	Solar panels	348,108
338.5	Collector system	133,736
338.7	Inverters	644,603
338.8	Other accessory electrical equipment	28,467
338.11	Communication equipment	83,073
338.2	Land and land rights	17,581,425
338.21	Structures and improvements	328,297,348
338.23	Wind turbines	2,211,944,271
338.24	Wind towers and fixtures	682,743,482
338.26	Collector system	208,165,060
338.27	Generator step-up transformers (GSU)	37,447,176
338.28	Inverters	1,227,600
338.29	Other accessory electrical equipment	9,842,522
338.3	Computer hardware	219,942
338.32	Communication equipment	2,406,407
338.33	Miscellaneous power plant equipment	14,839,107
338.34	Asset retirement costs for wind production	50,231,045
339.1	Land and land rights	41,195,596
339.2	Structures and improvements	8,560,163
339.3	Fuel holders	58,576,811
339.4	Boilers	2,604,945
339.6	Generators	35,970,982
339.8	Other accessory electrical equipment	8,555,197
339.9	Computer hardware	88,230
339.11	Communication equipment	1,006,471
339.12	Miscellaneous power plant equipment	1,351,533
339.13	Asset retirement costs for other renewable prod	5,846,630
340	Land and land rights	(17,656,411)
341	Structures and improvements	(104,029,144)
343	Prime movers	(2,957,479,569)
344	Generators	(169,604,244)
345	Accessory electric equipment	(251,736,290)
345.1	Computer hardware	417,454
345.2	Computer software	16,048
345.3	Communication equipment	2,648,247
346	Miscellaneous power plant equipment	(12,885,472)
347	Asset retirement costs for other prod plant	(50,231,045)
351.1	Computer hardware	81,473
351.2	Computer software	55,644,709
351.3	Communication equipment	169,762,641
363.1	Computer hardware	3,235,982
363.2	Computer software	46,821,866


363.3	Communication equipment	170,544,430
391	Office furniture and equipment	(60,043,869)
397	Communication equipment	(521,010,372)
397.1	Computer hardware	55,232,839
397.2	Computer software	671,464,050
397.3	Communication equipment	141,544,013
		$	�

(i) Concept: LandAndLandRightsSteamProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(j) Concept: StructuresAndImprovementsSteamProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(k) Concept: BoilerPlantEquipmentSteamProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(l) Concept: TurbogeneratorUnitsSteamProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(m) Concept: AccessoryElectricEquipmentSteamProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(n) Concept: ComputerHardwareSteamProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(o) Concept: ComputerSoftwareSteamProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(p) Concept: CommunicationEquipmentSteamProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(q) Concept: MiscellaneousPowerPlantEquipmentSteamProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(r) Concept: AssetRetirementCostsForSteamProductionPlantSteamProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(s) Concept: ComputerHardwareHydraulicProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(t) Concept: ComputerSoftwareHydraulicProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(u) Concept: CommunicationEquipmentHydraulicProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(v) Concept: LandAndLandRightsSolarProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(w) Concept: StructuresAndImprovementsSolarProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(x) Concept: SolarPanelsSolarProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(y) Concept: CollectorSystemSolarProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(z) Concept: InvertersSolarProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(aa) Concept: OtherAccessoryElectricalEquipmentSolarProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(ab) Concept: CommunicationEquipmentSolarProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(ac) Concept: LandAndLandRightsWindProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(ad) Concept: StructuresAndImprovementsWindProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(ae) Concept: WindTurbinesWindProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(af) Concept: WindTowersAndFixturesWindProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(ag) Concept: CollectorSystemWindProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(ah) Concept: GeneratorStepupTransformersWindProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(ai) Concept: InvertersWindProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(aj) Concept: OtherAccessoryElectricalEquipmentWindProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(ak) Concept: ComputerHardwareWindProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(al) Concept: CommunicationEquipmentWindProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(am) Concept: MiscellaneousPowerPlantEquipmentWindProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(an) Concept: AssetRetirementCostsWindProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(ao) Concept: LandAndLandRightsOtherRenewableProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(ap) Concept: StructuresAndImprovementsOtherRenewableProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(aq) Concept: FuelHoldersOtherRenewableProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(ar) Concept: BoilersOtherRenewableProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(as) Concept: GeneratorsOtherRenewableProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(at) Concept: OtherAccessoryElectricalEquipmentOtherRenewableProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(au) Concept: ComputerHardwareOtherRenewableProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(av) Concept: CommunicationEquipmentOtherRenewableProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(aw) Concept: MiscellaneousPowerPlantEquipmentOtherRenewableProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(ax) Concept: AssetRetirementCostsOtherRenewableProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(ay) Concept: LandAndLandRightsOtherProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(az) Concept: StructuresAndImprovementsOtherProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(ba) Concept: PrimeMoversOtherProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bb) Concept: GeneratorsOtherProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bc) Concept: AccessoryElectricEquipmentOtherProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bd) Concept: ComputerHardwareOtherProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(be) Concept: ComputerSoftwareOtherProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bf) Concept: CommunicationEquipmentOtherProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bg) Concept: MiscellaneousPowerPlantEquipmentOtherProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bh) Concept: AssetRetirementCostsForOtherProductionPlantOtherProductionTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bi) Concept: ComputerHardwareTransmissionPlantTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bj) Concept: ComputerSoftwareTransmissionPlantTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bk) Concept: CommunicationEquipmentTransmissionPlantTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bl) Concept: ComputerHardwareDistributionPlantTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bm) Concept: ComputerSoftwareDistributionPlantTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bn) Concept: CommunicationEquipmentDistributionPlantTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bo) Concept: OfficeFurnitureAndEquipmentGeneralPlantTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bp) Concept: ComputerHardwareGeneralPlantTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bq) Concept: ComputerSoftwareGeneralPlantTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(br) Concept: CommunicationEquipmentGeneralPlantTransfers

Refer to footnote on Transfers column of FERC Account 303, Miscellaneous Intangible Plant.

(bs) Concept: ElectricPlantSoldTransfers

Refer to Item 3 of Important Changes in this Form No. 1 and Docket No. AC25-50-000 filed with the FERC for further discussion on the transfer of Keno Dam to the U.S Department of the Interior.

(bt) Concept: ProductionPlant

Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:

Account (a)

Ref. Line No. (Column)

Balance End of Year (g)

TOTAL Production Plant

46 (g)

15,137,674,031

Less: (317) Asset Retirement Costs for Steam Production (1)

15 (g)

94,875,465

Less: (337) Asset Retirement Costs for Hydraulic Production(1)

34 (g)

�

Less: (338.34) Asset Retirement Costs for Wind Production (1)

35.31 (g)

58,290,273

Less: (339.13) Asset Retirement Costs for Other Renewable Production(1)

35.46 (g)

6,002,449

Less: (347) Asset Retirement Costs for Other Production (1)

44 (g)

6,188,508

Revised TOTAL Production Plant

14,972,317,336

(bu) Concept: TransmissionPlant

Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:

Account (a)

Ref. Line No. (Column)

Balance End of Year (g)

TOTAL Transmission Plant

58 (g)

11,801,051,868

Less: (359.1) Asset Retirement Costs for Transmission Plant (1)

57 (g)

3,433,491

Revised TOTAL Transmission Plant

11,797,618,377

(bv) Concept: DistributionPlant

Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:

Account (a)

Ref. Line No. (Column)

Balance End of Year (g)

TOTAL Distribution Plant

75 (g)

11,176,261,174

Less: (374) Asset Retirement Costs for Distribution Plant (1)

74 (g)

1,331,349

Revised TOTAL Distribution Plant

11,174,929,825

(bw) Concept: OtherTangibleProperty

Account 399.21, Land owned in fee

(bx) Concept: GeneralPlant

Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:

Account (a)

Ref. Line No. (Column)

Balance End of Year (g)

TOTAL General Plant

99 (g)

1,993,275,151

Less: (399) Other Tangible Property (1)

97 (g)

1,822,901

Less: (399.1) Asset Retirement Costs for General Plant (2)

98 (g)

37,690

Revised TOTAL General Plant

1,991,414,560

(1) To adjust PacifiCorp's formula rate, per FERC Docket No. FA16-4-000 for mining assets related to production plant.

(by) Concept: ElectricPlantInService

Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:

Account (a)

Ref. Line No. (Column)

Balance End. of Year (g)

TOTAL Intangible Plant

5 (g)

394,205,580

Revised TOTAL Production Plant (1)

14,972,317,336

Revised TOTAL Transmission Plant (2)

11,797,618,377

Revised TOTAL Distribution Plant (3)

11,174,929,825

Revised TOTAL General Plant (4)

1,991,414,560

(102) Electric Plant Purchased

101 (g)

�

(Less) (102) Electric Plant Sold

102 (g)

�

(103) Experimental Plant Unclassified

103 (g)

�

Revised TOTAL Electric Plant in Service

40,330,485,678

(1) Refer to footnote on page 204, line no. 46, column (g)

(2) Refer to footnote on page 204, line no. 58, column (g)

(3) Refer to footnote on page 204, line no. 75, column (g)

(4) Refer to footnote on page 204, line no. 99, column (g)

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Line No.	LesseeName Name of Lessee (a)	IndicationOfAssociatedCompany * (Designation of Associated Company) (b)	LeaseDescription Description of Property Leased (c)	CommissionAuthorization Commission Authorization (d)	ExpirationDateOfLease Expiration Date of Lease (e)	ElectricPlantLeasedToOthers Balance at End of Year (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47	TOTAL

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.	ElectricPlantHeldForFutureUseDescription Description and Location of Property (a)	ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate Date Originally Included in This Account (b)	ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate Date Expected to be used in Utility Service (c)	ElectricPlantHeldForFutureUse Balance at End of Year (d)
1	Land and Rights:
2	Barnes Butte Substation	08/24/2007	12/31/2032	746,268
3	Jumbers Point Substation	03/14/2008	12/31/2026	1,173,276
4	Mountain Green Substation	12/31/2009	12/31/2026	284,996
5	Hoggard Substation	02/21/2009	12/31/2030	254,397
6	Old Mill Substation	11/30/2012	12/31/2030	1,838,281
7	Chimney Butte-Paradise 230kV Transmission Line	03/11/2013	12/31/2030	598,457
8	Fiddlers Canyon Substation	06/29/2016	12/31/2031	1,136,587
9	Banfield Substation	12/29/2017	12/31/2026	3,166,189
10	Ochoco Substation	12/21/2020	12/31/2039	594,174
11	Mill City Substation	04/30/2024	12/31/2036	633,623
12	(a) Miscellaneous, each under $250,000:			750,057
21	Other Property:
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47	TOTAL			11,176,305

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: ElectricPlantHeldForFutureUseDescription

Various dates properties were originally included in FERC Account 105. Various dates properties are expected to be placed in service.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Report below descriptions and balances at end of year of projects in process of construction (107). Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts). Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line No.	ConstructionWorkInProgressProjectDescription Description of Project (a)	ConstructionWorkInProgress Construction work in progress - Electric (Account 107) (b)
1	Intangible:
2	Cutler Hydro Relicensing	8,044,223
3	Ashton Hydro Relicensing	1,255,632
4	Production:
5	Prospect 3 Hydro - South Fork Flowline Replacement	17,219,827
6	Yale Downstream Fish Passage	16,920,539
7	Yale Saddle Dam Seismic Remediation	10,996,849
8	Prospect 3 Hydro - Sag Pipe Replacement	10,573,106
9	Toketee 2 Turbine Refurbishment	9,235,880
10	Lewis River System Relicensing Implementation	8,654,608
11	Swift 1 Hydro Spillway Gate Retrofit	8,488,072
12	Toketee Dam Foundation Rehabilitation	7,698,211
13	Viva Naughton FERC Production Compliance	7,297,926
14	Yale Upstream Facility	6,284,418
15	U1 CT Rotor Replacement CY25-26	5,880,647
16	U2 CT Rotor Replacement CY25-26	5,880,647
17	Naughton U1 Gas Conversion CY26	5,252,853
18	Naughton U2 Gas Conversion CY26	4,605,499
19	Swift Upstream Facility	4,534,874
20	Yale Dam Spillway Upgrades	4,277,206
21	North Fork Dam Upgrade	3,867,362
22	Merwin PMF and Seismic Remediation Program	3,644,784
23	Lemolo 1 Spillway Improvements	2,959,879
24	Rockfall Barrier Replacement	2,514,567
25	Hermiston U1 Combustion Turbine Upgrade	2,355,141
26	Weber Dam Improvements	2,313,957
27	Oneida Dam Upgrades	2,207,722
28	Hermiston U1 Rotor Replacement	2,185,878
29	U3 OH BFP CY25	2,121,942
30	Fish Creek Forebay Improvements	1,712,318
31	U1 OH Field Rewind & Retaining Rings CY2	1,688,079
32	Main GSU Replacement	1,683,263
33	Yale Spillway Gate Improvements	1,641,904
34	Install Automated Avian Curtailment System	1,594,819
35	Swift 1 Minimum Discharge Line	1,555,979
36	Lemolo No. 2 Forebay Trash Rake	1,515,858
37	Ashton Hydro Trash Rake	1,512,129
38	Oneida Switchgear	1,433,267
39	Bigfork Dam Upgrades	1,346,058
40	Cutler Dam Upgrades	1,323,986
41	Air Preheater Baskets	1,245,201
42	Yale PMF and Seismic Remediation Program	1,240,676
43	HUB & MAIN SHAFT-BRG ASSY	1,219,468
44	Oneida Generator Protection Relays	1,175,729
45	Grace Canal Intake Headworks Upgrade	1,171,538
46	U4 - Turbine / Generator Refurbishment	1,166,042
47	Dave Johnston Plant Cooling Water Intake Structure	1,104,725
48	U3 New Ethos HP/IP Turb Rotor Cap Spare	1,066,513
49	HERMU2 Rotor Replacement CY28	1,058,838
50	Swift PMF and Seismic Remediation Program	1,037,489
51	Transmission:
52	Boardman - Hemingway 500kV Line	489,366,248
53	Populus - Hemingway 500kV Line	109,846,360
54	Anticline - Populus 500kV Line	79,546,574
55	Gateway Central-Limber Area Reinforcements Segment C	38,945,570
56	Powerex Corp Transmission Service Request	35,047,123
57	Project Specialized, 242 MW Load	30,788,209
58	Cottonwood-Snyderville 138kV Rebuild for Wildfire	27,494,206
59	Sams Valley New 500-230kV Substation	26,610,902
60	Camp Williams 345-138kV Transformer and 138kV Yard Addition	17,362,740
61	Bluffdale 138 kV Conversion	12,614,459
62	Malin-Casebeer New 69 kV Line	12,545,048
63	Lines 30 & 65 Convert to 115 kV, Construct New 230-69kV Substation	11,158,485
64	Lone Pine - Whetstone 230 kV Line	10,904,183
65	Pomona Heights Sub 230-115 kV Transformer Replacements TPL	9,692,378
66	Loop 90 S-Terminal into MidValley 345kV Line	9,325,916
67	St George Sub Install 345/138kV Transformer	9,264,812
68	Tucker 69 kV Tie Line	7,487,979
69	C1-5 Network Upgrades	7,428,799
70	N Umpqua Pump Storage Project - Dixonville Transformer T3843	7,149,073
71	RMP New Spare 138-46kV (150MVA) Transformer	7,111,521
72	Hurricane Sub Spare 230-69 kV-25 MVA Transformer	6,838,764
73	FERC Order 881 Mandate Upgrades	6,028,958
74	Hunter U1 Main Generator Step-Up Transformer Purchase	5,911,619
75	St. Johns (BPA) to Knott 115 kV Line Conversion	5,696,502
76	Glen Canyon Solar A, LLC	5,131,929
77	Rowan Green Data LLC	5,130,944
78	Scoville Substation Relocation	5,020,004
79	UAMPS Lehi 138kV Loop Carter-Saratoga	4,895,237
80	Fremont Solar, LLC - Fremont Solar	4,711,864
81	DUMAS-DIMPLE DELL 138KV UG FAILURE	4,704,260
82	Clawson Solar ESM	4,475,484
83	Sugarmill Sub New 161/12.47 kV Transformer	4,294,417
84	Spanish Fork-Mercer 345 kV Line	4,084,795
85	Pilot Butte-Installation 4th 230-69kV Transformer	3,994,659
86	Faraday Solar	3,970,952
87	COLD SPRINGS SUB: Replace Failed XFMR	3,967,263
88	High Top Solar, LLC	3,948,316
89	Ben Lomond-Naughton 230kV Lines 1 & 2 Rebuild for Wildfire	3,847,043
90	PAC ESM Swift-Troutdale 230kV Line Transmission Service Request	3,735,737
91	North Salt Lake 138kV Conversion	3,472,406
92	Burns 500 kV Series Capacitor Bank Replacement	3,371,761
93	Gateway Central Reinforcements Segment B	3,326,192
94	Silver Creek-Kamas 46 kV Rebuild for Wildfire	3,314,025
95	Rush Lake Solar LLC-Rush Lake Solar	3,290,916
96	Clover Series Reactor Bypass Breaker	3,279,564
97	Project Pivot	3,261,156
98	Proctor & Gamble Paper, Goldrush 108 MW	3,201,833
99	Weirich to BPA Lebanon 115kV Tie Line	3,147,388
100	Shirley Basin-Anticline 500kV Line D2.2	3,136,520
101	Park City - Judge 46kV Line Rebuild for Wildfire	3,029,670
102	Klamath Dam Network Upgrades and Removal	2,955,486
103	Camp Williams: Rpl TSC1 SVC Cap Bank	2,757,707
104	FHCA: Rebuild Grants Pass to Scenic 69kV	2,669,179
105	Dillard Tap:37-1 Winston:37- 5 69KV Tie	2,605,437
106	Fire High Consequence Area (FHCA) - Rebuild Coleman-Toquerville 69kV	2,447,766
107	Houston Lake-Ponderosa Add Second 115kV Line	2,206,662
108	Lyons Loop into Santiam - New Tie Line	2,111,539
109	Project 67	2,051,565
110	Northrop Grumman, 5 MW Load Addition	2,041,131
111	Mathington Solar	1,939,611
112	DJ-Deer Creek-Big Muddy 69kV Replacements	1,905,169
113	Uinta Wind Energy LLC	1,895,300
114	Construct Jackalope-Bixby 115kV Line	1,840,911
115	FHCA: Montague to Yuba 69kV	1,718,840
116	Harvest 138 kV Substation	1,698,284
117	Capitol-North Bench 138kV Line Rebuild for Wildfire	1,611,545
118	Astoria replace 2A2 & 2A6 line relaying	1,594,805
119	Dave Johnston OD Breaker Replacement TPL	1,593,481
120	Syracuse Transmission Sub 138/345kV HMI De-Automation	1,588,725
121	Ager Sub Wildfire Mitigation Upgrades	1,529,312
122	FPIA CAMP WILLIAMS-MONA #1 345KV LINE	1,524,328
123	Wake Robin Ave-Const New Substation	1,522,227
124	Day Ahead Market (EDAM) Metering Upgrade	1,509,047
125	Malin(Snow Goose)�Ponderosa(Corral)500kV	1,503,903
126	Jim Bridger - Goshen 345kV Line Structures Replacement	1,442,772
127	Huntington Plant Universal Spare Generator Step-Up Transformer	1,423,707
128	Butler New 115-69kV Substation	1,399,196
129	Lone Pine-Sage Rd Line Conversion	1,387,291
130	FPIB YELLOWTAIL-RIMROCK 161KV(CROW RES.)	1,368,493
131	Fire High Consequence Area (FHCA) - Rebuild Columbia-Mounds Switchyard 138	1,365,086
132	PAC (ESM) Stone Pit-Rockpile 230kV	1,345,748
133	BPA Ostrea	1,336,497
134	Huntington Sub: Rplc Failed EPU	1,324,428
135	Grants Pass Sub Wildfire Mitigation Upgrades	1,319,180
136	Meridian RAS Expansion	1,313,248
137	Quicksilver Solar STA NU	1,165,871
138	Mansface Rpl CSW0566 1H40 & CSW0606 1H42	1,110,691
139	Grants Pass-Replace 1R6&1R8 Circuit Breaker	1,098,397
140	ACQUIRE REPOWER SAFE HARBOR - FC II-IV R	1,097,134
141	Aligned Energy Data Ctrs Propco, 200 MW	1,095,302
142	Third West-Morton Court New 138kV Line	1,065,667
143	Lincoln Solar, LLC - Lincoln Solar	1,057,835
144	Distribution:
145	Portland Willamette River Crossing Project	192,553,564
146	Project Litespeed	98,318,845
147	Downtown SLC Development - Snarr Substation Conversion	23,449,822
148	RG Lakeview, 50.47 MW Load	12,968,450
149	CA Distribution Spacer Cable Install	12,773,469
150	Fort Jones 5G2 Rebuild PT	12,706,815
151	Summit Mountain Holding Group DBA Powder Mountain 11.357MW	12,337,692
152	Walker Bryan Rebuild Part 3	11,919,291
153	King Way New 115-12.47 kV Sub T&D	11,787,837
154	Bond Street Sub add 2nd Transformer	11,591,947
155	Northwest Quadrant Development - Lee Creek #2	11,378,370
156	Redwood Highway Line Rebuild	10,996,303
157	Seiad East & West Distribution Spacer Cable Install	10,836,028
158	Fremont Solar, LLC 2.260 MW Load	10,559,783
159	Deer Creek Sub - New 69/13.2kV 25MVA Substation	10,468,252
160	Hood River Mosier Tie Distribution Spacer Cable Install	10,395,214
161	Merrill Rebuild Part 2	10,314,726
162	Mt Shasta City 4kV CA Distribution Spacer Cable Install	10,212,248
163	Dick George Road Line Rebuild	8,815,075
164	Dalton Hay Company LLC, 675 kW Load	8,759,201
165	Syracuse 138-13.2 kV Transformer	8,574,872
166	Fire High Consequence Area (FHCA) - Rebuild Brighton 11	8,534,530
167	OR Fire Mitigation Distribution Sub Relay Replacement Phase 1	8,497,227
168	US SFR Owner, 20 MW Load	8,241,624
169	Caves Highway Line Rebuild	8,206,108
170	Pine Creek RNG LLC, 1,700 kW Load	7,927,688
171	Airport Road Westside Road Line Rebuild	7,406,920
172	FHCA 5R63 Riverbanks Road Rebuild Phase 10	7,368,962
173	Jumbers Point - New Substation	7,194,100
174	Zion Sunset Holdings LLC, 6,161 kW Load	7,098,658
175	Fire High Consequence Area (FHCA) - Rebuild Wallsburg 12	7,047,199
176	Mountain Green New 46-12.47kV Substation	7,020,970
177	Hiouchi Hill	6,966,184
178	FHCA Riverbanks Road Rebuild Phase 6	6,586,988
179	Cheney Creek Road Line Rebuild	6,556,026
180	Fire High Consequence Area (FHCA) - Rebuild Brighton 12	6,469,400
181	CA Fire Mitigation Distribution Sub Relay Replacement	6,386,560
182	JL Ventures LLC, 14.50 MW Load	6,291,650
183	Shotgun Creek Line Rebuild	6,165,297
184	STACK Farmington Land, 20,502 kW Load	6,120,119
185	FHCA-Jordanelle 11&12 Distribution Line Rebuild	6,118,469
186	Banfield New 115kV to 12.5kV Substation	6,020,153
187	FHCA S Lower River Road Rebuildd Ph 9	5,922,797
188	Fire High Consequence Area (FHCA) - Rebuild Eden 11	5,894,876
189	Holladay Sub Upgrade Transformer #2 to 30 MVA	5,821,220
190	Rigby 161-12 kV Transformer Addition	5,732,604
191	Rickreall Construct New Substation	5,629,804
192	Elk Horn Sub - Install 2nd 30MVA Transformer	5,533,109
193	Grants Pass OR Expulsion Fuse Replacement	5,510,929
194	FHCA Riverbanks Road Rebuild Phase 9	5,494,048
195	Spare 230-34.5kV 125MVA with LTC Transformer	5,479,881
196	Line Rebuild	5,426,681
197	Tap Lines Rebuild	5,398,362
198	Tieton Substation Capacity Increase - New Sub	5,063,644
199	FHCA Fort Jones rebuild Phase 13	5,031,349
200	FHCA Riverbanks Road Rebuild Phase 4	5,023,086
201	SRC Land Holdings, 12.067 MW Load	4,871,572
202	University of Utah, Huntsman Mental Health Institute, 1.6 MW	4,855,091
203	2024 Roseburg OR Expulsion Fuse Replacement	4,821,846
204	FHCA Riverbanks Road Rebuild Phase 11	4,750,583
205	Oregon Energy Storage Project	4,692,965
206	Fire High Consequence Area (FHCA) - Rebuild Snyderville 16	4,685,351
207	Walnut Grove Sib 138-13.2kV 33MVA Transformer Addition	4,382,151
208	FHCA S Lower River Road Rebuild Ph 3	4,243,602
209	Fire High Consequence Area (FHCA) - Rebuild 5R63 Riverbanks Road Phase 1	4,242,925
210	Highway 96 and Beaver Creek Line Rebuild	4,241,662
211	Fire High Consequence Area (FHCA) - Rebuild Coalville 13	3,954,120
212	American Packaging Corp, 9.089 MW Load	3,948,745
213	Fire Mitigation Distribution Sub Relay Replacement Phase 2	3,938,886
214	Russellville Distribution Automation Project - FLISR	3,914,842
215	Utah-Distribution Mandated Wildfire Mitigation	3,839,082
216	Ahtanum New 115-12.5 kV Substation	3,818,452
217	Stansbury Sub Install Second Transformer	3,810,807
218	Medford OR Expulsion Fuse Replacement	3,791,695
219	City Caves Highway Line Rebuild	3,676,864
220	Center Street Sub: Replace T3673 Transformer	3,529,537
221	East Mosier Tie Line Rebuild	3,498,183
222	Eastside Dr. Line Rebuild	3,403,034
223	FHCA: Fort Jones CB rebuild	3,374,858
224	Silver Creek Sub 2nd 138-12.47kV 33MVA Transformer	3,364,584
225	Tesla Inc. New 1,161 kW Load	3,334,347
226	Shotgun Creek Line Rebuild - 5G97	3,284,572
227	Santaquin City Corporaton, 1,350 kW Load	3,271,785
228	Cleveland Avenue Replace Transformer Bank 2	3,203,972
229	Saratoga Way Line Rebuild	3,198,376
230	Walker Bryan Rebuild Part 5	3,165,312
231	Lotus Acquisitions LLC, 1,456 kW Load	3,113,531
232	Line 668033/00 Taps Spacer Cablel	3,098,497
233	Fort Jones Rebuild PT_2	3,060,159
234	RMP New Spare 138-34.5kV (30MVA) Transformer	3,051,840
235	Fire High Consequence Area (FHCA) - Rebuild Panguitch 12	3,034,936
236	N Happy Camp 2023 Spacr	2,885,263
237	Gordon Hollow - New Substation	2,876,609
238	Fort Jones Rebuild PT_5	2,853,815
239	Yew Ave Capacity Increase	2,762,992
240	Laurel Road Tie Line Rebuild	2,761,142
241	Mill City - New Substation	2,735,885
242	70th South Install Second Transformer	2,718,734
243	FHCA S Lower River Road Rebuild Phase 1	2,693,669
244	Geneva Rock Products, 3.768 MW Load	2,653,573
245	Fire High Consequence Area (FHCA) - Rebuild Olympus 13	2,633,045
246	Dry Creek Road	2,528,250
247	Beagle Road	2,504,293
248	FHCA-Agness Ave Rebuild (Phase 2)	2,503,967
249	WA Fire Mitigation Distribution Sub Relay Replacement	2,503,556
250	FHCA - Hornet Rebuild (Phase 1)	2,498,397
251	New Mobile 161-13.2kV 33MVA Transformer	2,492,906
252	FHCA Walker-Bryan CB Rebuild	2,480,490
253	Fire High Consequence Area (FHCA) - Rebuild Pioneer 13	2,423,305
254	FHCA Hornet Rebuild Phase 2	2,422,479
255	Nutglade Distribution Spacer Cable Install	2,411,011
256	Urban Granary Montague, 3680 kW Load	2,376,635
257	FHCA Hugo Wirona Pleasant Vly Ph10	2,315,784
258	Fire High Consequence Area (FHCA) - Rebuild Cross Hollow 13	2,284,739
259	Brunswick Sub: Replace Transformer #1 & 46kV UG Cable	2,266,218
260	Fayette T#1 3rd 46-7.2 kV 333 kVA Transformer	2,259,465
261	Walker Bryan Rebuild Part 2	2,118,408
262	Lightning Renewables LLC, 2.866 MW Load	2,103,125
263	Fielder creek mainline rebuild	2,098,499
264	Fire High Consequence Area (FHCA) - Rebuild Brighton 21	2,083,313
265	FHCA-Rogue River Rebuild (Phase 1)	2,059,227
266	Fort Jones Rebuild PT_4	2,044,270
267	Spanish Fork Sub Add Distrib Transformer	2,036,628
268	California Expulsion Fuse Replacement	1,966,918
269	FHCA-Turkey Valley Rebuild	1,937,923
270	Elk Creek Road	1,931,749
271	FHCA-Agness Ave Rebuild (Phase 1)	1,931,343
272	FHCA Scenic Rebuild	1,924,046
273	Dodge Bridge Sub Wildfire Mitigation Upgrades	1,903,559
274	FHCA: Comm Park Ln Rbld-So Phase	1,901,539
275	Dorris Sub-Capacity Solution- Replace Transformer	1,883,732
276	Columbia Memorial Hospital	1,883,219
277	Antioch Road	1,865,351
278	West Weed/Edgewood Distribution Spacer Cable Install	1,842,302
279	California-Mandated Wildfire Mitigation	1,778,829
280	Enterprise Sub Wildfire Mitigation Upgrade	1,762,851
281	KEN01 4k TO 15k Conversion	1,735,894
282	FHCA- Skyes Creek Rebuild	1,717,641
283	Gasquet Line Rebuild	1,706,694
284	FHCA-Rogue River 5R78 Rebuild (Phase 1)	1,683,791
285	Meadows Rd	1,673,507
286	FHCA-Rogue River Rebuild (Phase 2)	1,666,185
287	Weed City Taps 2023 CA Distribution Spacer Cable Install	1,595,808
288	FHCA S Lower River Road Rebuild Ph 10	1,582,965
289	Enlaw LLC, 15.93 MW Load	1,580,952
290	Winchester Sub Dist Wildfire Mitigation Upgrades	1,574,220
291	Agness Ave Sub Wildfire Mitigation Upgrades	1,561,409
292	Riddle Sub Wildfire Mitigation Upgrades	1,551,069
293	Terminal Install T#8	1,527,052
294	FHCA S Lower River Road Rebuild Ph2	1,522,664
295	Medford Distribution Automation Project - FLISR	1,505,678
296	FHCA-Merrill Rebuild (Phase 1)	1,490,391
297	Amazon EV Chargers and Added Load	1,460,759
298	Park Street Sub Wildfire Mitigation Upgrades	1,449,080
299	Siren Crew Callout	1,439,908
300	Dowell Sub Wildfire Mitigation Upgrade	1,437,871
301	Chapman Creek Rd Line Rebuild	1,434,166
302	MW Line Rebuild	1,410,970
303	Walker Bryan Rebuild Part 4	1,357,821
304	FHCA Gasquet Rebuild	1,353,833
305	RPTR Protection	1,345,680
306	Truck Village Drive CA Spacer Cable	1,329,987
307	FHCA Hugo Wirona Pleasant Val Ph9	1,305,516
308	Grants Pass WTP & Pump Station New Load	1,302,283
309	Ashland Sub Wildfire Mitigation Upgrades	1,219,775
310	FHCA Patricks Creek Rebuild	1,192,678
311	RMP New Spare 69-13.2kV (7.5MVA) Transformer	1,185,329
312	Macdoel Sub Wildfire Mitigation Upgrades	1,178,286
313	Ski Resort Distrib Spacer Cable Install	1,176,938
314	FHCA Evans Creek rebuild	1,173,146
315	Line Rebuild - 5L3	1,142,781
316	WO3 Rogue River Dr	1,116,082
317	SEL Fast Trip Fault Indicators S Oregon	1,109,389
318	Salt Lake Dept of Airports - 14.7 MW Load	1,106,341
319	Merrill Sub Wildfire Mitigation Upgrds	1,101,851
320	FHCA Merlin Rebuild (Phase 1)	1,098,928
321	Zenith Bolinder, 12 MW Load	1,081,341
322	Old Creek Trail	1,068,412
323	City of Bend - New Service	1,054,910
324	FHCA - Winchester 5U17 Rebuild	1,045,794
325	2025 Medford OR Expulsion Fuse Replacement	1,036,322
326	Crater Lake Hwy (DE)	1,034,545
327	FHCA: Comm Park Line Rebuild-So Phase	1,031,899
328	Easy Valley Sub Wildfire Mitigation Upgrades	1,031,127
329	East Bench: HMI DPU & TPU Relay Replacement	1,023,236
330	Caveman Sub Wildfire Mitigation Upgrade	1,010,334
331	General:
332	Oracle Systems Software	329,406,957
333	North Temple Campus Redevelopment	120,460,589
334	Field Ai-Field Asset Intelligence and Related Software Implementations	49,017,760
335	Physical Access Control System FIPS 201	14,458,012
336	Mobile GIS Software	12,223,477
337	Palantir Foundry Renewal	8,918,572
338	Oracle Back Office & Ops Enh Wave2.5	6,671,507
339	PCI EDAM SW Enhancement and Implementation	5,596,545
340	Back Office and Ops Sustainment(Wave 3)	5,117,055
341	EDAM MCG Software Enhancement and Implementation	4,682,752
342	OT-STS Security Tools Standardization	4,039,682
343	Extend ADSS Fiber-8 Roseburg Subs	3,777,766
344	Customer Mobile Apps Software	3,470,580
345	Power Settlements EDAM Implementation	3,112,362
346	EDAM SOM Upgrades	3,032,659
347	Maximo Generation	2,788,804
348	New Salt Lake City Data Center	2,725,555
349	PowerPlan TFA- Tax Fixed Asset	2,209,164
350	LCT05 DataCenter Fabric TOM	2,106,324
351	EDAM- JLS Replacement	1,679,854
352	OpenMethods for Oracle	1,679,514
353	Vertex for Oracle	1,637,526
354	BHE Distribution New Construction Portal	1,471,470
355	Bill Print with Oracle C2M (software)	1,437,482
356	OATI EDAM Implementation	1,421,375
357	Content Management System, Phase 1	1,286,844
358	SCADA PARR Program RMP	1,213,419
359	TIBCO Upgrade	1,038,963
360	CAISO EDAM Implementation	1,033,856
361	PAC Genesys Cloud Conversion	1,008,350
362	Miscellaneous Projects each under $1,000,000	316,562,586
43	Total	3,305,302,836

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Explain in a footnote any important adjustments during year. Explain in a footnote any difference between the amount for book cost of plant retired, Line 12, column (c), and that reported for electric plant in service, page 204, column (d), excluding retirements of non-depreciable property. The provisions of Account 108 in the Uniform System of Accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Line No.	Item (a)	Total (c + d + e) (b)	Electric Plant in Service (c)	Electric Plant Held for Future Use (d)	Electric Plant Leased To Others (e)
Section A. Balances and Changes During Year
1	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance Beginning of Year	13,009,454,057	13,009,454,057
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	(a) 1,245,953,331	1,245,953,331
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs	(b) 0	0
5	ExpensesOfElectricPlantLeasedToOthers (413) Exp. of Elec. Plt. Leas. to Others
6	TransportationExpensesClearing Transportation Expenses-Clearing
7	OtherClearingAccounts Other Clearing Accounts
8	OtherAccounts Other Accounts (Specify, details in footnote):
9.1	Other Accounts (Specify, details in footnote):
9.2	Account 143, Other accounts receivable: depreciation expense billed to joint owners	642,474	642,474
9.3	Account 182.3, Other Regulatory Assets: asset retirement obligations asset depreciation	15,346,279	15,346,279
9.4	Account 182.3, Other Regulatory Assets: depreciation deferrals	29,487,991	29,487,991
9.5	Transportation depreciation allocated to operations and maintenance expense based on usage activity	23,521,291	23,521,291
9.6	Account 559.3, Steam from other sources: Blundell depreciation	2,500,616	2,500,616
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	1,258,476,000	1,258,476,000
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	616,708,648	616,708,648
13	CostOfRemovalOfPlant Cost of Removal	124,022,478	124,022,478
14	SalvageValueOfRetiredPlant Salvage (Credit)	4,900,089	4,900,089
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	735,831,037	735,831,037
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Other Debit or Cr. Items (Describe, details in footnote):
17.2	Transfer of FERC 111, Accumulated provision for amortization of electric utility plant, related to software assets as a result of FERC Order 898	658,393,844	658,393,844
17.3	Disallowance of Utah's share of the Fall Creek hatchery assets	14,641,256	14,641,256
17.4	Other items include:	5,351,163	5,351,163
17.5	Recovery from third parties for asset relocations and damaged property
17.6	Insurance recoveries
17.7	Adjustments of reserve related to electric plant sold and/or purchased
17.8	Reclassifications from electric plant
18	BookCostOfAssetRetirementCosts Book Cost or Asset Retirement Costs Retired	76,068,015	76,068,015
19	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)	14,134,417,268	(c) 14,134,417,268
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	4,905,498,898	(d)(e) 4,905,498,898
21	AccumulatedDepreciationNuclearProduction Nuclear Production
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional	525,612,315	(f) 525,612,315
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage
23.1	AccumulatedDepreciationSolarProduction Solar Production	184,969	(g) 184,969
23.2	AccumulatedDepreciationWindProduction Wind Production	412,947,699	(h) 412,947,699
23.3	AccumulatedDepreciationOtherRenewableProduction Other Renewable Production	105,869,531	(i) 105,869,531
24	AccumulatedDepreciationOtherProduction Other Production	720,469,355	(j) 720,469,355
25	AccumulatedDepreciationTransmission Transmission	2,674,361,552	(k) 2,674,361,552
26	AccumulatedDepreciationDistribution Distribution	3,690,865,513	(l) 3,690,865,513
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
27.1	AccumulatedDepreciationEnergyStorage Energy Storage
28	AccumulatedDepreciationGeneral General	1,098,607,436	(m) 1,098,607,436
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	14,134,417,268	(n) 14,134,417,268

FOOTNOTE DATA

(a) Concept: DepreciationExpenseExcludingAdjustments

For a discussion on provisions for depreciation that were made during the year, refer to Note 3 of Notes to Financial Statements in this Form No. 1.

(b) Concept: DepreciationExpenseForAssetRetirementCosts

Generally, PacifiCorp records the depreciation expense of asset retirement obligations as a regulatory asset.


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item	Ref. Line No.	Electric Plant in Service
(a)	(Column)	(c)
Revised Steam Production (1)		$	4,803,425,659
Nuclear Production	21 (c)	�
Revised Hydraulic Production - Conventional (2)		524,515,365
Hydraulic Production - Pumped Storage	23 (c)	�
Revised Solar Production (3)		184,969
Revised Wind Production (4)		405,363,731
Revised Other Renewables Production (5)		104,339,267
Revised Other Production (6)		722,171,073
Revised Transmission (7)		2,664,104,935
Revised Distribution (8)		3,689,261,954
Regional Transmission and Market Operation	27 (c)	�
Revised General (9)		1,098,770,327
Revised TOTAL		$	14,012,137,280

(1) Refer to footnote on page 219, line no. 20, column (c)
(2) Refer to footnote on page 219, line no. 22, column (c)
(3) Refer to footnote on page 219, line no. 23.1, column (c)
(4) Refer to footnote on page 219, line no. 23.2, column (c)
(5) Refer to footnote on page 219, line no. 23.3, column (c)
(6) Refer to footnote on page 219, line no. 24, column (c)
(7) Refer to footnote on page 219, line no. 25, column (c)
(8) Refer to footnote on page 219, line no. 26, column (c)
(9) Refer to footnote on page 219, line no. 28, column (c)

(d) Concept: AccumulatedDepreciationSteamProduction


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item	Ref. Line No.	Electric Plant in Service
(a)	(Column)	(c)
Steam Production	20 (c)	$	4,905,498,898
Less: Asset retirement obligations related cost components (1)		102,073,239
Revised Steam Production		$	4,803,425,659

(1) In accordance with 18 C.F.R.�35.18 (a-c) a public utility that files a transmission rate schedule, tariff or service agreement under �35.12 or �35.13 and has recorded an asset retirement obligation on its books, but is not seeking recovery of the asset retirement costs in rates, must remove all asset retirement obligations-related cost components from the cost of service supporting its proposed rates.

(e) Concept: AccumulatedDepreciationSteamProduction


This footnote applies to all lines in this Section B on Page 219 of this Form No. 1. The amounts presented herein include transfers on January 1, 2025 resulting from the adoption of FERC Order No. 898. These transfers include transfers between functions, as well as transfers from FERC Account 111, Accumulated provision for amortization of electric utility plant, for accumulated amortization on software assets that transferred from FERC Account 303, Miscellaneous Intangible Plant, to the functional plant accounts in accordance with the order. The following reflects the net transfers:

Functional Classification	Amount Transferred
Steam Production	$	88,256,196
Nuclear Production	�
Hydraulic Production-Conventional	(8,236,826)
Hydraulic Production-Pumped Storage	�
Solar Production	(155,723)
Wind Production	(262,577,831)
Other Renewable Production	(100,265,675)
Other Production	259,946,035
Transmission	(121,698,650)
Distribution	(112,683,985)
Regional Transmission and Market Operation	�
Energy Storage	�
General	(400,977,385)
	$	(658,393,844)

(f) Concept: AccumulatedDepreciationHydraulicProductionConventional


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item	Ref. Line No.	Electric Plant in Service
(a)	(Column)	(c)
Hydraulic Production - Conventional	22 (c)	$	525,612,315
Less: Asset retirement obligations related cost components (1)		1,096,950
Revised Hydraulic Production - Conventional		$	524,515,365

(1) In accordance with 18 C.F.R.�35.18 (a-c) a public utility that files a transmission rate schedule, tariff or service agreement under �35.12 or �35.13 and has recorded an asset retirement obligation on its books, but is not seeking recovery of the asset retirement costs in rates, must remove all asset retirement obligations-related cost components from the cost of service supporting its proposed rates.

(g) Concept: AccumulatedDepreciationSolarProduction


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item	Ref. Line No.	Electric Plant in Service
(a)	(Column)	(c)
Solar Production	23.1 (c)	$	184,969
Less: Asset retirement obligations related cost components (1)		�
Revised Solar Production		$	184,969

(1) In accordance with 18 C.F.R.�35.18 (a-c) a public utility that files a transmission rate schedule, tariff or service agreement under �35.12 or �35.13 and has recorded an asset retirement obligation on its books, but is not seeking recovery of the asset retirement costs in rates, must remove all asset retirement obligations-related cost components from the cost of service supporting its proposed rates.

(h) Concept: AccumulatedDepreciationWindProduction


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item	Ref. Line No.	Electric Plant in Service
(a)	(Column)	(c)
Wind Production	23.2 (c)	$	412,947,699
Less: Asset retirement obligations related cost components (1)		7,583,968
Revised Wind Production		$	405,363,731

(1) In accordance with 18 C.F.R.�35.18 (a-c) a public utility that files a transmission rate schedule, tariff or service agreement under �35.12 or �35.13 and has recorded an asset retirement obligation on its books, but is not seeking recovery of the asset retirement costs in rates, must remove all asset retirement obligations-related cost components from the cost of service supporting its proposed rates.

(i) Concept: AccumulatedDepreciationOtherRenewableProduction


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item	Ref. Line No.	Electric Plant in Service
(a)	(Column)	(c)
Other Renewable Production	23.3 (c)	$	105,869,531
Less: Asset retirement obligations related cost components (1)		1,530,264
Revised Other Renewable Production		$	104,339,267

(1) In accordance with 18 C.F.R.�35.18 (a-c) a public utility that files a transmission rate schedule, tariff or service agreement under �35.12 or �35.13 and has recorded an asset retirement obligation on its books, but is not seeking recovery of the asset retirement costs in rates, must remove all asset retirement obligations-related cost components from the cost of service supporting its proposed rates.

(j) Concept: AccumulatedDepreciationOtherProduction


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item	Ref. Line No.	Electric Plant in Service
(a)	(Column)	(c)
Other Production	24 (c)	$	720,469,355
Less: Asset retirement obligations related cost components (1)		(1,701,718)
Revised Other Production		$	722,171,073

(1) In accordance with 18 C.F.R.�35.18 (a-c) a public utility that files a transmission rate schedule, tariff or service agreement under �35.12 or �35.13 and has recorded an asset retirement obligation on its books, but is not seeking recovery of the asset retirement costs in rates, must remove all asset retirement obligations-related cost components from the cost of service supporting its proposed rates.

(k) Concept: AccumulatedDepreciationTransmission


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item	Ref. Line No.	Electric Plant in Service
(a)	(Column)	(c)
Transmission	25 (c)	$	2,674,361,552
Less: Asset retirement obligations related cost components (1)		420,365
Less: Disallowance of Oregon's share of transmission wildfire investments (2)		9,836,252
Revised Transmission		$	2,664,104,935

(1) In accordance with 18 C.F.R.�35.18 (a-c) a public utility that files a transmission rate schedule, tariff or service agreement under �35.12 or �35.13 and has recorded an asset retirement obligation on its books, but is not seeking recovery of the asset retirement costs in rates, must remove all asset retirement obligations-related cost components from the cost of service supporting its proposed rates.
(2) In December 2024, the Oregon Public Utility Commission issued an order in PacifiCorp�s general rate case imposing a partial disallowance for a portion of Oregon's share of wildfire mitigation investments. This adjustment reinstates the disallowed amount for purposes of PacifiCorp�s Formula Rate.

(l) Concept: AccumulatedDepreciationDistribution


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item	Ref. Line No.	Electric Plant in Service
(a)	(Column)	(c)
Distribution	26 (c)	$	3,690,865,513
Less: Asset retirement obligations related cost components (1)		1,603,559
Revised Distribution		$	3,689,261,954

(1) In accordance with 18 C.F.R.�35.18 (a-c) a public utility that files a transmission rate schedule, tariff or service agreement under �35.12 or �35.13 and has recorded an asset retirement obligation on its books, but is not seeking recovery of the asset retirement costs in rates, must remove all asset retirement obligations-related cost components from the cost of service supporting its proposed rates.

(m) Concept: AccumulatedDepreciationGeneral


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item	Ref. Line No.	Electric Plant in Service
(a)	(Column)	(c)
General	28 (c)	$	1,098,607,436
Less: Asset retirement obligations related cost components (1)		(162,891)
Revised General		$	1,098,770,327

(1) In accordance with 18 C.F.R.�35.18 (a-c) a public utility that files a transmission rate schedule, tariff or service agreement under �35.12 or �35.13 and has recorded an asset retirement obligation on its books, but is not seeking recovery of the asset retirement costs in rates, must remove all asset retirement obligations-related cost components from the cost of service supporting its proposed rates.

(n) Concept: AccumulatedProvisionForDepreciationOfElectricUtilityPlant


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Item	Ref. Line No.	Electric Plant in Service
(a)	(Column)	(c)
Revised Steam Production (1)		$	4,803,425,659
Nuclear Production	21 (c)	�
Revised Hydraulic Production - Conventional (2)		524,515,365
Hydraulic Production - Pumped Storage	23 (c)	�
Revised Solar Production (3)		184,969
Revised Wind Production (4)		405,363,731
Revised Other Renewables Production (5)		104,339,267
Revised Other Production (6)		722,171,073
Revised Transmission (7)		2,664,104,935
Revised Distribution (8)		3,689,261,954
Regional Transmission and Market Operation	27 (c)	�
Revised General (9)		1,098,770,327
Revised TOTAL		$	14,012,137,280

(1) Refer to footnote on page 219, line no. 20, column (c)
(2) Refer to footnote on page 219, line no. 22, column (c)
(3) Refer to footnote on page 219, line no. 23.1, column (c)
(4) Refer to footnote on page 219, line no. 23.2, column (c)
(5) Refer to footnote on page 219, line no. 23.3, column (c)
(6) Refer to footnote on page 219, line no. 24, column (c)
(7) Refer to footnote on page 219, line no. 25, column (c)
(8) Refer to footnote on page 219, line no. 26, column (c)
(9) Refer to footnote on page 219, line no. 28, column (c)

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Report below investments in Account 123.1, Investments in Subsidiary Companies. Provide a subheading for each company and list thereunder the information called for below. Sub-TOTAL by company and give a TOTAL in columns (e), (f), (g) and (h). (a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity, and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number. Report column (f) interest and dividend revenues from investments, including such revenues from securities disposed of during the year. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost) and the selling price thereof, not including interest adjustment includible in column (f). Report on Line 42, column (a) the TOTAL cost of Account 123.1.
Line No.	DescriptionOfInvestmentsInSubsidiaryCompanies Description of Investment (a)	DateOfAcquisitionInvestmentsInSubsidiaryCompanies Date Acquired (b)	DateOfMaturityInvestmentsInSubsidiaryCompanies Date of Maturity (c)	InvestmentInSubsidiaryCompanies Amount of Investment at Beginning of Year (d)	EquityInEarningsOfSubsidiaryCompanies Equity in Subsidiary Earnings of Year (e)	InterestAndDividendRevenueFromInvestments Revenues for Year (f)	InvestmentInSubsidiaryCompanies Amount of Investment at End of Year (g)	InvestmentGainLossOnDisplosal Gain or Loss from Investment Disposed of (h)
1	(a) Pacific Minerals, Inc. - Common Stock	12/10/1973		1			1
2	Pacific Minerals, Inc. - Paid-In-Capital	12/10/1973		47,960,000			47,960,000
3	Pacific Minerals, Inc. - Unappropriated Undistributed Subsidiary Earnings	12/10/1973		45,208,380	6,421,083		51,629,463
4	Energy West Mining Company - Common Stock	07/19/1990		1,000			1,000
5	Trapper Mining Inc. - Equity Contribution	12/29/1997		6,038,000			6,038,000
6	Trapper Mining Inc. - Unappropriated Undistributed Subsidiary Earnings	12/29/1997		11,406,732	4,936,040		(b) 16,298,767
42	Total Cost of Account 123.1 $ 53,999,001		Total	110,614,113	11,357,123		121,927,231

FOOTNOTE DATA

(a) Concept: DescriptionOfInvestmentsInSubsidiaryCompanies

Pacific Minerals, Inc. is a wholly owned subsidiary of PacifiCorp that holds a 66.67% ownership interest in Bridger Coal Company.

(b) Concept: InvestmentInSubsidiaryCompanies

During the year ended December 31, 2025, Trapper Mining Inc., a subsidiary of PacifiCorp, paid a distribution of $44,005 to PacifiCorp.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

MATERIALS AND SUPPLIES
For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a); estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if applicable.
Line No.	Account (a)	Balance Beginning of Year (b)	Balance End of Year (c)	Department or Departments which Use Material (d)
1	Fuel Stock (Account 151)	270,978,352	307,771,791	Electric
2	Fuel Stock Expenses Undistributed (Account 152)
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	422,879,240	491,203,668	Electric
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	97,696,263	91,395,514	Electric
8	Transmission Plant (Estimated)	1,871,312	2,405,992	Electric
9	Distribution Plant (Estimated)	34,702,284	27,022,646	Electric
10	Regional Transmission and Market Operation Plant (Estimated)
10.1	Energy Storage Plant (Estimated)
11	Assigned to - Other (provide details in footnote)
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	557,149,099	612,027,820
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)
15	Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16	Stores Expense Undistributed (Account 163)
17
18
19
20	TOTAL Materials and Supplies	828,127,451	919,799,611

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

Allowances and Environmental Credits (Accounts 158.1, 158.2, 158.3, and 158.4)
Report below the details related to allowances and environmental credits. Additional information about the type of allowances/environmental credits required by other regulatory bodies can be disclosed within the footnote data. Report all acquisitions of allowances and environmental credits at cost. Report allowances and environmental credits in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances and environmental credits transactions by the period they are first eligible for use: the current year�s allowances and environmental credits in columns (b)-(c), allowances and environmental credits for the three succeeding years in columns (d)-(i), starting with the following year, and allowances and environmental credits for the remaining succeeding years in columns (j)-(k). Report on Line 4 authoritative agency issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by an authoritative agency. Report on Line 39 the authoritative agency�s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the authoritative agency�s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances and environmental credits acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances and environmental credits disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance and environmental credits sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	Allowances and Environmental Credits Inventory (Accounts 158.1, 158.3, and 158.4) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year	(b) 3,266,630	(e) 2,677,526	156,646		156,646		156,646		4,048,772		7,785,340	2,677,526
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	2,150,607								156,645		2,307,252
5	Returned by authoritative agency
6
7
8	Purchases/Transfers:
9	California Air Resources Board (GHG Allowances)	746,000	20,662,920									746,000	20,662,920
10	Morgan Stanley Capital Group Inc (GHG Allowances)	70,000	2,106,300									70,000	2,106,300
11	Washington Department of Ecology (GHG Allowances)	1,137,532	65,520,619									1,137,532	65,520,619
12	Adams Solar Center (REC)	25,771	36,079									25,771	36,079
13	Bear Creek Solar Center (REC)	29,838	41,773									29,838	41,773
14	Bly Solar Center (REC)	27,200	38,080									27,200	38,080
14.1	Elbe Solar Center (REC)	30,770	43,078									30,770	43,078
14.2	Enterprise Solar, LLC (REC)	392,276	745,324									392,276	745,324
14.3	Escalante Solar III LLC (REC)	80,870	252,680									80,870	252,680
14.4	Pavant Solar, LLC (REC)	198,829	298,244									198,829	298,244
15	Total	2,739,086	89,745,097									2,739,086	89,745,097
16
17	Relinquished During Year:
18	Charges to Account 509, 555.2, and 555.3	(c) 18,114										18,114
19	Other:
20	Allowances Used
20.1	Allowances Used	(d) 1,846,799	(f) 20,554,518									1,846,799	20,554,518
20.2	(a) Prior period adjustment	14,219,521	49,835,509							24,258		14,243,779	49,835,509
21	Cost of Sales/Transfers:
22	California Air Resources Board	519,946	0									519,946
23
24
25
26
27
28	Total	519,946	0									519,946
29	Balance-End of Year	19,990,985	121,703,614	156,646		156,646		156,646		4,229,675		24,690,598	121,703,614
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)		14,587,086										14,587,086
34	Gains		14,587,086										14,587,086
35	Losses
	Allowances Withheld (Acct 158.2)
36	Balance-Beginning of Year	2,259		2,259		2,259		2,259		110,921		119,957
37	Add: Withheld by authoritative agency									4,528		4,528
38	Deduct: Returned by authoritative agency
39	Cost of Sales	2,259								2,269		4,528
40	Balance-End of Year			2,259		2,259		2,259		113,180		119,957
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: AllowancesRelinquishedOtherDescription

Due to the adoption of FERC Order No. 898 on January 1, 2025, 14,219,521 units and $49,835,509 of greenhouse gas allowances and renewable energy credits were transferred to FERC Accounts 158.1, 158.3 and 158.4 from FERC Account 165.

(b) Concept: AllowanceInventoryNumber

Due to the adoption of FERC Order No. 898, beginning of year balance includes renewable energy credits in the amount of 1,516,716 units and $2,677,526 that were recorded in FERC Account 158.1 at December 31, 2024 but not reflected in the ending balance on this page in the December 31, 2024 Form No. 1.

Amounts are associated with SO2 allowances and as they are zero-cost allowances, no amounts were charged to accounts 509, 555.2 or 555.3.

(d) Concept: AllowancesRelinquishedOtherNumber

Greenhouse gas allowances and renewable energy credits are charged to FERC Accounts 509, 555.2 and 555.3, respectively, when the obligation is incurred, not when they are relinquished from FERC Accounts 158.1, 158.3 and 158.4.

(e) Concept: AllowanceInventory

(f) Concept: AllowancesRelinquishedOther

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfExtraordinaryPropertyLoss Description of Extraordinary Loss [Include in the description the date of Commission Authorization to use Acc 182.1 and period of amortization (mo, yr to mo, yr).] (a)	ExtraordinaryPropertyLossesNotYetRecognized Total Amount of Loss (b)	ExtraordinaryPropertyLossesRecognized Losses Recognized During Year (c)	ExtraordinaryPropertyLossesWrittenOffAccountCharged Account Charged (d)	ExtraordinaryPropertyLossesWrittenOff Amount (e)	ExtraordinaryPropertyLosses Balance at End of Year (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
20	TOTAL

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfUnrecoveredPlantAndRegulatoryStudyCosts Description of Unrecovered Plant and Regulatory Study Costs [Include in the description of costs, the date of COmmission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)] (a)	UnrecoveredPlantAndRegulatoryStudyCostsNotYetRecognized Total Amount of Charges (b)	UnrecoveredPlantAndRegulatoryStudyCostsRecognized Costs Recognized During Year (c)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOffAccountCharged Account Charged (d)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOff Amount (e)	UnrecoveredPlantAndRegulatoryStudyCosts Balance at End of Year (f)
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49	TOTAL

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

Transmission Service and Generation Interconnection Study Costs
Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. List each study separately. In column (a) provide the name of the study. In column (b) report the cost incurred to perform the study at the end of period. In column (c) report the account charged with the cost of the study. In column (d) report the amounts received for reimbursement of the study costs at end of period. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.	DescriptionOfStudyPerformed Description (a)	StudyCostsIncurred Costs Incurred During Period (b)	StudyCostsAccountCharged Account Charged (c)	StudyCostsReimbursements Reimbursements Received During the Period (d)	StudyCostsAccountReimbursed Account Credited With Reimbursement (e)
1	Transmission Studies
2	Q3586	4,040	561.6	4,040	456
3	Q3637	1,108	561.6
4	Q3509	1,475	561.6	1,475	456
5	Q3246	222	561.6	222	456
6	Q3247-A	2,132	561.6	2,132	456
7	Q3585-A	1,795	561.6	1,795	456
8	Q3587-A	2,062	561.6	2,062	456
9	Q3546	133	561.6
10	Q3527	133	561.6
11	Q3283	1,773	561.6
12	Q3284	1,773	561.6
13	Q3634	1,961	561.6
14	Q3638	2,176	561.6
15	Q3635	4,240	561.6
16	Q3636	4,192	561.6
17	Q3589	1,543	561.6
18	Q3590	1,543	561.6
19	Q3593	1,543	561.6
20	Q3591	1,543	561.6
21	Q3592	1,543	561.6
22	Q3290	1,421	561.6
23	Q3588	156	561.6
24	Q3334	6,997
25	Q3438-A	10,842	561.6	10,842	456
26	Q3617	120	561.6
27	Q3648	2,993	561.6
28	Q3558	4,671	561.6	4,671	456
29	Q3642	263	561.6	263	456
30	Q3292	1,142	561.6
31	Q3662	2,097	561.6	2,097	456
32	Q3663	2,758	561.6	2,758	456
33	Q3681	6,112	561.6	6,112	456
34	Q3683	356	561.6
35	Q3528	2,969	561.6	2,969	456
36	Q3585-B	7,827	561.6	7,827	456
37	Q3694	4,192	561.6	4,192	456
38	Q3693	5,328	561.6	5,328	456
39	Q3247-B	1,615	561.6	1,615	456
40	Q3697	1,699	561.6
41	Q3698	621	561.6
42	Q3705	2,097	561.6
43	Q3587-B	4,153	561.6	4,153	456
44	Q3712	3,775	561.6	3,775	456
45	Q3722	1,089	561.6
46	C2-167	2,416	561.6
47	C2-168	1,353	561.6
48	C2-169	383	561.6
49	Q3725-A	3,463	561.6
50	Q3726	1,144	561.6
51	C2-014	1,928	561.6
52	Q3727	1,160	561.6
53	Q3271-A	1,598	561.6	1,598	456
54	Q3272	814	561.6	814	456
55	Q3740	12,416	561.6	12,416	456
56	Q3739	5,357	561.6	5,357	456
57	Q3747	891	561.6
58	Q3741-A	6,325	561.6	6,325	456
59	Q3742	2,411	561.6	2,411	456
60	Q3751	2,116	561.6	2,116	456
61	Q3752	1,135	561.6	1,135	456
62	Q3438-B	169	561.6	169	456
63	Q3725-B	1,136	561.6
64	Q3778	563	561.6
65	Q0002	1,029	561.6
66	Q3802	451	561.6
67	Q3807	7,073	561.6	7,073	456
68	Q3271-B	9,414	561.6	9,414	456
69	Q3832	8,086	561.6	8,086	456
70	Q3741-B	8,661	561.6	8,661	456
71	Q3839	2,063	561.6	2,063	456
72	Q3840	451	561.6	451	456
73	ESM Transmission study	21,724	561.6
20	Total	217,953		136,417
21	Generation Studies
22	C2-167	193	561.7
23	C2-168	193	561.7
24	AS067	92,044	561.7
25	C1-04	578	561.7	578	456
26	C1-10	1,300	561.7	1,300	456
27	C1-11	2,636	561.7	2,636	456
28	C1-14	1,026	561.7	1,026	456
29	C1-43	182	561.7	182	456
30	C1-58	578	561.7	578	456
31	C2-002	507	561.7
32	C2-006	560	561.7	560	456
33	C2-007	401	561.7	401	456
34	C2-008	402	561.7	402	456
35	C2-009	447	561.7	447	456
36	C2-02	1,998	561.7
37	C2-032	19,362	561.7	19,362	456
38	C2-039	5,955	561.7	5,955	456
39	C2-048	2,513	561.7
40	C2-05	1,988	561.7
41	C2-056	2,342	561.7	2,342	456
42	C2-057	10,580	561.7	10,580	456
43	C2-058	1,606	561.7	1,606	456
44	C2-059	6,646	561.7	6,646	456
45	C2-072	2,653	561.7	2,653	456
46	C2-106	6,798	561.7	6,798	456
47	C2-109-A	5,909	561.7	5,909	456
48	C2-109-B	3,534	561.7	3,534	456
49	C2-11	530	561.7
50	C2-110	8,789	561.7	8,789	456
51	C2-111	204	561.7	204	456
52	C2-112	1,882	561.7	1,882	456
53	C2-114	1,078	561.7	1,078	456
54	C2-115	2,887	561.7	2,887	456
55	C2-117	1,089	561.7	1,089	456
56	C2-12	338	561.7
57	C2-120	56	561.7	56	456
58	C2-13	316	561.7
59	C2-131	372	561.7	372	456
60	C2-133	1,678	561.7	1,678	456
61	C2-138-A	728	561.7	728	456
62	C2-138-B	399	561.7	399	456
63	C2-14	271	561.7
64	C2-141	1,183	561.7	1,183	456
65	C2-144-A	147	561.7	147	456
66	C2-144-B	113	561.7	113	456
67	C2-15	214	561.7
68	C2-156	847	561.7	847	456
69	C2-158	532	561.7	532	456
70	C2-162	2,662	561.7	2,662	456
71	C2-170	485	561.7	485	456
72	C2-171	91	561.7	91	456
73	C2-173	90	561.7	90	456
74	C2-175	133	561.7	133	456
75	C2-178	486	561.7	486	456
76	C2-180	204	561.7	204	456
77	C2-181	91	561.7	91	456
78	C2-182	91	561.7	91	456
79	C2-187	91	561.7	91	456
80	C2-204	8,247	561.7	8,247	456
81	C2-205	1,220	561.7	1,220	456
82	C2-209	4,379	561.7	4,379	456
83	C2-27	5,034	561.7	5,034	456
84	C2-45	2,630	561.7	2,630	456
85	C2-49	676	561.7	676	456
86	C2-54	2,470	561.7	2,470	456
87	C2-79	886	561.7	886	456
88	C2-82	163	561.7	163	456
89	C2-91	637	561.7	637	456
90	C2-92	637	561.7	637	456
91	C2-99	690	561.7	690	456
92	C3-008	46	561.7
93	C3-011-A	485	561.7
94	C3-011-B	163	561.7
95	C3-036	1,753	561.7	1,753	456
96	C3-038	2,767	561.7	2,767	456
97	C3-041	8,926	561.7	8,926	456
98	C3-062	46	561.7	46	456
99	C3-080	46	561.7
100	C3-081	46	561.7
101	C3-096	46	561.7
102	C3-097	46	561.7
103	C3-125	3,323	561.7	3,323	456
104	C3-132	3,789	561.7	3,789	456
105	C3-148	46	561.7	46	456
106	C3-163	137	561.7	137	456
107	C3-171	4,094	561.7	4,094	456
108	C3-186	3,355	561.7	3,355	456
109	C3-187	5,452	561.7	5,452	456
110	FT008	338	561.7	338	456
111	FT009-A	5,668	561.7	5,668	456
112	FT009-B	8,488	561.7	8,488	456
113	FT012	377	561.7	377	456
114	FT013	5,494	561.7	5,494	456
115	FT014	11,081	561.7	11,081	456
116	FT015	1,616	561.7	1,616	456
117	FT016-A	338	561.7	338	456
118	FT016-B	752	561.7	752	456
119	FT017	3,919	561.7	3,919	456
120	FT018	5,852	561.7	5,852	456
121	FT019	3,127	561.7	3,127	456
122	FT02-A	1,842	561.7	1,842	456
123	FT02-B	2,098	561.7	2,098	456
124	FT02-C	1,980	561.7	1,980	456
125	FT02-D	422	561.7	422	456
126	FT020	2,434	561.7	2,434	456
127	FT021	749	561.7	749	456
128	FT022	3,087	561.7	3,087	456
129	FT027	780	561.7	780	456
130	FT028	2,528	561.7	2,528	456
131	FT030	613	561.7	613	456
132	FT031	444	561.7	444	456
133	FT032	1,002	561.7	1,002	456
134	FT033	392	561.7	392	456
135	FT034	501	561.7	501	456
136	ISGIQ015	365	561.7	365	456
137	ISGIQ017	2,134	561.7	2,134	456
138	ISGIQ018	11,042	561.7	11,042	456
139	OCS0081	56	561.7	56	456
140	OCS0086	756	561.7	756	456
141	OCS0087-A	2,400	561.7	2,400	456
142	OCS0087-B	1,753	561.7	1,753	456
143	OCS0099	2,955	561.7	2,955	456
144	OCS086	466	561.7	466	456
145	OCS098-A	4,265	561.7	4,265	456
146	OCS098-B	2,868	561.7	2,868	456
147	OCS099	2,372	561.7	2,372	456
148	OCS100	9,861	561.7	9,861	456
149	OCS101-A	4,193	561.7	4,193	456
150	OCS101-B	6,727	561.7	6,727	456
151	OCS103-A	5,085	561.7	5,085	456
152	OCS103-B	1,886	561.7	1,886	456
153	OCS103-C	962	561.7	962	456
154	OCS104-A	6,762	561.7	6,762	456
155	OCS104-B	1,898	561.7	1,898	456
156	OCS105	4,417	561.7	4,417	456
157	OCS106-A	11,580	561.7	11,580	456
158	OCS106-B	507	561.7	507	456
159	OCS107-A	11,301	561.7	11,301	456
160	OCS107-B	225	561.7	225	456
161	OCS108	6,426	561.7	6,426	456
162	OCS109-A	5,432	561.7	5,432	456
163	OCS109-B	56	561.7	56	456
164	OCS110	5,876	561.7	5,876	456
165	OCS111	3,618	561.7	3,618	456
166	OCSGIQ002	113	561.7	113	456
167	OCSGIQ0080	319	561.7	319	456
168	OCSGIQ095	182	561.7	182	456
169	OTP0039	28,827	561.7
170	PIS0022	1,374	561.7	1,374	456
171	PIS0023	1,888	561.7	1,888	456
172	PIS0025	814	561.7	814	456
173	PIS0026	895	561.7	895	456
174	PIS0027	625	561.7	625	456
175	PIS0031	476	561.7	476	456
176	PIS0033	451	561.7	451	456
177	PIS0034	169	561.7	169	456
178	PIS009	2,895	561.7
179	PIS012	388	561.7
180	PIS033	2,586	561.7	2,586	456
181	PIS056	112	561.7
182	PIS090	23	561.7
183	PIS091	23	561.7
184	PIS092	23	561.7
185	PIS093	23	561.7
186	PIS094	23	561.7
187	PIS095	23	561.7
188	PIS096	23	561.7
189	PIS097	23	561.7
190	PIS098	23	561.7
191	PIS099	23	561.7
192	PIS100	113	561.7	113	456
193	S0022	5,171	561.7	5,171	456
194	S0023	7,866	561.7	7,866	456
195	S0024	6,855	561.7	6,855	456
196	S0025	13,274	561.7	13,274	456
197	S0026	8,382	561.7	8,382	456
198	S0027	4,837	561.7	4,837	456
199	S0028	594	561.7	594	456
200	S0029	7,479	561.7	7,479	456
201	S0030	7,018	561.7	7,018	456
202	S0031	8,953	561.7	8,953	456
203	S0032	460	561.7	460	456
204	S0033	8,345	561.7	8,345	456
205	S0034	12,326	561.7	12,326	456
206	S0035	623	561.7	623	456
207	S0036	10,078	561.7	10,078	456
208	S0037	7,296	561.7	7,296	456
209	S0038	553	561.7	553	456
210	S0039	1,579	561.7	1,579	456
211	SGIQ0171	6,581	561.7	6,581	456
212	SIS0007	425	561.7	425	456
213	SIS0008	334	561.7	334	456
214	SIS0009	334	561.7	334	456
215	SIS0010	712	561.7	712	456
216	SIS0011	334	561.7	334	456
217	SIS0012	334	561.7	334	456
218	SIS0013	334	561.7	334	456
219	SIS0014	152	561.7	152	456
220	SIS0015	1,196	561.7	1,196	456
221	SIS0016	1,256	561.7	1,256	456
222	SIS0017	717	561.7	717	456
223	SIS0019	91	561.7	91	456
224	SIS002	993	561.7
225	SIS0020	158	561.7	158	456
226	SIS0021	249	561.7	249	456
227	SIS003	46	561.7
228	SIS004	46	561.7
229	SIS005	46	561.7
230	SIS006	136	561.7
231	2024 Cluster Study Applications	106,417	561.7	106,417	456
232	2025 Transition Cluster	91,074	561.7	91,074	456
233	2025 Transition Cluster Study	2,516	561.7	2,516	456
234	C1 Cluster Area 6 Restudy 3	351	561.7	351	456
235	Cluster 1 CA12 Restudy 4	67,595	561.7	67,595	456
236	Cluster 1 CA12 Restudy 3	24,430	561.7	24,430	456
237	Cluster 1 - CA 7 Restudy 4	9,075	561.7	9,075	456
238	C2 Cluster Area 6 Restudy 2	973	561.7	973	456
239	C2 Cluster Area 7 Restudy 2	182	561.7	182	456
240	C2 Cluster Area 8 Restudy	383	561.7	383	456
241	CA2 Restudy 2	917	561.7	917	456
242	CA1 Restudy 2	4,400	561.7	4,400	456
243	Cluster 2 - CA12 Restudy 3	6,346	561.7	6,346	456
244	Cluster 2 - CA 14 Restudy 3	11,060	561.7	11,060	456
245	Cluster 2 - CA 14 Restudy 4	7,464	561.7	7,464	456
246	C2 Cluster Area 16 Restudy 2	308	561.7	308	456
247	CA19 Restudy 1	93,345	561.7	93,345	456
248	C2 - CA20 Restudy 2	115,428	561.7	115,428	456
249	CA3 Restudy 3	3,177	561.7	3,177	456
250	Cluster 2- CA 5 Restudy 2	1,125	561.7	1,125	456
251	Cluster 2 - CA 6 Restudy 3	4,730	561.7	4,730	456
252	C2 Cluster Area 9 Restudy 2	444	561.7	444	456
253	CA9 Restudy 4	21,411	561.7	21,411	456
254	CA16 Restudy 2	27,777	561.7	27,777	456
255	CA17 Restudy 2	17,769	561.7	17,769	456
256	CA3 Restudy 2	46	561.7	46	456
257	CA8 Restudy 2	977	561.7	977	456
258	Cluster 3 - CA 5 Restudy 2	9,657	561.7	9,657	456
259	CA6 Restudy 2	4,714	561.7	4,714	456
260	2025 Cluster Study Applications	37,330	561.7	37,330	456
261	2026 Cluster Study Applications	124,539	561.7	124,539	456
262	Cluster 2 - Cluster Area 12 Restudy 2	498	561.7	498	456
263	Cluster 2 Cluster Area 1 Restudy	802	561.7	802	456
264	Cluster 2 Cluster Area 2 Restudy	4,448	561.7	4,448	456
265	Cluster 2 Cluster Area 7 Restudy	687	561.7	687	456
266	Cluster 2 Cluster Area 9 Restudy	3,690	561.7	3,690	456
267	Cluster 3 - Cluster Area 1 Restudy	55,513	561.7	55,513	456
268	Cluster 3 - Cluster Area 3 Restudy	13,947	561.7	13,947	456
269	Cluster 3 - Cluster Area 4 Restudy	5,437	561.7	5,437	456
270	Cluster 3 - Cluster Area 6 Restudy	16,010	561.7	16,010	456
271	Cluster 3 - Cluster Area 7 Restudy	11,925	561.7	11,925	456
272	Cluster 3 - Cluster Area 8 Restudy	44,773	561.7	44,773	456
273	Cluster 3 - Cluster Area 9 Restudy	4,653	561.7	4,653	456
274	Cluster 3 Cluster Area 10 Restudy	55,977	561.7	55,977	456
275	Cluster 3 Cluster Area 11 Restudy	13,693	561.7	13,693	456
276	Cluster 3 Cluster Area 12 Restudy	10,597	561.7	10,597	456
277	Cluster 3 Cluster Area 13 Restudy	13,843	561.7	13,843	456
278	Cluster 3 Cluster Area 15 Restudy	106,610	561.7	106,610	456
279	Cluster 3 Cluster Area 16 Restudy	70,199	561.7	70,199	456
280	Cluster 3 Cluster Area 17 Restudy	56,622	561.7	56,622	456
281	Cluster 3 Cluster Area 19 Restudy	3,128	561.7	3,128	456
282	Cluster 3 Cluster Area 5 Restudy	24,568	561.7	24,568	456
283	Cluster 3 Study Report Production	128,868	561.7
284	Cluster 2 Cluster Area 12 Restudy	3,768	561.7	3,768	456
285	Cluster 2 Cluster Area 20 Restudy	29,215	561.7	29,215	456
286	Trans Cluster 4 Restudy	11,167	561.7	11,167	456
287	ESM APP	3,422	561.7
288	ESM Cluster Study 2	36,914	561.7
289	ESM Gen Clearing Order	119	561.7
290	ESM C5 App costs			11,742	456
291	PreQueue East	5,176	561.7	5,176	456
292	PreQueue West	23,702	561.7	23,702	456
293	GEN APP	30,909	561.7	30,909	456
39	Total	2,055,065		1,738,298
40	Grand Total	2,273,018		1,874,715

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

OTHER REGULATORY ASSETS (Account 182.3)
Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Assets being amortized, show period of amortization.
				CREDITS
Line No.	DescriptionAndPurposeOfOtherRegulatoryAssets Description and Purpose of Other Regulatory Assets (a)	OtherRegulatoryAssets Balance at Beginning of Current Quarter/Year (b)	IncreaseDecreaseInOtherRegulatoryAssets Debits (c)	OtherRegulatoryAssetsWrittenOffAccountCharged Written off During Quarter/Year Account Charged (d)	OtherRegulatoryAssetsWrittenOffRecovered Written off During the Period Amount (e)	OtherRegulatoryAssets Balance at end of Current Quarter/Year (f)
1	(a) DSM Balancing Account - UT	244,288,408	207,979,301	908	93,715,488	358,552,221
2	(b) DSM Balancing Account - WA	1,907,162	24,242,151	908	24,710,354	1,438,959
3	(c) DSM Balancing Account - WY	19,076,581	9,745,752	908	15,756,744	13,065,589
4	(d) Deferred Excess Net Power Costs - CA	25,141,888	5,206,836	555	12,786,183	17,562,541
5	(e) Deferred Excess Net Power Costs - ID	82,885,447	3,991,943	555	40,512,941	46,364,449
6	(f) Deferred Excess Net Power Costs - OR	233,621,206	23,163,616	555	125,209,310	131,575,512
7	(g) Deferred Excess Net Power Costs - UT	595,649,099	186,775,818	555	443,889,064	338,535,853
8	(h) Deferred Excess Net Power Costs - WA	200,296,817	20,913,431	555	111,500,587	109,709,661
9	(i) Deferred Excess Net Power Costs - WY	152,493,915	27,203,418	555	111,244,946	68,452,387
10	(j) Deferred Excess RECs in Rates - WY	339,225	507,509	411.11	846,734
11	(k) Deferred Excess RECs in Rates - UT	2,237,228	4,206,677	411.11	2,293,100	4,150,805
12	Decoupling Mechanism - WA	5,991,342	9,122,425	254, 440, 442	1,274,898	13,838,869
13	Solar Investment Tax Credit Basis Adjustment	428,330	69,174	282, 283	34,447	463,057
14	Metro Business Income Tax - OR	265				265
15	(l) Pension	265,572,168	5,864,482		(al) 16,199,390	255,237,260
16	Postemployment Costs		72,361			72,361
17	Deferred Steam Depreciation - UT	19,230,486	2,102,945	403	20,839,731	493,700
18	Colstrip Unit No. 4 Deferred Maintenance Costs - WA (Amortization period: 1 year, starting 04/2024)	64,726		923	(am) 64,726
19	(m) Carbon Plant Inventory	179,487		407.3	179,487
20	Cholla Unit No. 4 Closure Costs - CA (Amortization period: 5 years, starting 01/2024)	2,976,932		407.3	744,664	2,232,268
21	Cholla Unit No. 4 Closure Costs - ID	56,743				56,743
22	(n) Cholla Unit No. 4 Closure Costs - OR	299,835	9,580	408.1, 920, 931	(an) 390,731	81,316
23	Cholla Unit No. 4 Closure Costs - UT (Amortization period: 4.4 years, starting 01/2021)	537,800		407.3	537,800
24	Cholla Unit No. 4 Closure Costs - WY (Amortization period: 11 years, starting 07/2021)	31,662,014		407.3	4,221,429	27,440,585
25	Cholla Unit No. 4 Decommissioning Costs - CA (Amortization period: 5 years, starting 01/2024)	88,624	125,957	407.3	113,645	100,936
26	Cholla Unit No. 4 Decommissioning Costs - WY (Amortization period: 11 years, starting 07/2021)	1,017,394	1,253,492	407.3	617,828	1,653,058
27	Depreciation Study Deferral - ID (Amortization period: 4 years, starting 01/2022)	3,485,075		403	3,485,075
28	Depreciation Study Deferral - UT (Amortization period: 17 years, starting 09/2014)	832,282		403	128,043	704,239
29	Depreciation Study Deferral - WY (Amortization period: 18 years, starting 01/2014)	2,874,242		403	442,190	2,432,052
30	Generating Plant Liquidated Damages - UT (Amortization period: 20 years, starting 01/2014)	315,000		557	35,000	280,000
31	(o) Generating Plant Liquidated Damages - WY	864,396		557	54,289	810,107
32	Resource Tracking Mechanism - ID(Amortization period: 3 years, starting 01/2025)	2,724,603		403	908,201	1,816,402
33	Wind Test Energy Deferral - WY (Amortization period: 30 years, starting 12/2020)	198,100		557	7,644	190,456
34	(p) Environmental Costs	145,344,986	23,533,448	514, 545, 554, 598, 935	(ao) 10,372,164	158,506,270
35	(q) Asset Retirement Obligations Regulatory Difference	324,484,971	123,636,018	230, 426.5	18,751,720	429,369,269
36	North Temple Office Property Transfer	3,540,768	3,802,685			7,343,453
37	Unrealized Loss on Derivative Contracts	96,913,738	40,480,228			137,393,966
38	(r) Greenhouse Gas Allowance Revenues - CA	3,192,040	23,642,802	411.8	13,128,377	13,706,465
39	Emergency Service Resiliency Program - CA	6,795	306			7,101
40	(s) Solar Feed-In Tariff Deferral - OR	4,584,674	4,360,291	555, 908	4,412,847	4,532,118
41	(t) Oregon Community Solar Program	3,187,988	3,275,809	908	1,751,057	4,712,740
42	(u) Solar Incentive Subscriber Program - UT	1,777,070	95,995	908	200,467	1,672,598
43	Deferred Intervenor Funding Grants - CA	449,267	26,660			475,927
44	Deferred Intervenor Funding Grants - ID (Amortization period: 4 years, starting 01/2025)	40,000	27,247	928	10,000	57,247
45	(v) Deferred Intervenor Funding Grants - OR	833,017		928	833,017
46	Deferred Intervenor Funding Grants - WA	178,376	148,240			326,616
47	Deferred Independent Evaluator Costs - OR	167,607	10,090			177,697
48	Catastrophic Event - CA	21,503,322	1,731			21,505,053
49	(w) Low Income Bill Discount Admin Cost - OR	7,265,223	37,343,300	142	34,871,547	9,736,976
50	(x) Low Income Program - WA	1,079,201		142	1,079,201
51	(y) Deferred Overburden Cost - ID	945,692	2,181,696	501	2,266,088	861,300
52	(z) Deferred Overburden Cost - WY	2,116,400	5,377,858	501	5,396,601	2,097,657
53	(aa) BPA Balancing Account - WA	1,329,892		143	1,329,892
54	(ab) BPA Balancing Account - ID	429,954		143	429,954
55	(ac) Property Damage - OR	41,838,002	23,150,886	924	16,089,801	48,899,087
56	Property Damage - WA	370,164	1,089,109	924	1,377,896	81,377
57	(ad) Property Damage - CA	2,992,898	3,107,309	924	1,800,045	4,300,162
58	(ae) Property Damage - UT	2,218,441	58,066	924	1,564,459	712,048
59	(af) Utah Mine Disposition	83,182,247		506	3,200,042	79,982,205
60	Electric Vehicle Infrastructure - CA	3,926		254	3,926
61	Transportation Electrification Program - OR (Amortization period: 3 years, starting 04/2023)	1,492,222	51,023	908	1,093,271	449,974
62	Transportation Electrification Program - WA (Amortization period: 1 year, starting 04/2024)	464,942	211,287	908	228,794	447,435
63	(ag) Transportation Electrification Pilot - UT		7,630,794	908	7,599,829	30,965
64	Fire Hazard and Wildfire Mitigation Plan - CA (Amortization period: 6 years, starting 04/2025)	51,505,016	25,009,455	593	3,961,202	72,553,269
65	(ah) Wildfire Mitigation and Vegetation Management Plans - OR	47,593,993	25,880,239	440, 442, 444, 593	58,119,276	15,354,956
66	Wildfire Natural Disaster Plan - CA	94,815	4,280			99,095
67	Wildland Fire Mitigation Balancing Account - UT (Amortization period: 1 year, starting 04/2025)	4,752,081	1,730,800	593	4,216,933	2,265,948
68	AMI Replaced Meters - OR (Amortization period: 5 years, starting 01/2021)	4,139,908	84,827	407.3	4,064,930	159,805
69	COVID-19 Bill Assistance Program - OR (Amortization period: 4 years, starting 04/2023)	7,618,514	295,022	908	3,698,940	4,214,596
70	COVID-19 Bill Assistance Program - WA (Amortization period: 1 year, starting 04/2024)	775,332		908	775,332
71	Equity Advisory Group for Clean Energy Implementation Plan - WA	1,040,428	495,473	923	(ap) 239,935	1,295,966
72	Mobile Home Park Conversion - CA (Amortization period: 10 years, starting 05/2020)	166,171	23,744	407.3	36,774	153,141
73	TB Flats - OR (Amortization period: 3 years, starting 04/2023)	3,440,944	91,906	403, 431	3,272,870	259,980
74	Klamath Unrecovered Plant Net Book Value (Amortization period: 5 years, starting 12/2022)	7,983,775	224,392	407.3	1,405,772	6,802,395
75	(ai) Alternative Rate For Energy (CARE) - CA	3,463,445	229,820	142	247,372	3,445,893
76	(aj) Utility Bill Assistance - UT	162,060	15,290	142, 440, 442, 444	175,616	1,734
77	2023 GRC Memo Account - CA (Amortization period: 3 years, starting 01/2024)	12,498,096	423,461	403, 407.3, 431, 928	6,237,336	6,684,221
78	(ak) Injuries & Damages Reserve - OR	3,657,583	1,178,401	925	812,220	4,023,764
79	Deferred Insurance Premiums - ID (Amortization period: 3 years, starting 01/2025)	7,816,881	3,699,848	925	(aq) 6,078,099	5,438,630
80	Deferred Insurance Premiums - OR (Amortization period: 3 years, starting 01/2025)	38,970,960	1,815,115	925, 419	(ar) 12,728,792	28,057,283
81	Deferred Insurance Premiums - WY (Amortization period: 3 years, starting 06/2025)		12,000,000	925	(as) 2,013,323	9,986,677
82	Renewable Adjustment Clause - OR		1,469,964			1,469,964
83	Rock Creek II - ID		544,557			544,557
44	TOTAL	2,844,837,159	911,016,340		1,268,620,386	2,487,233,113

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Average amortization period is approximately 10 years.

(b) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

Average amortization period is approximately 10 years.

(d) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Average amortization period is approximately one year.

(e) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Average amortization period is approximately one year.

(f) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Weighted average remaining amortization period is approximately two years.

(g) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Average amortization period is approximately one year.

(h) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Average amortization period is approximately one year.

(i) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Average amortization period is approximately one year.

(j) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Average amortization period is approximately one year.

(k) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Average amortization period is approximately one year.

(l) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Weighted average remaining amortization period is approximately 13 years. Substantially represents amounts not yet recognized as a component of net periodic benefit cost.

(m) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Average amortization period is approximately three years.

(n) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Weighted average remaining amortization period is approximately one year.

(o) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Average amortization period is approximately 24 years.

(p) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Average amortization period is approximately 10 years.

(q) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(r) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(s) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Average amortization period is approximately one year.

(t) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(u) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(v) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(w) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(x) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(y) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(z) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(aa) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(ab) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(ac) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(ad) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(ae) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(af) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

$71 million is related to withdrawal from the 1974 UMWA Pension Trust and is indefinite-lived, while the remainder is associated with other closure costs and has an average remaining amortization period of three years.

(ag) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(ah) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Average amortization period is approximately one year.

(ai) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(aj) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(ak) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Amortization period varies depending on timing of underlying transactions.

(al) Concept: OtherRegulatoryAssetsWrittenOffRecovered

Pension costs are associated with labor and generally charged to operations and maintenance expense and construction work in progress. Settlement charges are charged to Account 926, Employee pensions and benefits and Account 228.3, Accumulated provision for pensions and benefits.

(am) Concept: OtherRegulatoryAssetsWrittenOffRecovered

In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No. ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations reflected in Administrative and General expense accounts should be excluded from the calculation of the wholesale transmission revenue requirement and charges under the wholesale formula rates, unless approved by the Commission. During the year ended December 31, 2025, regulatory asset amortization associated with Washington's share of Colstrip Unit No. 4 deferred maintenance costs of $64,726 was charged to Account 923.

(an) Concept: OtherRegulatoryAssetsWrittenOffRecovered

In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No. ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations reflected in Administrative and General expense accounts should be excluded from the calculation of the wholesale transmission revenue requirement and charges under the wholesale formula rates, unless approved by the Commission. During the year ended December 31, 2024, regulatory asset amortization associated with Oregon's share of Cholla Unit No. 4 closure costs of $140,409 was charged to Account 920 and $9,837 was charged to Account 931.

(ao) Concept: OtherRegulatoryAssetsWrittenOffRecovered

In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No. ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations reflected in Administrative and General expense accounts should be excluded from the calculation of the wholesale transmission revenue requirement and charges under the wholesale formula rates, unless approved by the Commission. During the year ended December 31, 2025, environmental cost regulatory asset amortization of $264,080 was charged to Account 935.

(ap) Concept: OtherRegulatoryAssetsWrittenOffRecovered

In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No. ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations reflected in Administrative and General Expense accounts should be excluded from the calculation of the wholesale transmission revenue requirement and charges under the wholesale formula rates, unless approved by the Commission. During the year ended December 31, 2025, regulatory asset amortization associated with Washington's share of Equity Advisory Group for Clean Energy Implementation Plan costs of $239,935 was charged to Account 923.

(aq) Concept: OtherRegulatoryAssetsWrittenOffRecovered

In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No. ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations reflected in Administrative and General expense accounts should be excluded from the calculation of the wholesale transmission revenue requirement and charges under the wholesale formula rates, unless approved by the Commission. During the year ended December 31, 2025, regulatory asset amortiziation associated with Idaho's share of deferred insurance premiums of $6,078,099 was charged to Account 925.

(ar) Concept: OtherRegulatoryAssetsWrittenOffRecovered

In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No. ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations reflected in Administrative and General expense accounts should be excluded from the calculation of the wholesale transmission revenue requirement and charges under the wholesale formula rates, unless approved by the Commission. During the year ended December 31, 2025, regulatory asset amortiziation associated with Oregon's share of deferred insurance premiums of $12,189,840 was charged to Account 925.

(as) Concept: OtherRegulatoryAssetsWrittenOffRecovered

In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No. ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations reflected in Administrative and General expense accounts should be excluded from the calculation of the wholesale transmission revenue requirement and charges under the wholesale formula rates, unless approved by the Commission. During the year ended December 31, 2025, regulatory asset amortiziation associated with Wyoming's share of deferred insurance premiums of $2,013,323 was charged to Account 925.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

MISCELLANEOUS DEFFERED DEBITS (Account 186)
Report below the particulars (details) called for concerning miscellaneous deferred debits. For any deferred debit being amortized, show period of amortization in column (a) Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by classes.
				CREDITS
Line No.	Description of Miscellaneous Deferred Debits (a)	Balance at Beginning of Year (b)	Debits (c)	Credits Account Charged (d)	Credits Amount (e)	Balance at End of Year (f)
1	Bogus Creek (Amortization Period: 41 years)	622,640		557	41,280	581,360
2	Point-to-Point Transmission Reservation Deposits	7,644,479	40,272	131	36,725	7,648,026
3	Hermiston Swap (Amortization Period: 40 years)	1,988,779		557	171,693	1,817,086
4	Lake Side Maintenance Prepaid	35,384,520	6,066,804	107	37,156,542	4,294,782
5	Lake Side 2 Maintenance Prepaid	7,751,697	7,920,562			15,672,259
6	Chehalis Maintenance Prepaid	21,468,460	6,082,982			27,551,442
7	Currant Creek Maintenance Prepaid	21,777,867	7,018,182			28,796,049
8	Seven Mile Hill Maintenance Prepaid	5,144,686	618,123	107	1,035,052	4,727,757
9	Seven Mile Hill II Maintenance Prepaid	800,472	121,752	107	20,670	901,554
10	Dunlap Ranch I Maintenance Prepaid	5,425,689	693,047	107	206,709	5,912,027
11	Ekola Flats Maintenance Prepaid	5,142,905	909,592	107	892,624	5,159,873
12	Foote Creek Maintenance Prepaid	1,485,359	267,442	107	534,211	1,218,590
13	Glenrock I Maintenance Prepaid	4,641,364	618,123	107	1,091,565	4,167,922
14	Glenrock III Maintenance Prepaid	1,844,544	121,752	107	222,525	1,743,771
15	Goodnoe Hills Maintenance Prepaid	4,460,750	392,589	107	800,893	4,052,446
16	High Plains Maintenance Prepaid	3,734,610	309,062	107	736,303	3,307,369
17	Leaning Juniper Maintenance Prepaid	5,008,518	627,489	107	485,917	5,150,090
18	Marengo Maintenance Prepaid	7,134,220	607,946	107	386,262	7,355,904
19	Marengo II Maintenance Prepaid	3,669,222	303,973	107	169,541	3,803,654
20	McFadden Ridge I Maintenance Prepaid	1,689,424	177,944			1,867,368
21	Pryor Mountain Maintenance Prepaid	6,989,330	1,468,893	107	2,564,407	5,893,816
22	Rolling Hills Maintenance Prepaid	4,265,594	618,123	107	696,508	4,187,209
23	TB Flats Maintenance Prepaid	2,262,338	3,823,739	107	2,922,069	3,164,008
24	Rock River Maintenance Prepaid			107	212,519	212,519
25	(a) Credit Agreement Costs	2,775,941	1,158,181	427, 431	1,114,698	2,819,424
26	PCRB Mode Conversion Costs	21,510		427	21,510
27	Deferred S-3 Shelf Registration Costs	135,670	48,825	181	62,729	121,766
28	Emission Reduction Credits	306,510				306,510
29	Sales of Electric Utility Facilities and Properties	66,308	373,361			439,669
30	(b) BPA Long-Term Transmission	3,702,790	134,398	131	886,621	2,950,567
31	Department of Energy Loan Program Office		946,124			946,124
32	Mortgage Modification		294,201			294,201
33	Other Deferred Charges	73,503	134,862	181	1,010	207,355
47	Miscellaneous Work in Progress
48	Deferred Regulatory Comm. Expenses (See pages 350 - 351)
49	TOTAL	167,419,699				156,847,459

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: DescriptionOfMiscellaneousDeferredDebits

The weighted average remaining life is approximately two years.

(b) Concept: DescriptionOfMiscellaneousDeferredDebits

Amortization period remaining is approximately four years.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Report the information called for below concerning the respondent�s accounting for deferred income taxes. At Other (Specify), include deferrals relating to other income and deductions.
Line No.	DescriptionOfAccumulatedDeferredIncomeTax Description and Location (a)	AccumulatedDeferredIncomeTaxes Balance at Beginning of Year (b)	AccumulatedDeferredIncomeTaxes Balance at End of Year (c)
1	Electric
2	Employee Benefits	48,632,066	47,806,883
3	State Carryfowards	87,765,765	80,725,849
4	Asset Retirement Obligations	102,515,279	125,051,682
5	Regulatory Liabilities	291,504,498	273,623,948
6	Loss Contingencies	356,084,999	287,570,077
7	Other Electric	81,244,774	104,346,517
8	Valuation Allowances	10,605,378	15,864,048
7	Other
8	TOTAL Electric (Enter Total of lines 2 thru 7)	957,142,003	903,260,908
9	Gas
15	Other
16	TOTAL Gas (Enter Total of lines 10 thru 15)
17.1	Other (Specify)
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	957,142,003	903,260,908

Notes

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

CAPITAL STOCKS (Account 201 and 204)
Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year. Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative. State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purpose of pledge.
Line No.	Class and Series of Stock and Name of Stock Series (a)	Number of Shares Authorized by Charter (b)	Par or Stated Value per Share (c)	Call Price at End of Year (d)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Shares (e)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Amount (f)	Held by Respondent As Reacquired Stock (Acct 217) Shares (g)	Held by Respondent As Reacquired Stock (Acct 217) Cost (h)	Held by Respondent In Sinking and Other Funds Shares (i)	Held by Respondent In Sinking and Other Funds Amount (j)
1	Common Stock (Account 201)
2	(a)(b)(c) Common Stock issued	750,000,000			357,060,915	3,417,945,896
6	Total	750,000,000			357,060,915	3,417,945,896
7	Preferred Stock (Account 204)
8	(d) Serial Preferred	350	1,000,000
9	Preferred Stock	16,000,000
15	Total	16,000,350

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: CapitalStockDescription

Berkshire Hathaway Energy Company indirectly owns all of the shares of PacifiCorp's outstanding common stock. Therefore, there is no public market for PacifiCorp's common stock.

(b) Concept: CapitalStockDescription

This class of stock is not redeemable.

Authorized and Unissued Capital Stock: Authorizations for the issuance of common stock are as follows: (a) Idaho Public Utilities Commission - Case No. PAC-E-06-7, Order No. 30099, dated July 7, 2006; (b) Oregon Public Utility Commission - Docket No. UF-4228, Order No. 06-417, dated July 17, 2006; and (c) Washington Utilities and Transportation Commission - Docket No. UE-060974, Order No. 1, dated June 28, 2006. PacifiCorp has regulatory approval from the aforementioned commissions for the issuance of an additional 30,000,000 shares of common stock out of the 750,000,000 authorized (357,060,915 outstanding) by PacifiCorp's articles of incorporation.

(d) Concept: CapitalStockDescription

On February 10, 2025, PacifiCorp effected a one-for-ten thousand reverse stock split ("Reverse Stock Split") of its Serial Preferred Stock. As a result of the Reverse Stock Split, every 10,000 shares of each of PacifiCorp's pre-reverse split Serial Preferred Stock were combined and reclassified into one share of Serial Preferred Stock, with a corresponding reduction in the number of authorized shares of Serial Preferred Stock from 3,500 thousand to 350 and change to stated value of $100 to $1,000,000 per share. No fractional shares were issued in connection with the Reverse Stock Split and shareholders who would have otherwise held a fractional share of Serial Preferred Stock received payment in cash. As a result, all issued and outstanding shares of PacifiCorp's preferred stock as of February 10, 2025, were held by PPW Holdings LLC. For further discussion, refer to Note 15 of Notes to Financial Statements in the Form No. 1.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

2026-04-14

Year/Period of Report

End of:

2025

Other Paid-in Capital
1. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change. Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation. Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class and series of stock to which related. Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210) - Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related. Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts.
Line No.	Item (a)	Amount (b)
1	DonationsReceivedFromStockholdersAbstract Donations Received from Stockholders (Account 208)
2	DonationsReceivedFromStockholders Beginning Balance Amount
3.1	IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders Increases (Decreases) from Sales of Donations Received from Stockholders
4	DonationsReceivedFromStockholders Ending Balance Amount
5	ReductionInParOrStatedValueOfCapitalStockAbstract Reduction in Par or Stated Value of Capital Stock (Account 209)
6	ReductionInParOrStatedValueOfCapitalStock Beginning Balance Amount
7.1	IncreasesDecreasesDueToReductionsInParOrStatedValueOfCapitalStock Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
8	ReductionInParOrStatedValueOfCapitalStock Ending Balance Amount
9	GainOrResaleOrCancellationOfReacquiredCapitalStockAbstract Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
10	GainOnResaleOrCancellationOfReacquiredCapitalStock Beginning Balance Amount
11.1	IncreasesDecreasesFromGainOrResaleOrCancellationOfReacquiredCapitalStock Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12	GainOnResaleOrCancellationOfReacquiredCapitalStock Ending Balance Amount
13	MiscellaneousPaidInCapitalAbstract Miscellaneous Paid-In Capital (Account 211)
14	MiscellaneousPaidInCapital Beginning Balance Amount	(a) 1,102,063,956
15	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital
16	MiscellaneousPaidInCapital Ending Balance Amount	1,102,063,956
17	OtherPaidInCapitalAbstract Other Paid in Capital
18	OtherPaidInCapitalDetail Beginning Balance Amount
19.1	IncreasesDecreasesInOtherPaidInCapital Increases (Decreases) in Other Paid-In Capital
20	OtherPaidInCapitalDetail Ending Balance Amount
40	OtherPaidInCapital Total	1,102,063,956

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

2026-04-14

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: MiscellaneousPaidInCapital


Miscellaneous Paid-In Capital (Account 211):
Share based payments (1)									1,973,218
Tax benefit from stock option exercises (2)									14,422,979
Benefit plan separation (3)									(3,575,760)
Capital contributions (4)									1,089,950,000
Gain on sale of ScottishPower plc stock (5)									136,208
Qualified production activity tax deduction (6)									(1,275,241)
Contribution of Intermountain Geothermal Company (7)									432,552
Total Miscellaneous Paid-In Capital (Account 211)									1,102,063,956

(1) Represents the fair value of stock options granted by ScottishPower plc for which certain performance measures were met in March 2005. These options became fully vested in May 2005.
(2) Represents the income tax deduction attributable to the exercise of stock options granted by ScottishPower plc.
(3) Represents the effect of transferring certain benefit plan obligations and assets to PPM Energy, Inc. as a result of the sale of PacifiCorp by ScottishPower plc.
(4) Represents capital contributions to PacifiCorp (with no shares of stock issued) from its indirect parent Berkshire Hathaway Energy Company ("BHE"). During the year being reported, no capital contributions were made by BHE to PacifiCorp.
(5) Represents a realized gain on stock related to separation of PPM Energy, Inc. participants from the deferred compensation plan, which invested in ScottishPower plc stock.
(6) Represents amounts associated with Internal Revenue Code Section 199 qualified production activities.
(7) Represents contribution of Intermountain Geothermal Company to PacifiCorp from BHE in March 2006, subsequent to the sale of PacifiCorp to BHE. Intermountain Geothermal Company was merged with and its direct parent, PacifiCorp, on August 31, 2007, with PacifiCorp surviving.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

CAPITAL STOCK EXPENSE (Account 214)
Report the balance at end of the year of discount on capital stock for each class and series of capital stock. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line No.	NameOfClassAndSeriesOfStock Class and Series of Stock (a)	CapitalStockExpense Balance at End of Year (b)
1	Common Stock	41,101,061
22	TOTAL	41,101,061

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

LONG-TERM DEBT (Account 221, 222, 223 and 224)
Report by Balance Sheet Account the details concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other Long-Term Debt. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds, and in column (b) include the related account number. For Advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received, and in column (b) include the related account number. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued, and in column (b) include the related account number. In a supplemental statement, give explanatory details for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a)principal advanced during year (b) interest added to principal amount, and (c) principal repaid during year. Give Commission authorization numbers and dates. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (m). Explain in a footnote any difference between the total of column (m) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line No.	ClassAndSeriesOfObligationCouponRateDescription Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates) (a)	RelatedAccountNumber Related Account Number (b)	Principal Amount of Debt Issued (c)	LongTermDebtIssuanceExpensePremiumOrDiscount Total Expense, Premium or Discount (d)	LongTermDebtIssuanceExpenses Total Expense (e)	LongTermDebtPremium Total Premium (f)	LongTermDebtDiscount Total Discount (g)	NominalDateOfIssue Nominal Date of Issue (h)	DateOfMaturity Date of Maturity (i)	AmortizationPeriodStartDate AMORTIZATION PERIOD Date From (j)	AmortizationPeriodEndDate AMORTIZATION PERIOD Date To (k)	Outstanding (Total amount outstanding without reduction for amounts held by respondent) (l)	Interest for Year Amount (m)
1	Bonds (Account 221)
2	First Mortgage Bonds: 3.35% Series due 2025		250,000,000		2,121,421		320,000	06/19/2015	07/01/2025	06/19/2015	07/01/2025		4,187,500
3	First Mortgage Bonds: 3.50% Series due 2029		400,000,000		2,134,659		740,000	03/01/2019	06/15/2029	03/01/2019	06/15/2029	400,000,000	14,000,000
4	First Mortgage Bonds: 2.70% Series due 2030		400,000,000		2,156,791		720,000	04/08/2020	09/15/2030	04/08/2020	09/15/2030	400,000,000	10,800,000
5	First Mortgage Bonds: 7.70% Series due 2031		300,000,000		2,874,150		864,000	11/21/2001	11/15/2031	11/21/2001	11/15/2031	300,000,000	23,100,000
6	First Mortgage Bonds: 5.90% Series due 2034		200,000,000		1,892,365		722,000	08/19/2004	08/15/2034	08/19/2004	08/15/2034	200,000,000	11,800,000
7	First Mortgage Bonds: 5.25% Series due 2035		300,000,000		2,912,021		1,080,000	06/13/2005	06/15/2035	06/13/2005	06/15/2035	300,000,000	15,750,000
8	First Mortgage Bonds: 6.10% Series due 2036		350,000,000		2,907,881		1,141,000	08/10/2006	08/01/2036	08/10/2006	08/01/2036	350,000,000	21,350,000
9	First Mortgage Bonds: 5.75% Series due 2037		600,000,000		589,216		24,000	03/14/2007	04/01/2037	03/14/2007	04/01/2037	600,000,000	34,500,000
10	First Mortgage Bonds: 6.25% Series due 2037		600,000,000		5,127,281		750,000	10/03/2007	10/15/2037	10/03/2007	10/15/2037	600,000,000	37,500,000
11	First Mortgage Bonds: 6.35% Series due 2038		300,000,000		2,290,333		1,671,000	07/17/2008	07/15/2038	07/17/2008	07/15/2038	300,000,000	19,050,000
12	First Mortgage Bonds: 6.00% Series due 2039		650,000,000		6,134,687		6,175,000	01/08/2009	01/15/2039	01/08/2009	01/15/2039	650,000,000	39,000,000
13	First Mortgage Bonds: 4.10% Series due 2042		300,000,000		2,737,911		987,000	01/06/2012	02/01/2042	01/06/2012	02/01/2042	300,000,000	12,300,000
14	First Mortgage Bonds: 4.125% Series due 2049		600,000,000		5,640,085		1,344,000	07/13/2018	01/15/2049	07/13/2018	01/15/2049	600,000,000	24,750,000
15	First Mortgage Bonds: 4.15% Series due 2050		600,000,000		5,149,489		2,790,000	03/01/2019	02/15/2050	03/01/2019	02/15/2050	600,000,000	24,900,000
16	First Mortgage Bonds: 3.30% Series due 2051		600,000,000		5,183,937		4,944,000	04/08/2020	03/15/2051	04/08/2020	03/15/2051	600,000,000	19,800,000
17	First Mortgage Bonds: 2.90% Series due 2052		1,000,000,000		8,390,124		7,670,000	07/09/2021	06/15/2052	07/09/2021	06/15/2052	1,000,000,000	29,000,000
18	First Mortgage Bonds: 5.35% Series due 2053		1,100,000,000		9,208,626		3,300,000	12/01/2022	12/01/2053	12/01/2022	12/01/2053	1,100,000,000	58,850,000
19	First Mortgage Bonds: 5.50% Series due 2054		1,200,000,000		9,133,192		528,000	05/17/2023	05/15/2054	05/17/2023	05/15/2054	1,200,000,000	66,000,000
20	First Mortgage Bonds: 5.10% Series due 2029		500,000,000		2,367,458		155,000	01/05/2024	02/15/2029	01/05/2024	02/15/2029	500,000,000	25,500,000
21	First Mortgage Bonds: 5.30% Series due 2031		700,000,000		3,662,442		1,211,000	01/05/2024	02/15/2031	01/05/2024	02/15/2031	700,000,000	37,100,000
22	First Mortgage Bonds: 5.45% Series due 2034		1,100,000,000		6,302,408		1,969,000	01/05/2024	02/15/2034	01/05/2024	02/15/2034	1,100,000,000	59,950,000
23	First Mortgage Bonds: 5.80% Series due 2055		1,500,000,000		13,467,375		9,015,000	01/05/2024	01/15/2055	01/05/2024	01/15/2055	1,500,000,000	87,000,000
24	Secured Medium-Term Notes: 6.71% Series G due 2026		100,000,000		904,467			01/23/1996	01/15/2026	01/23/1996	01/15/2026	100,000,000	6,710,000
25	(a) Environment Improvement Revenue Bonds - Secured: Converse County, WY, Series 1995		5,300,000		132,043			11/17/1995	11/01/2025	11/17/1995	11/01/2025		162,262
26	(b) Environment Improvement Revenue Bonds - Secured: Lincoln County, WY, Series 1995		22,000,000		404,262			11/17/1995	11/01/2025	11/17/1995	11/01/2025		628,759
27	Environment Improvement Revenue Bonds - Unsecured: Sweetwater County, WY, Series 1995		24,400,000		225,000			12/14/1995	11/01/2025	12/14/1995	11/01/2025		651,605
28	Subtotal		13,701,700,000		104,049,624		48,120,000					13,400,000,000	684,340,126
29	Reacquired Bonds (Account 222)
30
31
32
33	Subtotal
34	Advances from Associated Companies (Account 223)
35
36
37
38	Subtotal
39	Other Long Term Debt (Account 224)
40	(c) Junior Subordinated Debt		850,000,000		9,054,996			03/20/2025	09/15/2055	03/20/2025	09/15/2055	850,000,000	48,931,076
41	(d) Long-term debt authorized but unissued
42	Subtotal		850,000,000		9,054,996							850,000,000	48,931,076
33	TOTAL		14,551,700,000	161,224,620								14,250,000,000	(e) 733,271,202

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: ClassAndSeriesOfObligationCouponRateDescription

Secured by pledged first mortgage bonds registered to and held by the pollution control bond trustee generally with the same interest rates, maturity dates and redemption provisions as the pollution control bond obligations.

(b) Concept: ClassAndSeriesOfObligationCouponRateDescription

In March 2025, PacifiCorp issued $850 million of its 7.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due September 2055. State commission authorizations for these issuances were as follows: (a) OPUC � Docket No. UF-4354(1), Order No. 24-240, dated July 24, 2024; and (b) IPUC � Case No. PAC-E-24-03, Order 36136, dated April 12, 2024, effective through April 12, 2029.

(d) Concept: ClassAndSeriesOfObligationCouponRateDescription

As of December 31, 2025, PacifiCorp had regulatory authority from the Oregon Public Utility Commisson and the Idaho Public Utilities Commission to issue an additional $4.15 billion of long-term debt. PacifiCorp must make a notice filing with the Washington Utilities and Transportation Commission prior to any future issuance. In addition, as of December 31, 2025, PacifiCorp had an effective shelf registration statement filed with the United States Securities and Exchange Commission to issue an indeterminate amount of first mortgage bonds and unsecured debt securities through July 2027. For further information, refer to Item 6 in Important Changes During the Year in this Form No. 1.

(e) Concept: InterestExpenseOnLongTermDebtIssued

Amount represents interest expense charged to Account 427, Interest on long-term debt, and does not include any amount charged to Account 430, Interest on debt to associated companies, as all such interest was accrued on amounts included in Account 233, Notes payable to associated companies during the year. Difference of $12,194 between Account 427 and this Page 256 is due to interest expense reimbursed to PacifiCorp in 2025 on Emery County Pollution Control Revenue Bonds that matured in 2024.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be filed, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members. A substitute page, designed to meet a particular need of a company, may be used as long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line No.	Particulars (Details) (a)	Amount (b)
1	Net Income for the Year (Page 117)	640,140,656
2	Reconciling Items for the Year
3
4	Taxable Income Not Reported on Books
5	Allowance for Accounts Receivable	3,376,715
6	Contribution in Aid of Construction	362,016,078
7	Regulatory Asset - Alt Rate for Energy Program (CARE) - CA	17,551
8	Regulatory Asset - BPA Balancing Account - ID	429,953
9	Regulatory Asset - BPA Balancing Account - WA	1,329,891
10	Regulatory Asset - Deferred Excess RECs in Rates - WY	339,225
11	Regulatory Liability - BPA Balancing Account - ID	264,406
12	Regulatory Liability - BPA Balancing Account - OR	2,596,558
13	Regulatory Liability - BPA Balancing Account - WA	52,329
14	Regulatory Liability - Bridger Accelerated Depreciation - OR	3,818,882
15	Regulatory Liability - Bridger Accelerated Depreciation - WA	1,986,017
16	Regulatory Liability - California Greenhouse Gas Allowance Compliance	5,420,377
17	Regulatory Liability - Deferred Excess RECs in Rates - UT	7,364,569
18	Regulatory Liability - Deferred Excess RECs in Rates - WY	1,686,661
19	Regulatory Liability - Deferred Revenue - OR	13,758,144
20	Regulatory Liability - Gain on Sale of Assets - OR	442,581
21	Regulatory Liability - Plant Closure Cost - CA	634,367
22	Regulatory Liability - Plant Closure Cost - OR	1,346,558
23	Regulatory Liability - Plant Closure Cost - WA	1,355,736
24	Regulatory Liability - Renewable Portfolio Standards Compliance - OR	329,287
25	Regulatory Liability - Sale of REC - ID	1,301,882
26	Regulatory Liability - Utah Home Energy Lifeline	62,054
27	Regulatory Liability - WA Low Energy Program	2,013,420
28	Regulatory Liability - WA Rate Refunds	1,530,698
29	Regulatory Liability - WBA Deferred Revenue - UT	12,122,412
30	Unearned Joint Use Pole Contact Revenue	2,584,911
9	Deductions Recorded on Books Not Deducted for Return
10	Fed/State Tax Expense-Interest	3,096
11	Accrued Royalties	1,671
12	Accrued Severance	92,092
13	Accrued Vacation	2,619,302
14	Avoided Costs	168,524,142
15	Book Depreciation	1,221,469,711
16	Book Depreciation Allocated to Medicare and M&E	128,025
17	Capitalization of Test Energy	1,805,813
18	Capitalized labor and benefit costs	2,975,265
19	Company Plane	61,344
20	Deferred Revenue - Other	52,441,689
21	Employee Remuneration - Section 162(m) Limitation	3,240,828
22	Environmental Liability - Regulated	5,724,554
23	Hermiston Swap	171,693
24	Hydro Relicensing Obligation	1,424,361
25	Income Tax Interest	270
26	Inventory Reserve	150,859
27	Lobbying Expenses	1,732,633
28	Long Term Incentive Plan Mark to Market Gain/Loss	531,791
29	Meals and Entertainment	1,535,990
30	Nondeductible Fringe Benefits	129,241
31	Nondeductible Parking Costs	296,767
32	Oregon Regulatory Asset/Regulatory Liability Consolidation	6,201
33	Penalties	1,330,849
34	Property Insurance Reserve - ID	70,873
35	Property Insurance Reserve - UT	1,506,393
36	Property Insurance Reserve � WA	288,787
37	Property Insurance Reserve - WY	139,214
38	Regulatory Asset - Carbon Plant Decommissioning/Inventory	179,487
39	Regulatory Asset - Carbon Plant Deferred Depreciation - UT	18,736,786
40	Regulatory Asset - Cedar Springs II - OR	113,785
41	Regulatory Asset - Cholla U4 Closure	5,885,043
42	Regulatory Asset - Covid-19 Bill Assist Program - OR	3,403,918
43	Regulatory Asset - Covid-19 Bill Assist Program - WA	775,331
44	Regulatory Asset - Deferred Excess NPC - CA	7,579,347
45	Regulatory Asset - Deferred Excess NPC - ID	36,520,998
46	Regulatory Asset - Deferred Excess NPC - OR	102,045,694
47	Regulatory Asset - Deferred Excess NPC - UT	257,113,245
48	Regulatory Asset - Deferred Excess NPC - WA	90,587,155
49	Regulatory Asset - Deferred Excess NPC - WY	84,041,528
50	Regulatory Asset - Deferred Insurance Premiums - ID	2,378,251
51	Regulatory Asset - Deferred Insurance Premiums - OR	10,913,677
52	Regulatory Asset - Deferred Intervenor Funding Grants - OR	2,240,848
53	Regulatory Asset - Deferred Overburden Costs - ID	84,392
54	Regulatory Asset - Deferred Overburden Costs - WY	18,744
55	Regulatory Asset - Depreciation Increase - ID	3,485,076
56	Regulatory Asset - Depreciation Increase - UT	128,043
57	Regulatory Asset - Depreciation Increase - WY	442,191
58	Regulatory Asset - Emergency Service Program-Battery Storage-CA	11,334
59	Regulatory Asset - Environmental Costs - WA	594,474
60	Regulatory Asset - FAS 158 Pension Liability	5,156,724
61	Regulatory Asset - Generating Plant Liquidation Damages - WY	5,708
62	Regulatory Asset - Generating Plant Liquidated Damages - UT	35,000
63	Regulatory Asset - Goodnoe Hills Settlement - WY	21,250
64	Regulatory Asset - GRC Memo Account - CA	5,813,874
65	Regulatory Asset - Idaho RTM	908,201
66	Regulatory Asset - Klamath Unrecovered Plant	1,198,289
67	Regulatory Asset - Lake Side Settlement - WY	27,331
68	Regulatory Asset - Low-Carbon Energy Standards - WY	557,412
69	Regulatory Asset - Major Maintenance Expense Colstrip - WA	64,726
70	Regulatory Asset - Meters Replaced by AMI - OR	3,980,103
71	Regulatory Asset - Mobile Home Park Conversion - CA	13,031
72	Regulatory Asset - Pension Settlement - CA	32,133
73	Regulatory Asset - Pension Settlement - OR	585,171
74	Regulatory Asset - Pension Settlement - WA	235,766
75	Regulatory Asset - Pension Settlement - WY	270,217
76	Regulatory Asset - Post Merger Loss - Reacquired Debt	243,149
77	Regulatory Asset - Solar Feed-In Tariff Deferral - OR	52,556
78	Regulatory Asset - TB Flats - OR	3,067,179
79	Regulatory Asset - Transportation Electrification Pilot - CA	11,551
80	Regulatory Asset - Transportation Electrification Pilot - OR	1,372,031
81	Regulatory Asset - Transportation Electrification Pilot - WA	17,507
82	Regulatory Asset - Subscriber Solar Program - Utah	104,473
83	Regulatory Asset - Utah Mine Disposition	3,200,042
84	Regulatory Asset - Utility Community Advisory Group - OR	310,438
85	Regulatory Asset - Wildfire Damaged Asset - OR	1,748,765
86	Regulatory Asset - Wildfire Mitigation - OR	30,490,272
87	Regulatory Asset - Wildland Fire Protection - UT	4,752,080
88	Regulatory Asset - Wind Test Energy Deferral - WY	7,644
89	Reimbursements	3,493,674
90	Regulatory Liability - ARO/Reg Diff - Trojan - WA Portion	25,634
91	Regulatory Liability - Blue Sky - ID	19,449
92	Regulatory Liability - Blue Sky - WA	46,521
93	Regulatory Liability - Blue Sky - WY	45,301
94	Regulatory Liability - Klamath River Dams Removal	381
95	Regulatory Liability - Clean Fuels Program - OR	2,664,170
96	Regulatory Liability - OR Energy Conservation Charge	1,321,649
97	Regulatory Liability - OR Sch 291 Rate Clearing	29,444
98	Regulatory Liability - Pension Settlement - UT	1,046,635
99	Regulatory Liability - Steam Decommissioning - CA	742,672
100	Regulatory Liability - Steam Decommissioning - OR	2,141,452
101	Regulatory Liability - Steam Decommissioning - WA	3,569,616
102	Regulatory Liability - Steam Decommissioning - ID	2,370,635
103	Regulatory Liability - Steam Decommissioning - UT	17,053,629
104	Regulatory Liability - Steam Decommissioning - WY	5,668,840
105	Regulatory Liability - Utility Bill Assistance - UT	160,326
106	ROU Asset (Operating Leases)	1,638,837
107	Trapper Mine Contract Obligation	293,093
108	Utah Disallowed Loss	15,033,941
109	Intercompany Adjustment	4,936,040
14	Income Recorded on Books Not Included in Return
15	Book Fixed Asset Gain/Loss	11,727,714
16	Dividend Received Deduction - Deferred Compensation	73,129
17	Equity AFUDC	119,558,787
18	MCI F.O.G. Wire Lease	1,056
19	Officer's Life Insurance	9,531,747
20	Regulatory Asset - Electric Vehicle Infrastructure - CA	35,593
21	Regulatory Asset - REC Sales Deferral - UT - Noncurrent	1,913,578
22	Regulatory Asset - WA Decoupling Mechanism	7,847,527
23	Regulatory Liability - Excess Income Tax Deferral-WA	3,555,537
24	Regulatory Liability - OR Direct Access 5 Year Opt Out	1,757,233
25	Regulatory Liability - Sale of REC - WA	53,656
26	Regulatory Liability - WA Decoupling Mechanism	3,505,123
27	Transmission Service Deposit	3,170,043
28	Trapper Mining Stock Basis	1,482,090
29	Equity Earnings in Subsidiaries	11,357,123
30	Fed/State Tax Expense / (Benefit)	195,631,155
19	Deductions on Return Not Charged Against Book Income
20	Accrued Final Reclamation	245,900
21	Basis Intangible Difference	577,172
22	Bear River Settlement Agreement	305,886
23	Capitalized Depreciation	11,711,637
24	Contra Receivable from Joint Owners	36,506
25	Cost of Removal	136,812,118
26	CWIP Reserve	5,185,754
27	Debt AFUDC	90,963,119
28	Deferred Compensation Mark to Market Gain / Loss	820,005
29	Deferred Compensation	651,562
30	Dividend Deduction at 50%	19
31	Environmental Liability - Non-regulated	25,149
32	FAS 112 Book Reserve - Postemployment Benefits	107,008
33	FAS 158 Pension Asset	9,803,256
34	FAS 158 Post-retirement Asset	576,058
35	FAS 158 SERP Liability	1,694,452
36	Federal Tax Depreciation	1,586,073,080
37	Federal Tax Fixed Asset Gain/Loss	8,020,012
38	Fuel Cost Adjustment	1,369,916
39	Injuries and Damages Accrual, net of Insurance Reserves	278,667,739
40	Injuries & Damages Reserve - OR	366,181
41	Joint Owner Receivable in Dispute	1,313,074
42	Lease Depreciation - Timing Difference	1,101,592
43	Lewis River Settlement Agreement	301,016
44	Long Term Incentive Plan	3,715,041
45	Miscellaneous Current and Accrued Liability	163,374
46	N Umpqua Settlement Agreement	823,955
47	Operating Leases (Liability)	1,691,789
48	Pension/Retirement Accrual	342,453
49	Prepaid - FSA O& M - East	499,271
50	Prepaid - FSA O& M - West	62,749
51	Prepaid Aircraft Maintenance	26,217
52	Prepaid Membership Fees	39,991
53	Prepaid Surety Bond	310,288
54	Prepaid Taxes - ID PUC	65,474
55	Prepaid Taxes - OR PUC	213,764
56	Prepaid Taxes - Property Taxes	2,143,886
57	Prepaid Taxes - UT PUC	340,506
58	Property Insurance Reserve - CA	1,307,265
59	Property Insurance Reserve - OR	7,061,085
60	Regulatory Asset - CA Greenhouse Gas Allowance Compliance	10,514,424
61	Regulatory Asset - Catastrophic Event Deferral - CA	1,731
62	Regulatory Asset - Community Solar - OR	1,524,752
63	Regulatory Asset - Deferred Independent Evaluator Fees - OR	10,090
64	Regulatory Asset - Deferred Insurance Premiums - WY	9,986,677
65	Regulatory Asset - Deferred Intervenor Funding - WA	148,240
66	Regulatory Asset - Deferred Intervenor Funding Grants - CA	26,660
67	Regulatory Asset - Deferred Intervenor Funding Grants - ID	17,247
68	Regulatory Asset/Liability - Demand Side Management	105,172,796
69	Regulatory Asset - Electric Vehicle Charging Infrastructure - UT	3,989,378
70	Regulatory Asset - Environmental Costs	13,755,758
71	Regulatory Asset - Equity Advisory Group - WA	255,538
72	Regulatory Asset - FAS 158 Post Retirement Liability	1,399,827
73	Regulatory Asset - Fire Risk Mitigation - CA	21,052,839
74	Regulatory Asset - Klamath Unrecovered Plant - OR	16,909
75	Regulatory Asset - Low Income Bill Discount - OR	2,471,753
76	Regulatory Asset - North Temple Office Property Transfer Deferral	3,802,684
77	Regulatory Asset - Post Employment Costs	2,755,560
78	Regulatory Asset - Renewable Adjustment Clause - OR	1,469,964
79	Regulatory Asset - Rock Creek II Deferral - ID	544,557
80	Regulatory Asset - WBA GRC Deferral - UT	2,265,948
81	Repairs Deduction	207,820,220
82	Reserve for Bad Debts	2,055,510
83	Regulatory Liability - Blue Sky - CA	66,177
84	Regulatory Liability - Blue Sky - OR	447,649
85	Regulatory Liability - Blue Sky - UT	158,645
86	Regulatory Liability - Cholla Plant Unit No. 4 Decommissioning - CA	12,311
87	Regulatory Liability - Cholla Plant Unit No. 4 Closure & Decommissioning Costs - ID	506,366
88	Regulatory Liability - Cholla Plant Unit No. 4 Decommissioning - OR	2,229,382
89	Regulatory Liability - Cholla Plant Unit No. 4 Decommissioning - UT	3,769,900
90	Regulatory Liability - Cholla Plant Unit No. 4 Decommissioning - WY	635,664
91	Regulatory Liability - California Energy Savings Assistance	491,874
92	Regulatory Liability - FAS 158 Post Retirement	1,511,961
93	Regulatory Liability - FERC Formula Rate True-Up	21,258,723
94	Regulatory Liability - Fly Ash - WA	1,667,788
95	Rogue River - Habitat Enhancement Liability	68,831
96	Trojan Decommissioning	289,985
97	Tax Depletion-SRC	51,162
98	Tax Percentage Depletion - Blundell Steam Field	588,287
99	Wasatch Workers Comp Reserve	271,408
100	Western Coal Carrier Retiree Medical Accrual	27,657
101	State Tax Deductions	17,503,841
27	Federal Tax Net Income	321,236,198
28	Show Computation of Tax:
29	Federal Income Tax at 21.00%	67,459,602
30	Provision to Return Adjustment	817,610
31	Tax Reserve Changes	37,040
32	Renewable Energy Production Tax Credits	240,159,123
33	Other Federal Tax Credits	239,818
34	(a) Federal Income Tax Accrual	172,084,689

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: ComputationOfTaxDescription


Berkshire Hathaway Inc. includes PacifiCorp in its United States Federal Income Tax Return. PacifiCorp's provision for income taxes has been computed on a stand-alone basis.
Names of group members who will file a consolidated United States Federal Income Tax Return:
Under Berkshire Hathaway Energy Company ("BHE"):

PPW Holdings LLC Sub-Group:
PacifiCorp
PPW Holdings LLC

PacifiCorp Sub-Group:
Energy West Mining Company
Pacific Minerals, Inc.

BHE Sub-Group:
ABA Management, L.L.C.	Elmore Company	MidAmerican Energy Company
AC Eagle Corporation	Elmore North Geothermal LLC	MidAmerican Energy Services, LLC
AC Palm Desert Corporation	Energy West Mining Company	MidAmerican Funding, LLC
AC2015 Corporation	Esslinger-Wooten-Maxwell, Inc.	MidAmerican Geothermal Development Corporation
Aeronavis, LLC	E-W-M Referral Services, Inc.	MidAmerican Wind Tax Equity Holdings, LLC
Alamo 6 Solar Holdings, LLC	F&R/T LLC	Midcontinent Grid Solutions Holdco, LLC
Alamo 6, LLC	Falcon Power Operating Company	Midland Escrow Services, Inc.
Alaska Gas Transmission Company, LLC	First Network Realty, Inc.	Mid-States Title Insurance Agency, LLC
Alliance Title Group, LLC	First Realty, Ltd.	Midwest Capital Group, Inc.
Ambassador Real Estate Company	First Weber Illinois, LLC	Midwest Power Transmission Iowa, LLC
American Eagle Referral Service, LLC	First Weber Referral Associates, Inc.	Midwest Power Transmission Texas, LLC
Americana Arizona Referrals, LLC	First Weber, Inc.	Midwest Preferred Realty, Inc.
Americana Arizona, LLC	Fishlake Power LLC	Midwest Realty Ventures, LLC
Americana, L.L.C.	Flat Top Holdings, LLC	Modular LNG Holdings, Inc.
ARE Commercial Real Estate, LLC	Flat Top Wind I, LLC	Montana Alberta Tie LP Inc.
ARE Iowa, LLC	Florida Network LLC	Montana Alberta Tie US Holdings GP Inc.
Arizona HomeServices, L.L.C.	Florida Network Property Management, LLC	Morton Bay Geothermal LLC
Attorneys Title Holdings, Incorporated	Fluvanna Holdings 2, LLC	MTL Canyon Holdings, LLC
BDFH, Inc.	Fluvanna Wind Energy 2, LLC	Nebraska Referral, Inc.
Beach Properties of Florida, LLC	For Rent, Inc.	Nevada Electric Investment Company
Bennion & Deville Fine Homes, Inc.	Fort Dearborn Land Title Company, LLC	Nevada Power Company
Berkshire Hathaway Energy Company	FR Mariah Holdings II, LLC	Niche Storage Solutions, LLC
BH2H Holdings, LLC	FRTC, LLC	NNGC Acquisition, LLC
BHE AC Holding, LLC	Geronimo Community Solar Gardens Holding Company, LLC	Northeast Referral Group, LLC
BHE America Transco, LLC	Geronimo Community Solar Gardens, LLC	Northern Machining and Fabrication, LLC


BHE B Tax Equity Holdings, LLC	Gibraltar Title Services, LLC	Northern Natural Gas Company
BHE B2H, LLC	Glacier Balancing Authority Services, LLC	Northrop Realty, LLC
BHE Canada, LLC	Glacier Wind 1, LLC	NRS Referral Services, LLC
BHE Community Solar, LLC	Glacier Wind 2, LLC	NV Energy, Inc.
BHE Compression Services, LLC	GPWH Holdings, LLC	NVE Holdings, LLC
BHE CS Holdings, LLC	Grande Prairie Land Holding, LLC	NVE Insurance Company, Inc.
BHE Gas, Inc.	Grande Prairie Wind Holdings, LLC	NW Referral Services, LLC
BHE Geothermal, LLC	Grande Prairie Wind II, LLC	Pacific Minerals, Inc.
BHE GT&S, LLC	Grande Prairie Wind, LLC	PacifiCorp
BHE Hydro, LLC	Greater Metro, LLC	PCRE, L.L.C.
BHE Infrastructure Group, LLC	Guarantee Real Estate	PHM Holdings, LLC
BHE Infrastructure Services, LLC	Hegg Limited Referral Company, LLC	Pickford Escrow Company, Inc.
BHE Investment Group LLC	HEGG Realtors Iowa, Inc.	Pickford Holdings LLC
BHE Montana, LLC	HEGG, Realtors Inc.	Pickford Real Estate, Inc.
BHE Pearl Solar Holdings, LLC	HL Commercial Group, LLC	Pickford Services Company
BHE Pearl Solar, LLC	HN Real Estate Group, L.L.C.	Pilot Butte, LLC
BHE Pipeline Group, LLC	HN Referral Corporation	Pinyon Pines Funding, LLC
BHE Ravenswood, LLC	HomeServices Insurance, Inc.	Pinyon Pines I Holding Company, LLC
BHE Renewables, LLC	HomeServices KOI, Inc.	Pinyon Pines II Holding Company, LLC
BHE Solar, LLC	HomeServices Lending, LLC	Pinyon Pines Projects Holding, LLC
BHE Texas Transco, LLC	HomeServices MidAtlantic, LLC	Pinyon Pines Wind I, LLC
BHE Turbomachinery, LLC	HomeServices Northeast, LLC	Pinyon Pines Wind II, LLC
BHE U.K. Electric, Inc.	HomeServices of Alabama, Inc.	Pivotal JAX LNG, LLC
BHE U.K. Inc.	HomeServices of America, Inc	Pivotal LNG, LLC
BHE U.K. Power, Inc.	HomeServices of Arizona, LLC	PNJP, LLC
BHE U.S. Transmission, LLC	HomeServices of California, LLC	PNW Referral, LLC
BHE Wind, LLC	HomeServices of Colorado, LLC	Power Watch, LLC
BHE WV Holdings, LLC	HomeServices of Florida, Inc.	PPW Holdings LLC
BHE WV Renewables, LLC	HomeServices of Georgia, LLC	Preferred Carolinas Realty, Inc.
BHER Flat Top Wind Holdings, LLC	HomeServices of Illinois Holdings, LLC	Prime Alliance Real Estate Services, LLC
BHER Gopher Wind Holdings, LLC	HomeServices of Illinois, LLC	Priority Title Corporation
BHER Independence Wind Holdco, LLC	HomeServices of Iowa, Inc.	PRL Solar, LLC
BHER IWE Holdco, LLC	HomeServices of Kentucky Real Estate Academy, LLC	Property Services Northeast, LLC
BHER Mariah Wind Holdings LLC	HomeServices of Minnesota, LLC	Prosperity Home Mortgage, LLC
BHER Market Operations, LLC	HomeServices of MOKAN, LLC	Pru-One, Inc.
BHER Minerals, LLC	HomeServices of Nebraska, Inc.	Real Estate Knowledge Services, LLC
BHER Operating Company, LLC	HomeServices of Nevada, LLC	Real Living Real Estate, LLC
BHER Power Resources, Inc.	HomeServices of New York, LLC	Reece & Nichols Alliance, Inc.
BHER Ravenswood Solar 1, LLC	HomeServices of Oregon, LLC	Reece & Nichols Realtors, Inc.
BHER Rio Bravo Wind Holdings, LLC	HomeServices of the Carolinas, Inc.	Reece Commercial, Inc.
BHER San Vicente Holdings LLC	HomeServices of Washington, LLC	Referral Associates of Georgia, LLC
BHER Santa Rita Holdings, LLC	HomeServices of Wisconsin, LLC	Referral Network of IL, LLC


BHER Santa Rita Investment, LLC	HomeServices Partnership Group, LLC	Renewable Development Ventures LLC
BHER TL Tech, LLC	HomeServices Property Management, LLC	REV LNG SSL BC LLC
BHER Willows Solar, LLC	HomeServices Referral Network, LLC	RGS Title, LLC
BHER WV Solar, LLC	HomeServices Relocation, LLC	RHL Referral Company, L.L.C.
BHER WV Wind, LLC	HomeServices Title Holdings, LLC	Rim Rock Wind, LLC
BHER-Kiewit SVESF LLC	Houlihan Lawrence Associates, LLC	Rio Bravo Wind Holdings LLC
BHES CSG Holdings, LLC	Houlihan/Lawrence, Inc.	Rio Bravo Windpower, LLC
BHES Pearl Solar Holdings, LLC	HS Franchise Holding, LLC	Roberts Brothers, Inc.
BHH Affiliates, LLC	HSF Affiliates LLC	Roy H. Long Realty Company, Inc.
BHH Iowa Affiliates, LLC	HSGA Real Estate Group, L.L.C.	S.W. Hydro, Inc.
Bishop Hill Energy II LLC	HSN Holdings, LLC	Sage Title Group, LLC
Bishop Hill II Holdings, LLC	HSNV Title Holding, LLC	Salton Sea Power Company
Black Rock Geothermal LLC	HSTX Title, LLC	Salton Sea Power Generation Company
BPFLA Referrals, LLC	HSW Affiliates Holding, LLC	Salton Sea Power L.L.C.
CalEnergy Company, Inc.	IES Holding II, LLC	Santa Rita Wind Energy LLC
CalEnergy Generation Operating Company	Imperial Magma LLC	Saranac Energy Company, Inc.
CalEnergy Geothermal Holding, LLC	Independence Wind Energy LLC	Sequoia Aviation Corporation
CalEnergy International Services, Inc.	Insight Home Inspections, LLC	Shared Success Center, LLC
CalEnergy Minerals LLC	Intero Franchise Services, Inc.	Sierra Gas Holdings Company
CalEnergy Operating Corporation	Intero Nevada, LLC	Sierra Pacific Power Company
CalEnergy Pacific Holdings Corp.	Intero Real Estate Holdings, Inc.	Silver State Property Holdings, LLC
CalEnergy YCA Partner 2, LLC	Intero Real Estate Services, Inc.	SoCal Services & Property Management
CalEnergy, LLC	Intero Referral Services, Inc.	Solar San Antonio LLC
California Energy Development Corporation	Iowa Realty Co., Inc.	Solar Star 3, LLC
California Energy Yuma Corporation	Iowa Title Company	Solar Star 4, LLC
California Utility Holdco, LLC	Iroquois GP Holding Company, LLC	Solar Star California XIX, LLC
CanopyTitle, LLC	Iroquois, Inc.	Solar Star California XX, LLC
Capitol Title Company	JBRC, Inc.	Solar Star Funding, LLC
Carolina Gas Services, Inc.	JRHBW Realty, Inc. d/b/a/ RealtySouth	Solar Star Projects Holding, LLC
Carolina Gas Transmission, LLC	Jumbo Road Holdings, LLC	Southwest Settlement Services, LLC
CE Electric (NY), Inc	Kansas City Title, Inc.	SSC XIX, LLC
CE Generation, LLC	Kentucky Residential Referral Service, LLC	SSC XX, LLC
CE Geothermal, Inc.	Kentwood Commercial, LLC	Texas Emergency Power Reserve, LLC
CE International Investments, Inc	Kentwood Real Estate Services, LLC	The Escrow Firm, Inc.
CE Leathers Company	Kentwood, LLC	The Long & Foster Companies, Inc.
CE Turbo LLC	Kern River Gas Transmission Company	The Referral Co.
Commonsite, Inc.	KR Holding, LLC	Thoroughbred Title Services, LLC
Cordova Energy Company LLC	Lands of Sierra, Inc.	Tioga Properties, LLC
Cove Point GP Holding Company, LLC	Larabee School of Real Estate, Inc.	TL BHER Ex-IV, LLC
Crown Solar Holdings, LLC	Long & Foster Institute of Real Estate, LLC	TLTC LLC
Crown Solar, LLC	Long & Foster Mortgage Ventures, Inc.	Topaz Solar Farms LLC
CTRE, L.L.C.	Long & Foster Real Estate, Inc.	TPZ Holding, LLC


Dakota Dunes Development Company	Lovejoy Realty, Inc.	TRMC LLC
DCCO INC.	Lovejoy Referral Network LLC	TX Jumbo Road Wind, LLC
Del Ranch Company	M & M Ranch Acquisition Company, LLC	TX Referral Alliance, Inc.
Denver Rental, LLC	M & M Ranch Holding Company, LLC	Volantes, LLC
Desert Valley Company	Magma Land Company I	Vulcan Power Company
DesertLink Investments, LLC	Magma Power Company	Vulcan/BN Geothermal Power Company
Earth Energy Power Link LLC	Mariah del Norte LLC	Wailuku Holding Company, LLC
Eastern Energy Gas Holdings, LLC	Marshall Wind Energy Holdings, LLC	Wailuku Investment, LLC
Eastern Gas Transmission and Storage, Inc	Marshall Wind Energy LLC	Wailuku River Hydroelectric Power Company, Inc.
Eastern Gathering and Processing Inc.	MEHC Investment, Inc.	Walnut Ridge Wind, LLC
Eastern MLP Holding Company II, LLC	MES Holding, LLC	Watermark Realty Referral, Inc.
Ebby Halliday Alliance, LLC	Metro Referral Associates, Inc.	Watermark Realty, Inc.
Ebby Halliday Real Estate, LLC	Metro Referrals, LLC	Weathervane Referral Network, Inc.
Edina Realty Referral Network, Inc.	MHC Inc.	West Virginia Land Holdings, LLC
Edina Realty Title, Inc.	MHC Investment Company	Western Capital Group, LLC
Edina Realty, Inc.	Mid-America Referral Network, Inc.	Willows Solar Holdings LLC
Elk Valley Wind, LLC	MidAmerican Central California Transco, LLC	Wind Watch, LLC
		WRW Holding, LLC

With respect to members of the BHE Sub-Group, Berkshire Hathaway Energy Co. (BHE) requires all subsidiaries to pay to or receive from BHE an amount of tax based primarily on the stand-alone method of allocation. The computation includes all tax benefits from tax deductions stemming from cost borne by utility customers.

Berkshire Hathaway Inc. Sub-Group:
121 Acquisition Co., LLC	GEICO Casualty Co.	NFM Custom Countertops, LLC
21 SPC, Inc.	GEICO Choice Insurance Company	NFM of Cedar Park, Inc.
21st Communities, Inc.	GEICO Corporation	NFM of Iowa, Inc.
21st Mortgage Corporation	GEICO Discovery Corporation	NFM of Kansas, Inc.
2K Polymer Systems, Inc.	GEICO Discovery II Corporation	NFM of Nebraska, Inc.
Acme Brick Company	GEICO Discovery III Corporation	NFM SERVICES, LLC
Acme Building Brands, Inc	GEICO Discovery IV Corporation	NFM Wellness, LLC
Acme Management Company	GEICO Endeavor Corporation	NJE Holdings, LLC
Acme Services Company, LLC	GEICO Endeavor II Corporation	NJI Sales, Inc.
Adalet Company	GEICO Endeavor III Corporation	Noranco Manufacturing (USA) Ltd.
AEROCRAFT HEAT TREATING CO INC	GEICO Endeavor IV Corporation	NorGUARD Insurance Company
Aero-Hose Corporation	GEICO General Insurance Co.	Northern States Agency, Inc.
AEROSPACE DYNAMICS INTERNATIONAL INC	GEICO Horizon Corporation	Noveon Hilton Davis, Inc.
Affordable Housing Partners, Inc.	GEICO Horizon II Corporation	NSS TECHNOLOGIES INC
AIPCF V CHI Blocker Inc	GEICO Horizon III Corporation	Oak River Insurance Company
AJF Warehouse Distributors, Inc.	GEICO Horizon IV Corporation	Old United Casualty Company
Albecca, Inc.	GEICO Indemnity Co.	Old United Life Insurance Company
Alleghany Capital Corporation	GEICO Lone Star Corporation	Orien Risk Analysts, Inc.
Alleghany Corporation	GEICO Lone Star II Corporation	Oriental Trading Company, Inc.


Alleghany Properties Holdings LLC	GEICO Lone Star III Corporation	OTC Brands, Inc.
Alleghany Reinsurance Company LLC	GEICO Lone Star IV Corporation	OTC Direct, Inc.
Alpha Cargo Motor Express, Inc	GEICO Marine Insurance Company	OTC Worldwide Holdings, Inc.
Alu-Forge, Inc	GEICO Perspective Corporation	PCC ROLLMET INC
American All Risk Insurance Services Inc.	GEICO Perspective II Corporation	PCC STRUCTURALS INC
American Commercial Claims Administrators Inc	GEICO Perspective III Corporation	PELI, Inc.
American Dairy Queen Corporation	GEICO Products, Inc.	Penn Coal Land, Inc.
AmGUARD Insurance Company	GEICO Protection Insurance Company	Perfection Hy-Test Company
Andrews Laser Works Corporation	GEICO Secure Insurance Company	PERMASWAGE HOLDINGS, INC.
APACE Holding Company LLC	GEICO Voyager Corporation	Pine Canyon Land Company
Artform International Inc.	GEICO Voyager II Corporation	Piper Finance Company
ATLANTIC PRECISION INC	GEICO Voyager III Corporation	Platte River Insurance Company
AVIBANK MANUFACTURING INC	GEICO Voyager IV Corporation	Plaza Financial Services Co.
AzGUARD Insurance Company	Gen Re Intermediaries Corporation	Plaza Resources Co.
Bayport Systems, Inc.	General Re Corporation	PLICO
Ben Bridge Jeweler, Inc.	General Re Financial Products Corporation	Precision Brand Products, Inc.
Benjamin Moore & Co.	General Re Life Corporation	PRECISION CASTPARTS CORP
Benson, Ltd.	General Reinsurance Corporation	Precision Cutting Technologies, Inc.
Berkshire Hathaway Assurance Corporation	General Star Indemnity Company	PRECISION FOUNDERS INC
Berkshire Hathaway Automotive Inc.	General Star National Insurance Company	Press Forge Company
Berkshire Hathaway Credit Corporation	Genesis Insurance Company	Princeton Insurance Company
Berkshire Hathaway Direct Insurance Company	GINSU LLC	Priority One Financial Services, Inc.
Berkshire Hathaway Finance Corporation	Government Employees Financial Corp.	PRISM Holdings LLC
Berkshire Hathaway Homestate Insurance Company	Government Employees Insurance Co.	PRISM Plastics, Inc.
Berkshire Hathaway Inc.	GRD Holdings Corporation	Procrane Holdings, Inc.
Berkshire Hathaway Life Insurance Company of Nebraska	GREENVILLE METALS INC	Professional Risk Management Services, Inc.
Berkshire Hathaway Specialty Insurance Company	GUARDco, Inc.	PROGRESSIVE INCORPORATED
BH Columbia Inc.	H. H. Brown Shoe Company, Inc.	PROTECTIVE COATING INC
BH Credit LLC	H.J. Justin & Sons, Inc.	QS Partners LLC
BH Finance, Inc.	Halex Electric Company	QS Security Services LLC
BH Holding H Jewelry Inc.	HAMILTON AVIATION INC	R.C. Tway Company, LLC
BH Holding LLC	Hawthorn Life International, Ltd.	R.C. Willey Home Furnishings
BH Holding S Furniture Inc	HeatPipe Technology, Inc.	Radnor Specialty Insurance Company
BH Media Group, Inc.	Heibar Installation, Inc.	Railserve, Inc.
BH Shoe Holdings, Inc.	Heibar Manufacturing, Inc.	Railsplitter Holdings Corporation
BHA Minority Interest Holdco, Inc.	HELICOMB INTERNATIONAL INC	RATHGIBSON HOLDING CO LLC
BHG Life Insurance Company	Henley Holdings, LLC	Redwood Fire and Casualty Insurance Company
BHG Structured Settlements, Inc.	Hohmann & Barnard, Inc.	RENTCO Trailer Corporation
BHHC Special Risks Insurance Company	Homefirst Agency, Inc.	Resolute Management Inc.
BH-IMC Holdings Inc.	Homemakers Plaza, Inc.	Resurgens Specialty Underwriting, Inc.
BHSF, Inc.	HUNTINGTON ALLOYS CORPORATION	Richline Group, Inc
biBERK Insurance Services, Inc.	IdeaLife Insurance Company	RIECP, LLC


BKI Oldco Inc.	IMC International Metalworking Companies Inc.	Ringwalt & Liesche Co.
Blue Chip Stamps, Inc.	Ingersoll Cutting Tool Company Inc.	Rio Grande, Inc.
BN Leasing Corporation	Innovative Building Products, Inc	Rochester Crematory, Inc.
BNSF Communications, Inc.	Innovative Coatings Technology Corporation	Roxell USA, Inc.
BNSF Logistics, LLC	Innovative Quality Solutions LLC	RSUI Group, Inc.
BNSF Railway Company	Interco Tobacco Retailers, Inc.	RSUI Indemnity Company
BNSF Spectrum, Inc.	International Dairy Queen, Inc.	RSUI Insurance Exchange RPG, Inc.
Boat America Corporation	International Insurance Underwriters, Inc.	RSUI Surplus Lines Insurance Services, Inc.
Borsheim Jewelry Company, Inc	Intrepid JSB, Inc.	Sager Electrical Supply Co. Inc
Braemac (CA) L.L.C.	Ironwood Plastics Inc	Santa Fe Pacific Insurance Company
Brainy Toys, Inc.	Iscar Metals Inc.	Santa Fe Pacific Pipeline Holdings, Inc.
Brilliant National Services, Inc.	ITTI Group USA Holdings Inc.	Santa Fe Pacific Pipelines, Inc.
Brooks Sports, Inc.	ITTI Investment Holdings Inc.	Santa Fe Pacific Railroad Company
Build a Better, LLC	J.L. Mining Company	ScottCare Corporation
Burlington Northern Railroad Holdings, Inc.	Jazplus, LLC	See's Candies, Inc.
Burlington Northern Santa Fe, LLC	Jazwares Canada Holdings Inc.	See's Candy Shops, Incorporated
Business Wire, Inc.	Jazwares Entertainment, LLC	Seventeenth Street Realty, Inc.
CALEDONIAN ALLOYS INC	Jazwares Soft Creations LLC	Shaw Asia Pacific Holdings, LLC
CalGO Insurance Company	Jazwares, LLC	Shaw Diversified Services, Inc.
Camp Manufacturing Company	Johns Manville Corporation	Shaw Floors, Inc.
Cannon Equipment LLC	Johns Manville, Inc.	Shaw Funding Company
CANNON MUSKEGON CORPORATION	Jordan's Furniture, Inc.	Shaw Industries Group, Inc.
Capitol Facilities Corporation	Joyce Steel Erection LLC	Shaw Industries, Inc.
Capitol Indemnity Corporation	Justin Brands, Inc.	Shaw Integrated and Turf Solutions, Inc.
Capitol Specialty Insurance Corporation	Kahn Ventures, Inc.	Shaw International Services, Inc.
CapSpecialty, Inc.	Kelly Amusement Holdings, LLC	Shaw Retail Properties, Inc.
Carefree Company	Kinexo, Inc.	Shaw Sports Turf California, Inc.
CATA Services Company	KITCO Fiber Optics, Inc.	Shaw Transport, Inc.
Cavalier Homes, Inc.	KLUNE INDUSTRIES INC	Shaw Watershed Holdings, LLC.
Central States Indemnity Co. of Omaha	L.A. Terminals, Inc.	SHX Flooring, Inc.
Central States of Omaha Companies, Inc.	Landmark American Insurance Company	SidePlate Systems, Inc.
CH Industries, Inc.	Larson-Juhl International LLC	Smilemakers Canada Inc.
Charter Brokerage Holdings Corp.	LeachGarner, Inc.	Smilemakers, Inc.
CJE II	Lipotec USA, Inc.	SN Management, Inc.
Claims Services, Inc.	LiquidPower Specialty Products, Inc.	Soco West, Inc.
Clayton Education Corp.	LJ AERO HOLDINGS INC	Solqs
Clayton Homes, Inc.	LJ SYNCH HOLDINGS INC	Sonnax Transmission Company
Clayton Properties Group, Inc.	LMG Ventures, LLC	Southern Energy Homes, Inc.
Clayton Supply, Inc.	Loch Vale Logistics, Inc.	SOUTHWEST UNITED INDUSTRIES INC
Clayton, Inc.	Los Angeles Junction Railway Company	SPS INTERNATIONAL INVESTMENT COMPANY
CMH Capital, Inc.	LSPI Holdings Inc.	SPS TECHNOLOGIES LLC
CMH Homes, Inc.	Lubrizol Advanced Materials Holding Corporation	SPS Technologies Mexico LLC


CMH Manufacturing West, Inc.	Lubrizol Advanced Materials, Inc.	SSP-SiMatrix Inc.
CMH Manufacturing, Inc.	Lubrizol Global Management, Inc.	Stahl Truck Equipment Company
CMH Services Aviation, Inc.	Lubrizol Inter-Americas Corporation	Star Lake Railroad Company
CMH Services, Inc.	Lubrizol International, Inc.	Summit Distribution Services, Inc.
CMH Transport, Inc.	Lubrizol Life Science, Inc.	SXP SCHULZ XTRUDED PRODUCTS LLC
Coil Master Corporation	Lubrizol Overseas Trading Corporation	TBCW Holdings, Inc.
Columbia Insurance Company	M & C Products, Inc.	TBS USA, Inc.
Complementary Coatings Corp.	M&M Manufacturing, Inc.	Tenn-Tex Plastics, Inc.
Composites Horizons LLC	M2 Liability Solutions, Inc.	TEXAS HONING INC
Consumer Value Products, Inc.	Mapletree Transportation, Inc.	The Ben Bridge Corporation
Continental Divide Insurance Company	Marine Tech Wire and Cable, Inc.	The BVD Licensing Corporation
Cort Business Services Corporation	Marmon Beverage Technologies, Inc.	The Duracell Company
Covington Specialty Insurance Company	Marmon Crane Services, Inc.	The Fechheimer Brothers Co.
CPM Development, LLC	Marmon Distribution Services, Inc.	The Indecor Group, Inc.
Criterion Insurance Agency	Marmon Energy Services Company	The Lubrizol Corporation
Crown Holdco One, Inc.	Marmon Engineered Components Company	The Medical Protective Company
Crown Holdco Two, Inc.	Marmon Financial Group, Inc.	The Pampered Chef, Ltd.
Crown Parent, Inc.	Marmon Foodservice Technologies, Inc.	The Zia Company
CSI Life Insurance Company	Marmon Holdings, Inc.	Thermoform Plastics, Inc.
CTB Credit Corp	Marmon Link Inc	TITANIUM METALS CORPORATION
CTB Inc.	Marmon Metal Solutions, Inc.	TM City Leasing Inc.
CTB International Corp	Marmon Power Systems, Inc.	Tool-Flo Manufacturing, Inc.
CTB Investment Holdings Inc.	Marmon Rail Group, Inc.	Top Five Club, Inc.
CTB IW INC	Marmon Railroad Services LLC	Total Quality Apparel Resource, Inc
CTB Midwest Inc	Marmon Renew, Inc.	TPC European Holdings, LTD.
CTB MN Investments	Marmon Retail & Highway Technologies Company LLC	TPC North America, Ltd.
CTB Technology Holding Inc.	Marmon Retail LLC	Transatlantic Holdings, Inc.
Cumberland Asset Management, Inc.	Marmon Retail Products, Inc.	Transatlantic Reinsurance Company
Cypress Insurance Company	Marmon Specialty Products Company	Transco Rail Services US Inc.
D.I. Properties Inc.	Marmon Technologies Company	Transco Railcar Repair Inc
Daniels-Head Insurance Agency, Inc. (CA)	Marmon Tubing, Fittings & Wire Products, Inc.	Transco, Inc.
Daniels-Head Insurance Agency, Inc. (TX)	Marmon Water, Inc.	Transportation Technology Services, Inc.
Daniels-Head Management Corp.	Marmon Wire & Cable, Inc.	TransRe Underwriting Managers Agency Ltd.
DCI Marketing Inc.	Marmon-Herrington Company	TRH Holding Corp.
DESIGNED METAL CONNECTIONS, INC.	Maryland Ventures, Inc..	Triangle Suspension Systems, Inc.
DICKSON TESTING CO INC	McCarty-Hull Cigar Company, Inc.	Trilogy Communications, Inc.
DL Trading Holdings I, Inc.	McLane Beverage Distribution, Inc.	TrueNorth Development Inc.
DQF, Inc.	McLane Beverage Holding, Inc.	TS City Leasing Inc
DQGC, Inc.	McLane Company, Inc.	TSE Brakes, Inc.
Duracell Industrial Operations, Inc.	McLane Eastern, Inc.	TTI JV 1
Duracell U.S. Operations, Inc.	McLane Express, Inc.	TTI JV 2
Easley Custom Plastics, Inc.	McLane Foods, Inc.	TTI, Inc.


EastGUARD Insurance Company	McLane Foodservice Distribution, Inc.	Tucker Safety Products, Inc.
Eco Color Company	McLane Foodservice, Inc.	Tungaloy-NTK America Inc.
Ecodyne Corporation	McLane Interstate Warehouse, Inc.	TXFM, Inc.
Ellis & Watts Global Industries, Inc.	McLane Mid-Atlantic, Inc.	U.S. Investment Corporation
Elm Street Corporation	McLane Midwest, Inc.	U.S. Underwriters Insurance Co.
Empire Distributors of Colorado, Inc.	McLane Minnesota, Inc.	UCFS Europe Company
Empire Distributors of North Carolina, Inc.	McLane Network Solutions, Inc.	UCFS International Holding Company
Empire Distributors of Tennessee, Inc.	McLane New Jersey, Inc.	UFC Transition Co.
Empire Distributors, Inc.	McLane Ohio, Inc.	Unified Supply Chain, Inc.
ENVIRONMENT ONE CORPORATION	McLane Southern, Inc.	Union Tank Car Company
EP SALES INC	McLane Suneast, Inc.	Union Underwear Co., Inc
EXACTA AEROSPACE INC	McLane Tri-States, Inc.	United Consumer Financial Services Company
Executive Jet Management, Inc.	McLane Western, Inc.	United Direct Finance, Inc.
Exponential Technology Group, Inc.	MCWILLIAMS FORGE COMPANY	United States Aviation Underwriters, Incorporated
Exsif Worldwide, Inc.	Medical Protective Finance Corporation	United States Liability Insurance Company
ExtruMed, Inc.	MedPro Group, Inc	V3 Insurance Agency Inc.
Fair American Insurance and Reinsurance Company	MedPro Risk Retention Services, Inc.	Van Enterprises, Inc.
Fair American Select Insurance Company	Merit Distribution Services, Inc.	Vanderbilt ABS Corp.
FATIGUE TECHNOLOGY INC	METALAC FASTENERS INC	Vanderbilt Mortgage and Finance, Inc.
Financial Services Plus, Inc.	Meyn LLC	Vanity Fair, Inc.
Finial Reinsurance Company	MFS Fleet, Inc.	Veritas Insurance Group, Inc.
First Act, LLC	Miller Sage Holdings, Inc.	Vesta Intermediate Funding, Inc.
First Berkshire Hathaway Life Insurance Company	Mindware Corporation	VFI-Mexico, Inc.
FlightSafety Capital Corp.	MiTek Holdings, Inc.	Visilinx, Inc.
FlightSafety Defense Corporation	MiTek Inc.	Vision Retailing, Inc.
FlightSafety Development Corp.	MiTek Industries, Inc.	VT Insurance Acquisition Sub Inc.
FlightSafety International Inc.	MLMIC Insurance Company	Wayne Combustion Systems, Inc.
FlightSafety International Middle East Inc.	MLMIC Services, Inc.	Wayne Water Systems, Inc.
FlightSafety New York, Inc.	Morgantown-National Supply, Inc.	Webb Wheel Products, Inc.
FlightSafety Properties, Inc.	Mount Vernon Fire Insurance Company	Wellfleet Insurance Company
Floors, Inc.	Mount Vernon Specialty Insurance Company	Wellfleet New York Insurance Company
Fontaine Commercial Trailer, Inc.	Mouser Electronics, Inc.	Western Builders Supply, Inc.
Fontaine Engineered Products, Inc.	Mouser JV 1, Inc	Western Enterprises, Inc.
Fontaine Fifth Wheel Company	Mouser JV 2	Western Fruit Express Company
Fontaine Modification Company	MPP Co., Inc.	WestGUARD Insurance Company
Fontaine Spray Suppression Company	MPP Pipeline Corporation	Whittaker, Clark & Daniels, Inc.
Fontaine Trailer Company LLC	MS Property Company	Wilbert Funeral Services, Inc.
Forest River Holdings, Inc.	MW Wholesale, Inc.	Wilbert, Inc.
Forest River, Inc.	National Fire & Marine Insurance Company	World Book Company
Forseti Assurance Company, LLC	National Indemnity Company	World Book Encyclopedia, Inc.
Frasca International, Inc.	National Indemnity Company of Mid-America	World Book, Inc.
Freedom Warehouse Corp.	National Indemnity Company of the South	Worldwide Containers, Inc.


Fruit of the Loom Direct, Inc.	National Liability & Fire Insurance Company	WPLG, Inc.
Fruit of the Loom Trading Company	Nationwide Uniforms	WYMAN GORDON COMPANY
Fruit of the Loom, Inc.	Nebraska Furniture Mart, Inc.	WYMAN GORDON FORGINGS CLEVELAND INC
Fruit of the Loom, Inc. (Sub)	NetJets Aviation, Inc.	WYMAN GORDON FORGINGS INC
FTL Regional Sales Co., Inc.	NetJets Card Holdings, Inc.	WYMAN GORDON INVESTMENT CASTINGS INC
Garan Central America Corp.	NetJets Card Partners, Inc.	WYMAN GORDON PENNSYLVANIA LLC
Garan Incorporated	NetJets Europe Holdings, LLC	Xelix Distribution, Inc.
Garan Manufacturing Corp.	NetJets Financial Holdings LLC	X-L-Co., Inc.
Garan Services Corp	NetJets Inc.	XTRA Companies, Inc.
Gateway Underwriters Agency, Inc.	NetJets International, Inc.	XTRA Corporation
GEICO Advantage Insurance Company	NetJets Sales, Inc.	XTRA Finance Corporation
GEICO Atlantis Corporation	NetJets Services, Inc.	XTRA Intermodal, Inc.
GEICO Atlantis II Corporation	NetJets U.S., Inc.	Z Global Logistics, LLC
GEICO Atlantis III Corporation	New England Asset Management, Inc.	Zag Toys Holdings, LLC
GEICO Atlantis IV Corporation	Newtool

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are known, show the amounts in a footnote and designate whether estimated or actual amounts. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (g) and (h). The balancing of this page is not affected by the inclusion of these taxes. Include in column (g) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (d). Enter all adjustments of the accrued and prepaid tax accounts in column (i) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. Report in columns (l) through (o) how the taxes were distributed. Report in column (o) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 409.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (o) the taxes charged to utility plant or other balance sheet accounts. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
					BALANCE AT BEGINNING OF YEAR					BALANCE AT END OF YEAR		DISTRIBUTION OF TAXES CHARGED
Line No.	DescriptionOfTaxesAccruedPrepaidAndCharged Kind of Tax (See Instruction 5) (a)	TypeOfTax Type of Tax (b)	TaxJurisdiction State (c)	TaxYear Tax Year (d)	TaxesAccrued Taxes Accrued (Account 236) (e)	PrepaidTaxes Prepaid Taxes (Include in Account 165) (f)	TaxesCharged Taxes Charged During Year (g)	TaxesPaid Taxes Paid During Year (h)	TaxAdjustments Adjustments (i)	TaxesAccrued Taxes Accrued (Account 236) (j)	PrepaidTaxes Prepaid Taxes (Included in Account 165) (k)	TaxesAccruedPrepaidAndCharged Electric (Account 408.1, 409.1) (l)	IncomeTaxesExtraordinaryItems Extraordinary Items (Account 409.3) (m)	AdjustmentsToRetainedEarnings Adjustment to Ret. Earnings (Account 439) (n)	TaxesIncurredOther Other (o)
1					0	0				0
2	Subtotal Federal Tax				0	0	0	0	0	0	0	0	0	0	0
3	Subtotal State Tax				0	0	0	0	0	0	0	0	0	0	0
4	Subtotal Local Tax				0	0	0	0	0	0	0	0	0	0	0
5	Subtotal Other Tax				0	0	0	0	0	0	0	0	0	0	0
6	Property Tax	Property Tax	Arizona		34,778	0	69,317	69,436		34,659	0	309,801			(c) 240,484
7	Property Tax	Property Tax	California		0	0	6,198,810	6,198,810		0	0	6,035,984			(d) 162,826
8	Property Tax	Property Tax	Colorado		1,230,000	0	3,550,642	1,260,642		3,520,000	0	3,547,116			(e) 3,526
9	Property Tax	Property Tax	Idaho		2,060,046	0	3,134,023	3,198,969		1,995,100	0	3,111,066			(f) 22,957
10	Property Tax	Property Tax	Montana		2,602,519	0	5,544,266	5,377,979		2,768,806	0	5,544,266			0
11	Property Tax	Property Tax	New Mexico		0	0	18,992	18,992		0	0	18,992			0
12	Property Tax	Property Tax	Oregon		0	25,377,999	52,795,671	55,393,501		0	27,975,829	40,239,029			(g) 12,556,642
13	Property Tax	Property Tax	Utah		487,236	0	67,349,757	67,257,702		579,291	0	66,126,134			(h) 1,223,623
14	Property Tax	Property Tax	Washington		8,100,000	0	9,689,139	9,189,139		8,600,000	0	9,615,093			(i) 74,046
15	Property Tax	Property Tax	Wyoming		10,874,181	0	20,631,778	21,190,064		10,315,895	0	20,610,783			(j) 20,995
16	Goshute Possessory Interest	Property Tax	Idaho		0	0	28,460	28,460		0	0	28,460
17	Sho-Ban Possessory Interest	Property Tax	Utah		0	0	119,354	119,354		0	0	119,354
18	Navajo Possessory Interest	Property Tax	Utah		16,000	0	16,000	24,000		8,000	0	16,000
19	Ute Possessory Interest	Property Tax	Colorado		0	0	12,304	12,304		0	0	12,304
20	Crow Possessory Tax	Property Tax	Montana		91,000	0	98,068	94,068		95,000	0	98,068
21	Umatilla Possessory Interest	Property Tax	Oregon		0	0	146,329	146,329	0	0	0	146,329
22	Subtotal Property Tax				25,495,760	25,377,999	169,402,910	169,579,749	0	27,916,751	27,975,829	155,578,779	0	0	13,824,131
23	Subtotal Real Estate Tax				0	0	0	0	0	0	0	0	0	0	0
24	Federal Unemployment Tax	Unemployment Tax			237,465	0	229,863	222,960		244,368					(k) 229,863
25	Federal Unemployment Tax	Unemployment Tax	Arizona		2,186	0	389	389		2,186					(l) 389
26	Unemployment Tax	Unemployment Tax	California		17,428	0	18,116	19,311		18,623					(m) 18,116
27	Unemployment Tax	Unemployment Tax	Colorado		1,471	0				1,471
28	Unemployment Tax	Unemployment Tax	Florida		728	0	35	763		0					(n) 35
29	Unemployment Tax	Unemployment Tax	Idaho		3,578	0	20,495	20,920		3,153					(o) 20,495
30	Unemployment Tax	Unemployment Tax	Nevada		13,374	0	3,762	3,762		13,374					(p) 3,762
31	Unemployment Tax	Unemployment Tax	Oregon		391,952	4,497	1,384,438	1,406,980		418,991					(q) 1,384,438
32	Unemployment Tax	Unemployment Tax	Texas		43	0	108	108		43					(r) 108
33	Unemployment Tax	Unemployment Tax	Utah		13,364	0	199,415	204,712		18,661					(s) 199,415
34	Unemployment Tax	Unemployment Tax	Washington		125,978	0	458,847	546,108		38,717					(t) 458,847
35	Unemployment Tax	Unemployment Tax	Minnesota		1,281	0	202	202		1,281					(u) 202
36	Unemployment Tax	Unemployment Tax	Montana		3,541	0	2,692	1,968		2,817					(v) 2,692
37	Unemployment Tax	Unemployment Tax	Missouri		277	0	125	125		277					(w) 125
38	Unemployment Tax	Unemployment Tax	South Carolina		1	0	1,680	1,680		1					(x) 1,680
39	Unemployment Tax	Unemployment Tax	Wyoming		161,429	0	1,009,466	987,200		139,163					(y) 1,009,466
40	Unemployment Tax	Unemployment Tax	Illinois		1,061	0	522	522		1,061					(z) 522
41	Unemployment Tax	Unemployment Tax	Indiana		776	0		174		950
42	Unemployment Tax	Unemployment Tax	Maryland		206	0		26		232
43	Unemployment Tax	Unemployment Tax	North Carolina		843	0	398	398		843					(aa) 398
44	Unemployment Tax	Unemployment Tax	New Hampshire		377	0	182	182		377					(ab) 182
45	Unemployment Tax	Unemployment Tax	New York		2,497	0				2,497
46	Unemployment Tax	Unemployment Tax	Pennsylvania		501	0	262	262		501					(ac) 262
47	Unemployment Tax	Unemployment Tax	Wisconsin		772	0				772
48	Unemployment Tax	Unemployment Tax	District of Columbia		522	0	261	244		505					(ad) 261
49	Subtotal Unemployment Tax				246,067	4,497	3,331,258	3,418,996	0	338,302		0	0	0	3,331,258
50	Use Tax	Sales And Use Tax	California		47,752	0	609,169	641,510		15,411					(ae) 609,169
51	Use Tax	Sales And Use Tax	Idaho		2,560	0	254,496	238,622		18,434					(af) 254,496
52	Use Tax	Sales And Use Tax	Utah		459,635	0	10,630,952	10,282,105		808,482					(ag) 10,630,952
53	Use Tax	Sales And Use Tax	Washington		103,582	0	1,159,666	1,175,407		87,841					(ah) 1,159,666
54	Use Tax	Sales And Use Tax	Wyoming		61,712	0	1,571,760	1,575,393		58,079					(ai) 1,571,760
55	Subtotal Sales And Use Tax				675,241	0	14,226,043	13,913,037	0	988,247	0	0	0	0	14,226,043
56	Federal Income Tax	Income Tax			0	0	172,084,689	81,572,780	(a) 90,511,909	0		193,604,485			(aj) 21,519,796
57	Income Tax	Income Tax	Arizona		36,120	0	28,384	13,900		6,164		22,722			(ak) 5,662
58	Franchise - Income Tax	Income Tax	California		232,970	0	827,432	6,264		1,054,138		570,634			(al) 256,798
59	Income Tax	Income Tax	Colorado		13,315	0	40,098			26,783		31,979			(am) 8,119
60	Income Tax	Income Tax	Idaho		269,032	0	44,493	42,554		356,079		239,939			(an) 284,432
61	Corporate License - Income Tax	Income Tax	Montana		55,864	0	108,333	18,109		70,578		144,914			(ao) 36,581
62	Income Tax	Income Tax	New Mexico		7,818	0	15,093	17,048		5,863		8,655			(ap) 6,438
63	Excise - Income Tax	Income Tax	Oregon		2,473,058	0	3,083,488	395,799		5,952,345		900,907			(aq) 2,182,581
64	City of Portland - Income Tax	Income Tax	Oregon		12,127	0	163,153	69,883		245,163		140,994			(ar) 22,159
65	Corporate Activity Tax	Income Tax	Oregon		1,971,901	0	9,406,460	9,024,301	(b) 60	2,354,000		9,406,460			0
66	Metro Business Income Tax	Income Tax	Oregon		127,100	0	19,057	30,497	0	138,540		19,057			0
67	Income Tax	Income Tax	North Carolina		0	0	200	200	0	0		200			0
68	Public Utility Tax	Income Tax	South Carolina		0	0	25	25	0	0		25			0
69	Income Tax	Income Tax	New Hampshire		0	0	727	1,450	0	723		727			0
70	Income Tax	Income Tax	District of Columbia		0	0	250	250	0	0		250			0
71	Income Tax	Income Tax	Utah		3,968,085	0	626,970	236,113		4,358,942		1,443,898			(as) 2,070,868
72	Subtotal Income Tax				9,068,520	0	157,975,306	72,821,653	90,511,849	14,426,716	0	184,368,740	0	0	26,393,434
73	Natural Gas Use Tax	Excise Tax	Washington		370,251	0	1,937,964	2,048,334		259,881					(at) 1,937,964
74	Forest Excise Tax	Excise Tax	Washington		0	0	6,660	6,660		0					(au) 6,660
75	Subtotal Excise Tax				370,251	0	1,944,624	2,054,994	0	259,881	0	0	0	0	1,944,624
76	Subtotal Fuel Tax				0	0	0	0	0	0	0	0	0	0	0
77	Foreign Insurance Premiums	Federal Insurance Tax					4,434,331	4,434,331		0		4,434,331
78	Subtotal Federal Insurance Tax				0	0	4,434,331	4,434,331	0	0	0	4,434,331	0	0	0
79	Local Franchise Tax	Franchise Tax	California		1,521,900	0	2,156,040	1,802,440		1,875,500		2,156,040
80	Local Franchise Tax	Franchise Tax	Oregon		6,753,092	0	45,641,959	45,065,362		7,329,689		45,641,959
81	Local Franchise Tax	Franchise Tax	Utah		0	0	8,926	8,926		0		8,926
82	Local Franchise Tax	Franchise Tax	Washington		0	0				0
83	Local Franchise Tax	Franchise Tax	Wyoming		319,900	0	2,629,433	2,607,133		342,200		2,629,433
84	Subtotal Franchise Tax				8,594,892	0	50,436,358	49,483,861	0	9,547,389	0	50,436,358	0	0	0
85	Subtotal Miscellaneous Other Tax				0	0	0	0	0	0	0	0	0	0	0
86	Subtotal Other Federal Tax				0	0	0	0	0	0	0	0	0	0	0
87	KWh	Other State Tax	Idaho		14,729	0	56,771	53,046	0	18,454	0	56,771	0	0	0
88	Energy License	Other State Tax	Montana		90,000	0	339,392	339,392	0	90,000	0	339,392	0	0	0
89	Wholesale Energy	Other State Tax	Montana		70,000	0	241,824	241,824	0	70,000	0	241,824	0	0	0
90	Commerce Tax	Other State Tax	Nevada		12,000	0	73	73	0	12,000	0	73	0	0	0
91	Department of Energy	Other State Tax	Oregon		0	739,730	1,635,903	1,792,346	0	0	896,173	1,635,903	0	0	0
92	Business and Occupation Tax	Other State Tax	Washington		3,200	0	34,548	32,848	0	4,900	0	34,548	0	0	0
93	Public Utility Tax	Other State Tax	Washington		1,950,000	0	20,911,971	20,601,971	0	2,260,000	0	20,911,971	0	0	0
94	Wind Generation Tax	Other State Tax	Wyoming		4,426,292	0	4,878,957	4,427,417	0	4,877,832	0	4,878,957	0	0	0
95	Annual Report	Other State Tax	Wyoming		0	0	124,767	124,767	0	0	0	124,767	0	0	0
96	Subtotal Other State Tax				6,566,221	739,730	28,224,206	27,613,684	0	7,333,186	896,173	28,224,206	0	0	0
97	Subtotal Other Property Tax				0	0	0	0	0	0	0	0	0	0	0
98	Subtotal Other Use Tax				0	0	0	0	0	0	0	0	0	0	0
99	Subtotal Other Advalorem Tax				0	0	0	0	0	0	0	0	0	0	0
100	Subtotal Other License And Fees Tax				0	0	0	0	0	0	0	0	0	0	0
101	Federal FICA Tax	Payroll Tax			634,269	24,707	48,373,979	48,275,330		708,211					(av) 48,373,979
102	Tri-Met Transit Tax	Payroll Tax	Oregon		125,511	0	1,404,646	1,335,461		194,696					(aw) 1,404,646
103	Lane Transit Tax	Payroll Tax	Oregon		0	0	1,421	1,421		0					(ax) 1,421
104	Family and Medical Leave	Payroll Tax	Colorado		294	0		600		306
105	Family and Medical Leave	Payroll Tax	Oregon		127,611	0	941,878	911,698		157,791					(ay) 941,878
106	Family and Medical Leave	Payroll Tax	Washington		64,229	0	55,609	165,096		173,716					(az) 55,609
107	Long Term Care EE	Payroll Tax	Washington		114,005	0	177,320	179,807		116,492					(ba) 177,320
108	Subtotal Payroll Tax				709,451	24,707	50,954,853	50,869,413	0	770,184	0	0	0	0	50,954,853
109	Subtotal Advalorem Tax				0	0	0	0	0	0	0	0	0	0	0
110	Subtotal Other Allocated Tax				0	0	0	0	0	0	0	0	0	0	0
111	Subtotal Severance Tax				0	0	0	0	0	0	0	0	0	0	0
112	Subtotal Penalty Tax				0	0	0	0	0	0	0	0	0	0	0
113	Subtotal Other Taxes And Fees				0	0	0	0	0	0	0	0	0	0	0
40	TOTAL				(bb) 51,234,269	26,146,933	164,979,277	248,546,412	90,511,849	(bc) 60,904,052	28,872,002	54,304,934	0	0	110,674,343

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: TaxAdjustments

Account 146, Accounts receivable from other associated companies, which represents income taxes receivable from Berkshire Hathaway Energy Company, PacifiCorp�s indirect parent company.

(b) Concept: TaxAdjustments

Account 182.3, Other Regulatory Assets, which represents a reclassification of the balance

Account 182.3, Other Regulatory Assets

(d) Concept: TaxesIncurredOther

Account 408.2, Taxes other than income taxes, other income and deductions

(e) Concept: TaxesIncurredOther

Account 408.2, Taxes other than income taxes, other income and deductions

(f) Concept: TaxesIncurredOther

$ 134 Account 408.2, Taxes other than income taxes, other income and deductions 22,823 Account 107, Construction work in progress$ 22,957

(g) Concept: TaxesIncurredOther

$ 23,710 Account 408.2, Taxes other than income taxes, other income and deductions 169,145 Account 589, Rents 12,363,787 Account 107, Construction work in progress$ 12,556,642

(h) Concept: TaxesIncurredOther

$ 70,504 Account 408.2, Taxes other than income taxes, other income and deductions 1,153,119 Account 107, Construction work in progress$ 1,223,623

(i) Concept: TaxesIncurredOther

Account 408.2, Taxes other than income taxes, other income and deductions

(j) Concept: TaxesIncurredOther

$ 2,860 Account 408.2, Taxes other than income taxes, other income and deductions 18,135 Account 589, Rents$ 20,995

(k) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(l) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(m) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(n) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(o) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(p) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(q) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(r) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(s) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(t) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(u) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(v) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(w) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(x) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(y) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(z) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(aa) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(ab) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(ac) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(ad) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(ae) Concept: TaxesIncurredOther

Charged to same account as related goods.

(af) Concept: TaxesIncurredOther

Charged to same account as related goods.

(ag) Concept: TaxesIncurredOther

Charged to same account as related goods.

(ah) Concept: TaxesIncurredOther

Charged to same account as related goods.

(ai) Concept: TaxesIncurredOther

Charged to same account as related goods.

(aj) Concept: TaxesIncurredOther

Account 409.2, Income Taxes - Federal, which represents income tax applicable to other income and deductions.

(ak) Concept: TaxesIncurredOther

Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.

(al) Concept: TaxesIncurredOther

Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.

(am) Concept: TaxesIncurredOther

Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.

(an) Concept: TaxesIncurredOther

Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.

(ao) Concept: TaxesIncurredOther

Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.

(ap) Concept: TaxesIncurredOther

Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.

(aq) Concept: TaxesIncurredOther

Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.

(ar) Concept: TaxesIncurredOther

Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.

(as) Concept: TaxesIncurredOther

Account 409.2, Income taxes - Other, which represents state income tax applicable to other income and deductions.

(at) Concept: TaxesIncurredOther

Account 151, Fuel stock

(au) Concept: TaxesIncurredOther

Account 408.2, Taxes other than income taxes, other income and deductions

(av) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(aw) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(ax) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(ay) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(az) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(ba) Concept: TaxesIncurredOther

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.

(bb) Concept: TaxesAccrued

As of December 31, 2024, Account 236, Taxes accrued, included $9,068,520 of income tax payable to Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.

(bc) Concept: TaxesAccrued

As of December 31, 2025, Account 236, Taxes accrued, included $14,426,715 of income tax payable to Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g). Include in column (i) the average period over which the tax credits are amortized.
			Deferred for Year		Allocations to Current Year's Income
Line No.	Account Subdivisions (a)	Balance at Beginning of Year (b)	Account No. (c)	Amount (d)	Account No. (e)	Amount (f)	Adjustments (g)	Balance at End of Year (h)	Average Period of Allocation to Income (i)	ADJUSTMENT EXPLANATION (j)
1	Electric Utility
2	3%
3	4%
4	7%
5	10%	238,094			(a) 411.4	200,246		37,848	39.3 years
6	30	2,011,175			(b) 420	153,688		1,857,487	24.0 years
7	Idaho (Pre-2013)	4,642			(c) 411.4	2,365		2,277	39.3 years
8	Idaho	13,629			(d) 420	2,485		11,144	30.0 years
8	TOTAL Electric (Enter Total of lines 2 thru 7)	2,267,540				358,784		1,908,756
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10										`
11	Idaho (nonutility)	8,163,885	190	1,571,603	420	1,237,290	(e) 128,617	8,626,815	30.0 years
47	OTHER TOTAL	8,163,885		1,571,603		1,237,290	128,617	8,626,815
48	GRAND TOTAL	10,431,425		1,571,603		1,596,074	128,617	10,535,571

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredInvestmentTaxCreditsAllocationToIncomeAccountNumber

Internal Revenue Code 46(f) 2

(b) Concept: AccumulatedDeferredInvestmentTaxCreditsAllocationToIncomeAccountNumber

Internal Revenue Code 46(f) 1

Internal Revenue Code 46(f) 2

(d) Concept: AccumulatedDeferredInvestmentTaxCreditsAllocationToIncomeAccountNumber

Internal Revenue Code 46(f) 1

(e) Concept: AccumulatedDeferredInvestmentTaxCreditsAdjustments

Represents an adjustment to the prior year balance that was made in the current year.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

OTHER DEFERRED CREDITS (Account 253)
Report below the particulars (details) called for concerning other deferred credits. For any deferred credit being amortized, show the period of amortization. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
			DEBITS
Line No.	Description and Other Deferred Credits (a)	Balance at Beginning of Year (b)	Contra Account (c)	Amount (d)	Credits (e)	Balance at End of Year (f)
1	Reclamation Costs - Trapper Mine	10,614,977	131	761,341	1,104,352	10,957,988
2	Western Coal Carriers Benefits Obligation	6,796,000	131	665,747	638,090	6,768,343
3	Deferred Compensation Plans	6,597,364	131	2,082,423	1,430,861	5,945,802
4	Long-Term Incentive Plan	20,671,571	131	5,453,202	1,738,161	16,956,530
5	Regulated Environmental Liabilities	83,205,667	131, 182.3	18,113,422	23,837,977	88,930,222
6	Non-Regulated Environmental Liabilities	1,468,399	131, 426.5	98,239	73,090	1,443,250
7	(a) Unearned Joint Use Pole Contact Revenue	4,465,827	454	12,667,555	15,252,466	7,050,738
8	Transmission Security Deposits	32,155,113	131	1,033,050	11,537,220	42,659,283
9	Transmission Service Deposits	7,014,428	131, 235	6,898,113	3,728,070	3,844,385
10	Transmission Study Deposits for Financial Security	117,391,335	131	61,804,320	15,000,000	70,587,015
11	Transmission Study Deposits for Site Control	1,530,000	131	950,000	130,000	710,000
12	Transmission Deposits for Cluster Studies	42,329,882	131, 242, 456	22,877,835	6,533,389	25,985,436
13	Miscellaneous Security Deposits	200,680			220,000	420,680
14	MCI F.O.G. Wire Lease (Amortization Period: 1 year)	125,580	454	748,200	747,144	124,524
15	Accrued Right-of-Way Obligations	2,091,732			624,791	2,716,523
16	(b) Facility Use Fee	601,174	451, 456	181,990	132,797	551,981
17	Employee Housing Security Deposits	20,300	131	2,300	9,200	27,200
18	Project Development Security Deposits	4,186,306				4,186,306
19	CIAC Tax Gross-Up	1,224,866	421	8,681,572	13,105,539	5,648,833
20	IT Software Licenses	3,371,610	107, 131, 556	8,627,102	58,581,969	53,326,477
21	(c) Software Charges		234	2,122,280	7,899,240	5,776,960
47	TOTAL	346,062,811		153,768,691	162,324,356	354,618,476

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: DescriptionOfOtherDeferredCredits

The weighted average remaining life is approximately one year.

(b) Concept: DescriptionOfOtherDeferredCredits

The weighted average remaining life is approximately six years.

Amount is due to Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
Report the information called for below concerning the respondent�s accounting for deferred income taxes rating to amortizable property. For other (Specify),include deferrals relating to other income and deductions. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Accelerated Amortization (Account 281)
2	Electric
3	Defense Facilities
4	Pollution Control Facilities	111,057,724	6,051,385	21,832,212							95,276,897
5	Other
5.1	Other:
8	TOTAL Electric (Enter Total of lines 3 thru 7)	111,057,724	6,051,385	21,832,212							95,276,897
9	Gas
10	Defense Facilities
11	Pollution Control Facilities
12	Other
12.1	Other:
15	TOTAL Gas (Enter Total of lines 10 thru 14)
16	Other
16.1	Other
16.2	Other
17	TOTAL (Acct 281) (Total of 8, 15 and 16)	111,057,724	6,051,385	21,832,212							95,276,897
18	Classification of TOTAL
19	Federal Income Tax	90,550,536	4,196,798	17,063,643							77,683,691
20	State Income Tax	20,507,188	1,854,587	4,768,569							17,593,206
21	Local Income Tax

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
Report the information called for below concerning the respondent�s accounting for deferred income taxes rating to property not subject to accelerated amortization. For other (Specify),include deferrals relating to other income and deductions. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 282
2	Electric	3,345,774,488	766,824,420	684,641,577			182.3, 254	6,074,103	182.3, 254	28,964,959	3,450,848,187
3	Gas
4	Other (Specify)
5	Total (Total of lines 2 thru 4)	3,345,774,488	766,824,420	684,641,577				6,074,103		28,964,959	3,450,848,187
6
7
8
9	TOTAL Account 282 (Total of Lines 5 thru 8)	3,345,774,488	766,824,420	684,641,577				6,074,103		28,964,959	3,450,848,187
10	Classification of TOTAL
11	Federal Income Tax	2,741,316,441	513,820,312	447,442,274				2,665,331		21,387,612	2,826,416,760
12	State Income Tax	604,458,047	253,004,108	237,199,303				3,408,772		7,577,347	624,431,427
13	Local Income Tax

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts recorded in Account 283. For other (Specify),include deferrals relating to other income and deductions. Provide in the space below explanations for Page 276. Include amounts relating to insignificant items listed under Other. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 283
2	Electric
3	Regulatory Assets	716,045,792	172,036,085	256,451,054	33,686,130	23,733,419	182.3, 190, 283	16,133,938	182.3, 190, 283	2,538,174	627,987,770
4	Other	49,694,953	15,785,356	10,662,352	501,416	632,166	190, 283	2,868,363	190, 283	3,367,359	55,186,203
9	TOTAL Electric (Total of lines 3 thru 8)	765,740,745	187,821,441	267,113,406	34,187,546	24,365,585		19,002,301		5,905,533	683,173,973
10	Gas
11
12
13
14
15
16
17	TOTAL Gas (Total of lines 11 thru 16)
18	TOTAL Other
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	765,740,745	187,821,441	267,113,406	34,187,546	24,365,585		19,002,301		5,905,533	683,173,973
20	Classification of TOTAL
21	Federal Income Tax	624,344,091	149,414,650	214,065,081	27,920,768	19,912,466		15,566,355		4,887,950	557,023,557
22	State Income Tax	141,396,654	38,406,791	53,048,325	6,266,778	4,453,119		3,435,946		1,017,583	126,150,416
23	Local Income Tax
NOTES

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

OTHER REGULATORY LIABILITIES (Account 254)
Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Liabilities being amortized, show period of amortization.
			DEBITS
Line No.	Description and Purpose of Other Regulatory Liabilities (a)	Balance at Beginning of Current Quarter/Year (b)	Account Credited (c)	Amount (d)	Credits (e)	Balance at End of Current Quarter/Year (f)
1	(a) DSM Balancing Account - CA	963,699	440, 442, 444	1,251,809	1,146,176	858,066
2	(b) DSM Balancing Account - ID	3,695,730	440, 442, 444	5,386,127	7,306,491	5,616,094
3	(c) DSM Balancing Account - OR	585,473	440, 442, 444, 557	3,225,632	4,022,723	1,382,564
4	(d) Oregon Energy Conservation Charge	9,249,590	908, 909	115,292,245	116,613,894	10,571,239
5	Deferred Excess RECs in Rates - ID				1,301,882	1,301,882
6	(e) Deferred Excess RECs in Rates - UT	5,475,221	411.11	5,475,221	12,839,789	12,839,789
7	(f) Deferred Excess RECs in Rates - WY	60,922	411.11	333,324	2,019,985	1,747,583
8	(g) Decoupling Mechanism - WA	3,505,121	440, 442	3,603,431	98,310
9	(h) Investment Tax Credit	64,804	190.0	54,044	43	10,803
10	(i)(j) Deferred Income Tax Electric	860,468,743	190, 282, 411.1	111,281,827	12,719,684	761,906,600
11	Corporate Activity Tax - OR	134,271	409.1	1,158	1,219	134,332
12	Excess Income Tax Deferral (Amortization period: 5 years, starting 01/2021)	3,555,536	440, 442, 444	3,555,537		1
13	(k) Low Income Program - WA		142	2,434,243	3,368,462	934,219
14	(l) Other Postretirement	52,998,415		(ag) 2,911,788	1,399,827	51,486,454
15	(m) Postemployment Costs	13,805,747		(ah) 2,755,560		11,050,187
16	Pension Settlement - UT (Amortization period: 3 years, starting 04/2025)	3,157,263	440, 442, 444	687,775	1,734,410	4,203,898
17	Bridger Mine Depreciation and Reclamation - OR	14,548,083			3,818,882	18,366,965
18	Bridger Mine Depreciation and Reclamation - WA	9,775,089			1,986,017	11,761,106
19	Cholla Unit No. 4 Closure and Decommissioning Costs - ID	1,421,335	131	506,366		914,969
20	Cholla Unit No. 4 Decommissioning Costs - OR	3,528,242	131	2,229,382		1,298,860
21	Cholla Unit No. 4 Decommissioning Costs - UT	10,881,522	131	3,769,901		7,111,621
22	Deferral of Coal Plant Closure Costs - CA	634,367			1,980,925	2,615,292
23	Deferral of Coal Plant Closure Costs - WA	5,422,943			1,355,736	6,778,679
24	Revenues Subject to Refund - WA (Amortization period: 1 year, starting 04/2025)		440, 442, 444	37,832	1,568,530	1,530,698
25	(n) Greenhouse Gas Allowance Compliance Costs - CA	2,572,903	509	11,282,619	16,745,466	8,035,750
26	Schedule 292 Rate Clearing - OR				29,444	29,444
27	(o) Solar on Multifamily Affordable Housing - CA	12,298,396	411.8, 908	89,288	46,818	12,255,926
28	(p) Renewable Portfolio Standards Compliance - OR	898,301	555.3	309,001	769,972	1,359,272
29	Emergency Service Resiliency Program - CA	264,664			11,335	275,999
30	Klamath Hydro Dam Removal - CA	260,025			381	260,406
31	(q) Deferred Intervenor Funding Grants - OR		928	487,359	1,895,191	1,407,832
32	Deferred Gains	462,106				462,106
33	(r)(s) Utah Home Energy Lifeline	2,895,632	142	1,408,984	1,471,037	2,957,685
34	(t) California Energy Savings Assistance Program	805,958	908, 909, 929	581,859	89,985	314,084
35	BPA Balancing Account - OR	1,837,682			2,596,558	4,434,240
36	BPA Balancing Account - ID				264,406	264,406
37	BPA Balancing Account - WA				52,329	52,329
38	(u) Blue Sky - CA	231,326	440, 442	168,128	101,952	165,150
39	(v) Blue Sky - OR	1,903,279	440, 442, 555	2,188,111	1,740,462	1,455,630
40	(w) Blue Sky - ID	244,623	440, 442	46,899	66,348	264,072
41	(x) Blue Sky - UT	6,282,961	440, 442	3,628,924	3,470,278	6,124,315
42	(y) Blue Sky - WA	610,402	440, 442	263,532	310,053	656,923
43	(z) Blue Sky - WY	531,788	440, 442	161,566	206,867	577,089
44	Property Sales Balancing Account - OR	244,613			442,581	687,194
45	Direct Access 5-Year Opt Out - OR (Amortization period: 10 years, starting 02/2016)	1,919,596	442	1,864,079	106,846	162,363
46	(aa) Transportation Electrification Program - OR	5,500,233	440, 442, 909	2,677,836	3,007,618	5,830,015
47	(ab) Transportation Electrification Program - CA	255,944	431	39,519	11,551	227,976
48	(ac) Transportation Electrification Pilot - UT	3,958,412	908	3,958,412
49	(ad) Oregon Clean Fuels Program	9,160,350	908, 909	2,519,691	5,183,861	11,824,520
50	Pryor Mountain - OR (Amortization period: 3 years, starting 04/2023)	174,905	411.11	137,102	5,418	43,221
51	Pryor Mountain - WA (Amortization period: 1 year, starting 04/2024)	53,655	411.11	53,655
52	Fly Ash Sales - WA (Amortization period: 2 years, starting 04/2024)	2,461,152	456	1,791,751	123,963	793,364
53	(ae) Low-Carbon Energy Standards - WY	3,600,162	923	853,838	1,411,249	4,157,573
54	(af) Utility Community Advisory Group - OR	64,503	908	286,684	597,122	374,941
55	FERC Formula Rate True-up	32,531,457	142	23,353,472	2,094,749	11,272,734
56	Wildfire Balancing Account - UT				12,122,412	12,122,412
57	Vegetation Management - OR				13,758,144	13,758,144
58	Miscellaneous Regulatory Assets and Liabilities - OR	91,601			6,199	97,800
41	TOTAL	1,096,048,745		322,945,511	244,023,580	1,017,126,814

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(b) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(d) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(e) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Average amortization period is approximately one year.

(f) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Average amortization period is approximately one year.

(g) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(h) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(i) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21%, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.

(j) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(k) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(l) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Weighted average amortization period of portion being amortized is approximately 13 years. Substantially represents amounts not yet recognized as a component of net periodic benefit cost.

(m) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Weighted average remaining amortization period is approximately six years.

(n) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(o) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(p) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Average amortization period is approximately one year.

(q) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(r) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(s) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Includes utility assistance billing.

(t) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(u) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(v) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(w) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(x) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(y) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(z) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(aa) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(ab) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(ac) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(ad) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(ae) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(af) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Amortization period varies depending on timing of underlying transactions.

(ag) Concept: DecreaseInOtherRegulatoryLiabilities

Other postretirement costs are associated with labor and generally charged to operations and maintenance expense and construction work in progress. Other postretirement settlements are charged to Account 926, Employee pensions and benefits.

(ah) Concept: DecreaseInOtherRegulatoryLiabilities

Other postemployment costs are associated with labor and generally charged to operations and maintenance expense and work in progress.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

Electric Operating Revenues
The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The average number of customers means the average of twelve figures at the close of each month. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.	Title of Account (a)	Operating Revenues Year to Date Quarterly/Annual (b)	Operating Revenues Previous year (no Quarterly) (c)	MEGAWATT HOURS SOLD Year to Date Quarterly/Annual (d)	MEGAWATT HOURS SOLD Amount Previous year (no Quarterly) (e)	AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly) (f)	AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly) (g)
1	SalesOfElectricityHeadingAbstract Sales of Electricity
2	ResidentialSalesAbstract (440) Residential Sales	2,769,186,023	2,474,881,031	18,269,615	18,252,979	1,867,245	1,837,507
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	2,504,346,609	2,152,393,616	22,673,128	21,585,176	233,923	230,579
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	1,675,916,847	1,523,073,081	18,167,642	18,531,262	32,689	32,784
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	16,707,527	16,088,695	101,477	105,737	2,996	3,180
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	6,966,157,006	6,166,436,423	59,211,862	58,475,154	2,136,853	2,104,050
11	SalesForResaleAbstract (447) Sales for Resale	(a) 198,655,537	(d) 123,793,686	4,353,895	2,279,646
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	7,164,812,543	6,290,230,109	63,565,757	60,754,800	2,136,853	2,104,050
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	7,164,812,543	6,290,230,109	63,565,757	60,754,800	2,136,853	2,104,050
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	13,885,484	13,897,817
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(b) 7,176,450	9,984,625
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power	6,405	5,895
19	RentFromElectricProperty (454) Rent from Electric Property	22,296,935	19,210,970
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(c) 27,633,676	57,641,635
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	204,803,970	196,258,831
23	RegionalTransmissionServiceRevenues (457.1) Regional Control Service Revenues
24	MiscellaneousRevenue (457.2) Miscellaneous Revenues
25	OtherMiscellaneousOperatingRevenues Other Miscellaneous Operating Revenues
26	OtherOperatingRevenues TOTAL Other Operating Revenues	275,802,920	296,999,773
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	7,440,615,463	6,587,229,882
Line12, column (b) includes $ 380,479,000 of unbilled revenues.
Line12, column (d) includes 3,093,705 MWH relating to unbilled revenues

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: SalesForResale

For a complete list of the number of customers during 2025 see pages 310-31, Sales for resale, in this Form No. 1. For a complete list of the number of customers during the prior year see pages 310-311, Sales for resale, in PacifiCorp's December 31, 2024 Form No. 1.

(b) Concept: MiscellaneousServiceRevenues

Account 451, Miscellaneous service revenues, includes the following items that were $250,000 or greater during the years ended December 31:


	2025	2024
Account service charges - application fees, disconnects, reconnects and returned check charges	$7,034,619	$6,773,873
Customer contract flat rate billings and facility buyout charges	(a)	3,205,862

(a) Amount is less than $250,000.

Account 456, Other electric revenues, includes the following items that were $250,000 or greater during the years ended December 31:


	2025	2024
Transmission service reimbursements	$11,742,139	(a)
Fly-ash and by-product sales	10,709,581	$10,020,101
Revenues from generation interconnection and transmission service request studies	1,874,224	2,148,541
Congestion revenue rights	1,010,448	(a)
Maintenance charges for work on transmission facilities	600,054	772,172
Steam sales	587,680	731,189
Revenue from other requested customer studies	272,024	257,749
Renewable energy credit sales, net of deferrals and amortization	(a)	22,707,118
Amortization of California greenhouse gas allowance revenue	(a)	15,748,818
Amortization of Oregon Clean Fuels Program credits	(a)	$3,844,435
Bid fee credits in excess of independent evaluator costs	(a)	782,543
Phase shifting equipment fee from Western Electricity Coordinating Council	(a)	368,737

(a) Amount is less than $250,000.

(d) Concept: SalesForResale

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.
Line No.	Description of Service (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46	TOTAL

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, list the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	CALIFORNIA - 06CHCK000R-CA RES CHECK M			1		0.0000
2	CALIFORNIA - 06NBDDL136-NET BL LOW INC RES DEL NORTE	56	10,359	6	9,333	0.1850
3	CALIFORNIA - 06NBDDP136-NET BL CARE + RES DEL NORTE	15	2,704	2	7,500	0.1803
4	CALIFORNIA - 06NBLDL136-NET BILLING LOW INC-RES	455	85,862	51	8,922	0.1887
5	CALIFORNIA - 06NBLDN136-NET BLNG LOW INC-RES DELNORTE	827	140,844	111	7,450	0.1703
6	CALIFORNIA - 06NBLDP136-CA NET BILLING CARE PLUS RES		28			0.0000
7	CALIFORNIA - 06NBLDT136-NET BILLING RES TOU PILOT	5	979	1	5,000	0.1959
8	CALIFORNIA - 06RESD00DT-CA RESIDENTIAL TOU PILOT	122	22,579	12	10,167	0.1851
9	CALIFORNIA - 06NETBL136-CALIFORNIA NET BILLING RES	2,124	393,256	237	8,962	0.1851
10	CALIFORNIA - 06NETMT135 - CA RES NET METERING	3,313	545,385	538	6,158	0.1646
11	CALIFORNIA - 06NMTDT135-RES TOU PILOT NET METERING	2	288			0.1441
12	CALIFORNIA - 06OALT015R-OUTD AR LGT SR	221	89,807	251	880	0.4064
13	CALIFORNIA - 06RESD000D-RES SRVC	171,011	32,289,059	17,887	9,561	0.1888
14	CALIFORNIA - 06RESDDL06-CA LOW INCOME	107,435	20,581,964	10,153	10,582	0.1916
15	CALIFORNIA - 06RESDDNDT-RES TOU PILOT-DEL NORTE CNTY	27	4,766	3	9,000	0.1765
16	CALIFORNIA - 06RESDDP06-CALIFORNIA CARE PLUS RES	1	71			0.0707
17	CALIFORNIA - 06RESDL6DT-RESIDENTIAL TOU PILOT LOW INC	69	12,975	6	11,500	0.1880
18	CALIFORNIA - 06RGNSV025-CA SMALL GENERAL SVC-RES	1,209	175,528	465	2,600	0.1452
19	CALIFORNIA - 06RNB25136-CA RES NET BILL GEN SVC<20 KW		227	1		0.0000
20	CALIFORNIA - 06RNM25135 - CA NET MTR, GEN SVC-RES		254	1		0.0000
21	CALIFORNIA - 06RESD0DM9 - MULTI FAMILY	60	4,471	5	12,000	0.0745
22	CALIFORNIA - 06RESD0DS8-MULT FAM SBMET	1,506	179,305	18	83,667	0.1191
23	CALIFORNIA - REVENUE_ACCOUNTING ADJUSTMENTS - RES		928,028			0.0000
24	CALIFORNIA - REVENUE ADJUSTMENT - DEFERRED NPC - RES		27,527			0.0000
25	CALIFORNIA - 06RESD00DN - CA RES SRVC - DEL NORTE CTY	73,151	13,806,410	7,322	9,991	0.1887
26	CALIFORNIA - DSM REVENUE-RESIDENTIAL		979,514			0.0000
27	CALIFORNIA - BLUE SKY REVENUE-RESIDENTIAL		120,852			0.0000
28	IDAHO - 07BLSKY01R-BLUESKY ENERGY		1			0.0000
29	IDAHO - 07LNX00010-MNTHLY 80%GUAR - RES		1,580			0.0000
30	IDAHO - 07LNX00035-ADV 80%MO GUAR - RES		3,008			0.0000
31	IDAHO - 07NBL36136-ID TOU RES NET BILLING	2,417	234,693	266	9,086	0.0971
32	IDAHO - 07NBW36136-TOD RES NET BILL WATTSMART	192	14,944	26	7,385	0.0778
33	IDAHO - 07NETBL136-ID RES NET BILLING	8,273	968,582	1,305	6,339	0.1171
34	IDAHO - 07NETBW136-BPA ID RES NET BIL-WATTSMART	524	57,960	122	4,295	0.1106
35	IDAHO - 07NETMT135 - ID RESIDENTIAL NET METERING	8,337	1,081,180	1,126	7,404	0.1297
36	IDAHO - 07NETMW135-BPA ID RES NET MTR-WATTSMART	118	15,266	15	7,867	0.1294
37	IDAHO - 07NMT36135-IDAHO TIME-OF-DAY RES NET MTR	3,020	322,510	250	12,080	0.1068
38	IDAHO - 07NMW36135-BPA TOD RES NET MTR-WATTSMART	28	2,478	3	9,333	0.0885
39	IDAHO - 07OALT07AR-SECURITY AR LG	82	20,086	104	788	0.2450
40	IDAHO - 07RESD0001-RES SRVC	636,651	90,522,863	62,865	10,127	0.1422
41	IDAHO - 07RESD0036-RES SRVC-OPTIO	147,883	18,884,395	9,113	16,228	0.1277
42	IDAHO - 07RGNSV06A-ID LRG GENERAL SVC-RES	301	33,460	4	75,250	0.1112
43	IDAHO - 07RGNSV23A-ID SMALL GENERAL SVC-RES	10,354	1,439,336	1,170	8,850	0.1390
44	IDAHO - 07RN23A136-RES NET BILLING SMALL GEN SVC	18	1,952	4	4,500	0.1084
45	IDAHO - 07RNM23135-RES USE NET MTR SMALL GEN SVC	291	30,538	9	32,333	0.1049
46	IDAHO - 07UPPL000R-BASE SCH FALL			2		0.0000
47	IDAHO - DSM REVENUE-RESIDENTIAL		2,414,795			0.0000
48	IDAHO - BLUE SKY REVENUE-RESIDENTIAL		35,024			0.0000
49	OREGON - 01CHCK000R-RES CHECK MTR			1		0.0000
50	OREGON - 01COST0004 - 01RESD0004	5,107,839	369,963,104			0.0724
51	OREGON - 01COST0006 - 01RESD0006	1,594	104,616			0.0656
52	OREGON - 01COST004T-RES TOU ENERGY SUPPLY SVC	17,001	1,132,872			0.0666
53	OREGON - 01COST04MT-RES CST-BSD SPLY SVC TOU MTR	4,756	349,910			0.0736
54	OREGON - 01COSTR023, OR RES GEN SRV, COST BASED	90,896	6,529,548			0.0718
55	OREGON - 01COSTR028, OR RES GEN SVC>30KW CST BSD	42,604	2,938,298			0.0690
56	OREGON - 01COSTR029-OR GEN SVC TOU PILOT >30KW	4	296			0.0739
57	OREGON - 01COSTR23T-RES GEN SVC TOU ENGY SPLY SVC	3	230			0.0766
58	OREGON - 01CSTR23MT-GEN SVC CST-BSD SPLY TOU MTR	1	63			0.0632
59	OREGON - 01FXRENEWR - Fixed Renewable Blue Sky		1			0.0000
60	OREGON - 01HABIT004 - 01RESD0004	52,039	3,767,735			0.0724
61	OREGON - 01HABTR023-RES GEN SVC HABITAT BLND	191	13,949			0.0730
62	OREGON - 01LNX00102-LINE EXT 80% G - RES		853			0.0000
63	OREGON - 01LNX00105-CNTRCT $ MIN G - RES		135			0.0000
64	OREGON - 01LNX00109-REF/NREF ADV + - RES		11,559			0.0000
65	OREGON - 01NETMT135-NET METERING		10,867,271	20,367		0.0000
66	OREGON - 01NETMT138-RES NET METERING-OSIP		4,362	7		0.0000
67	OREGON - 01NETTM135-RESIDENTIAL NET METERING TOU		10,455	18		0.0000
68	OREGON - 01NMT06135-RES TOU PILOT NET METERING		20,419	17		0.0000
69	OREGON - 01NMT07135-OR RES NET METERING LOW INC		493,177	704		0.0000
70	OREGON - 01NMT67135-RES TOU PLT NET MTR LOW INC		73			0.0000
71	OREGON - 01NMT7T135-OR TOU RES LOW INC NET METER		2,212	4		0.0000
72	OREGON - 01NMTM7135-RES LOW INC NET MTR TOU		615	1		0.0000
73	OREGON - 01NMTOU135-TOU NET METERING		161,655	281		0.0000
74	OREGON - 01NMTOU138-RES TOU NET METERING OSIP		109			0.0000
75	OREGON - 01OALTB15R-OR OUTD AR LGT RES	1,735	314,013	2,163	802	0.1810
76	OREGON - 01PTOU0004 - 01RESD0004	6,024	420,493			0.0698
77	OREGON - 01PTOURB23-RES GEN SVC; TOU SUPPLY SVC	8	564			0.0705
78	OREGON - 01RENEW004 - 01RESD0004	468,975	33,976,222			0.0724
79	OREGON - 01RENEW4MT-RENEWABLE USAGE SPPLY SVC TOU	2	135			0.0673
80	OREGON - 01RENWR023-RENEW USAGE SPLY SVC-GEN SVC	508	37,003			0.0728
81	OREGON - 01RESD0004-RES SRVC		405,516,893	455,228		0.0000
82	OREGON - 01RESD0006-RES TIME-OF-DA		91,434	56		0.0000
83	OREGON - 01RESD0007-OR RESIDENTIAL LOW INCOME		65,692,609	67,684		0.0000
84	OREGON - 01RESD004T - RES Time Option		1,629,968	1,548		0.0000
85	OREGON - 01RESD007T-OR TOU RESIDENTIAL LOW INCOME		166,403	160		0.0000
86	OREGON - 01RESD0607-OR RES TOU PILOT LOW INC		6,874	5		0.0000
87	OREGON - 01RESDT004-OR TIME-OF-USE RES TOU METER		344,663	382		0.0000
88	OREGON - 01RESDT007-RESIDENTIAL TOU METER LOW INC		49,038	52		0.0000
89	OREGON - 01RGNS2807-RES GEN SVC > 30 KW LOW INC		25,898	7		0.0000
90	OREGON - 01RGNSB023-SMALL GENERAL SVC-RES		10,543,651	16,672		0.0000
91	OREGON - 01RGNSB028 - GENERAL SVC > 30 KW - RES		1,752,578	197		0.0000
92	OREGON - 01RGNSB029-OR RES GEN SVC TOU PILOT		1,287	1		0.0000
93	OREGON - 01RGNSB23T-RES GEN SVC TOU PORTFOLIO		1,288	2		0.0000
94	OREGON - 01RGNST023-GEN SVC <= 30 KW TOU METER		145			0.0000
95	OREGON - 01RNETM023-NET METER RESIDENTIAL GEN SVC		207,352	439		0.0000
96	OREGON - 01RNETM028-NET METER RESIDENTIAL GEN SVC		136,219	11		0.0000
97	OREGON - 01RNM23135-NET METER SMALL GEN SVC		2,077	6		0.0000
98	OREGON - 01UPPL000R-BASE SCH FALL			2		0.0000
99	OREGON - 01VIR04136-OR RES VOLUME INCENTIVE		596,103	441		0.0000
100	OREGON - 01VIR06136-OR RES VOLUME INCENTIVE		663			0.0000
101	OREGON - 01VIR07136-OR RES VOLUME INCNTV LOW INC		10,027	9		0.0000
102	OREGON - 01VIR4T136-RES VOLUMETRIC INCENTIVE TOU		6,572	6		0.0000
103	OREGON - REVENUE_ACCOUNTING ADJUSTMENTS - RES		15,776,812			0.0000
104	OREGON - SOLAR FEED-IN REVENUE - RES		1,661,088			0.0000
105	OREGON - OTHER CUSTOMER RETAIL REVENUE - RES		762,299			0.0000
106	OREGON - COMMUNITY SOLAR REVENUE - RES		705,670			0.0000
107	OREGON - DSM REVENUE-RESIDENTIAL		48,574,600			0.0000
108	OREGON - BLUE SKY REVENUE-RESIDENTIAL		1,127,067			0.0000
109	UTAH - 08ACTSETUP-NEW SRVC SETUP					0.0000
110	UTAH - 08BLSKY01R-BLUESKY ENERGY		2			0.0000
111	UTAH - 08CFR00001-MTH FACILITY S		735			0.0000
112	UTAH - 08CGENR136-UT RES TRANSITION GENERATION	750	86,544	71	10,563	0.1154
113	UTAH - 08CGNSL136-UT RES TRANSITION GEN-SOLEIL	2,961	306,310	600	4,935	0.1034
114	UTAH - 08CGR01136-UTAH RESIDENTIAL TRANS GEN	148,726	16,793,238	16,740	8,884	0.1129
115	UTAH - 08CGR01137-UT RES CUST GENERATION 137	195,904	22,206,339	23,713	8,261	0.1134
116	UTAH - 08CGR02136-UT RES TOU TRANSITION GEN	244	26,558	23	10,609	0.1088
117	UTAH - 08CGR02137-UT RES TOU CUST GEN 137	367	40,649	42	8,738	0.1108
118	UTAH - 08CGR03136-UTAH LOW INC RES TRANS GEN	1,431	161,433	162	8,833	0.1128
119	UTAH - 08CGR03137-UT LOW INC RES CUST GEN 137	1,755	198,820	195	9,000	0.1133
120	UTAH - 08CGR06136-RES USE, GEN SVC RATE, MANUAL	241	24,277	2	120,500	0.1007
121	UTAH - 08CGR1T136-UT RES TRANSITION GEN TOU	157	14,829	10	15,700	0.0945
122	UTAH - 08CGR1T137-UT RES CUST GEN 137 TOU	400	36,960	25	16,000	0.0924
123	UTAH - 08CGR23136-RESIDENTIAL SMALL GEN SVC	647	60,537	9	71,889	0.0936
124	UTAH - 08CGR23137-RES SM GEN SVC - CUST GEN 137	585	59,591	42	13,929	0.1019
125	UTAH - 08CGR2E136-UT RES EV TOU PILOT-TRAN GEN	1,347	111,197	93	14,484	0.0826
126	UTAH - 08CGR2E137-UT RES EV TOU PILOT CUST GEN	3,039	246,432	217	14,005	0.0811
127	UTAH - 08CGRA1137-UT RES CUST GEN AGGEGATED	6,081	690,651	1,066	5,705	0.1136
128	UTAH - 08CGRW1136-UT RES TRANS GEN-WATTSMART	1,897	222,657	292	6,497	0.1174
129	UTAH - 08CGRW1137-UT RES CUST GEN 137-WATTSMART	17,022	1,971,817	2,517	6,763	0.1158
130	UTAH - 08CGRW2137-RES TOU CUS GEN 137 WATTSMART	5	536	1	5,000	0.1073
131	UTAH - 08CGS23136-RES SMALL GEN SVC MANUAL	604	67,895	51	11,843	0.1124
132	UTAH - 08CGW03137-LOW INC CUST GEN 137 WTTSMRT	48	5,524	7	6,857	0.1151
133	UTAH - 08CGW1T136-UT RES TRANS GEN-WTSMT TOU	18	1,596	1	18,000	0.0887
134	UTAH - 08CGW1T137-UT RES CUST GEN 137-WTSMT TOU	22	1,980	2	11,000	0.0900
135	UTAH - 08CGW2E136-RES EV TOU PLT TRAN GEN-WTSMT	49	4,166	4	12,250	0.0850
136	UTAH - 08CGW2E137-RES EV TOU PILOT-CUST GEN 137	167	14,262	17	9,824	0.0854
137	UTAH - 08CHCK000R-UT RES CHECK M			1		0.0000
138	UTAH - 08COOLKPRR - Utah Cool Keeper Program		85			0.0000
139	UTAH - 08CRA23137-UT RES SML GEN SVC 137 AGGREG	191	21,966	21	9,095	0.1150
140	UTAH - 08LNX00001-MTHLY 80% GUAR		4,040			0.0000
141	UTAH - 08LNX00013-80% MNTHLY MIN		18,048			0.0000
142	UTAH - 08LNX00108-ANN COST MTHLY		1,224			0.0000
143	UTAH - 08MHTP0006-MOBILE HOME & TRAILER	11,166	878,655	7	1,595,143	0.0787
144	UTAH - 08MHTP0023-MOBILE HOME & TRAILER	148	11,814	1	148,000	0.0798
145	UTAH - 08NETAGFEE-> 6 NET METER AGGREGATION FEE		3,725	12		0.0000
146	UTAH - 08NETMT135 - Net Metering	158,600	19,494,532	29,139	5,443	0.1229
147	UTAH - 08NETMW135-UT RES NET METER-WATTSMART	1,484	189,912	319	4,652	0.1280
148	UTAH - 08NMT02135-UTAH RESIDENTIAL TOU NET MTR	2	249	1	2,000	0.1244
149	UTAH - 08NMT03135-LOW INCOME RES NET METERING	1,800	203,368	238	7,563	0.1130
150	UTAH - 08NMTOU135-UT RES NET METERING TOU	29	3,237	4	7,250	0.1116
151	UTAH - 08OALT007R-SECURITY AR LG	1,874	333,179	2,078	902	0.1778
152	UTAH - 08PTLD000R-POST TOP LIGHT			1		0.0000
153	UTAH - 08RCG23136-RES NET METER, SMALL GEN SVC	239	22,379	15	15,933	0.0936
154	UTAH - 08RESD0001-RES SRVC	7,720,445	869,330,653	857,508	9,003	0.1126
155	UTAH - 08RESD0002-RES SRVC-OPTIO	3,908	437,264	412	9,485	0.1119
156	UTAH - 08RESD0003-LIFELINE PRGRM	166,481	18,497,603	21,225	7,844	0.1111
157	UTAH - 08RESD001T-UTAH RESIDENTIAL TOU	2,426	232,606	177	13,706	0.0959
158	UTAH - 08RESD002E-RES ELCTRC VEHICLE TOU PILOT	25,111	2,317,775	1,540	16,306	0.0923
159	UTAH - 08RESD003E-UT RES LOW INC ELEC V TOU PLT	93	9,383	7	13,286	0.1009
160	UTAH - 08RESD003T-UT RES LOW INCOME TOU	8	907	1	8,000	0.1134
161	UTAH - 08RESD3401-RESIDENTIAL SCH 34	75	9,430	16	4,688	0.1257
162	UTAH - 08RGNSV006-GEN SRVC-RES	121,115	9,358,065	308	393,231	0.0773
163	UTAH - 08RGNSV008-UT RESIDENTIAL GENERAL SVC	700	50,123	1	700,000	0.0716
164	UTAH - 08RGNSV023-GEN SRVC-RES	103,418	11,354,044	14,778	6,998	0.1098
165	UTAH - 08RGNSV06A-UT SMALL GENERAL SVC-RES-TOU	7,744	629,654	30	258,133	0.0813
166	UTAH - 08RGNSV346-RES USE GEN SVC SCH 34	1,278	107,849	4	319,500	0.0844
167	UTAH - 08RNM06135 - UT NET MTR, GEN SVC-RES	3,359	300,928	13	258,385	0.0896
168	UTAH - 08RNM23135 - UT NET MTR, GEN SVC-RES	1,412	176,902	401	3,521	0.1253
169	UTAH - 08RNM6A135-RES GEN SVC NET METERING	188	18,772	3	62,667	0.0999
170	UTAH - 08RTCVLNGA-TCV LNX GAR		3,792			0.0000
171	UTAH - 08SSLR0001 - RESIDENTIAL SUBSCRB SOLAR	24,993	3,043,824			0.1218
172	UTAH - 08SSLR0003-RES LOW INC SUBSCR SOLAR	198	24,173	18	11,000	0.1221
173	UTAH - 08SSLRRG23-RES SMALL GEN SV SUBSCR SOLAR	51	7,787	18	2,833	0.1527
174	UTAH - REVENUE_ACCOUNTING ADJUSTMENTS - RES		34,695,718			0.0000
175	UTAH - REVENUE ADJUSTMENT - DEFERRED NPC - RES		156,220,025			0.0000
176	UTAH - OTHER CUSTOMER RETAIL REVENUE - RES		2,277,497			0.0000
177	UTAH - DSM REVENUE-RESIDENTIAL		22,181,228			0.0000
178	UTAH - BLUE SKY REVENUE-RESIDENTIAL		2,005,736			0.0000
179	WASHINGTON - 02BLSKY01R-BLUESKY ENERGY					0.0000
180	WASHINGTON - 02CHCK000R-WA RES CHECK M			3		0.0000
181	WASHINGTON - 02LNX00102-LINE EXT 80% G - RES		79			0.0000
182	WASHINGTON - 02LNX00109-REF/NREF ADV + - RES		2,933			0.0000
183	WASHINGTON - 02NETMT135 - WA RES NET METERING	26,188	3,757,682	3,177	8,243	0.1435
184	WASHINGTON - 02NML17135-RES BILL ASSIST NET METERING	140	21,524	18	7,778	0.1537
185	WASHINGTON - 02NMT17135-WA RES BILL ASSIST NET MTR	199	26,492	12	16,583	0.1331
186	WASHINGTON - 02NMT19135-RES TOU PILOT NET METERING	62	8,579	6	10,333	0.1384
187	WASHINGTON - 02OALTB15R-WA OUTD AR LGT RES	833	137,781	951	876	0.1654
188	WASHINGTON - 02RES1719T-RES BILL ASSIST TOU PILOT	32	4,765	3	10,667	0.1489
189	WASHINGTON - 02RESD0016-WA RES SRVC	1,439,092	202,099,979	102,252	14,074	0.1404
190	WASHINGTON - 02RESD0017-RESIDENTIAL BILL ASSISTANCE	55,813	7,412,362	3,072	18,168	0.1328
191	WASHINGTON - 02RESD019T-WA RESIDENTIAL TOU PILOT	1,228	169,996	74	16,595	0.1384
192	WASHINGTON - 02RESDL017-RESIDENTIAL BILL ASSISTANCE	58,660	8,644,755	4,624	12,686	0.1474
193	WASHINGTON - 02RESDL19T-WA RES BILL ASSIST TOU PILOT	5	751	1	5,000	0.1502
194	WASHINGTON - 02RGNSB024-WA SMALL GENERAL SVC-RES	20,916	3,443,448	3,374	6,199	0.1646
195	WASHINGTON - 02RGNSB036-RES LRG GEN SVC < 1000 KW	2,164	268,346	4	541,000	0.1240
196	WASHINGTON - 02RNM24135-RES NET METER SMALL GEN SVC	456	75,630	79	5,772	0.1659
197	WASHINGTON - RESIDENTIAL CUSTOMER BILL CREDITS		552,879			0.0000
198	WASHINGTON - INCOME TAX DEFERRAL ADJUSTMENTS - RES		963,240			0.0000
199	WASHINGTON - REVENUE ADJUSTMENT - DEFERRED NPC - RES		1,070,835			0.0000
200	WASHINGTON - REVENUE_ACCOUNTING ADJUSTMENTS - RES		10,872,967			0.0000
201	WASHINGTON - DSM REVENUE-RESIDENTIAL		11,044,234			0.0000
202	WASHINGTON - BLUE SKY REVENUE-RESIDENTIAL		179,071			0.0000
203	WASHINGTON - ALT REVENUE PROGRAM ADJUSTMENTS - RES		22,642,810			0.0000
204	WYOMING - 05BLSKY01R-BLUESKY ENERGY					0.0000
205	WYOMING - 05LNX00102-LINE EXT 80% G - RES		582			0.0000
206	WYOMING - 05LNX00109-REF/NREF ADV + - RES		1,921			0.0000
207	WYOMING - 05NETMT135 - EXPERIMENTAL PARTIAL REQ - RES	4,562	717,263	818	5,577	0.1572
208	WYOMING - 05NMT19135-RES NET METER TOU PILOT	6	1,109	2	3,000	0.1848
209	WYOMING - 05OALT015R-OUTD AR LGT SR - RES	733	110,989	918	798	0.1514
210	WYOMING - 05RESD0002-WY RES SRVC - RES	894,889	130,351,109	104,019	8,603	0.1457
211	WYOMING - 05RESD0019-WY RES TOU PILOT - RES	494	65,604	38	13,000	0.1328
212	WYOMING - 05RGNSV025-WY SMALL GENERAL SVC-RES - RES	9,451	1,517,537	1,547	6,109	0.1606
213	WYOMING - 05RNM25135-WY RES SMALL GEN SVC NET MTR	10	1,823	3	3,333	0.1823
214	WYOMING - REVENUE ADJUSTMENT - DEFERRED NPC - RES		346,697			0.0000
215	WYOMING - REVENUE_ACCOUNTING ADJUSTMENTS - RES		635,437			0.0000
216	WYOMING - DSM REVENUE-RESIDENTIAL - RES		2,375,699			0.0000
217	WYOMING - DSM REVENUE-RESIDENTIAL GEN SVC - RES		36,862			0.0000
218	WYOMING - BLUE SKY REVENUE-RESIDENTIAL - RES		113,417			0.0000
219	WYOMING - OTHER CUSTOMER RETAIL REVENUE - RES		29,159			0.0000
220	WYOMING - 05RESD0002-WY RES SRVC	115,453	16,691,890	13,064	8,837	0.1446
221	WYOMING - 05RESD0019-WY RES TOU PILOT	36	5,137	4	9,000	0.1427
222	WYOMING - 05RGNSV025-WY SMALL GENERAL SVC-RES	583	114,728	156	3,737	0.1968
223	WYOMING - 05NETMT135 - EXPERIMENTAL PARTIAL REQ	1,502	225,929	269	5,584	0.1504
224	WYOMING - 05OALT015R-OUTD AR LGT SR	62	10,727	79	785	0.1730
225	WYOMING - 09RES00002			1		0.0000
226	WYOMING - 09RESD0002			3		0.0000
227	WYOMING - DSM REVENUE-RESIDENTIAL		461,336			0.0000
228	WYOMING - DSM REVENUE-RESIDENTIAL GEN SVC		3,263			0.0000
229	WYOMING - BLUE SKY REVENUE-RESIDENTIAL		19,567			0.0000
230	LESS MULTIPLE BILLINGS			25,451
41	TOTAL Billed Residential Sales	18,350,850	2,742,104,023	1,867,245	9,828	0.1494
42	TOTAL Unbilled Rev. (See Instr. 6)	81,235	27,082,000			0.3334
43	TOTAL	18,269,615	2,769,186,023	1,867,245	9,828	0.1516

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, list the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	CALIFORNIA - 06GNSV0025-CA GEN SRVC - COM	54,710	11,888,134	6,567	8,331	0.2173
2	CALIFORNIA - 06GNSV025F-GEN SRVC-< 20	909	236,934	82	11,085	0.2607
3	CALIFORNIA - 06GNSV029L-GEN SVC TOU PILOT > 20 KW	81	21,819	2	40,500	0.2694
4	CALIFORNIA - 06GNSV0A32-GEN SRVC-20 KW - COM	88,031	20,501,331	1,129	77,973	0.2329
5	CALIFORNIA - 06LGSV048T-LRG GEN SERV - COM	29,690	5,213,800	12	2,474,167	0.1756
6	CALIFORNIA - 06NMT48135-CA GEN SVC NET MTR->500 KW	3,112	480,454	1	3,112,000	0.1544
7	CALIFORNIA - 06LGSV0A36-LRG GEN SRVC-O - COM	51,506	10,391,161	130	396,200	0.2017
8	CALIFORNIA - 06LNX00102-LINE EXT 80% G		11,026	0		0.0000
9	CALIFORNIA - 06LNX00109-REF/NREF ADV +		107,815	0		0.0000
10	CALIFORNIA - 06LNX00300 - 80% MONTHLY MIN GUAR + 80%		1,344	0		0.0000
11	CALIFORNIA - 06LNX00311 - LINE EXT 80% GUARANTEE		11,761	0		0.0000
12	CALIFORNIA - 06NB29L136-GEN SVC>20KW NO CCC OPT TOU			0		0.0000
13	CALIFORNIA - 06NBL25136-CA NET BILL GEN SVC < 20 KW	614	147,156	18	34,111	0.2397
14	CALIFORNIA - 06NBL32136-CA NET BILL GEN SVC >= 20 KW	3,230	714,608	13	248,462	0.2212
15	CALIFORNIA - 06NBL36136-NT BILL GEN SRV =>100 KW OPTL	193	60,830	1	193,000	0.3152
16	CALIFORNIA - 06NMT36135-CA GEN SVC NET MTR->100 KW	3,188	673,894	6	531,333	0.2114
17	CALIFORNIA - 06OALT015N-OUTD AR LGT SR	544	200,535	427	1,274	0.3686
18	CALIFORNIA - 06RCFL0042-AIRWAY & ATHLE	161	54,812	37	4,351	0.3404
19	CALIFORNIA - 06NMT25135-CA GEN SVC NET MTR<20KW	222	43,859	46	4,826	0.1976
20	CALIFORNIA - 06NMT32135-CA GEN SVC NET MTR>20KW	4,000	946,786	36	111,111	0.2367
21	CALIFORNIA - REVENUE_ACCOUNTING ADJUSTMENTS - COM		551,429			0.0000
22	CALIFORNIA - REVENUE ADJUSTMENT - DEFERRED NPC - COM		16,844			0.0000
23	CALIFORNIA - DSM REVENUE-COMMERCIAL		592,059			0.0000
24	CALIFORNIA - BLUE SKY REVENUE-COMMERCIAL		9,206			0.0000
25	IDAHO - 07GNSV0006-GEN SRVC-LRG P - COM	252,969	27,755,532	990	255,524	0.1097
26	IDAHO - 07GNSV0009-GEN SRVC-HI VO - COM	58,942	4,806,897	5	11,788,400	0.0816
27	IDAHO - 07GNSV0023-GEN SRVC-SML P - COM	233,442	28,550,395	9,162	25,479	0.1223
28	IDAHO - 07GNSV0035-GEN SRVCOPTION	579	85,431	6	96,500	0.1475
29	IDAHO - 07GNSV006A-GEN SRVC-LRG P - COM	18,062	2,060,436	152	118,829	0.1141
30	IDAHO - 07GNSV023A-GEN SRVC-SML P - COM	30,053	3,663,121	1,250	24,042	0.1219
31	IDAHO - 07GNSV023F-GEN SRVC SML P	6	2,180	4	1,500	0.3633
32	IDAHO - 07GNSV035A-GEN SRVCOPTION	63	9,830	2	31,500	0.1560
33	IDAHO - 07LNX00010-MNTHLY 80%GUAR - COM		22,793	0		0.0000
34	IDAHO - 07LNX00035-ADV 80%MO GUAR - COM		266,729	0		0.0000
35	IDAHO - 07LNX00040-ADV+REFCHG+80% - COM		18,709	0		0.0000
36	IDAHO - 07OALT007N-SECURITY AR LG - COM	200	29,672	152	1,316	0.1484
37	IDAHO - 07OALT07AN-SECURITY AR LG	8	2,374	11	727	0.2967
38	IDAHO - 07TCVLNAGN-TCV LNX ANNUAL GAR-NON RES		277	0		0.0000
39	IDAHO - 07TCVLNXGN-TCV LNX - 80% GAR - NON RES		10,437	0		0.0000
40	IDAHO - 07TCVLXACN-GAR ADDED CAPACITY NON RES		8,757	0		0.0000
41	IDAHO - 07LNX00312 - ID LINE EXT - COM		13,838	0		0.0000
42	IDAHO - 07NBL23136-ID NET BILLING SML GEN SVC - COM	474	38,320	27	17,556	0.0808
43	IDAHO - 07NBL6A136-ID NET BILLING LRG GEN SVC	305	35,489	1	305,000	0.1164
44	IDAHO - 07NBW23136-SM GEN SVC NET BILL WATTSMART	3	526	1	3,000	0.1755
45	IDAHO - 07NMT06135 - ID NET MTR - LARGE GEN SVC	3,687	410,740	8	460,875	0.1114
46	IDAHO - 07NMT23135 - ID NET MTR - SMALL GEN SVC - COM	1,728	188,750	42	41,143	0.1092
47	IDAHO - 07NMT6A135-NET METERING LARGE GEN SVC	130	16,744	1	130,000	0.1288
48	IDAHO - 07LNX00311 - LINE EXT 80% GUARANTEE - COM		20,692			0.0000
49	IDAHO - 07LNX00300 - 80% MONTHLY MIN GUAR + 80%		2,430			0.0000
50	IDAHO - DSM REVENUE-COMMERCIAL		1,389,342			0.0000
51	IDAHO - BLUE SKY REVENUE-COMMERCIAL		3,027	1		0.0000
52	OREGON - 01COST0023, OR GEN SRV, COST BASED - COM	1,022,982	70,991,991	0		0.0694
53	OREGON - 01COST0048 - 01LGSV0048 - COM	3,054,449	181,932,776	0		0.0596
54	OREGON - 01COST023F - OR GEN SRV - COST-BASED - COM	2,884	209,525	0		0.0727
55	OREGON - 01COST023T-GEN SVC TOU ENERGY SUPPLY SVC - COM	127	8,010	0		0.0631
56	OREGON - 01COST23MT-OR GEN SVC COST TOU MTR - COM	6,993	399,914	0		0.0572
57	OREGON - 01COST28MT-OR GEN SVC>30KW COST TOU MTR	1,842	126,717	0		0.0688
58	OREGON - 01COST30MT-LG GEN SVC>200KW COST TOU MTR - COM	83,887	4,491,489	0		0.0535
59	OREGON - 01COSTB023 - OR GEN SRV, CST-BSD SPLY - COM	20,635	1,457,072	0		0.0706
60	OREGON - 01COSTEV45-ELECT VEHICLE DC FAST CHG SVC	9,192	633,100	0		0.0689
61	OREGON - 01COSTL030 - OR LRG GEN SRV, CST >200 kW - COM	957,759	51,470,183	0		0.0537
62	OREGON - 01COSTS028, OR GEN SERV, COST > 30kW - COM	1,880,143	129,514,384	0		0.0689
63	OREGON - 01COSTS029-OR GEN SVC TOU PILOT COS>30KW	3,110	225,893	0		0.0726
64	OREGON - 01GNCEL23F-OR SMALL CELL FLAT RATE		3,489	3		0.0000
65	OREGON - 01GNSB0023, OR GEN SRV, BPA, < 30 kW - COM		2,216,793	2,695		0.0000
66	OREGON - 01GNSB0028, OR GEN SRV, BPA, > 30 kW - COM		2,218,034	229		0.0000
67	OREGON - 01GNSB0029-OR GEN SVC TOU BPA		13,085	2		0.0000
68	OREGON - 01GNSB023T - OR GEN SRV - TOU - BPA		11,194	16		0.0000
69	OREGON - 01GNSBT023-OR GEN SVC<=30 KW TOU MTR		11,809	16		0.0000
70	OREGON - 01GNSEV45T-ELECT VEHICLE DC FAST CHG<1MW		979,068	29		0.0000
71	OREGON - 01GNSV0023, OR GEN SRV, < 30 KW - COM		91,155,892	63,596		0.0000
72	OREGON - 01GNSV0028, OR GEN SRV > 30 kW - COM		84,040,716	8,953		0.0000
73	OREGON - 01GNSV0029-OR GEN SVC TOU PILOT > 30 KW		248,622	19		0.0000
74	OREGON - 01GNSV023F - OR GEN SRV - FLAT RATE - COM	8,892	1,984,556	790	11,256	0.2232
75	OREGON - 01GNSV023M - OR GEN SRV, MANUAL BILL - COM	75	10,635	2	37,500	0.1418
76	OREGON - 01GNSV023T, OR GEN SRV, TOU Option - COM		109,683	86		0.0000
77	OREGON - 01GNSV0723-OR GEN SVC DIR ACCESS <= 30KW		105,868	6		0.0000
78	OREGON - 01HABT0023, OR HABITAT BLENDED SPLY SRV	2,180	153,627	0		0.0705
79	OREGON - 01HABTB023 - OR HABITAT BLENDED	6	423	0		0.0706
80	OREGON - 01LGSB0030, GEN DEL SRV, > 200 kW(R)		1,570,781	20		0.0000
81	OREGON - 01LGSV0030 - OR LRG GEN SRV, > 1000 kW - COM		47,913,158	587		0.0000
82	OREGON - 01LGSV0048-1000KW AND OVR - COM		75,705,657	98		0.0000
83	OREGON - 01LGSV048M-LRG GEN SRVC 1 - COM	51,122	4,553,597	1	51,122,000	0.0891
84	OREGON - 01LGSVT030-OR LG GEN SVC>200KW TOU MTR - COM		3,970,432	29		0.0000
85	OREGON - 01LNX00100-LINE EXT 60% G		282	0		0.0000
86	OREGON - 01LNX00102-LINE EXT 80% G - COM		922,704	0		0.0000
87	OREGON - 01LNX00103-LINE EXT 80% G - COM		532	0		0.0000
88	OREGON - 01LNX00105-CNTRCT $ MIN G		11,703	0		0.0000
89	OREGON - 01LNX00109-REF/NREF ADV + - COM		1,317,695	0		0.0000
90	OREGON - 01LNX00110-REF/NREF ADV + - COM		7,123	0		0.0000
91	OREGON - 01LNX00311 - LINE EXT 80% G		149,468	0		0.0000
92	OREGON - 01LNX00312 - OR IRG LINE EXT - COM		1,465	0		0.0000
93	OREGON - 01LNX00300 - LINE EXT 80% GUARANTEE - COM		104,997	0		0.0000
94	OREGON - 01LPRS047M-PART REQ SRVC - COM	42,868	5,459,416	5	8,573,600	0.1274
95	OREGON - 01NM23T135-OR NET MTR TOU GEN SVC<30 KW		3,238	2		0.0000
96	OREGON - 01NMB23135-OR NET MTR GEN SVC <= 30 KW		35,839	78		0.0000
97	OREGON - 01NMB28135-OR NET MTR GEN SVC > 30 KW		56,152	6		0.0000
98	OREGON - 01NMT23135 - OR NET MTR, GEN, < 30 kW - COM		938,063	779		0.0000
99	OREGON - 01NMT23138-NET MTR GEN SVC <=30 KW OSIP		47			0.0000
100	OREGON - 01NMT28135 - OR NET MTR, GEN, > 30 kW - COM		3,795,715	368		0.0000
101	OREGON - 01NMT28138-NET MTR GEN SVC>30 KW OSIP		2,167	1		0.0000
102	OREGON - 01NMT30135 - OR NET MTR, GEN, > 200 kW - COM		3,521,930	43		0.0000
103	OREGON - 01NMT48135-NET METERING GEN SVC => 1000		1,113,947	5		0.0000
104	OREGON - 01NTM23135-NET MTR GEN SVC <=30 KW TOU		414	1		0.0000
105	OREGON - 01OALT015N-OUTD AR LGT NR - COM	4,763	646,625	2,741	1,738	0.1358
106	OREGON - 01OALTB15N-OR OUTD AR LGT NR - COM	1,238	216,433	1,004	1,233	0.1748
107	OREGON - 01OSU0000N-NON-RESIDENTIAL-OSU METERS			107		0.0000
108	OREGON - 01PTOU0023, OR GEN SRV, TOU ENG SPLY SRV - COM	1,107	76,803			0.0694
109	OREGON - 01PTOUB023, OR GEN SRV, TOU SPLY SRV	98	6,999			0.0714
110	OREGON - 01RCFL0054-REC FIELD LGT	1,397	146,464	95	14,705	0.1048
111	OREGON - 01RENW0023, OR RENW USAGE SPLY SRV - COM	9,651	682,258			0.0707
112	OREGON - 01RENWB023 - OR RENEWABLE USAGE	31	2,291			0.0739
113	OREGON - 01STDAY023 - OR DAY STD OFR, SCH 23	3,310	220,575			0.0666
114	OREGON - 01STDAY028 - OR DAY STD OFF, SCH 28 - COM	4,244	275,769			0.0650
115	OREGON - 01STDAY030 - OR STD DAY OFF, SCH 27 - COM	5,558	283,121			0.0509
116	OREGON - 01VIR23136-OR VOLUME INCENTIVE <= 30 KW - COM		312,781	133		0.0000
117	OREGON - 01VIR28136-OR VOLUME INCENTIVE > 30 KW - COM		732,953	74		0.0000
118	OREGON - 01VIR30136-OR VOLUME INCENTIVE > 200 kW - COM		312,349	4		0.0000
119	OREGON - 01VIR48136-OR VOLUME INCENTIVE > 1000 KW		181,815	1		0.0000
120	OREGON - 01ZZMERGCR-MERGER CREDITS		1			0.0000
121	OREGON - 01LGSB0048 - LG GEN SVC > 1000KW (R) - COM		871,818	1		0.0000
122	OREGON - 01LGSV028M - OR LGSV, <1000 kW, Manual	538	62,947	1	538,000	0.1170
123	OREGON - 01GNSV0728 - OR GEN SVC DIR ACCESS >30KW - COM		350,338	17		0.0000
124	OREGON - 01GNSV0730 -OR GEN SVC DIR ACCESS >200KW - COM		2,311,339	18		0.0000
125	OREGON - 01GNSV0748 LG GEN SVC DIR ACCESS 1000KW+ - COM		4,158,603	4		0.0000
126	OREGON - 01GNSV0848-LG GEN SVC > 1000 DA DEL		2,641,717	1		0.0000
127	OREGON - 01GNSVT023-OR GEN SVC <=30 KW TOU MTR - COM		520,538	78		0.0000
128	OREGON - 01GNSVT028-OR GEN SVC>30KW TOU MTR - COM		94,713	7		0.0000
129	OREGON - REVENUE_ACCOUNTING ADJUSTMENTS - COM		15,713,842			0.0000
130	OREGON - SOLAR FEED-IN REVENUE - COM		1,722,280			0.0000
131	OREGON - OTHER CUSTOMER RETAIL REVENUE - COM		995,056			0.0000
132	OREGON - COMMUNITY SOLAR REVENUE - COM		812,475			0.0000
133	OREGON - DSM REVENUE-COMMERCIAL		55,682,695			0.0000
134	OREGON - BLUE SKY REVENUE-COMMERCIAL		1,289,269	86		0.0000
135	UTAH - 08ABTCLAGN-80% CONTRACT MINIMUM ANNUAL		18,546			0.0000
136	UTAH - 08ABTCLXGN-LINE EXT 80% CONTRACT MIN		58,713			0.0000
137	UTAH - 08C3423136-NET MTR SM GEN SVC SCH 34 - COM	16	1,942	1	16,000	0.1213
138	UTAH - 08C346A136-GEN SVC TRANS TOU MAN SCH 34	164	16,804	1	164,000	0.1025
139	UTAH - 08C346A137-GEN SVC TRANS TOU MAN SCH 34	503	39,893	1	503,000	0.0793
140	UTAH - 08CFR00051-MTH FAC SRVCHG - COM		22,947			0.0000
141	UTAH - 08CG6MN137-GENSVC CUSTGEN137 NOMIGRATION	3,677	272,307	1	3,677,000	0.0741
142	UTAH - 08CGA06137-UT GEN SVC CUST GEN 137	116	19,572	2	58,000	0.1687
143	UTAH - 08CGA23137-UT NET MTR SMALL GEN SVC - COM	998	103,778	47	21,234	0.1040
144	UTAH - 08CGA6A137-GEN SVC TOU ENRGY 137 AGRGTD	385	46,406	2	192,500	0.0000
145	UTAH - 08CGAG6137-GEN SVC CUST GEN 137 AGGREGAT	198	43,554	3	66,000	0.0000
146	UTAH - 08CGM06136-UT NET METERING GENERAL SVC	6,179	589,470	10	617,900	0.0954
147	UTAH - 08CGM23136-UTAH NET METER SM GEN SVC - COM	836	92,111	49	17,061	0.1102
148	UTAH - 08CGM6A136-UTAH GEN SVC TRANS GEN TOU	5,115	519,376	22	232,500	0.1015
149	UTAH - 08CGM6A137-UT GEN SVC TRANS TOU MAN 137 - COM	5,145	540,635	19	270,789	0.1051
150	UTAH - 08CGN08136-UT NET MTR GEN SVC > 1000 KW	14,760	1,139,718	2	7,380,000	0.0772
151	UTAH - 08CGN08137-UT NET MTR FEN SVC>1000 KW - COM	2,703	266,991	1	2,703,000	0.0988
152	UTAH - 08CGN06136-UT GEN SVC TRANSITION GEN - COM	43,018	3,894,689	76	566,026	0.0905
153	UTAH - 08CGN06137-UT GEN SVC CUST GEN 137 - COM	28,770	3,049,688	106	271,415	0.1060
154	UTAH - 08CGN23136-UTAH NET METER SMALL GEN SVC	2,581	267,178	133	19,406	0.1035
155	UTAH - 08CGN23137-UT NET MTR SMALL GEN SVC - COM	4,028	396,283	157	25,656	0.0984
156	UTAH - 08CGN6B136-UT GEN SVC TRAN TOU - DEMAND					0.0000
157	UTAH - 08CGW06136-GEN SVC TRANS GEN WATTSMART	766	63,320	2	383,000	0.0827
158	UTAH - 08CGW06137 -GEN SVC CUST GEN 137 WATTSMT	4	1,029			0.2573
159	UTAH - 08CGW23136-NET METER SM GEN SVC WTTSMRT	1	139			0.1392
160	UTAH - 08CMW6A136-GEN SVC TRANS TOU MAN-WTTSMRT	503	40,665	1	503,000	0.0808
161	UTAH - 08CN346136-GEN SVC TRANSITION GEN SCH 34 - COM	982	101,681	5	196,400	0.1035
162	UTAH - 08COOLKPRN - A/C DIRECT LOAD CONTROL		43			0.0000
163	UTAH - 08FEE01034-SCH 34 ELEKTRON FEE-DEER VLY		5,500	1		0.0000
164	UTAH - 08FEE02034-SCH 34 ELEKTRON FEE-PARK CITY		6,000	1		0.0000
165	UTAH - 08FEE03034-SCH 34 ELEKTRON FEE-SLC CORP		6,000	1		0.0000
166	UTAH - 08FEE04034-SCH 34 ELEKTRON FEE-SUMMIT		5,664	6		0.0000
167	UTAH - 08FEE05034-SCH 34 ELEKTRON FEE-UVU		6,000	1		0.0000
168	UTAH - 08FEE06034-SCH 34 ELEKTRON FEE-VRCPC		6,000	5		0.0000
169	UTAH - 08GNSV0006-GEN SRVC-DISTR - COM	5,232,426	447,428,414	12,288	425,816	0.0855
170	UTAH - 08GNSV0009-GEN SRVC-HI VO - COM	1,251,542	71,778,594	52	24,068,115	0.0574
171	UTAH - 08GNSV0023-GEN SRVC-DISTR - COM	1,388,506	137,690,845	83,456	16,637	0.0992
172	UTAH - 08GNSV006A-GEN SRVC-ENERG - COM	313,503	36,539,597	2,005	156,361	0.1166
173	UTAH - 08GNSV006M-MNL DIST VOLTG			1		0.0000
174	UTAH - 08GNSV009A-GEN SRVC HI VO - COM	25,634	1,412,215	2	12,817,000	0.0551
175	UTAH - 08GNSV009M-MANL HIGH VOLT - COM	235,237	13,599,928	2	117,618,500	0.0578
176	UTAH - 08GNSV023F-GEN SRVC FIXED	1,272	183,091	128	9,938	0.1439
177	UTAH - 08GNSV06AM-MNL ENERGY TOD	246	26,201	1	246,000	0.1065
178	UTAH - 08GNSV06MN-GNSV DIST VOLT - COM	22,282	1,850,627	402	55,428	0.0831
179	UTAH - 08GNSV3406-GENERAL SERVICE SCH 34 - COM	85,850	7,017,316	128	670,703	0.0817
180	UTAH - 08GNSV3408-TOU GEN SVC > 1000 KW SCH 34	30,765	2,953,886	13	2,366,538	0.0960
181	UTAH - 08GNSV3409-TOU GEN SVC TRANS DEL SCH 34 - COM	51,701	3,223,919	3	17,233,667	0.0624
182	UTAH - 08GNSV3423-SMALL GEN SVC SCH 34 - COM	8,090	794,091	596	13,574	0.0982
183	UTAH - 08GNSV346A-GEN SVC TOU ENERGY SCH 34 - COM	21,076	2,272,002	136	154,971	0.1078
184	UTAH - 08LNX00002-MTHLY 80% GUAR - COM		3,233,662			0.0000
185	UTAH - 08LNX00004-ANNUAL 80%GUAR - COM		397,064			0.0000
186	UTAH - 08LNX00006-FIXD MTHLY MIN		420			0.0000
187	UTAH - 08LNX00014-80% MIN MNTHLY - COM		2,748,825			0.0000
188	UTAH - 08LNX00017-ADV/REF&80%ANN - COM		147,734			0.0000
189	UTAH - 08LNX00158-ANNUALCOST MTH		29,274			0.0000
190	UTAH - 08LNX00300 - LINE EXT 80% PLUS MONTHLY - COM		175,574			0.0000
191	UTAH - 08LNX00310 - IRR, 80% ANNUAL MIN + 80% ?		36,862			0.0000
192	UTAH - 08LNX00312 UT IRG LINE EXT - COM		6,169			0.0000
193	UTAH - 08NMT06135-UT NET METERING GEN SVC - COM	107,784	9,562,706	259	416,154	0.0887
194	UTAH - 08NMT08135 - NET METERING GEN SVC - COM	41,265	3,208,776	15	2,751,000	0.0778
195	UTAH - 08NMT23135 - UT NET MTR, GEN, < 25 KW - COM	9,637	1,031,273	810	11,898	0.1070
196	UTAH - 08NMT6A135-NET METERING GEN SVC TOU - COM	14,739	1,404,956	86	171,384	0.0953
197	UTAH - 08NMT8135M - NET METERING GEN SVC MANUAL	10,874	943,126	1	10,874,000	0.0867
198	UTAH - 08NMW23135-UT NET MTR SM GEN SVC WTTSMRT	1	188			0.1877
199	UTAH - 08OALT007N-SECURITY AR LG - COM	6,673	924,772	3,982	1,676	0.1386
200	UTAH - 08PRSV031M-BKUP MNT&SUPPL - COM	208,031	12,079,718	4	52,007,750	0.0581
201	UTAH - 08PTLD000N-POST TOP LIGHT	6	453	2	3,000	0.0755
202	UTAH - 08REFP034M-RENEWABLE QUAL CUST > 5000 KW	1,279,359	54,229,252	1	1,279,360,000	0.0424
203	UTAH - 08REFS032M-UT RENEWABLE FAC & SUPP PWR	287,821	20,052,801	24	11,992,542	0.0697
204	UTAH - 08SSLR0006-GENERAL SVC SUBSCR SOLAR - COM	1,003	131,106	4	250,750	0.1307
205	UTAH - 08SSLR0023-SMALL GEN SVC SUBSCR SOLAR - COM	2,582	295,969			0.1146
206	UTAH - 08SSLR06AM-GEN SVC TOU SOLAR SUBSCR MAN - COM	29,730	4,361,394	317	93,785	0.1467
207	UTAH - 08TCVLNAGN-UTAH LNX ANNUAL GAR NON RES - COM		10,150			0.0000
208	UTAH - 08TCVLNXGN-TCV LNX - 80% GAR - NON RES - COM		702,319			0.0000
209	UTAH - 08TCVLXACN-GAR ADDED CAPACITY NON RES		12,668			0.0000
210	UTAH - 08TOSS015F-TRAFFIC SIG NM - COM	170	15,515	20	8,500	0.0913
211	UTAH - 08TOSS3415-TRAFFIC OTHER SIGNAL MTR SCH - COM	138	16,891	81	1,704	0.1224
212	UTAH - 08TOSS0015-TRAF & OTHER S - COM	3,855	395,336	1,188	3,245	0.1026
213	UTAH - 08MONL0015-MTR OUTDONIGHT - COM	11,599	614,004	683	16,982	0.0529
214	UTAH - 08MONL3415-MTR OUTDOOR NIGHT LIGHT SCH 3 - COM	2,211	96,711	38	58,184	0.0437
215	UTAH - 08N3423135-SMALL GENERAL SERVICE SCH 34	321	29,975	15	21,400	0.0934
216	UTAH - 08N346A135-NT MTR GEN SVC TOU ENGY SCH34	1,057	126,927	7	151,000	0.1201
217	UTAH - 08NM346135-NET MTR GEN SVC SCH 34	11,429	1,009,103	17	672,294	0.0883
218	UTAH - 08NM348135-NET MTR GEN SVC > 1000 KW SCH	5,960	444,013	1	5,960,000	0.0745
219	UTAH - REVENUE_ACCOUNTING ADJUSTMENTS - COM		29,643,201			0.0000
220	UTAH - REVENUE ADJUSTMENT - DEFERRED NPC - COM		205,571,938			0.0000
221	UTAH - OTHER CUSTOMER RETAIL REVENUE - COM		2,995,698			0.0000
222	UTAH - 08LNX00311 - LINE EXT 80% GUARANTEE - COM		302,897			0.0000
223	UTAH - 08GNSV0008 - UT GEN SVC TOU > 1000KW - COM	923,917	70,150,197	136	6,793,507	0.0759
224	UTAH - 08GNSV008M - UT GEN SVC TOU > 1000KW - COM	5,862	399,020	2	2,931,000	0.0681
225	UTAH - DSM REVENUE-COMMERCIAL		22,405,258			0.0000
226	UTAH - BLUE SKY REVENUE-COMMERCIAL		965,274			0.0000
227	WASHINGTON - 02GN24EV45-WA ELECTRIC VEHICLE FAST CHG	537	95,855	7	76,714	0.1785
228	WASHINGTON - 02GNSB0024-WA GEN SRVC DO - COM	25,250	3,679,031	1,472	17,154	0.1457
229	WASHINGTON - 02GNSB024F-GEN SRVC DOM/F	1	261	1	1,000	0.2612
230	WASHINGTON - 02GNSB24FP-WA GEN SVC SEASONAL	153	66,030	60	2,550	0.4316
231	WASHINGTON - 02GNSV0024-WA GEN SRVC - COM	473,992	66,203,370	15,495	30,588	0.1397
232	WASHINGTON - 02GNSV0029-WA NON RES TOU PILOT	509	88,704	14	36,357	0.1743
233	WASHINGTON - 02GNSV024F-WA GEN SRVC-FL - COM	1,200	224,140	102	11,765	0.1868
234	WASHINGTON - 02LGSB0036-LRG GEN SVC IRG - COM	38,342	4,889,981	59	649,864	0.1275
235	WASHINGTON - 02LGSV0036-WA LRG GEN SRV - COM	763,766	95,642,017	848	900,667	0.1252
236	WASHINGTON - 02LGSV048T-LRG GEN SRVC 1 - COM	159,116	18,961,611	31	5,132,774	0.1192
237	WASHINGTON - 02LNX00102-LINE EXT 80% G - COM		124,814			0.0000
238	WASHINGTON - 02LNX00103-LINE EXT 80% G - COM		34,370			0.0000
239	WASHINGTON - 02LNX00105-CNTRCT $ MIN G - COM		2,380			0.0000
240	WASHINGTON - 02LNX00109-REF/NREF ADV + - COM		234,600			0.0000
241	WASHINGTON - 02LNX00110-REF/NREF ADV + - COM		15,001			0.0000
242	WASHINGTON - 02LNX00112-YR INCURRED CH		669			0.0000
243	WASHINGTON - 02LNX00300-LINE EXT 80% G		35,967			0.0000
244	WASHINGTON - 02LNX00311 - LINE EXT 80% GUARANTEE		23,445			0.0000
245	WASHINGTON - 02LNX00312 - WA IRG LINE EXT - COM		1,927			0.0000
246	WASHINGTON - 02NMB24135-WA NET METERING - COM	145	34,098	41	3,537	0.2352
247	WASHINGTON - 02OALT015N-WA OUTD AR LGT - COM	1,290	165,079	733	1,760	0.1280
248	WASHINGTON - 02OALTB15N-WA OUTD AR LGT NR - COM	436	69,630	417	1,046	0.1597
249	WASHINGTON - 02RCFL0054-WA REC FIELD L	325	31,455	23	14,130	0.0968
250	WASHINGTON - 02NMT24135, Net metering, WA - COM	13,572	1,898,624	226	60,053	0.1399
251	WASHINGTON - 02NMT36135-WA NET METER LRG SVC < 1000KW - COM	32,738	4,151,089	31	1,056,065	0.1268
252	WASHINGTON - 02NMT48135-WA LG SVC NET METER=>1000 KW	15,249	1,791,200	3	5,083,000	0.1175
253	WASHINGTON - INCOME TAX DEFERRAL ADJUSTMENTS - COM		924,766			0.0000
254	WASHINGTON - REVENUE ADJUSTMENT - DEFERRED NPC - COM		1,028,063			0.0000
255	WASHINGTON - REVENUE_ACCOUNTING ADJUSTMENTS - COM		10,088,668			0.0000
256	WASHINGTON - DSM REVENUE-COMMERCIAL		8,869,758			0.0000
257	WASHINGTON - BLUE SKY REVENUE-COMMERCIAL		32,266	3		0.0000
258	WASHINGTON - ALT REVENUE PROGRAM ADJUSTMENTS - COM		13,725,821			0.0000
259	WYOMING - 05CHCK000N-WY NRES CHECK			1		0.0000
260	WYOMING - 05GNCEL25F-WYOMING SMALL CELL FLAT RATE	5	3,347	1	5,000	0.6694
261	WYOMING - 05GNSV0025-WY GEN SRVC - COM - PPL	215,918	28,924,644	18,829	11,467	0.1340
262	WYOMING - 05GNSV0028-GEN SVC > 15 KW - COM - PPL	779,426	88,449,818	3,032	257,067	0.1135
263	WYOMING - 05GNSV0029-WY GEN SVC TOU PILOT - COM - PPL	2,178	491,982	8	272,250	0.2259
264	WYOMING - 05GNSV025F-GEN SRVC-FL RA - COM - PPL	984	200,724	169	5,822	0.2040
265	WYOMING - 05LGSV0046-WY LRG GEN SRV - COM - PPL	251,510	22,577,237	25	10,060,400	0.0898
266	WYOMING - 05LGSV048T-LRG GENSRV TIM - COM	15,694	1,443,573	1	15,694,000	0.0920
267	WYOMING - 05LNX00100-LINE EXT 60% G - COM		24,604			0.0000
268	WYOMING - 05LNX00102-LINE EXT 80% G - COM - PPL		521,575			0.0000
269	WYOMING - 05LNX00105-CNTRCT $ MIN G - COM		5,343			0.0000
270	WYOMING - 05LNX00109-REF/NREF ADV + - COM - PPL		432,613			0.0000
271	WYOMING - 05LNX00110-REF/NREF ADV + - COM - PPL		6,849			0.0000
272	WYOMING - 05LNX00114-TEMP SVC 12MO>		272			0.0000
273	WYOMING - 05NMT25135 - WY NET MTR, GEN, < 25 KW - COM - PPL	803	100,040	62	12,952	0.1246
274	WYOMING - 05NMT28135-NET MTR SMALL GEN SVC > 15 KW - COM	10,083	1,199,732	32	315,094	0.1190
275	WYOMING - 05OALT015N-OUTD AR LGT SR - COM - PPL	2,438	318,549	1,574	1,549	0.1307
276	WYOMING - 05RCFL0054-WY REC FIELD L - COM - PPL	983	65,421	55	17,873	0.0666
277	WYOMING - 05LNX00300 - LINE EXT 80% GUARANTEE - COM - PPL		41,816			0.0000
278	WYOMING - 05LNX00311 - LINE EXT 80% GUARANTEE - COM - PPL		28,127			0.0000
279	WYOMING - REVENUE ADJUSTMENT - DEFERRED NPC - COM		467,826			0.0000
280	WYOMING - REVENUE_ACCOUNTING ADJUSTMENTS - COM		835,820			0.0000
281	WYOMING - DSM REVENUE-SMALL COMMERCIAL - COM		2,559,929			0.0000
282	WYOMING - DSM REVENUE-LARGE COMMERCIAL - COM		170,630			0.0000
283	WYOMING - BLUE SKY REVENUE-COMMERCIAL - COM		10,312	1		0.0000
284	WYOMING - OTHER CUSTOMER RETAIL REVENUE - COM		39,353			0.0000
285	WYOMING - 05GNSV0025-WY GEN SRVC - COM	31,878	4,225,128	2,651	12,025	0.1325
286	WYOMING - 05GNSV0028-GEN SVC > 15 KW - COM	86,982	9,700,446	380	228,900	0.1115
287	WYOMING - 05GNSV0029-WY GEN SVC TOU PILOT - COM	834	190,530	6	139,000	0.2285
288	WYOMING - 05GNSV025F-GEN SRVC-FL RA - COM	199	32,866	33	6,030	0.1652
289	WYOMING - 05LGSV0046-WY LRG GEN SRV - COM	171	168,235	1	171,000	0.9838
290	WYOMING - 05LNX00102-LINE EXT 80% G - COM		168,602			0.0000
291	WYOMING - 05LNX00109-REF/NREF ADV + - COM		169,519			0.0000
292	WYOMING - 05LNX00110-REF/NREF ADV + - COM		5,754			0.0000
293	WYOMING - 05LNX00300 - LINE EXT 80% GUARANTEE - COM		2,969			0.0000
294	WYOMING - 05NMT25135 - WY NET MTR, GEN, < 25 KW - COM	75	9,420	6	12,500	0.1256
295	WYOMING - 05NMT28135-NET MTR SMALL GEN SVC > 15 KW	685	74,674	3	228,333	0.1090
296	WYOMING - 05OALT015N-OUTD AR LGT SR - COM	285	43,564	144	1,979	0.1529
297	WYOMING - 05RCFL0054-WY REC FIELD L - COM	160	11,567	14	11,429	0.0723
298	WYOMING - 05LNX00311 - LINE EXT 80% GUARANTEE - COM		5,515			0.0000
299	WYOMING - DSM REVENUE-SMALL COMMERCIAL		373,396			0.0000
300	WYOMING - DSM REVENUE-LARGE COMMERCIAL		2,555			0.0000
301	WYOMING - BLUE SKY REVENUE-COMMERCIAL		616			0.0000
302	LESS MULTIPLE BILLINGS			23,392
41	TOTAL Billed Small or Commercial	22,705,437	2,494,851,609	233,923	97,064	0.1099
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)	32,309	9,495,000			0.2939
43	TOTAL Small or Commercial	22,673,128	2,504,346,609	233,923	97,064	0.1105

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, list the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	CALIFORNIA - 06GNSV0025-CA GEN SRVC	482	101,633	78	6,179	0.2109
2	CALIFORNIA - 06GNSV0A32-GEN SRVC-20 KW	3,471	806,743	21	165,286	0.2324
3	CALIFORNIA - 06LGSV048T-LRG GEN SERV	45,984	7,891,420	9	5,109,333	0.1716
4	CALIFORNIA - 06LGSV0A36-LRG GEN SRVC-O	5,096	1,132,022	11	463,273	0.2221
5	CALIFORNIA - REVENUE_ACCOUNTING ADJUSTMENTS - IND		108,766			0.0000
6	CALIFORNIA - REVENUE ADJUSTMENT - DEFERRED NPC - IND		4,445			0.0000
7	CALIFORNIA - DSM REVENUE-INDUSTRIAL		112,365			0.0000
8	CALIFORNIA - BLUE SKY REVENUE-INDUSTRIAL		31,116	1		0.0000
9	IDAHO - 07GNSV0006-GEN SRVC-LRG P	66,670	6,568,876	99	673,434	0.0985
10	IDAHO - 07GNSV0009-GEN SRVC-HI VO	55,107	4,971,101	14	3,936,214	0.0902
11	IDAHO - 07GNSV0023-GEN SRVC-SML P	17,468	2,052,995	292	59,822	0.1175
12	IDAHO - 07GNSV006A-GEN SRVC-LRG P	1,291	164,680	20	64,550	0.1276
13	IDAHO - 07GNSV009M-MANL HIGH VOLT	127,646	9,657,268	1	127,646,000	0.0757
14	IDAHO - 07GNSV023A-GEN SRVC-SML P - IND	1,849	240,859	129	14,333	0.1303
15	IDAHO - 07LNX00010-MNTHLY 80%GUAR		4,388			0.0000
16	IDAHO - 07LNX00035-ADV 80%MO GUAR - IND		2,542			0.0000
17	IDAHO - 07LNX00108-ANN COST MTHLY		1,996			0.0000
18	IDAHO - 07LNX00311 - LINE EXT 80% GUARANTEE		1,440			0.0000
19	IDAHO - 07NBL23136-ID NET BILLING SML GEN SVC	9	191	1	9,000	0.0213
20	IDAHO - 07NMT23135 - ID NET MTR - SMALL GEN SVC	15	1,793	1	15,000	0.1195
21	IDAHO - 07OALT007N-SECURITY AR LG	12	2,660	15	800	0.2217
22	IDAHO - 07SPCL0001	1,454,000	114,098,307	1	1,454,000,000	0.0785
23	IDAHO - DSM REVENUE-INDUSTRIAL		155,511			0.0000
24	OREGON - 01COST0023, OR GEN SRV, COST BASED	16,482	1,149,567			0.0697
25	OREGON - 01COST0048 - 01LGSV0048 - IND	1,150,568	71,224,323			0.0619
26	OREGON - 01COST023T-GEN SVC TOU ENERGY SUPPLY SVC	6	323			0.0539
27	OREGON - 01COST23MT-OR GEN SVC COST TOU MTR	5	359			0.0719
28	OREGON - 01COST30MT-LG GEN SVC>200KW COST TOU MTR	27,883	1,489,935			0.0534
29	OREGON - 01COSTB023 - OR GEN SRV, CST-BSD SPLY	135	9,008			0.0667
30	OREGON - 01COSTL030 - OR LRG GEN SRV, CST >200 kW	122,999	6,599,153			0.0537
31	OREGON - 01COSTS028, OR GEN SERV, COST > 30kW	71,340	4,906,913			0.0688
32	OREGON - 01GNSB0023, OR GEN SRV, BPA, < 30 kW		15,374	14		0.0000
33	OREGON - 01GNSB0028, OR GEN SRV, BPA, > 30 kW		1,299			0.0000
34	OREGON - 01GNSV0023, OR GEN SRV, < 30 KW		1,505,450	922		0.0000
35	OREGON - 01GNSV0028, OR GEN SRV > 30 kW		3,937,974	363		0.0000
36	OREGON - 01GNSV023F - OR GEN SRV - FLAT RATE - IND		109			0.0000
37	OREGON - 01GNSV023M - OR GEN SRV, MANUAL BILL		366	1		0.0000
38	OREGON - 01GNSV023T, OR GEN SRV, TOU Option - IND		1,878	2		0.0000
39	OREGON - 01GNSV0728 - OR GEN SVC DIR ACCESS >30KW		20,246			0.0000
40	OREGON - 01GNSV0730 -OR GEN SVC DIR ACCESS >200KW		35,594			0.0000
41	OREGON - 01GNSV0748 LG GEN SVC DIR ACCESS 1000KW+		1,775,173	2		0.0000
42	OREGON - 01GNSVT023-OR GEN SVC <=30 KW TOU MTR		697	1		0.0000
43	OREGON - 01GNSVT028-OR GEN SVC>30KW TOU MTR					0.0000
44	OREGON - 01LGSV0030 - OR LRG GEN SRV, > 1000 kW		8,394,436	99		0.0000
45	OREGON - 01LGSV0048-1000KW AND OVR - IND		38,440,331	72		0.0000
46	OREGON - 01LGSV048M-LRG GEN SRVC 1	48,422	4,957,902	2	24,211,000	0.1024
47	OREGON - 01LGSV30MN-OR LG GEN SVC>200 KW NO AUTO		64,766	1		0.0000
48	OREGON - 01LGSVT030-OR LG GEN SVC>200KW TOU MTR		1,740,541	12		0.0000
49	OREGON - 01LNX00102-LINE EXT 80% G		5,315,207			0.0000
50	OREGON - 01LNX00300 - LINE EXT 80% GUARANTEE		32,068			0.0000
51	OREGON - 01LPRS047M-PART REQ SRVC	2,328	1,091,607	1	2,328,000	0.4689
52	OREGON - 01NMT23135 - OR NET MTR, GEN, < 30 kW		4,467	4		0.0000
53	OREGON - 01NMT28135 - OR NET MTR, GEN, > 30 kW		138,329	12		0.0000
54	OREGON - 01NMT30135 - OR NET MTR, GEN, > 200 kW		67,833	1		0.0000
55	OREGON - 01OALT015N-OUTD AR LGT NR - IND	209	23,479	101	2,069	0.1123
56	OREGON - 01OALTB15N-OR OUTD AR LGT NR	3	405	3	1,000	0.1349
57	OREGON - 01PTOU0023, OR GEN SRV, TOU ENG SPLY SRV - IND	11	806			0.0733
58	OREGON - 01RENW0023, OR RENW USAGE SPLY SRV	79	5,768			0.0730
59	OREGON - 01STDAY028 - OR DAY STD OFF, SCH 28	32	2,111			0.0660
60	OREGON - 01STDAY030 - OR STD DAY OFF, SCH 27	608	38,911			0.0640
61	OREGON - 01VIR23136-OR VOLUME INCENTIVE <= 30 KW		1,503	1		0.0000
62	OREGON - 01VIR28136-OR VOLUME INCENTIVE > 30 KW		26,331	2		0.0000
63	OREGON - 01VIR30136-OR VOLUME INCENTIVE > 200 kW		119,248	1		0.0000
64	OREGON - REVENUE_ACCOUNTING ADJUSTMENTS - IND		4,231,524			0.0000
65	OREGON - SOLAR FEED-IN REVENUE - IND		360,158			0.0000
66	OREGON - OTHER CUSTOMER RETAIL REVENUE - IND		185,564			0.0000
67	OREGON - COMMUNITY SOLAR REVENUE - IND		163,557			0.0000
68	OREGON - DSM REVENUE-INDUSTRIAL		11,817,557			0.0000
69	OREGON - BLUE SKY REVENUE-INDUSTRIAL		568,273	4		0.0000
70	UTAH - 08C3423136-NET MTR SM GEN SVC SCH 34					0.0000
71	UTAH - 08CFR00051-MTH FAC SRVCHG - IND		15,065			0.0000
72	UTAH - 08CGA23137-UT NET MTR SMALL GEN SVC		118			0.0000
73	UTAH - 08CGM23136-UTAH NET METER SM GEN SVC	70	6,991	2	35,000	0.0999
74	UTAH - 08CGM6A137-UT GEN SVC TRANS TOU MAN 137	611	78,056	1	611,000	0.1278
75	UTAH - 08CGN06136-UT GEN SVC TRANSITION GEN	1,420	143,098	1	1,420,000	0.1008
76	UTAH - 08CGN06137-UT GEN SVC CUST GEN 137	1,526	166,827	5	305,200	0.1093
77	UTAH - 08CGN08137-UT NET MTR FEN SVC>1000 KW	10,323	877,076	1	10,323,000	0.0850
78	UTAH - 08CGN23137-UT NET MTR SMALL GEN SVC	82	7,592	2	41,000	0.0926
79	UTAH - 08CN346136-GEN SVC TRANSITION GEN SCH 34	700	53,580			0.0765
80	UTAH - 08GNSV0006-GEN SRVC-DISTR	497,130	43,536,959	790	629,278	0.0876
81	UTAH - 08GNSV0009-GEN SRVC-HI VO	2,515,802	143,818,999	93	27,051,624	0.0572
82	UTAH - 08GNSV0023-GEN SRVC-DISTR	47,700	4,761,681	2,898	16,465	0.0998
83	UTAH - 08GNSV006A-GEN SRVC-ENERG	52,721	6,087,742	215	245,214	0.1155
84	UTAH - 08GNSV009A-GEN SRVC HI VO	17,623	1,593,861	6	2,937,167	0.0904
85	UTAH - 08GNSV009M-MANL HIGH VOLT	882,796	48,096,061	13	67,907,385	0.0545
86	UTAH - 08GNSV06MN-GNSV DIST VOLT	467	45,194	14	33,357	0.0968
87	UTAH - 08GNSV3406-GENERAL SERVICE SCH 34	8,614	719,704	18	478,556	0.0836
88	UTAH - 08GNSV3409-TOU GEN SVC TRANS DEL SCH 34	2,888	202,871	1	2,888,000	0.0702
89	UTAH - 08GNSV3423-SMALL GEN SVC SCH 34	464	48,919	47	9,872	0.1054
90	UTAH - 08GNSV346A-GEN SVC TOU ENERGY SCH 34	2,281	226,613	19	120,053	0.0993
91	UTAH - 08LNX00002-MTHLY 80% GUAR - IND		770,029			0.0000
92	UTAH - 08LNX00004-ANNUAL 80%GUAR - IND		22,964			0.0000
93	UTAH - 08LNX00014-80% MIN MNTHLY - IND		73,786			0.0000
94	UTAH - 08LNX00017-ADV/REF&80%ANN - IND		640			0.0000
95	UTAH - 08LNX00300 - LINE EXT 80% PLUS MONTHLY - IND		13,971			0.0000
96	UTAH - 08OALT007N-SECURITY AR LG	736	85,399	356	2,067	0.1160
97	UTAH - 08TOSS0015-TRAF & OTHER S - IND	7	886	5	1,400	0.1265
98	UTAH - 08MONL0015-MTR OUTDONIGHT - IND	21	1,615	6	3,500	0.0769
99	UTAH - 08NMT06135-UT NET METERING GEN SVC	2,325	381,661	16	145,313	0.1642
100	UTAH - 08NMT08135 - NET METERING GEN SVC	66	171,106	2	33,000	2.5925
101	UTAH - 08NMT23135 - UT NET MTR, GEN, < 25 KW	285	33,965	42	6,786	0.1192
102	UTAH - 08NMT6A135-NET METERING GEN SVC TOU	4,512	545,136	15	300,800	0.1208
103	UTAH - 08PRSV031M-BKUP MNT&SUPPL	59,894	4,520,167	3	19,964,667	0.0755
104	UTAH - 08SPCL0001	611,255	35,653,332	1	611,255,000	0.0583
105	UTAH - 08SPCL0002	598	15,705			0.0263
106	UTAH - 08SPCL0003	1,178,281	70,294,646	1	1,178,282,000	0.0597
107	UTAH - 08SSLR0006-GENERAL SVC SUBSCR SOLAR	257	27,641	1	257,000	0.1076
108	UTAH - 08SSLR0023-SMALL GEN SVC SUBSCR SOLAR	178	18,660	18	9,889	0.1048
109	UTAH - 08SSLR06AM-GEN SVC TOU SOLAR SUBSCR MAN	10,233	1,058,861	22	465,136	0.1035
110	UTAH - 08TCVLNXGN-TCV LNX - 80% GAR - NON RES - IND		19,411			0.0000
111	UTAH - REVENUE_ACCOUNTING ADJUSTMENTS - IND		12,369,423			0.0000
112	UTAH - REVENUE ADJUSTMENT - DEFERRED NPC - IND		127,888,068			0.0000
113	UTAH - 08GNSV0008 - UT GEN SVC TOU > 1000KW	903,281	67,679,877	85	10,626,835	0.0749
114	UTAH - 08GNSV008M - UT GEN SVC TOU > 1000KW	22,964	1,837,084	4	5,741,000	0.0800
115	UTAH - OTHER CUSTOMER RETAIL REVENUE - IND		1,865,581			0.0000
116	UTAH - DSM REVENUE-INDUSTRIAL		10,026,445			0.0000
117	UTAH - BLUE SKY REVENUE-INDUSTRIAL		181,768	5		0.0000
118	WASHINGTON - 02GNSB0024-WA GEN SRVC DO	739	110,093	40	18,475	0.1490
119	WASHINGTON - 02GNSV0024-WA GEN SRVC	14,545	2,035,411	321	45,312	0.1399
120	WASHINGTON - 02GNSV024F-WA GEN SRVC-FL	26	9,241	2	13,000	0.3554
121	WASHINGTON - 02LGSV0036-WA LRG GEN SRV	89,803	11,572,102	81	1,108,679	0.1289
122	WASHINGTON - 02LGSV048M-WA LRG GEN SRV	433,698	44,999,563	1	433,698,000	0.1038
123	WASHINGTON - 02LGSV048T-LRG GEN SRVC 1	156,137	18,551,579	22	7,097,136	0.1188
124	WASHINGTON - 02LNX00103-LINE EXT 80% G - IND		23,271			0.0000
125	WASHINGTON - 02NMB24135-WA NET METERING		126	1		0.0000
126	WASHINGTON - 02NMT24135, Net metering, WA	51	11,964	5	10,200	0.2346
127	WASHINGTON - 02NMT36135-WA NET METER LRG SVC < 1000KW		14,881	1		0.0000
128	WASHINGTON - 02OALT015N-WA OUTD AR LGT	78	8,421	34	2,294	0.1080
129	WASHINGTON - 02OALTB15N-WA OUTD AR LGT NR	24	3,518	14	1,714	0.1466
130	WASHINGTON - 02PRSV47TM-LRG PART REQMT	1,764	397,865	1	1,764,000	0.2255
131	WASHINGTON - 02LGSB0036-LRG GEN SVC IRG	887	172,398	6	147,833	0.1944
132	WASHINGTON - INCOME TAX DEFERRAL ADJUSTMENTS - IND		451,823			0.0000
133	WASHINGTON - REVENUE ADJUSTMENT - DEFERRED NPC - IND		502,292			0.0000
134	WASHINGTON - REVENUE_ACCOUNTING ADJUSTMENTS - IND		4,866,093			0.0000
135	WASHINGTON - DSM REVENUE-INDUSTRIAL		4,009,660			0.0000
136	WASHINGTON - ALT REVENUE PROGRAM ADJUSTMENTS		596,891			0.0000
137	WYOMING - 05GNSV0025-WY GEN SRVC - IND	18,623	2,291,766	1,037	17,976	0.1231
138	WYOMING - 05GNSV0028-GEN SVC > 15 KW - IND	221,480	21,672,685	371	596,981	0.0979
139	WYOMING - 05GNSV0029-WY GEN SVC TOU PILOT	1,219	126,037	8	152,375	0.1034
140	WYOMING - 05GNSV025F-GEN SRVC-FL RA	26	5,472	8	3,250	0.2105
141	WYOMING - 05LGSV0046-WY LRG GEN SRV - IND	1,798,802	152,562,176	56	32,121,482	0.0848
142	WYOMING - 05LGSV046M-WY LRG GEN SRV	11,200	1,066,464	1	11,200,000	0.0952
143	WYOMING - 05LGSV048M-TOU>1000KW MAN - IND	422,810	32,370,103	1	422,810,000	0.0766
144	WYOMING - 05LGSV048T-LRG GENSRV TIM - IND	1,507,951	110,511,377	10	150,795,200	0.0733
145	WYOMING - 05LNX00100-LINE EXT 60% G		1,056			0.0000
146	WYOMING - 05LNX00102-LINE EXT 80% G - IND		173,875			0.0000
147	WYOMING - 05LNX00105-CNTRCT $ MIN G		6,263			0.0000
148	WYOMING - 05LNX00109-REF/NREF ADV + - IND - PPL		81,775			0.0000
149	WYOMING - 05LNX00300 - LINE EXT 80% GUARANTEE		30,545			0.0000
150	WYOMING - 05LNX00311 - LINE EXT 80% GUARANTEE		10,356			0.0000
151	WYOMING - 05NMT25135 - WY NET MTR, GEN, < 25 KW - IND	17	2,179	1	17,000	0.1282
152	WYOMING - 05OALT015N-OUTD AR LGT SR - IND	65	6,755	38	1,711	0.1039
153	WYOMING - 05PRSV033M-PART SERV REQ - IND	1,156,594	106,066,158	12	96,382,833	0.0917
154	WYOMING - REVENUE ADJUSTMENT - DEFERRED NPC - IND		2,073,278			0.0000
155	WYOMING - REVENUE_ACCOUNTING ADJUSTMENTS - IND		520,510			0.0000
156	WYOMING - DSM REVENUE-SMALL INDUSTRIAL - IND		508,536			0.0000
157	WYOMING - DSM REVENUE-LARGE INDUSTRIAL - IND		2,381,430			0.0000
158	WYOMING - BLUE SKY REVENUE-INDUSTRIAL - IND		168			0.0000
159	WYOMING - OTHER CUSTOMER RETAIL REVENUE - IND		174,320			0.0000
160	WYOMING - 05GNSV0025-WY GEN SRVC	3,813	489,531	278	13,765	0.1284
161	WYOMING - 05GNSV0028-GEN SVC > 15 KW	52,245	5,057,348	55	949,909	0.0968
162	WYOMING - 05GNSV028M-GEN SVC > 15 KW MANUAL BILL	3,485	294,545	3	1,161,667	0.0845
163	WYOMING - 05LGSV0046-WY LRG GEN SRV	2,010	461,066	2	1,005,000	0.2294
164	WYOMING - 05LGSV048M-TOU>1000KW MAN	102,612	9,056,257	2	51,306,000	0.0883
165	WYOMING - 05LGSV048T-LRG GENSRV TIM	646,682	54,136,855	14	46,191,643	0.0837
166	WYOMING - 05LNX00102-LINE EXT 80% G		2,353,988			0.0000
167	WYOMING - 05LNX00109-REF/NREF ADV + - IND		24,874			0.0000
168	WYOMING - 05NMT25135 - WY NET MTR, GEN, < 25 KW	44	4,882	1	44,000	0.1109
169	WYOMING - 05OALT015N-OUTD AR LGT SR	6	639	4	1,500	0.1065
170	WYOMING - 05PRSV033M-PART SERV REQ	1,378	278,594	1	1,378,000	0.2022
171	WYOMING - DSM REVENUE-SMALL INDUSTRIAL		152,376			0.0000
172	WYOMING - DSM REVENUE-LARGE INDUSTRIAL		920,291			0.0000
173	WYOMING - BLUE SKY REVENUE-INDUSTRIAL		140			0.0000
174	LESS MULTIPLE BILLINGS			757
175	CALIFORNIA - 06APS20LTA-AG PMP>20 KW TOU 2-6PM NO CCC	414	96,111	4	103,500	0.2322
176	CALIFORNIA - 06APSV0020-AG PMP SRVC	9,848	1,919,493	825	11,937	0.1949
177	CALIFORNIA - 06APSV020L-AG PMP SRVC-NO GHG CREDIT	41,934	9,423,585	521	80,488	0.2247
178	CALIFORNIA - 06APSV20TA-AGR PUMP TOU OPT A 2 PM-6PM	209	44,381	3	69,667	0.2124
179	CALIFORNIA - 06LNX00103-LINE EXT 80% G		38,474			0.0000
180	CALIFORNIA - 06LNX00110-REF/NREF ADV +		56,323			0.0000
181	CALIFORNIA - 06LNX00310 - IRG, 80% ANNUAL MIN + 80%		704			0.0000
182	CALIFORNIA - 06LNX00312 - CA IRG LINE EXT		13,366			0.0000
183	CALIFORNIA - 06NB20L136-CA IRG NET BILL NO GHG CR	785	163,171	6	130,833	0.2079
184	CALIFORNIA - 06NBL20136-CA IRG NET BILLING		90	1		0.0000
185	CALIFORNIA - 06NML20135-AGRI PUMP-NET MTR NO GHG CR	1,680	543,230	44	38,182	0.3234
186	CALIFORNIA - 06NMT20135-AGRICULTURAL PUMP-NET METER	49	13,393	20	2,450	0.2733
187	CALIFORNIA - 06USBR0020-KLAM IRG ONPRJ	3,399	789,935	265	12,826	0.2324
188	CALIFORNIA - 06USBR020L-KLAM IRG ONPRJ-NO CHG CREDIT	15,891	3,984,770	327	48,596	0.2508
189	CALIFORNIA - DSM REVENUE-IRRIGATION		145,616			0.0000
190	CALIFORNIA - BLUE SKY REVENUE-IRRIGATION		272			0.0000
191	CALIFORNIA - REVENUE_ACCOUNTING ADJUSTMENTS - IRR		124,914			0.0000
192	CALIFORNIA - REVENUE ADJUSTMENT - DEFERRED NPC - IRR		7,055			0.0000
193	IDAHO - 07APSA010L - IRG & Pump Large Load	319,279	37,960,949	1,985	160,846	0.1189
194	IDAHO - 07APSA010S - IRG & Pump Small Load	5,037	704,598	292	17,250	0.1399
195	IDAHO - 07APSAL10X - IRG & PUMP - Large load	311,792	37,512,207	2,279	136,811	0.1203
196	IDAHO - 07APSAS10X - IRG & PUMP - Small load	14,551	1,985,468	721	20,182	0.1364
197	IDAHO - 07APSV006A-LRG POWER OPTIONAL SVC - IRG	512	47,040	1	512,000	0.0919
198	IDAHO - 07APSV023A-SMALL POWER OPTIONAL SVC-IRG	380	48,346	4	95,000	0.1272
199	IDAHO - 07APSVCNLL-LRG LOAD CANAL	13,035	1,426,384	36	362,083	0.1094
200	IDAHO - 07APSVCNLS-SML LOAD CANAL	35	6,501	11	3,182	0.1857
201	IDAHO - 07GNSV023A-GEN SRVC-SML P	192	21,244	1	192,000	0.1106
202	IDAHO - 07LNX00015-ANNUAL 80%GUAR		33,112			0.0000
203	IDAHO - 07LNX00035-ADV 80%MO GUAR		1,040			0.0000
204	IDAHO - 07LNX00040-ADV+REFCHG+80%		116,306			0.0000
205	IDAHO - 07LNX00312 - ID LINE EXT		2,075			0.0000
206	IDAHO - 07NB10X136-NON BPA ID PUMP LRG NET BILL	388	33,678	8	48,500	0.0868
207	IDAHO - 07NBL10136-ID IRG LRG LOAD NET BILLING	69	9,933	3	23,000	0.1440
208	IDAHO - 07NM10X135-ID NET METERING - IRG	333	42,430	3	111,000	0.1274
209	IDAHO - 07APSN010L - ID LG IRR & PUMP	12,264	1,397,489	41	299,122	0.1140
210	IDAHO - 07APSN010S - IRRIGATION, SMALL, 3 PH	90	11,929	3	30,000	0.1325
211	IDAHO - 07APSNS10X - IRRIGATION, SMALL, 3 PHASE	1,179	146,517	23	51,261	0.1243
212	IDAHO - DSM REVENUE-IRRIGATION		1,726,538			0.0000
213	IDAHO - BLUE SKY REVENUE-IRRIGATION		54			0.0000
214	OREGON - 01APSBA41T-OR IRR TOU OPT A - 2PM-6PM		59,729	44		0.0000
215	OREGON - 01APSBB41T-OR IRR TOU OPT B - 6PM-10PM		9,955	22		0.0000
216	OREGON - 01APSBT041-OR IRG TOU METER		470	1		0.0000
217	OREGON - 01APSV0041-AG PMP SRVC BP		1,665,200	1,931		0.0000
218	OREGON - 01APSV041L-OR Pumping Serv >30KW		2,766,346	482		0.0000
219	OREGON - 01APSV041T - AGR PUMP SRV-TOU OPTION		18,441	22		0.0000
220	OREGON - 01APSV041X-AG PMP SRVC<30 kW		2,373,063	2,898		0.0000
221	OREGON - 01APSV41TA-OR IRG PUMPING TOU OPT-A		76,086	44		0.0000
222	OREGON - 01APSV41TB-OR IRG PUMPING TOU OPT-B		6,880	17		0.0000
223	OREGON - 01APSV41XL-OR Pumping Serv no BPA >30KW		3,825,769	606		0.0000
224	OREGON - 01APSVT041-OR IRG TOU METER		8,635	8		0.0000
225	OREGON - 01APSVT41L-OR AGRICULTUARL PUMPING>30 KW		794			0.0000
226	OREGON - 01COST0041 -01APSV0041-01APSV041X AG PMP	134,088	8,818,664			0.0658
227	OREGON - 01COST0048 - 01LGSV0048	23,315	1,432,724			0.0615
228	OREGON - 01COST041T- AG IRG TOU ENERGY SUPPLY SVC	1,679	97,934			0.0583
229	OREGON - 01COST41MT-OR IRG COST SUPPLY TOU MTR	38	2,484			0.0654
230	OREGON - 01CSTUSB41-USBR IRRIGATION CONTRACTS CSS	61,323	4,032,405			0.0658
231	OREGON - 01GNSV023T, OR GEN SRV, TOU Option		137	1		0.0000
232	OREGON - 01HABIT041 - 01APSV0041 AG PMP SRVC	2	157			0.0783
233	OREGON - 01LGSB0048 - LG GEN SVC > 1000KW (R)		130,721	1		0.0000
234	OREGON - 01LGSV0048-1000KW AND OVR		870,989	2		0.0000
235	OREGON - 01LNX00103-LINE EXT 80% G		45,736			0.0000
236	OREGON - 01LNX00109-REF/NREF ADV +		662			0.0000
237	OREGON - 01LNX00110-REF/NREF ADV +		80,042			0.0000
238	OREGON - 01LNX00310-LINE EXTENSION CONTRACT		3,442			0.0000
239	OREGON - 01PTOU0023, OR GEN SRV, TOU ENG SPLY SRV		16			0.0000
240	OREGON - 01PTOU0041 - 01APSV0041 AG PMP SRVC	311	20,401			0.0656
241	OREGON - 01RENEW041 - 01APSV0041 AG PMP SRVC	45	2,933			0.0652
242	OREGON - 01STDAY041 - Daily Standard Offer Sch 25	75	4,546			0.0606
243	OREGON - 01USBONT41-USBR IRG CONTR-PRJCT LND TOU			1		0.0000
244	OREGON - 01USBRGV41-IRG TOU W/O BPA		96,091	9		0.0000
245	OREGON - 01USBROF41-KLAMATH BASIN IRG OFF PRJ LND		1,908,469	472		0.0000
246	OREGON - 01USBRON41-KLAMATH BASIN IRG ON PJT LND		2,471,698	1,063		0.0000
247	OREGON - 01VIR41136-OR VOLUME INCENTIVE-AGRI PUMP		96,514	26		0.0000
248	OREGON - 01VRU41136-OR VOL INCENTIVE USB CONTRACT		569,306	109		0.0000
249	OREGON - SOLAR FEED-IN REVENUE - IRR		38,142			0.0000
250	OREGON - OTHER CUSTOMER RETAIL REVENUE - IRR		28,942			0.0000
251	OREGON - COMMUNITY SOLAR REVENUE - IRR		24,294			0.0000
252	OREGON - DSM REVENUE-IRRIGATION		1,843,432			0.0000
253	OREGON - BLUE SKY REVENUE-IRRIGATION		516			0.0000
254	OREGON - 01LNX00312 - OR IRG LINE EXT		22,440			0.0000
255	OREGON - 01NB41A135-NET MTR IRG TOU OPT A 2-6		452	1		0.0000
256	OREGON - 01NB41B135-NET MTR IRG TOU OPT B 6-10		252	1		0.0000
257	OREGON - 01NMB41135-OREGON NET METER IRRIGATION		53,201	24		0.0000
258	OREGON - 01NMO41135-OR USBR IRG NT MTR OFF PJ LND		40	1		0.0000
259	OREGON - 01NMT41135 - NETMTR AG PMP SVC		46,788	49		0.0000
260	OREGON - 01NMT41138-OR NET MTR AGR PUMP OSIP		84			0.0000
261	OREGON - 01NMU41135 - OR NET MTR - PROJECT LAND		46,410	12		0.0000
262	OREGON - REVENUE_ACCOUNTING ADJUSTMENTS - IRR		526,200			0.0000
263	UTAH - 08AP3410NS-IRG NON-SEASONAL, SCH 34	1,007	84,863	6	167,833	0.0843
264	UTAH - 08APSV0010-IRR & SOIL DRA	201,109	15,759,761	3,204	62,749	0.0784
265	UTAH - 08APSV10NS- Irg Soil Drain Pump Non Seas	44,589	3,265,906	320	139,341	0.0732
266	UTAH - 08APSV3410-IRG & SOIL DRAIN PUMP SCH 34	49	8,483	5	9,800	0.1731
267	UTAH - 08CGA10137-IRG & SOIL DRNG 137 AGGRGTD	245	21,940	6	40,833	0.0896
268	UTAH - 08CGM10136-UT IRG NET METER MANUAL	631	48,601	3	210,333	0.0770
269	UTAH - 08CGN10136-UT IRG AND SOIL DRAIN NET MTR	5	738	1	5,000	0.1476
270	UTAH - 08CGN10137-UT IRRIGATION - NET METER 137	1,401	114,693	12	116,750	0.0819
271	UTAH - 08CNA10137-IRG NONSEASON137 AGGREGATED10	43	4,231	1	43,000	0.0984
272	UTAH - 08CNS10137-UT IRG NON-SEASONAL NET MTR	26	2,600			0.1000
273	UTAH - 08LNX00002-MTHLY 80% GUAR		241			0.0000
274	UTAH - 08LNX00004-ANNUAL 80%GUAR		16,909			0.0000
275	UTAH - 08LNX00014-80% MIN MNTHLY		594			0.0000
276	UTAH - 08LNX00017-ADV/REF&80%ANN		106,847			0.0000
277	UTAH - 08LNX00300 - LINE EXT 80% PLUS MONTHLY		866			0.0000
278	UTAH - 08LNX00310 - IRR, 80% ANNUAL MIN + 80%		5,155			0.0000
279	UTAH - 08LNX00311 - LINE EXT 80% GUARANTEE		801			0.0000
280	UTAH - 08LNX00312 UT IRG LINE EXT		10,918			0.0000
281	UTAH - 08NMT010NS-IRR & SOIL DRAIN NON SEASONAL	390	36,562	6	65,000	0.0937
282	UTAH - 08NMT10135-UT IRR_SOIL DRNG NET MTR SVC	8,251	701,844	75	110,013	0.0851
283	UTAH - 08TCVLAACN-UTAH TCV LNX ANNUAL GAR		1,231			0.0000
284	UTAH - 08TCVLNAGN-UTAH LNX ANNUAL GAR NON RES		8,478			0.0000
285	UTAH - 08TCVLNXGN-TCV LNX - 80% GAR - NON RES		55			0.0000
286	UTAH - REVENUE_ACCOUNTING ADJUSTMENTS - IRR		732,245			0.0000
287	UTAH - REVENUE ADJUSTMENT - DEFERRED NPC - IRR		4,295,713			0.0000
288	UTAH - OTHER CUSTOMER RETAIL REVENUE - IRR		62,477			0.0000
289	UTAH - DSM REVENUE-IRRIGATION		586,203			0.0000
290	UTAH - BLUE SKY REVENUE-IRRIGATION		92			0.0000
291	WASHINGTON - 02APSV0040-WA AG PMP SRVC	78,593	10,640,053	2,064	38,679	0.1016
292	WASHINGTON - 02APSV040X-WA AG PMP SRVC	89,896	12,294,739	2,970	30,360	0.1029
293	WASHINGTON - 02LNX00102-LINE EXT 80% G		11,805			0.0000
294	WASHINGTON - 02LNX00103-LINE EXT 80% G		33,056			0.0000
295	WASHINGTON - 02LNX00105-CNTRCT $ MIN G		76			0.0000
296	WASHINGTON - 02LNX00109-REF/NREF ADV +		4,251			0.0000
297	WASHINGTON - 02LNX00110-REF/NREF ADV +		91,904			0.0000
298	WASHINGTON - 02LNX00310 - IRG, 80% ANNUAL MIN + 80%		5,399			0.0000
299	WASHINGTON - 02LNX00312 - WA IRG LINE EXT		2,294			0.0000
300	WASHINGTON - 02NMT40135-WA NET METERING-IRG	611	94,066	18	36,500	0.1186
301	WASHINGTON - 02NMX40135-WA NET METERING-IRG	75	24,989	16	4,563	0.2717
302	WASHINGTON - REVENUE ADJUSTMENT - DEFERRED NPC - IRR		113,710			0.0000
303	WASHINGTON - REVENUE_ACCOUNTING ADJUSTMENTS - IRR		1,123,893			0.0000
304	WASHINGTON - INCOME TAX DEFERRAL ADJUSTMENTS		102,285			0.0000
305	WASHINGTON - DSM REVENUE-IRRIGATION		704,072			0.0000
306	WASHINGTON - BLUE SKY REVENUE-IRRIGATION		1,746			0.0000
307	WYOMING - 05APS00040-AG PUMPING SVC - IRR	23,389	2,339,020	796	29,383	0.1000
308	WYOMING - 05APS0040T-WY IRG TOU PILOT - IRR	59	7,526	4	14,750	0.1276
309	WYOMING - 05APSNS040-AG PUMPING SVC - NON SEASON - IRR	1,674	174,721	36	46,500	0.1044
310	WYOMING - 05LNX00103-LINE EXT 80% G		415			0.0000
311	WYOMING - 05LNX00109-REF/NREF ADV + - IRR		288			0.0000
312	WYOMING - 05LNX00110-REF/NREF ADV + - IRR		53,952			0.0000
313	WYOMING - 05LNX00310-LINE EXTENSION CONTRACT		626			0.0000
314	WYOMING - 05LNX00312 - WY IRG LINE EXT - IRR		57			0.0000
315	WYOMING - REVENUE_ACCOUNTING ADJUSTMENTS - IRR		17,431			0.0000
316	WYOMING - REVENUE ADJUSTMENT - DEFERRED NPC - IRR		11,894			0.0000
317	WYOMING - DSM REVENUE-IRRIGATION - IRR		26,081			0.0000
318	WYOMING - BLUE SKY REVENUE-IRRIGATION - IRR		2			0.0000
319	WYOMING - OTHER CUSTOMER RETAIL REVENUE - IRR		998			0.0000
320	WYOMING - 05APS00040-AG PUMPING SVC	9,051	768,835	117	77,359	0.0849
321	WYOMING - 05APS0040T-WY IRG TOU PILOT	128	10,261	2	64,000	0.0802
322	WYOMING - 05APSNS040-AG PUMPING SVC - NON SEASON	661	58,970	6	110,167	0.0892
323	WYOMING - 05LNX00109-REF/NREF ADV +		394			0.0000
324	WYOMING - 05LNX00110-REF/NREF ADV +		9,681			0.0000
325	WYOMING - 05LNX00312 - WY IRG LINE EXT		323			0.0000
326	WYOMING - DSM REVENUE-IRRIGATION		23,743			0.0000
327	WYOMING - BLUE SKY REVENUE-IRRIGATION		47			0.0000
328	LESS MULTIPLE BILLINGS IRRIGATION			950
41	TOTAL Billed Large (or Ind.) Sales	18,142,023	1,660,015,847	32,689	554,989	0.0915
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)	25,619	15,901,000			0.6207
43	TOTAL Large (or Ind.)	18,167,642	1,675,916,847	32,689	555,772	0.0922

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, list the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	CALIFORNIA - 06CUSL053E-SPECIAL CUST O	1,055	258,583	130	8,115	0.2451
2	CALIFORNIA - 06SLCO0051-COMPANY OWNED STREET LIGHTING	697	317,748	97	7,186	0.4559
3	CALIFORNIA - DSM REVENUE-PSHL		4,111			0.0000
4	CALIFORNIA - REVENUE_ACCOUNTING ADJUSTMENTS		3,724			0.0000
5	CALIFORNIA - REVENUE ADJUSTMENT - DEFERRED NPC		130			0.0000
6	IDAHO - 07GNSV023S-IDAHO TRAFFIC SIGNALS	136	21,220	24	5,667	0.1560
7	IDAHO - 07SLCO0011-STR LGT CO-OWN	198	104,970	72	2,750	0.5302
8	IDAHO - 07SLCU012E-ENGY STR LGT-CUST OWN	553	59,286	71	7,789	0.1072
9	IDAHO - 07SLCU012F-FULL MNT STR LGT-CUST OWN	1,538	288,717	171	8,994	0.1877
10	IDAHO - 07SLCU012P-PART MNT STR LGT CUST OWN	182	24,682	14	13,000	0.1356
11	IDAHO - DSM REVENUE-PSHL		10,963			0.0000
12	OREGON - 01COST023F - OR GEN SRV - COST-BASED	612	44,490			0.0727
13	OREGON - 01CUSL0053-CUS-OWNED MTRD	408	35,203	70	5,829	0.0863
14	OREGON - 01GNSV023F - OR GEN SRV - FLAT RATE		143,140	15		0.0000
15	OREGON - 01CUSL053E-STR LGT SVC	6,831	588,079	216	31,625	0.0861
16	OREGON - 01CUSL053F-STR LGT SRVC C	65	5,978	3	21,667	0.0920
17	OREGON - 01CUSL53E2-STR LGT SVC	775	66,678	13	59,615	0.0860
18	OREGON - 01HPSV0051-HI PRESSURE SO	10,395	1,920,125	545	19,073	0.1847
19	OREGON - 01OALT015N-OUTD AR LGT NR		281			0.0000
20	OREGON - 01SLCO0051-OR COMPANY OWNED STREET LIGHT	8,783	2,345,255	684	12,841	0.2670
21	OREGON - COMMUNITY SOLAR REVENUE		1,586			0.0000
22	OREGON - DSM REVENUE-PSHL		259,987			0.0000
23	OREGON - REVENUE_ACCOUNTING ADJUSTMENTS		79,305			0.0000
24	OREGON - SOLAR FEED-IN REVENUE		6,369			0.0000
25	OREGON - OTHER CUSTOMER RETAIL REVENUE		4,067			0.0000
26	UTAH - 08CFR00012-STR LGTS (CONV		54			0.0000
27	UTAH - 08CFR00051-MTH FAC SRVCHG		4,529			0.0000
28	UTAH - 08CFR00062-STREET LIGHTS		79			0.0000
29	UTAH - 08TOSS015F-TRAFFIC SIG NM	1,121	100,613	122	9,189	0.0898
30	UTAH - 08TOSS3415-TRAFFIC OTHER SIGNAL MTR SCH	341	41,702	201	1,697	0.1223
31	UTAH - 08SLCO0011-STR LGT CO-OWN	10,770	3,386,287	810	13,295	0.3144
32	UTAH - 08TOSS0015-TRAF & OTHER S	3,206	342,467	1,175	2,731	0.1068
33	UTAH - 08MONL0015-MTR OUTDONIGHT	908	50,706	104	8,731	0.0558
34	UTAH - 08MONL3415-MTR OUTDOOR NIGHT LIGHT SCH 3	106	5,821	12	8,833	0.0549
35	UTAH - 08SLCU012P-STR LGT CUST-O	1,269	108,487	126	10,071	0.0855
36	UTAH - 08SLCU012F-STR LGT CUST-O	522	51,897	54	9,667	0.0994
37	UTAH - 08SLCU012E-DECOR CUST-OWN	36,198	1,675,505	1,164	31,097	0.0463
38	UTAH - DSM REVENUE-PSHL		125,330			0.0000
39	UTAH - REVENUE_ACCOUNTING ADJUSTMENTS		238,116			0.0000
40	UTAH - REVENUE ADJUSTMENT - DEFERRED NPC		1,012,991			0.0000
41	UTAH - OTHER CUSTOMER RETAIL REVENUE		14,780			0.0000
42	WASHINGTON - 02CFR00012-STR LGTS (CONV		91			0.0000
43	WASHINGTON - 02CUSL053F-WA STR LGT SRV	1,358	116,456	108	12,574	0.0858
44	WASHINGTON - 02CUSL053M-WA STR LGT SRV	632	53,316	112	5,643	0.0844
45	WASHINGTON - 02SLCO0051-WA COMPANY STREET LIGHTING	2,014	671,596	235	8,566	0.3336
46	WASHINGTON - INCOME TAX DEFERRAL ADJUSTMENTS - PSHL		2,439			0.0000
47	WASHINGTON - DSM REVENUE-PSHL		29,757			0.0000
48	WASHINGTON - REVENUE_ACCOUNTING ADJUSTMENTS		34,487			0.0000
49	WASHINGTON - REVENUE ADJUSTMENT - DEFERRED NPC		2,711			0.0000
50	WYOMING - 05CUSL0058-CUST OWND STR	30	1,848	10	3,000	0.0616
51	WYOMING - 05CUSL0E58-WY CUST OWNED STREET LIGHT	640	38,781	23	27,826	0.0606
52	WYOMING - 05CUSL0M58-CUST OWNED STREET LT W/MAIT - PSHL	7	655	2	3,500	0.0935
53	WYOMING - 05SLCO0051-WY STREET LIGHT COMPANY OWNED - PSHL	8,796	1,866,872	452	19,458	0.2123
54	WYOMING - DSM REVENUE-PSHL - PSHL		39,664			0.0000
55	WYOMING - OTHER CUSTOMER RETAIL REVENUE		321			0.0000
56	WYOMING - REVENUE_ACCOUNTING ADJUSTMENTS		4,124			0.0000
57	WYOMING - REVENUE ADJUSTMENT - DEFERRED NPC		3,815			0.0000
58	WYOMING - 05CUSL0M58-CUST OWNED STREET LT W/MAIT	33	5,020	4	8,250	0.1521
59	WYOMING - 05RCFL0054-WY REC FIELD L	46	4,919	15	3,067	0.1069
60	WYOMING - 05SLCO0051-WY STREET LIGHT COMPANY OWNED	1,456	317,056	58	25,103	0.2178
61	WYOMING - DSM REVENUE-PSHL		8,684			0.0000
62	LESS MULTIPLE BILLINGS			3,916
41	TOTAL Billed Public Street and Highway Lighting	101,681	16,712,527	2,996	33,939	0.1644
42	TOTAL Unbilled Rev. (See Instr. 6)	204	5,000			0.0245
43	TOTAL	101,477	16,707,527	2,996	33,939	0.1646

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, list the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
41	TOTAL Billed - All Accounts	59,299,991	6,913,684,006	2,136,853
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts	88,129	52,473,000
43	TOTAL - All Accounts	59,211,862	6,966,157,006	2,136,853	27,735	0.1057

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

SALES FOR RESALE (Account 447)
Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326). Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for long-term service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means longer than one year but less than five years. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the length of the contract and service from designated units of less than one year. Describe the nature of the service in a footnote. AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the last line of the schedule. Report subtotals and total for columns (g) through (k). In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate lines, list all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the last line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,line 24. Footnote entries as required and provide explanations following all required data.
					ACTUAL DEMAND (MW)			REVENUE
Line No.	Name of Company or Public Authority (Footnote Affiliations) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Average Monthly Billing Demand (MW) (d)	Average Monthly NCP Demand (e)	Average Monthly CP Demand (f)	Megawatt Hours Sold (g)	Demand Charges ($) (h)	Energy Charges ($) (i)	Other Charges ($) (j)	Total ($) (h+i+j) (k)
1	Requirement Sales:
2	Helper City	RQ	T-6	1	1	1	7,196	147,586	127,187		274,773
3	Helper City Annex	RQ	T-6	1	1	1	4,018	75,296	71,011		146,307
4	Navajo Tribal Utility Authority	RQ	T-12	37	37	35	308,722	7,173,555	9,178,162	(l) 1,394,800	17,746,517
5	Navajo Tribal Utility Authority (Mexican Hat)	RQ	T-6	0	0	0	962	16,416	16,720		33,136
6	Accrual	RQ					1,202			(m) 186,190	186,190
7	Non-Requirement Sales:
8	3PR Trading, Inc	SF	T-12				102,865		3,534,482		3,534,482
9	Altop Energy Trading, LLC	SF	T-12				114,051		4,856,191		4,856,191
10	Altop Energy Trading, LLC	SF	WSPP-Q				400		10,800		10,800
11	Arizona Electric Power Cooperative, Inc.	SF	T-12				700		31,209		31,209
12	Arizona Public Service Company	SF	T-12				5,851		240,904		240,904
13	Avangrid Power, LLC	SF	T-12				10,697		452,199		452,199
14	Avangrid Power, LLC	SF	T-13				21			(n) 727	727
15	Avista Corporation	SF	T-12				800		17,775		17,775
16	Avista Corporation	SF	T-13				22			(o) 878	878
17	Basin Electric Power Cooperative	SF	T-12				18,183		759,067		759,067
18	Black Hills Power, Inc.	SF	T-12				53,925		1,981,552		1,981,552
19	Black Hills Power, Inc.	SF	WSPP-Q				51		3,570		3,570
20	Bonneville Power Administration	SF	T-12				199,695		8,700,203		8,700,203
21	Bonneville Power Administration	SF	T-13				34			(p) 1,568	1,568
22	Bonneville Power Administration	SF	WSPP-Q				3,400		77,400		77,400
23	BP Energy Company	SF	T-12				157,585		6,784,093		6,784,093
24	BP Energy Company	SF	WSPP-Q				5,320		189,750		189,750
25	British Columbia Hydro and Power Authority	SF	T-13				20			(q) 777	777
26	Calpine Energy Services, L.P.	SF	T-12				152		7,622		7,622
27	Citigroup Energy Inc.	SF	T-12				446,301		19,445,087		19,445,087
28	City of Burbank	SF	T-12				1,400		37,800		37,800
29	City of St. George, Utah	SF	T-12				415		13,950		13,950
30	Clatskanie People's Utility District	SF	T-12				1,967		82,483		82,483
31	Colorado Springs Utilities	SF	T-12				365		9,905		9,905
32	ConocoPhillips Company	SF	T-12				1,763		78,153		78,153
33	Constellation Energy Generation, LLC	SF	T-12				18,789		823,858		823,858
34	CP Energy Marketing (US) Inc.	SF	T-12				2,935		92,980		92,980
35	DRW Energy Trading LLC	SF	T-12				1,600		44,732		44,732
36	Dynasty Power Inc.	(b) AD	T-12							(r) 7	7
37	Dynasty Power Inc.	SF	T-12				692,294		39,641,589		39,641,589
38	Dynasty Power Inc.	SF	WSPP-Q				4,201		149,366		149,366
39	EDF Trading North America, LLC	SF	T-12				28		1,540		1,540
40	El Paso Electric Company	SF	T-12				1,971		89,227		89,227
41	Energy Keepers, Inc.	SF	T-12				437		9,668		9,668
42	Eugene Water & Electric Board	SF	T-12				7,269		299,695		299,695
43	Eugene Water & Electric Board	SF	WSPP-Q				430		24,310		24,310
44	Gridforce Energy Management, LLC	(c) AD	T-13							(s) 9	9
45	Gridforce Energy Management, LLC	SF	T-13				310			(t) 13,959	13,959
46	Guzman Energy, LLC	SF	T-12				76,231		2,463,928		2,463,928
47	Guzman Energy, LLC	SF	WSPP-Q				200		5,600		5,600
48	Idaho Power Company	SF	T-13				140			(u) 5,439	5,439
49	J. Aron & Company	SF	T-12				36,566		1,662,843		1,662,843
50	Los Angeles Department of Water and Power	SF	T-12				3,879		142,020		142,020
51	Macquarie Energy LLC	(d) AD	WSPP-Q							(v) 4,930	4,930
52	Macquarie Energy LLC	SF	T-12				98,798		4,013,622		4,013,622
53	Macquarie Energy LLC	SF	WSPP-Q				2,000		83,200		83,200
54	Mag Energy Solutions Inc	SF	WSPP-Q				1,475		42,250		42,250
55	Mercuria Energy America, LLC	SF	T-12				366,337		17,350,287		17,350,287
56	Mercuria Energy America, LLC	SF	WSPP-Q				4,844		225,770		225,770
57	Morgan Stanley Capital Group Inc.	SF	T-12				173,821		7,872,169		7,872,169
58	Morgan Stanley Capital Group Inc.	SF	WSPP-Q				5,792		235,538		235,538
59	NaturEner Power Watch, LLC	SF	T-13				15			(w) 730	730
60	(a) Nevada Power Company	SF	WSPP-Q				190		10,255		10,255
61	NorthWestern Corporation dba NorthWestern Energy	SF	T-12				205		8,200		8,200
62	NorthWestern Corporation dba NorthWestern Energy	SF	T-13				48			(x) 1,345	1,345
63	NorthWestern Corporation dba NorthWestern Energy	SF	WSPP-Q				150		10,500		10,500
64	Phillips 66 Energy Trading, LLC	SF	T-12				366,085		16,032,862		16,032,862
65	Phillips 66 Energy Trading, LLC	SF	WSPP-Q				15,119		436,218		436,218
66	Portland General Electric Company	SF	T-12				4,823		144,770		144,770
67	Portland General Electric Company	SF	T-13				66			(y) 2,930	2,930
68	Powerex Corporation	SF	T-12				27,616		693,055		693,055
69	Powerex Corporation	SF	WSPP-Q				3,047		73,910		73,910
70	Public Service Company of Colorado	IF	T-12				363,349		13,171,569		13,171,569
71	Public Service Company of Colorado	(e) AD	T-12				328			(z) 31,907	31,907
72	Public Service Company of Colorado	SF	T-12				22,715		883,357		883,357
73	Public Service Company of New Mexico	(f) AD	T-12							(aa) 621	621
74	Public Service Company of New Mexico	SF	T-12				90,487		3,704,400		3,704,400
75	Public Utility District No. 1 of Chelan County	SF	T-13				6			(ab) 128	128
76	Public Utility District No. 1 of Snohomish County	SF	T-12				25		1,500		1,500
77	Public Utility District No. 2 of Grant County	SF	T-13				4			(ac) 161	161
78	Puget Sound Energy, Inc.	SF	T-12				13,070		580,686		580,686
79	Puget Sound Energy, Inc.	SF	T-13				21			(ad) 657	657
80	Puget Sound Energy, Inc.	SF	WSPP-Q				319		11,815		11,815
81	Rainbow Energy Marketing Corporation	SF	T-12				6,368		180,900		180,900
82	Rainbow Energy Marketing Corporation	SF	WSPP-Q				6,780		148,840		148,840
83	Sacramento Municipal Utility District	SF	T-12				155,784		12,688,620		12,688,620
84	Sacramento Municipal Utility District	SF	T-13				6			(ae) 362	362
85	Salt River Project	SF	T-12				3,309		159,080		159,080
86	Seattle City Light	SF	T-12				1,550		60,625		60,625
87	Seattle City Light	SF	T-13				19			(af) 549	549
88	Shell Energy North America (US), L.P.	(g) AD	T-12							(ag) 6,855	6,855
89	Shell Energy North America (US), L.P.	SF	T-12				438,032		18,531,911		18,531,911
90	Shell Energy North America (US), L.P.	SF	WSPP-Q				38,777		1,335,095		1,335,095
91	Tacoma Power	SF	T-12				190		5,425		5,425
92	Tenaska Power Services Co.	SF	T-12				15,925		589,501		589,501
93	Tenaska Power Services Co.	SF	WSPP-Q				485		22,760		22,760
94	The Energy Authority, Inc.	SF	T-12				159,095		6,304,446		6,304,446
95	The Energy Authority, Inc.	SF	WSPP-Q				530		23,820		23,820
96	TransAlta Energy Marketing (U.S.) Inc.	SF	T-12				39,999		1,724,354		1,724,354
97	TransAlta Energy Marketing (U.S.) Inc.	SF	WSPP-Q				290		14,700		14,700
98	Tri-State Generation and Transmission Association, Inc.	SF	T-12				23,414		1,034,912		1,034,912
99	Tucson Electric Power Company	SF	T-12				13,539		649,904		649,904
100	Turlock Irrigation District	SF	T-12				11,277		425,937		425,937
101	UNS Electric, Inc.	SF	T-12				934		45,187		45,187
102	Utah Associated Municipal Power Systems	(h) AD	WSPP-Q							(ah) 1,724	1,724
103	Utah Associated Municipal Power Systems	SF	T-12				365		23,015		23,015
104	Utah Associated Municipal Power Systems	SF	WSPP-Q				4,718		171,949		171,949
105	Utah Municipal Power Agency	SF	T-12				40		1,640		1,640
106	Utah Municipal Power Agency	SF	WSPP-Q				31,548		1,084,169		1,084,169
107	Vitol Inc.	SF	T-12				6,369		168,286		168,286
108	Western Area Power Administration-Colorado Missouri	SF	T-12				14,300		513,010		513,010
109	Western Area Power Administration-Upper Colorado	SF	T-12				16,279		738,619		738,619
110	Test Generation	(i) OS	NA				53,930			(ai) 1,814,552	1,814,552
111	Transmission Loss Sales Revenue	(j) AD	T-11				3			(aj) 101	101
112	Transmission Loss Sales Revenue	(k) OS	T-11				301,588			(ak) 8,982,888	8,982,888
113	Netting-Bookouts						735,873			(al) 31,387,399	31,387,399
114	Netting-Trading									(am) 176,515	176,515
115	Accrual						1,529			(an) 28,121	28,121
15	Subtotal - RQ						319,696	7,412,853	9,393,080	1,208,610	18,014,543
16	Subtotal-Non-RQ						4,034,199		204,998,189	24,357,195	180,640,994
17	Total						4,353,895	7,412,853	214,391,269	23,148,585	(ao) 198,655,537

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

Nevada Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.

(b) Concept: StatisticalClassificationCode

Settlement adjustment.

(d) Concept: StatisticalClassificationCode

Settlement adjustment.

(e) Concept: StatisticalClassificationCode

Settlement adjustment.

(f) Concept: StatisticalClassificationCode

Settlement adjustment.

(g) Concept: StatisticalClassificationCode

Settlement adjustment.

(h) Concept: StatisticalClassificationCode

Settlement adjustment.

(i) Concept: StatisticalClassificationCode

The negative revenue reported on this line reflects test energy generated at the Rock Creek I Wind generating facility and the Rock Creek II Wind generating facility that was transferred to construction. Energy generated during testing was delivered to PacifiCorp's electric system for sale, as required by the guidance in 18 CFR Electric Plant Instructions 18(a), is a component of construction and is the fair value of the energy delivered.

(j) Concept: StatisticalClassificationCode

Settlement adjustment.

(k) Concept: StatisticalClassificationCode

Transmission loss sales revenues collected from PacifiCorp's third-party transmission service customers.

(l) Concept: OtherChargesRevenueSalesForResale


Load retention payment	$	(936,125)
Customer service charges related to:	2,330,925
- Schedule 94, Utah Energy Balancing Account
- Schedule 98, Utah Renewable Energy Credits Revenue Adjustment
- Schedule 196, Utah Sustainable Transportation and Energy Plan Cost Adjustment Pilot Program
- Schedule 197, Utah Federal Tax Act Adjustment
	$	1,394,800

(m) Concept: OtherChargesRevenueSalesForResale

Represents the difference between actual requirement sales revenues for the period as reflected on the individual line items within this schedule and the accruals charged to account 447, Sales for resale, during the period.

(n) Concept: OtherChargesRevenueSalesForResale

Reserve share.

(o) Concept: OtherChargesRevenueSalesForResale

Reserve share.

(p) Concept: OtherChargesRevenueSalesForResale

Reserve share.

(q) Concept: OtherChargesRevenueSalesForResale

Reserve share.

(r) Concept: OtherChargesRevenueSalesForResale

Settlement adjustment.

(s) Concept: OtherChargesRevenueSalesForResale

Settlement adjustment.

(t) Concept: OtherChargesRevenueSalesForResale

Reserve share.

(u) Concept: OtherChargesRevenueSalesForResale

Reserve share.

(v) Concept: OtherChargesRevenueSalesForResale

Settlement adjustment.

(w) Concept: OtherChargesRevenueSalesForResale

Reserve share.

(x) Concept: OtherChargesRevenueSalesForResale

Reserve share.

(y) Concept: OtherChargesRevenueSalesForResale

Reserve share.

(z) Concept: OtherChargesRevenueSalesForResale

Settlement adjustment.

(aa) Concept: OtherChargesRevenueSalesForResale

Settlement adjustment.

(ab) Concept: OtherChargesRevenueSalesForResale

Reserve share.

(ac) Concept: OtherChargesRevenueSalesForResale

Reserve share.

(ad) Concept: OtherChargesRevenueSalesForResale

Reserve share.

(ae) Concept: OtherChargesRevenueSalesForResale

Reserve share.

(af) Concept: OtherChargesRevenueSalesForResale

Reserve share.

(ag) Concept: OtherChargesRevenueSalesForResale

Settlement adjustment.

(ah) Concept: OtherChargesRevenueSalesForResale

Settlement adjustment.

(ai) Concept: OtherChargesRevenueSalesForResale

(aj) Concept: OtherChargesRevenueSalesForResale

Settlement adjustment.

(ak) Concept: OtherChargesRevenueSalesForResale

Transmission loss sales revenues collected from PacifiCorp's third-party transmission service customers.

(al) Concept: OtherChargesRevenueSalesForResale

Reflects transactions that did not physically settle.

(am) Concept: OtherChargesRevenueSalesForResale

Reflects transactions that were categorized as trading activities.

(an) Concept: OtherChargesRevenueSalesForResale

Represents the difference between actual non-requirement sales revenues for the period as reflected on the individual line items within this schedule and the accruals charged to Account 447, Sales for resale, during the period.

(ao) Concept: SalesForResale

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line No.	Account (a)	Amount for Current Year (b)	Amount for Previous Year (c) (c)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION EXPENSES
2	SteamPowerGenerationAbstract A. Steam Power Generation
3	SteamPowerGenerationOperationAbstract Operation
4	OperationSupervisionAndEngineeringSteamPowerGeneration (500) Operation Supervision and Engineering	16,150,874	17,137,494
5	FuelSteamPowerGeneration (501) Fuel	862,964,197	711,344,075
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	74,108,380	67,096,534
7	SteamFromOtherSources (503) Steam from Other Sources		8,382,176
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	1,154,606	1,005,100
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	48,873,223	45,199,460
11	RentsSteamPowerGeneration (507) Rents	467,267	352,264
12	Allowances (509) Allowances	56,192,723
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	1,059,911,270	850,517,103
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	3,793,842	4,419,667
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	19,791,437	26,805,144
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	77,648,148	78,342,955
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	36,453,400	37,450,581
18.1	MaintenanceOfComputerHardwareSteamPowerGeneration (513.1) Maintenance of Computer Hardware	3,065
18.2	MaintenanceOfComputerSoftwareSteamPowerGeneration (513.2) Maintenance of Computer Software	588,070
18.3	MaintenanceOfCommunicationEquipmentSteamPowerGeneration (513.3) Maintenance of Communication Equipment	273,040
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	16,115,402	15,338,535
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	154,666,404	162,356,882
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	1,214,577,674	1,012,873,985
22	NuclearPowerGenerationAbstract B. Nuclear Power Generation
23	NuclearPowerGenerationOperationAbstract Operation
24	OperationSupervisionAndEngineeringNuclearPowerGeneration (517) Operation Supervision and Engineering
25	NuclearFuelExpense (518) Fuel
26	CoolantsAndWater (519) Coolants and Water
27	SteamExpensesNuclearPowerGeneration (520) Steam Expenses
28	SteamFromOtherSourcesNuclearPowerGeneration (521) Steam from Other Sources
29	SteamTransferredCreditNuclearPowerGeneration (Less) (522) Steam Transferred-Cr.
30	ElectricExpensesNuclearPowerGeneration (523) Electric Expenses
31	MiscellaneousNuclearPowerExpenses (524) Miscellaneous Nuclear Power Expenses
32	RentsNuclearPowerGeneration (525) Rents
33	NuclearPowerGenerationOperationsExpense TOTAL Operation (Enter Total of lines 24 thru 32)
34	NuclearPowerGenerationMaintenanceAbstract Maintenance
35	MaintenanceSupervisionAndEngineeringNuclearPowerGeneration (528) Maintenance Supervision and Engineering
36	MaintenanceOfStructuresNuclearPowerGeneration (529) Maintenance of Structures
37	MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration (530) Maintenance of Reactor Plant Equipment
38	MaintenanceOfElectricPlantNuclearPowerGeneration (531) Maintenance of Electric Plant
38.1	MaintenanceOfComputerHardwareNuclearPowerGeneration (531.1) Maintenance of Computer Hardware
38.2	MaintenanceOfComputerSoftwareNuclearPowerGeneration (531.2) Maintenance of Computer Software
38.3	MaintenanceOfCommunicationEquipmentNuclearPowerGeneration (531.3) Maintenance of Communication Equipment
39	MaintenanceOfMiscellaneousNuclearPlant (532) Maintenance of Miscellaneous Nuclear Plant
40	NuclearPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 35 thru 39)
41	PowerProductionExpensesNuclearPower TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)
42	HydraulicPowerGenerationAbstract C. Hydraulic Power Generation
43	HydraulicPowerGenerationOperationAbstract Operation
44	OperationSupervisionAndEngineeringHydraulicPowerGeneration (535) Operation Supervision and Engineering	14,021,746	13,327,979
45	WaterForPower (536) Water for Power	45,288	71,282
46	HydraulicExpenses (537) Hydraulic Expenses	5,448,342	5,791,762
47	ElectricExpensesHydraulicPowerGeneration (538) Electric Expenses
48	MiscellaneousHydraulicPowerGenerationExpenses (539) Miscellaneous Hydraulic Power Generation Expenses	16,211,447	16,025,914
49	RentsHydraulicPowerGeneration (540) Rents	2,042,786	1,622,828
50	HydraulicPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 44 thru 49)	37,769,609	36,839,765
51	HydraulicPowerGenerationContinuedAbstract C. Hydraulic Power Generation (Continued)
52	HydraulicPowerGenerationMaintenanceAbstract Maintenance
53	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration (541) Maintenance Supervision and Engineering	381	1,588
54	MaintenanceOfStructuresHydraulicPowerGeneration (542) Maintenance of Structures	495,154	650,504
55	MaintenanceOfReservoirsDamsAndWaterways (543) Maintenance of Reservoirs, Dams, and Waterways	695,038	1,337,998
56	MaintenanceOfElectricPlantHydraulicPowerGeneration (544) Maintenance of Electric Plant	1,056,413	1,478,883
56.1	MaintenanceOfComputerHardwareHydraulicPowerGeneration (544.1) Maintenance of Computer Hardware
56.2	MaintenanceOfComputerSoftwareHydraulicPowerGeneration (544.2) Maintenance of Computer Software	50
56.3	MaintenanceOfCommunicationEquipmentHydraulicPowerGeneration (544.3) Maintenance of Communication Equipment	1,642
57	MaintenanceOfMiscellaneousHydraulicPlant (545) Maintenance of Miscellaneous Hydraulic Plant	5,403,328	16,634,253
58	HydraulicPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 53 thru 57)	7,652,006	20,103,226
59	PowerProductionExpensesHydraulicPower TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)	45,421,615	56,942,991
60	OtherPowerGenerationAbstract D. Other Power Generation
61	OtherPowerGenerationOperationAbstract Operation
62	OperationSupervisionAndEngineeringOtherPowerGeneration (546) Operation Supervision and Engineering	506,112	587,789
63	Fuel (547) Fuel	403,443,315	411,478,539
64	GenerationExpenses (548) Generation Expenses	21,306,177	29,285,518
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses	3,140,802	11,253,834
66	RentsOtherPowerGeneration (550) Rents	44,447	9,710,440
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	428,440,853	462,316,120
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering
70	MaintenanceOfStructures (552) Maintenance of Structures	2,561,852	3,118,861
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant	17,673,216	23,540,449
71.1	MaintenanceOfComputerHardwareOtherPowerGeneration (553.1) Maintenance of Computer Hardware	533
71.2	MaintenanceOfComputerSoftwareOtherPowerGeneration (553.2) Maintenance of Computer Software	124,279
71.3	MaintenanceOfCommunicationEquipmentOtherPowerGeneration (553.3) Maintenance of Communication Equipment	28,452
72	MaintenanceOfMiscellaneousOtherPowerGenerationPlant (554) Maintenance of Miscellaneous Other Power Generation Plant	2,019,488	6,909,485
73	OtherPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 69 thru 72)	22,407,820	33,568,795
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	450,848,673	495,884,915
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	1,676,351,194	1,451,956,663
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations
76.2	BundledEnvironmentalCredits (555.2) Bundled Environmental Credits
76.3	UnbundledEnvironmentalCredits (555.3) Unbundled Environmental Credits	9,085,101
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	2,451,802	4,252,372
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	65,340,911	60,738,555
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	1,753,229,008	1,516,947,590
79.1	SolarGenerationAbstract F. Solar Generation
79.2	SolarGenerationOperationAbstract Operation
79.3	OperationSupervisionAndEngineeringSolarGeneration (558.1) Operation Supervision and Engineering
79.4	SolarPanelGenerationAndOtherPlantOperatingExpensesSolarGeneration (558.2) Solar Panel Generation and Other Plant Operating Expenses	395,148
79.6	RentsSolarGeneration (558.4) Rents	58,885
79.7	SolarGenerationOperationsExpense TOTAL Operation (Enter Total of lines 79.3 thru 79.6)	454,033
79.8	SolarGenerationMaintenanceAbstract Maintenance
79.9	MaintenanceSupervisionAndEngineeringSolarGeneration (558.6) Maintenance Supervision and Engineering
79.10	MaintenanceOfSolarPanelsStructuresAndEquipmentSolarGeneration (558.7) Maintenance of Solar Panels, Structures, and Equipment
79.11	MaintenanceOfComputerHardwareSolarGeneration (558.8) Maintenance of Computer Hardware
79.12	MaintenanceOfComputerSoftwareSolarGeneration (558.9) Maintenance of Computer Software
79.13	MaintenanceOfCommunicationEquipmentSolarGeneration (558.10) Maintenance of Communication Equipment
79.14	MaintenanceOfMiscellaneousSolarGenerationPlant (558.11) Maintenance of Miscellaneous Solar Generation Plant
79.15	SolarGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 79.9 thru 79.14)
79.16	PowerProductionExpensesSolar TOTAL Power Production Expenses-Solar (total of lines 79.7 & 79.15)	454,033
79.17	WindGenerationAbstract G. Wind Generation
79.18	WindGenerationOperationAbstract Operation
79.19	OperationSupervisionAndEngineeringWindGeneration (558.13) Operation Supervision and Engineering	10,149
79.20	WindTurbineGenerationAndOtherPlantOperatingExpensesWindGeneration (558.14) Wind Turbine Generation and Other Plant Operating Expenses	3,655,512
79.21	RentsWindGeneration (558.16) Rents	3,630,027
79.22	WindGenerationOperationsExpense TOTAL Operation (Enter Total of lines 79.19 thru 79.21)	7,295,688
79.23	WindGenerationMaintenanceAbstract Maintenance
79.24	MaintenanceSupervisionAndEngineeringWindGeneration (558.18) Maintenance Supervision and Engineering
79.25	MaintenanceOfWindTurbinesStructuresAndEquipmentWindGeneration (558.19) Maintenance of Wind Turbines, Structures, and Equipment	5,676,004
79.26	MaintenanceOfComputerHardwareWindGeneration (558.20) Maintenance of Computer Hardware	161
79.27	MaintenanceOfComputerSoftwareWindGeneration (558.21) Maintenance of Computer Software
79.28	MaintenanceOfCommunicationEquipmentWindGeneration (558.22) Maintenance of Communication Equipment	116,497
79.29	MaintenanceOfMiscellaneousWindGenerationPlant (558.23) Maintenance of Miscellaneous Wind Generation Plant	43,290,530
79.30	WindGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 79.24 thru 79.29)	48,850,198
79.31	PowerProductionExpensesWind TOTAL Power Production Expenses-Wind (total of lines 79.22 & 79.30)	56,145,886
79.32	OtherRenewableGenerationAbstract H. Other Renewable Generation
79.33	OtherRenewableGenerationOperationAbstract Operation
79.34	OperationSupervisionAndEngineeringOtherRenewableGeneration (559.1) Operation Supervision and Engineering	1,722
79.35	OtherMiscellaneousGenerationAndOtherPlantOperatingExpensesOtherRenewableGeneration (559.2) Other Miscellaneous Generation and Other Plant Operating Expenses	6,918,774
79.36	FuelOtherRenewableGeneration (559.3) Fuel	1,466,525
79.37	RentsOtherRenewableGeneration (559.4) Rents
79.38	OtherRenewableGenerationOperationsExpense TOTAL Operation (Enter Total of lines 79.34 thru 79.37)	8,387,021
79.39	OtherRenewableGenerationMaintenanceAbstract Maintenance
79.40	MaintenanceSupervisionAndEngineeringOtherRenewableGeneration (559.6) Maintenance Supervision and Engineering
79.41	MaintenanceOfStructuresOtherRenewableGeneration (559.7) Maintenance of Structures	157,845
79.42	MaintenanceOfBoilersOtherRenewableGeneration (559.9) Maintenance of Boilers	286,908
79.43	MaintenanceOfGeneratingAndElectricEquipmentOtherRenewableGeneration (559.10) Maintenance of Generating and Electric Equipment	412,039
79.44	MaintenanceOfComputerHardwareOtherRenewableGeneration (559.12) Maintenance of Computer Hardware	7,370
79.45	MaintenanceOfComputerSoftwareOtherRenewableGeneration (559.13) Maintenance of Computer Software	499,159
79.46	MaintenanceOfCommunicationEquipmentOtherRenewableGeneration (559.14) Maintenance of Communication Equipment	10,233
79.47	MaintenanceOfMiscellaneousRenewableProductionPlantOtherRenewableGeneration (559.15) Maintenance of Miscellaneous Renewable Production Plant	146,529
79.48	OtherRenewableGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 79.40 thru 79.47)	1,520,083
79.49	PowerProductionExpensesOtherRenewable TOTAL Power Production Expenses-Other Renewable (total of lines 79.38 & 79.48)	9,907,104
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74, 79, 79.16, 79.31, & 79.49)	3,530,583,993	3,082,649,481
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	10,233,003	13,931,723
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	9,683,320	8,449,519
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	926,016	832,432
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	1,349,537	3,114,499
90	TransmissionServiceStudies (561.6) Transmission Service Studies	218,353	228,730
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies	2,055,065	2,498,329
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services	7,461,595	5,866,427
93	StationExpensesTransmissionExpense (562) Station Expenses	3,938,114	3,599,181
94	OverheadLineExpense (563) Overhead Lines Expenses	1,630,364	1,616,329
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	187,499,790	176,350,418
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	5,421,395	3,771,126
98	RentsTransmissionElectricExpense (567) Rents	2,242,603	2,412,686
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	232,659,155	222,671,399
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	2,374,189	1,164,967
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	87,003	158,935
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	12,379	641
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	2,537,879	109,580
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	6,807,381	5,594,986
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	15,436,853	14,234,262
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	33,953,022	28,035,336
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines		85,062
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	480,928	223,355
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	61,515,628	49,607,124
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	294,174,783	272,278,523
113	RegionalMarketExpensesAbstract 3. REGIONAL MARKET EXPENSES
114	RegionalMarketExpensesOperationAbstract Operation
115	OperationSupervision (575.1) Operation Supervision
116	DayAheadAndRealTimeMarketAdministration (575.2) Day-Ahead and Real-Time Market Facilitation
117	TransmissionRightsMarketAdministration (575.3) Transmission Rights Market Facilitation
118	CapacityMarketAdministration (575.4) Capacity Market Facilitation
119	AncillaryServicesMarketAdministration (575.5) Ancillary Services Market Facilitation
120	MarketMonitoringAndCompliance (575.6) Market Monitoring and Compliance
121	MarketFacilitationMonitoringAndComplianceServices (575.7) Market Facilitation, Monitoring and Compliance Services
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)
124	RegionalMarketExpensesMaintenanceAbstract Maintenance
125	MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses (576.1) Maintenance of Structures and Improvements
126	MaintenanceOfComputerHardware (576.2) Maintenance of Computer Hardware
127	MaintenanceOfComputerSoftware (576.3) Maintenance of Computer Software
128	MaintenanceOfCommunicationEquipmentRegionalMarketExpenses (576.4) Maintenance of Communication Equipment
129	MaintenanceOfMiscellaneousMarketOperationPlant (576.5) Maintenance of Miscellaneous Market Operation Plant
130	RegionalMarketMaintenanceExpense Total Maintenance (Lines 125 thru 129)
131	RegionalMarketExpenses TOTAL Regional Transmission and Market Operation Expenses (Enter Total of Lines 123 and 130)
131.1	EnergyStorageExpensesAbstract 4. ENERGY STORAGE EXPENSES
131.2	EnergyStorageExpensesOperationAbstract Operation
131.3	OperationSupervisionAndEngineeringEnergyStorageExpenses (577.1) Operation Supervision and Engineering
131.4	OperationOfEnergyStorageEquipmentEnergyStorageExpense (577.2) Operation of Energy Storage Equipment
131.5	StorageFuelEnergyStorageExpense (577.3) Storage Fuel
131.6	RentsEnergyStorageExpense (577.4) Rents
131.7	EnergyStorageOperationExpenses Total Operation (Lines 131.3 thru 131.6)
131.8	EnergyStorageMaintenanceAbstract Maintenance
131.9	MaintenanceSupervisionAndEngineeringEnergyStorageExpenses (578.1) Maintenance Supervision and Engineering
131.10	MaintenanceOfEnergyStorageEquipmentAndStructuresEnergyStorageExpenses (578.2) Maintenance of Energy Storage Equipment and Structures
131.11	MaintenanceOfComputerHardwareEnergyStorageExpenses (578.3) Maintenance of Computer Hardware
131.12	MaintenanceOfComputerSoftwareEnergyStorageExpenses (578.4) Maintenance of Computer Software
131.13	MaintenanceOfCommunicationEquipmentEnergyStorageExpenses (578.5) Maintenance of Communication Equipment
131.14	MaintenanceOfMiscellaneousOtherEnergyStoragePlantEnergyStorageExpenses (578.6) Maintenance of Miscellaneous Other Energy Storage Plant
131.15	EnergyStorageMaintenanceExpenses Total Maintenance (Lines 131.9 thru 131.14)
131.16	EnergyStorageExpenses TOTAL Energy Storage Expenses (Total of 131.7 and 131.15)
132	DistributionExpensesAbstract 5. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	13,197,848	29,043,375
135	LoadDispatching (581) Load Dispatching	17,994,410	17,581,179
136	StationExpensesDistribution (582) Station Expenses	5,816,929	6,183,946
137	OverheadLineExpenses (583) Overhead Line Expenses	13,210,450	14,267,026
138	UndergroundLineExpenses (584) Underground Line Expenses
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	322,380	277,325
140	MeterExpenses (586) Meter Expenses	4,188,292	3,859,612
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	21,220,299	20,990,006
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	984,917	200,081
143	RentsDistributionExpense (589) Rents	3,828,308	3,675,197
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	78,793,999	96,077,747
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	6,721,644	8,759,368
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	3,744,213	2,958,957
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	8,432,274	9,639,970
148.1	MaintenanceOfComputerHardwareDistribution (592.2) Maintenance of Computer Hardware	95,475
148.2	MaintenanceOfComputerSoftwareDistribution (592.3) Maintenance of Computer Software	5,926,702
148.3	MaintenanceOfCommunicationEquipmentDistribution (592.4) Maintenance of Communication Equipment	7,139,815.00
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	192,701,779	226,974,973
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	47,226,996	42,396,520
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	1,059,328	1,117,795
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	1,984,418	2,274,277
153	MaintenanceOfMeters (597) Maintenance of Meters	681,412	397,101
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	9,383,947	9,668,300
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	285,098,003	304,187,261
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	363,892,002	400,265,008
157	CustomerAccountsExpensesAbstract 6. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision	23,042,111	10,677,993
160	MeterReadingExpenses (902) Meter Reading Expenses	9,205,320	9,145,570
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	39,294,739	44,503,825
162	UncollectibleAccounts (904) Uncollectible Accounts	22,085,103	25,388,863
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses		78
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	93,627,273	89,716,329
165	CustomerServiceAndInformationalExpensesAbstract 7. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	257,250,496	197,549,890
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses	6,326,547	5,649,617
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	424,153	22,979
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	264,001,196	203,222,486
172	SalesExpenseAbstract 8. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses
176	AdvertisingExpenses (913) Advertising Expenses
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)
179	AdministrativeAndGeneralExpensesAbstract 9. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	(a) 96,387,210	84,934,601
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	9,975,943	11,603,649
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	45,491,053	47,078,025
184	OutsideServicesEmployed (923) Outside Services Employed	(b) 53,800,982	46,178,414
185	PropertyInsurance (924) Property Insurance	(c) 27,400,989	23,447,828
186	InjuriesAndDamages (925) Injuries and Damages	(d) 345,548,576	481,106,207
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	(e) 145,553,646	138,901,694
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	37,398,113	35,681,963
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.	(f) 166,110,969	160,152,618
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	272,335	203,856
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	3,242,359	2,973,018
193	RentsAdministrativeAndGeneralExpense (931) Rents	(g) 641,534	1,059,594
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	508,619,665	618,860,181
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	(h) 4,256,437	38,053,495
196.1	MaintenanceOfComputerHardwareAdministrativeAndGeneralExpenses (935.1) Maintenance of Computer Hardware	1,242,782
196.2	MaintenanceOfComputerSoftwareAdministrativeAndGeneralExpenses (935.2) Maintenance of Computer Software	33,065,260
196.3	MaintenanceOfCommunicationEquipmentAdministrativeAndGeneralExpenses (935.3) Maintenance of Communication Equipment	89,864
196.4	AdministrativeAndGeneralMaintenanceExpenses TOTAL Maintenance (Enter Total of lines 196 thru 196.3)	38,654,343	38,053,495
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196.4)	(i) 547,274,008	656,913,676
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 131.16, 156, 164, 171, 178, and 197)	5,093,553,255	4,705,045,503

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: AdministrativeAndGeneralSalaries


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Account	Ref. Line No.	Amount for Current Year
(a)	(Column)	(b)
(920) Administrative and General Salaries	181(b)	$	96,387,210
Less: Regulatory asset amortization of Oregon's share of Cholla Unit No. 4 Closure Costs (1)		140,409
Revised (920) Administrative and General Salaries		$	96,246,801

(1) In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No. ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations reflected in Administrative and General expense accounts should be excluded from the calculation of the wholesale transmission revenue requirement and charges under the wholesale formula rates, unless approved by the Commission.

(b) Concept: OutsideServicesEmployed


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Account	Ref. Line No.	Amount for Current Year
(a)	(Column)	(b)
(923) Outside Services Employed	184(b)	$	53,800,982
Less: Regulatory asset amortization of Washington's share of Equity Advisory Group for Clean Energy Implementation Plan costs (1)		239,935
Less: Regulatory asset amortization of Washington's share of Colstrip Unit No. 4 Deferred Maintenance Costs (1)		64,726
Less: Energy Day Ahead Market (EDAM) costs related to Energy Supply Management		1,951
Revised (923) Outside Services Employed		$	53,494,370

(1) In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No. ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations reflected in Administrative and General expense accounts should be excluded from the calculation of the wholesale transmission revenue requirement and charges under the wholesale formula rates, unless approved by the Commission.


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Account	Ref. Line No.	Amount for Current Year
(a)	(Column)	(b)
(924) Property Insurance	185(b)	$	27,400,989
Less: Situs property loss reserves, net of reimbursements (1)		21,187,377
Revised (924) Property Insurance		$	6,213,612

(1) To adjust PacifiCorp's formula rate, per FERC Docket No. FA16-4-000 for situs property loss reserves, net of reimbursements.

(d) Concept: InjuriesAndDamages


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Account	Ref. Line No.	Amount for Current Year
(a)	(Column)	(b)
(925) Injuries and Damages	186(b)	$	345,548,576
Less: Regulatory asset amortization of Oregon's share of deferred insurance premiums (1)		12,189,840
Less: Regulatory asset amortization of Idaho's share of deferred insurance premiums (1)		6,078,099
Less: Regulatory asset amortization of Wyoming's share of deferred insurance premiums (1)		2,013,323
Revised (925) Injuries and Damages		$	325,267,314

(1) In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No. ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations reflected in Administrative and General expense accounts should be excluded from the calculation of the wholesale transmission revenue requirement and charges under the wholesale formula rates, unless approved by the Commission.

(e) Concept: EmployeePensionsAndBenefits

As required by Commission regulations, the cost of pensions, postretirement other than pensions and other employee benefits are reported in Account 926, Employee pensions and benefits. Pensions and benefits expense is associated with labor and generally charged to operations and maintenance expense and construction work in progress, therefore, pursuant to FERC Docket No. FA16-4-000, these pensions and benefits are offset in Account 929, Duplicate charges-credit. In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No. ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations reflected in Administrative and General expense accounts should be excluded from the calculation of the wholesale transmission revenue requirement and charges under the wholesale formula rates, unless approved by the Commission. During the year ended December 31, 2025, pension and postretirement regulatory asset amortization was $1,172,422.

(f) Concept: DuplicateChargesCredit

Includes the offset of pensions and benefits in Account 926, Employee pensions and benefits, pursuant to FERC Docket No. FA16-4-000.

(g) Concept: RentsAdministrativeAndGeneralExpense


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Account	Ref. Line No.	Amount for Current Year
(a)	(Column)	(b)
(931) Rents	193(b)	$	641,534
Less: Regulatory asset amortization of Oregon's share of Cholla Unit No. 4 Closure Costs (1)		9,837
Revised (931) Rents		$	631,697

(1) In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No. ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations reflected in Administrative and General expense accounts should be excluded from the calculation of the wholesale transmission revenue requirement and charges under the wholesale formula rates, unless approved by the Commission.

(h) Concept: MaintenanceOfGeneralPlant


Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, is as follows:
Account	Ref. Line No.	Amount for Current Year
(a)	(Column)	(b)
(935) Maintenance of General Plant	196(b)	$	4,256,437
Less: Write-off of assets under construction (1)		119,324
Less: Regulatory asset amortization of environmental costs (2)		264,080
Revised (935) Maintenance of General Plant		$	3,873,033

(1) To adjust PacifiCorp's formula rate, per the resolution of the preliminary challenge of PacifiCorp�s OATT Formula Rate 2021 Annual Update, for write-offs of assets under construction.
(2) In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No. ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations reflected in Administrative and General expense accounts should be excluded from the calculation of the wholesale transmission revenue requirement and charges under the wholesale formula rates, unless approved by the Commission.

(i) Concept: AdministrativeAndGeneralExpenses


Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment H-1, are as follows:
Account	Ref. Line No.	Amount for Current Year
(a)	(Column)	(b)
TOTAL Administrative & General Expenses	197(b)	$	547,274,008
Less: Account 920 regulatory asset amortization (1)		140,409
Less: Account 923 regulatory asset amortization (2)		304,661
Less: Energy Day Ahead Market (EDAM) costs related to Energy Supply Management (2)		1,951
Less: Situs property loss reserves, net of reimbursements (3)		21,187,377
Less: Account 925 regulatory asset amortization (4)		20,281,262
Less: Account 926 regulatory asset amortization (5)		1,172,422
Less: Account 931 regulatory asset amortization (6)		9,837
Less: Write-off of assets under construction (7)		119,324
Less: Account 935 regulatory asset amortization (7)		264,080
Revised TOTAL Administrative & General Expenses		$	503,792,685

(1) To adjust Account 920, Administrative and General Salaries. Refer to footnote on Page 320, Line No. 181, Column (b)
(2) To adjust Account 923, Outside Services Employed. Refer to footnote on Page 320, Line No. 184, Column (b)
(3) To adjust Account 924, Property insurance. Refer to footnote on Page 320, Line No. 185, Column (b)
(4) To adjust Account 925, Injuries and Damages. Refer to footnote on Page 320, Line No. 186, Column (b).
(5) To adjust Account 926, Employee pensions and benefits. Refer to footnote on Page 320, Line No. 187, Column (b).
(6) To adjust Account 931, Rents. Refer to footnote on Page 320, Line No. 193, Column (b)
(7) To adjust Account 935, Maintenance of General Plant. Refer to footnote on Page 320, Line No. 196, Column (b).

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

PURCHASED POWER (Account 555)
Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the length of the contract and service from designated units of less than one year. Describe the nature of the service in a footnote for each adjustment. AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatthours shown on bills rendered to the respondent, excluding purchases for energy storage. Report in column (h) the megawatthours shown on bills rendered to the respondent for energy storage purchases. Report in columns (i) and (j) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. Report demand charges in column (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m). Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. The data in columns (g) through (n) must be totaled on the last line of the schedule. The total amount in columns (g) and (h) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13. Footnote entries as required and provide explanations following all required data.
					Actual Demand (MW)				POWER EXCHANGES		COST/SETTLEMENT OF POWER
Line No.	NameOfCompanyOrPublicAuthorityProvidingPurchasedPower Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	RateScheduleTariffNumber Ferc Rate Schedule or Tariff Number (c)	AverageMonthlyBillingDemand Average Monthly Billing Demand (MW) (d)	AverageMonthlyNonCoincidentPeakDemand Average Monthly NCP Demand (e)	AverageMonthlyCoincidentPeakDemand Average Monthly CP Demand (f)	MegawattHoursPurchasedOtherThanStorage MegaWatt Hours Purchased (Excluding for Energy Storage) (g)	MegawattHoursPurchasedForEnergyStorage MegaWatt Hours Purchased for Energy Storage (h)	EnergyReceivedThroughPowerExchanges MegaWatt Hours Received (i)	EnergyDeliveredThroughPowerExchanges MegaWatt Hours Delivered (j)	DemandChargesOfPurchasedPower Demand Charges ($) (k)	EnergyChargesOfPurchasedPower Energy Charges ($) (l)	OtherChargesOfPurchasedPower Other Charges ($) (m)	SettlementOfPower Total (k+l+m) of Settlement ($) (n)
1	3Degrees Group, Inc.	(c) AD					0	0	0	0			(ay)(az) 398,000	398,000
2	Adams Solar Center, LLC	LU					20,174	0	0	0		1,545,040		1,545,040
3	Airport Solar, LLC	OS					0	0	0	0			(ba) 376,250	376,250
4	Alberta Electric System Operator	SF					22	0	0	0			(bb) 901	901
5	Altop Energy Trading, LLC	SF					139,324	0	0	0		7,646,756		7,646,756
6	Amor IX LLC	LU					126,549	0	0	0		8,354,979		8,354,979
7	Antelope Creek Solar, LLC	(d) AD					47	0	0	0			(bc) 1,725	1,725
8	Antelope Creek Solar, LLC	LU					2,671	0	0	0		116,192		116,192
9	Anticline Wind, LLC	LU					387,246	0	0	0		15,079,365		15,079,365
10	Appaloosa Solar I, LLC	LU					542,262	0	0	0		15,969,626		15,969,626
11	Apple, Inc.	LU					6,859	0	0	0		581,954		581,954
12	Arizona Electric Power Cooperative, Inc.	SF					129	0	0	0		856		856
13	Arizona Public Service Company	SF					56,283	0	0	0		2,263,265	(bd) 6,676	2,269,941
14	Arizona Public Service Company	OS					11,490	0	0	0			(be) 387,312	387,312
15	Avangrid Power, LLC	SF					427,683	0	0	0		37,818,490	(bf) 2,725	37,821,215
16	Avangrid Renewables, LLC	SF					133,410	0	0	0		8,664,391		8,664,391
17	Avista Corporation	(e) AD					190	0	0	0		5,671		5,671
18	Avista Corporation	OS					49	0	0	0			(bg) 4,697	4,697
19	Avista Corporation	SF					106,043	0	0	0		4,982,774	(bh) 9,234	4,992,008
20	Basin Electric Power Cooperative	SF					8,872	0	0	0		470,408		470,408
21	BC Solar, LLC	LU					14,537	0	0	0		1,114,329		1,114,329
22	Bear Creek Solar Center, LLC	LU					21,780	0	0	0		1,673,624		1,673,624
23	Beaver City Corporation	(f) LF					24	0	0	0		4,516		4,516
24	Bell Mountain Hydro, LLC	(g) AD					44	0	0	0			(bi) 5,655	5,655
25	Bell Mountain Hydro, LLC	LU					543	0	0	0		56,673		56,673
26	Beryl Solar, LLC	LU		3	3	1	6,466	0	0	0	478,201	398,973		877,174
27	Big Top, LLC	LU					3,376	0	0	0		115,036		115,036
28	Biomass One, L.P.	LU					199,096	0	0	0		17,277,288		17,277,288
29	Birch Power Company, Inc.	LU					10,351	0	0	0		688,539		688,539
30	Black Cap Solar, LLC	LU					577	0	0	0		26,929		26,929
31	Black Hills Power, Inc.	SF					17,772	0	0	0		880,916		880,916
32	Blackwell Creek Solar, LLC	LU					2,964	0	0	0		128,442		128,442
33	Bly Solar Center, LLC	LU					19,077	0	0	0		1,459,961		1,459,961
34	Bonneville Power Administration	OS					367,856	0	0	0		348,893	(bj) 15,602,939	15,951,832
35	Bonneville Power Administration	(h) AD					2,347	0	0	0		81,834		81,834
36	Bonneville Power Administration	SF					477,199	0	0	0		27,626,220	(bk) 46,801	27,673,021
37	Boswell Wind, LLC	LU					1,149,855	0	0	0		33,207,817		33,207,817
38	Bourdet, Peter M	LU					34	0	0	0		1,424		1,424
39	Box Canyon Limited Partnership	LU		0	5	2	22,768	0	0	0		2,225,241		2,225,241
40	BP Energy Company	SF					106,422	0	0	0		5,883,343		5,883,343
41	Brigham Young University - Idaho	IU					38,937	0	0	0		2,651,186		2,651,186
42	British Columbia Hydro and Power Authority	SF					250	0	0	0			(bl) 10,240	10,240
43	Brookfield Renewable Trading and Marketing LP	SF					1,100	0	0	0		58,400		58,400
44	Buckhorn Solar, LLC	LU		3	3	1	5,476	0	0	0	475,024	337,852		812,876
45	Butter Creek Power, LLC	LU					9,703	0	0	0		332,612		332,612
46	C Drop Hydro, LLC	LU					1,463	0	0	0		125,149		125,149
47	CA Solar Retail Customer	LU					2,771	0	0	0		289,904		289,904
48	CA Solar Retail Customer	(i) AD					0	0	0	0		218,115		218,115
49	California Independent System Operator Corporation	SF					19,805	0	0	0		1,325,237		1,325,237
50	Calpine Energy Services, L.P.	SF					26,199	0	0	0		1,538,572		1,538,572
51	Castle Solar, LLC	LU					108,839	0	0	0		3,355,441		3,355,441
52	Cedar Creek Wind, LLC	LU					456,251	0	0	0		20,531,310		20,531,310
53	Cedar Springs III, LLC	LU					475,181	0	0	0		8,410,700		8,410,700
54	Cedar Springs IV, LLC	LU					1,055,469	0	0	0		29,432,351		29,432,351
55	Cedar Springs Wind, LLC	LU					699,666	0	0	0		10,844,829		10,844,829
56	Cedar Valley Solar, LLC	LU		3	3	1	6,185	0	0	0	473,242	381,640		854,882
57	Central Oregon Irrigation District	LU		0	3	3	31,735	0	0	0		2,837,810		2,837,810
58	Central Rivers Power US	LU					12,168	0	0	0		539,248		539,248
59	Chapman Creek Solar, LLC	LU					5,570	0	0	0		229,338		229,338
60	Cherry Creek Solar, LLC	LU					833	0	0	0		35,823		35,823
61	Cherry Creek Solar, LLC	(j) AD					3	0	0	0		183		183
62	Chiloquin Solar LLC	LU					13,160	0	0	0		1,156,330		1,156,330
63	Chopin Wind, LLC	LU					49,655	0	0	0		2,544,941		2,544,941
64	Citigroup Energy Inc.	SF					155,318	0	0	0		15,392,410		15,392,410
65	City of Astoria	LU					62	0	0	0		6,157		6,157
66	City of Burbank	SF					3,752	0	0	0		188,564		188,564
67	City of Portland, Portland Water Bureau	LU					77	0	0	0		6,500		6,500
68	City of Preston Idaho	LU					2,368	0	0	0		172,461		172,461
69	City of St. George, Utah	SF					45	0	0	0		675		675
70	Clatskanie People's Utility District	SF					554	0	0	0		26,824		26,824
71	Colorado Springs Utilities	SF					170	0	0	0		4,250		4,250
72	Commercial Energy Management Inc.	LU					1,590	0	0	0		77,698		77,698
73	Confederate Tribes of Warm Springs	LU					80	0	0	0		3,596		3,596
74	ConocoPhillips Company	SF					89,787	0	0	0		10,590,118		10,590,118
75	Consolidated Irrigation Company	LU					2,018	0	0	0		154,512		154,512
76	Constellation Energy Generation, LLC	SF					6,236	0	0	0		251,445		251,445
77	Cottonwood Hydro, LLC	IU					2,768	0	0	0		132,670		132,670
78	Cove Mountain Solar 2, LLC	LU					321,394	0	0	0		9,172,590		9,172,590
79	Cove Mountain Solar, LLC	LU					158,954	0	0	0		3,899,161	(bm)(bn) 1,569,037	5,468,198
80	Cove Mountain Solar, LLC	(k) AD					0	0	0	0		24,695		24,695
81	CP Energy Marketing (US) Inc.	SF					41,294	0	0	0		2,585,845		2,585,845
82	Crook County Solar 1, LLC	LU					1,139	0	0	0		52,370		52,370
83	Deschutes Valley Water District	LU		0	3	3	27,988	0	0	0		1,030,205		1,030,205
84	Dominguez Grid, LLC	OS					0	0	0	0			(bo) 1,215,290	1,215,290
85	Dorena Hydro, LLC	LU					8,540	0	0	0		725,881		725,881
86	Douglas Co., Inc. dba Douglas Co. Forest Products	LU					4,046	0	0	0		141,248		141,248
87	Douglas County	LU					4,495	0	0	0		224,562		224,562
88	Draper Irrigation Company	IU					219	0	0	0		17,992		17,992
89	Dry Creek	LU					7,763	0	0	0		348,976		348,976
90	Dynasty Power Inc.	SF					797,566	0	0	0		53,466,693		53,466,693
91	Dynasty Power Inc.	(l) AD					0	0	0	0		6		6
92	Eagle Point Irrigation District	LU					1,952	0	0	0		158,178		158,178
93	EDF Trading North America, LLC	SF					1,913	0	0	0		81,480		81,480
94	El Paso Electric Company	SF					89,471	0	0	0		3,293,247	(bp) 1,434	3,294,681
95	El Paso Electric Company	(m) AD					0	0	0	0		3,991		3,991
96	Elbe Solar Center, LLC	(n) AD					0	0	0	0		1		1
97	Elbe Solar Center, LLC	LU					22,569	0	0	0		1,725,249		1,725,249
98	Elektron Solar, LLC	LU					212,248	0	0	0		6,460,824		6,460,824
99	Energy Keepers, Inc.	SF					14,252	0	0	0		806,304		806,304
100	Enterprise Solar, LLC	LU					219,406	0	0	0		12,005,729		12,005,729
101	Escalante Solar I, LLC	LU					211,478	0	0	0		11,307,471		11,307,471
102	Escalante Solar II, LLC	LU					211,574	0	0	0		10,756,192		10,756,192
103	Escalante Solar II, LLC	OS					0	0	0	0			(bq) 427,524	427,524
104	Escalante Solar III, LLC	LU					208,592	0	0	0		10,240,493		10,240,493
105	Escalante Solar III, LLC	OS					0	0	0	0			(br) 768,414	768,414
106	Eugene Water & Electric Board	SF					4,119	0	0	0		192,464	(bs) 155,000	347,464
107	ExxonMobil Production Company	LU					423	0	0	0		23,719		23,719
108	Fall River Rural Electric Cooperative, Inc.	LU					24,318	0	0	0		1,527,252		1,527,252
109	Faraday Solar B, LLC	LU					610,589	0	0	0		17,373,460		17,373,460
110	Farm Power Misty Meadow, LLC	LU					1,333	0	0	0		113,287		113,287
111	Farmers Irrigation District	LU					21,129	0	0	0		1,767,154		1,767,154
112	Fillmore City Corporation	(o) LF					28	0	0	0		3,158		3,158
113	Flathead Electric Cooperative, Inc.	OS					345	0	0	0			(bt) 13,463	13,463
114	Four Corners Windfarm, LLC	LU					19,497	0	0	0		660,717		660,717
115	Four Mile Canyon Windfarm, LLC	LU					20,376	0	0	0		697,981		697,981
116	Georgetown Irrigation Company	LU					1,580	0	0	0		75,621		75,621
117	Goodling Community Solar, LLC	LU					239	0	0	0		10,928		10,928
118	Grand Valley Power	(p) LF					50	0	0	0		9,058		9,058
119	Granite Mountain Solar East, LLC	LU					203,118	0	0	0		10,552,682		10,552,682
120	Granite Mountain Solar West, LLC	LU					125,109	0	0	0		6,830,664		6,830,664
121	Granite Peak Solar, LLC	LU		3	3	1	6,091	0	0	0	420,658	254,176		674,834
122	Graphite Solar I, LLC	LU					188,160	0	0	0		5,259,075		5,259,075
123	Green Solar, LLC	LU					6,203	0	0	0		265,172		265,172
124	Green Solar, LLC	(q) AD					213	0	0	0		10,552		10,552
125	Greenville Solar, LLC	LU		2	2	0	3,254	0	0	0	214,559	200,780		415,339
126	Gridforce Energy Management, LLC	SF					98	0	0	0			(bu) 4,218	4,218
127	Guzman Energy, LLC	SF					31,535	0	0	0		1,861,674		1,861,674
128	Hammerich 1&2	LU					739	0	0	0		33,162		33,162
129	Hay Creek Community Solar	LU					1,251	0	0	0		54,257		54,257
130	Hayward Paul Luckey and Joanne Luckey Revocable Trust of 2005	LU					206	0	0	0		6,517		6,517
131	Hornshadow Solar I, LLC	LU					175,796	0	0	0		4,862,797		4,862,797
132	Hornshadow Solar II, LLC	LU					303,993	0	0	0		8,461,277		8,461,277
133	Horseshoe Solar, LLC	LU					195,820	0	0	0		6,272,126		6,272,126
134	Hunter Solar LLC	LU					259,574	0	0	0		6,541,267	(bv) 939,662	7,480,929
135	Hunter Solar LLC	(r) AD					0	0	0	0		595,707		595,707
136	Idaho Power Company	SF					131,580	0	0	0		2,262,040	(bw) 3,339	2,265,379
137	Idaho Power Company	OS					103,091	0	0	0			(bx) 3,880,553	3,880,553
138	Idaho Power Company	(s) AD					12,236	0	0	0		127,836		127,836
139	Idaho Solar Retail Customer	LU					732	0	0	0		10,109		10,109
140	Imperial Irrigation District	SF					14	0	0	0			(by) 573	573
141	Iron Springs Solar, LLC	LU					213,833	0	0	0		11,478,533		11,478,533
142	J Bar 9 Ranch, Inc.	LU					49	0	0	0		392		392
143	J. Aron & Company	SF					1,000	0	0	0		26,130		26,130
144	Jake Amy	LU					1,143	0	0	0		64,353		64,353
145	Joseph Community Solar	LU					676	0	0	0		30,252		30,252
146	Keeton 1 & 2	LU					304	0	0	0		13,584		13,584
147	Kettle Butte Digester, LLC	LU					1,530	0	0	0		72,944		72,944
148	Klamath Falls Solar 1, LLC	LU					1,187	0	0	0		90,944		90,944
149	Klamath Falls Solar 2, LLC	IU					6,933	0	0	0		608,961		608,961
150	Lacomb Irrigation District	LU					3,981	0	0	0		199,715		199,715
151	Laho Solar, LLC	LU		3	3	1	6,399	0	0	0	422,419	267,025		689,444
152	Latigo Wind Park, LLC	LU					151,194	0	0	0		9,245,581		9,245,581
153	Linkville Community Solar	LU					6,278	0	0	0		269,037		269,037
154	Linkville Community Solar	(t) AD					337	0	0	0		13,421		13,421
155	Los Angeles Department of Water and Power	SF					66,385	0	0	0		3,017,404		3,017,404
156	Los Angeles Department of Water and Power	OS					1,461	0	0	0			(bz) 43,061	43,061
157	Macquarie Energy LLC	SF					369,351	0	0	0		31,888,554		31,888,554
158	Macquarie Energy LLC	(u) AD					0	0	0	0		11,088		11,088
159	Mag Energy Solutions Inc	SF					4,518	0	0	0		204,523		204,523
160	Marble Community Solar	LU					5,155	0	0	0		219,223		219,223
161	Marsh Valley Hydro Electric Company	LU					3,498	0	0	0		266,527		266,527
162	Meadow Creek Project Company LLC	LU					281,245	0	0	0		26,941,584		26,941,584
163	Mercuria Energy America, LLC	SF					373,566	0	0	0		27,712,865		27,712,865
164	Meta (Facebook)	OS					0	0	0	0		197,284		197,284
165	Meta (Facebook)	(v) AD					0	0	0	0		1,059,895		1,059,895
166	Middle Fork Irrigation District	LU					3,143	0	0	0		92,368		92,368
167	Milford Flat Solar, LLC	LU		3	3	1	6,380	0	0	0	421,955	266,254		688,209
168	Milford Solar I, LLC	LU					261,631	0	0	0		6,820,731	(ca) 1,028,214	7,848,945
169	Milford Solar I, LLC	(w) AD					0	0	0	0		488,682		488,682
170	Millican Solar Energy LLC	LU					142,822	0	0	0		2,977,849	(cb) 1,818,124	4,795,973
171	Millican Solar Energy LLC	(x) AD					0	0	0	0		956,795		956,795
172	Mink Creek Hydro LLC	LU					8,744	0	0	0		422,835		422,835
173	Morgan City Corporation	(y) LF					7	0	0	0		1,049		1,049
174	Morgan Stanley Capital Group Inc.	SF					192,908	0	0	0		10,517,173		10,517,173
175	Mountain Wind Power II, LLC	LU					191,452	0	0	0		12,402,389		12,402,389
176	Mountain Wind Power, LLC	LU					151,425	0	0	0		8,484,594		8,484,594
177	Myron Jones, Nola Jones, Larry Oja and Christie Oja	LU					453	0	0	0		20,389		20,389
178	Myron Jones, Nola Jones, Larry Oja and Christie Oja	(z) AD					0	0	0	0		7		7
179	NaturEner Power Watch, LLC	SF					4	0	0	0			(cc) 129	129
180	(a) Nevada Power Company	SF					1,957	0	0	0		74,047	(cd) 9,485	83,532
181	Nevada Power Company	OS					1,817	0	0	0			(ce) 69,256	69,256
182	NorthWestern Corporation dba NorthWestern Energy	OS					1,573	0	0	0			(cf) 46,525	46,525
183	NorthWestern Corporation dba NorthWestern Energy	(aa) AD					0	0	0	0		2		2
184	NorthWestern Corporation dba NorthWestern Energy	SF					891	0	0	0		33,325	(cg) 7,330	40,655
185	NorWest Energy 2, LLC	IU					19,101	0	0	0		1,471,283		1,471,283
186	NorWest Energy 4, LLC	IU					2,617	0	0	0		201,042		201,042
187	NorWest Energy 7, LLC	IU					16,356	0	0	0		1,254,879		1,254,879
188	NorWest Energy 9, LLC	IU					12,149	0	0	0		1,068,176		1,068,176
189	Nucor Corporation	IU					0	0	0	0			(ch) 8,160,000	8,160,000
190	Oak Lea Digester LLC	LU					78	0	0	0		6,667		6,667
191	Obsidian Finance Group, LLC	LU					336	0	0	0		17,102		17,102
192	Old Mill Solar, LLC	LU					7,147	0	0	0		536,039		536,039
193	OR Solar 2, LLC	LU					20,779	0	0	0		1,824,656		1,824,656
194	OR Solar 3, LLC	LU					15,435	0	0	0		1,355,796		1,355,796
195	OR Solar 5, LLC	LU					17,690	0	0	0		1,556,124		1,556,124
196	OR Solar 6, LLC	LU					22,246	0	0	0		1,947,722		1,947,722
197	OR Solar 6, LLC	(ab) AD					23	0	0	0		2,011		2,011
198	OR Solar 8, LLC	LU					20,009	0	0	0		1,747,470		1,747,470
199	Orchard Knob Community Solar	LU					1,017	0	0	0		35,074		35,074
200	Orchard Windfarm 1, LLC	LU					19,069	0	0	0		1,498,165		1,498,165
201	Orchard Windfarm 2, LLC	LU					18,999	0	0	0		1,492,896		1,492,896
202	Orchard Windfarm 3, LLC	LU					17,483	0	0	0		1,378,401		1,378,401
203	Orchard Windfarm 4, LLC	LU					17,770	0	0	0		1,399,583		1,399,583
204	Oregon Environmental Industries, LLC	LU					16,321	0	0	0		1,528,701		1,528,701
205	Oregon Solar Incentive	LU					9,012	0	0	0		406,863		406,863
206	Oregon Trail Windfarm, LLC	LU					22,315	0	0	0		759,205		759,205
207	OSLH, LLC	IU					20,779	0	0	0		1,826,126		1,826,126
208	P4 Production, LLC	IF					0	0	0	0			(ci) 20,600,000	20,600,000
209	Pacific Canyon Windfarm, LLC	LU					16,810	0	0	0		576,000		576,000
210	Pacificorp	OS					0	0	0	0			(cj) 571,558	571,558
211	Pavant Solar II LLC	LU					85,905	0	0	0		4,064,092		4,064,092
212	Pavant Solar III LLC	LU					44,265	0	0	0		2,337,199		2,337,199
213	Pavant Solar LLC	LU					114,349	0	0	0		7,730,612		7,730,612
214	Phillips 66 Energy Trading, LLC	SF					376,060	0	0	0		21,834,460		21,834,460
215	Pilot Rock Solar 1, LLC	LU					413	0	0	0		15,930		15,930
216	Pilot Rock Solar 2, LLC	LU					343	0	0	0		11,090		11,090
217	Pine Grove Community Solar	LU					1,878	0	0	0		74,815		74,815
218	Pioneer Wind Park I, LLC	LU					251,631	0	0	0		10,523,592		10,523,592
219	Platte River Power Authority	OS					1,370	0	0	0			(ck) 34,688	34,688
220	Portland General Electric Company	(ac) LF					11,990	0	0	0	274,031			274,031
221	Portland General Electric Company	(ad) AD					0	0	0	0		7,987		7,987
222	Portland General Electric Company	OS					522	0	0	0			(cl) 11,856	11,856
223	Portland General Electric Company	SF					119,124	0	0	0		4,724,608	(cm) 16,539	4,741,147
224	Power County Wind Park North, LLC	LU					63,860	0	0	0		6,090,424		6,090,424
225	Power County Wind Park South, LLC	LU					56,755	0	0	0		5,455,980		5,455,980
226	Powerex Corporation	SF					118,497	0	0	0		7,281,164		7,281,164
227	Prineville Solar Energy LLC	LU					97,959	0	0	0		2,042,444	(cn) 1,247,005	3,289,449
228	Prineville Solar Energy LLC	(ae) AD					0	0	0	0		616,286		616,286
229	Provo City Corporation	(af) LF					46	0	0	0		4,068		4,068
230	Public Service Company of Colorado	SF					6,754	0	0	0		373,815	(co) 5,898	379,713
231	Public Service Company of Colorado	OS					6,824	0	0	0			(cp) 277,308	277,308
232	Public Service Company of New Mexico	SF					13,321	0	0	0		694,190	(cq) 2,908	697,098
233	Public Utility District No. 1 of Chelan County	SF					5,592	0	0	0		295,886	(cr) 1,637	297,523
234	Public Utility District No. 1 of Cowlitz County	SF					0	0	0	0			(cs) 125,000	125,000
235	Public Utility District No. 1 of Douglas County	SF					16	0	0	0			(ct) 574	574
236	Public Utility District No. 1 of Snohomish County	SF					4,695	0	0	0		147,061		147,061
237	Public Utility District No. 2 of Grant County	LU					87,714	0	0	0			(cu) 2,545,625	2,545,625
238	Public Utility District No. 2 of Grant County	SF					780,969	0	0	0			(cv)(cw) 126,819,359	126,819,359
239	Public Utility District No. 2 of Grant County	(ag) LF					0	0	0	0			(cx) 17,188,899	17,188,899
240	Public Utility District No. 2 of Grant County	(ah) AD					0	0	0	0			(cy) 38,520	38,520
241	Puget Sound Energy, Inc.	SF					107,949	0	0	0		5,268,521	(cz) 15,928	5,284,449
242	Quichapa 1, LLC	LU		3	3	1	7,367	0	0	0	407,532	307,049		714,581
243	Quichapa 2, LLC	LU		3	3	1	7,635	0	0	0	402,130	318,285		720,415
244	Quichapa 3, LLC	LU		3	3	1	7,217	0	0	0	400,658	301,115		701,773
245	Rainbow Energy Marketing Corporation	SF					25,656	0	0	0		1,175,882		1,175,882
246	Rocket Solar I, LLC	LU					210,533	0	0	0		6,743,365		6,743,365
247	Roseburg Forest Products Company	LU					92,269	0	0	0		3,987,478		3,987,478
248	Roseburg LFG Energy, LLC	LU					5,943	0	0	0		504,165		504,165
249	Round Lake Community Solar	LU					1,896	0	0	0		79,464		79,464
250	Round Lake Community Solar	(ai) AD					1	0	0	0		20		20
251	Sacramento Municipal Utility District	SF					38,378	0	0	0		1,262,248	(da) 2,376	1,264,624
252	Sage Solar I LLC	LU					46,971	0	0	0		2,179,745		2,179,745
253	Sage Solar II LLC	LU					47,019	0	0	0		2,196,614		2,196,614
254	Sage Solar III LLC	LU					42,622	0	0	0		1,968,750		1,968,750
255	Salt River Project	SF					87,505	0	0	0		4,208,380	(db) 7,455	4,215,835
256	Sand Ranch Windfarm, LLC	LU					18,887	0	0	0		646,838		646,838
257	Seattle City Light	SF					35,162	0	0	0		1,858,643	(dc)(dd) 4,882	1,863,525
258	Shell Energy North America (US), L.P.	SF					337,902	0	0	0		20,876,074		20,876,074
259	Sierra Pacific Power Company	OS					328	0	0	0			(de) 13,321	13,321
260	(b) Sierra Pacific Power Company	SF					196	0	0	0			(df) 8,028	8,028
261	Sigurd Solar LLC	LU					199,973	0	0	0		5,403,279	(dg) 851,885	6,255,164
262	Sigurd Solar LLC	(aj) AD					0	0	0	0		316,928		316,928
263	Simplot Phosphates LLC	LU					61	0	0	0		2,290		2,290
264	Simplot Phosphates LLC	(ak) AD					13	0	0	0		1,278		1,278
265	Skysol Solar, LLC	LU					123,076	0	0	0		5,701,599		5,701,599
266	Solarize Rogue LLC	LU					174	0	0	0		7,485		7,485
267	Solwatt, LLC	LU					791	0	0	0		34,835		34,835
268	Spanish Fork Wind Park 2, LLC	LU					42,510	0	0	0		2,705,102		2,705,102
269	Sprague Hydro LLC	LU		221	1		1,123	0	0	0		109,619		109,619
270	St. Anthony Hydro, LLC	LU					5,359	0	0	0		418,721		418,721
271	Stahlbush Island Farms, Inc.	(al) AD					237	0	0	0		6,609		6,609
272	Strawberry Electric Service District	(am) LF					130	0	0	0		1,476		1,476
273	Strawberry Electric Service District	(an) AD					7	0	0	0		310		310
274	SunE DB18, LLC	LU		3	3	1	7,561	0	0	0	454,010	466,512		920,522
275	SunE DB24, LLC	LU		2	3	4	6,939	0	0	0	381,478	289,553		671,031
276	SunE Solar XVII Project1, LLC	LU		3	8	3	7,252	0	0	0	446,451	447,423		893,874
277	SunE Solar XVII Project2, LLC	LU		3	8	3	6,652	0	0	0	410,067	410,422		820,489
278	SunE Solar XVII Project3, LLC	LU		3	8	3	7,389	0	0	0	400,610	308,352		708,962
279	Sunny Bar Ranch LLLP	LU					1,633	0	0	0		96,331		96,331
280	Sunset Ridge Community Solar	LU					2	0	0	0		52		52
281	Sunset Ridge Solar, LLC	LU					1,721	0	0	0		80,251		80,251
282	Swalley Irrigation District	LU					1,870	0	0	0		81,482		81,482
283	Sweetwater Solar LLC	LU					173,282	0	0	0		7,416,419		7,416,419
284	Tacoma Power	SF					19,962	0	0	0		791,018	(dh)(di) 194,383	985,401
285	Tata Chemicals (Soda Ash) Partners	LU					1,974	0	0	0		34,035		34,035
286	Tata Chemicals (Soda Ash) Partners	(ao) AD					0	0	0	0		20,390		20,390
287	Tenaska Power Services Co.	SF					29,667	0	0	0		1,576,208		1,576,208
288	Tesoro Refining & Marketing Company, LLC	LU					757	0	0	0		19,292		19,292
289	Thayn Hydro LLC	LU		0	1	1	3,951	0	0	0		244,702		244,702
290	The Energy Authority, Inc.	SF					157,410	0	0	0		7,502,976		7,502,976
291	The Energy Authority, Inc.	(ap) AD					10	0	0	0		146		146
292	Three Buttes Windpower, LLC	LU					277,110	0	0	0		17,679,644		17,679,644
293	Three Peaks Power, LLC	LU					225,758	0	0	0		9,593,520		9,593,520
294	Three Sisters Irrigation District	LU					2,380	0	0	0		142,766		142,766
295	Threemile Canyon Wind I, LLC	LU					17,755	0	0	0		610,343		610,343
296	TMF Biofuels, LLC	LU					35,391	0	0	0		3,442,907		3,442,907
297	Tooele Army Depot	LU					93	0	0	0		2,571		2,571
298	Top of the World Wind Energy LLC	LU					441,361	0	0	0		29,129,811	(dj) 5,996,295	35,126,106
299	TransAlta Energy Marketing (U.S.) Inc.	SF					59,076	0	0	0		2,951,118		2,951,118
300	TransCanada Energy Sales Ltd.	SF					3,750	0	0	0		167,800		167,800
301	Tri-State Generation and Transmission Association, Inc.	SF					4,900	0	0	0		270,270		270,270
302	Tri-State Generation and Transmission Association, Inc.	(aq) AD					79	0	0	0		1,650		1,650
303	Tri-State Generation and Transmission Association, Inc.	OS					840	0	0	0			(dk) 39,336	39,336
304	Tucson Electric Power Company	SF					11,121	0	0	0		478,021	(dl) 2,458	480,479
305	Tucson Electric Power Company	OS					7	0	0	0			(dm) 346	346
306	Tumbleweed Solar LLC	LU					18,481	0	0	0		1,623,620		1,623,620
307	Turlock Irrigation District	SF					10	0	0	0			(dn) 410	410
308	U.S. Department of the Interior - Bureau of Land Management	LU					21	0	0	0		248		248
309	U.S. Department of the Interior - Bureau of Land Management	(ar) AD					0	0	0	0		822		822
310	UNS Electric, Inc.	SF					2,000	0	0	0		61,124		61,124
311	Utah Associated Municipal Power Systems	SF					195	0	0	0		9,945		9,945
312	Utah Municipal Power Agency	SF					130,082	0	0	0		8,288,932		8,288,932
313	Utah Red Hills Renewable Park, LLC	LU					209,252	0	0	0		12,213,940		12,213,940
314	Utah Solar Retail Customer	LU					238,616	0	0	0		16,299,169		16,299,169
315	Utah Solar Retail Customer	AD					939	0	0	0
316	Vitol Inc.	SF					11,268	0	0	0		484,602		484,602
317	Wagon Trail, LLC	LU					5,851	0	0	0		200,286		200,286
318	Wallowa County Community Solar	LU					740	0	0	0		32,969		32,969
319	Ward Butte Windfarm, LLC	LU					14,907	0	0	0		506,030		506,030
320	Western Area Power Administration	OS					41,128	0	0	0			(do) 1,163,902	1,163,902
321	Western Area Power Administration	SF					182	0	0	0		3,360	(dp) 3,523	6,883
322	Whisky Creek Community Solar	LU					372	0	0	0		15,735		15,735
323	Whisky Creek Community Solar	(as) AD					1	0	0	0		65		65
324	Wocus Marsh Community Solar	LU					2,168	0	0	0		92,953		92,953
325	Wocus Marsh Community Solar	(at) AD					34	0	0	0		1,952		1,952
326	Wolverine Creek Energy, LLC	LU					143,681	0	0	0		9,362,234		9,362,234
327	Wood River Solar	LU					852	0	0	0		36,940		36,940
328	Woodline Solar, LLC	IU					19,024	0	0	0		1,670,338		1,670,338
329	Yakima-Tieton Irrigation District	LU					6,273	0	0	0		467,433		467,433
330	Liquidated Damages						0	0	0	0			(dq) 10,667,246	10,667,246
331	PACTRANS						2,807	0	0	0			(dr) 110,328	110,328
332	REC sale to relieve inventory						0	0	0	0			(ds) 9,639	9,639
333	Net Power Cost Deferrals						0	0	0	0			(dt) 648,185,422	648,185,422
334	Netting - Bookouts						735,868	0	0	0			(du) 31,387,399	31,387,399
335	Netting - Trading						0	0	0	0			(dv) 176,515	176,515
336	System Deviation						888	0	0	0
337	Accrual						0	0	0	0			(dw) 7,339,198	7,339,198
338	Power Exchanges:
339	Bonneville Power Administration	EX	T- BPA				0	0	27,715	4,396
340	Bonneville Power Administration	EX	237				0	0	1,165,060	1,128,645			(dx) 883,416	883,416
341	Bonneville Power Administration	(au) AD	237				0	0	0	0			(dy) 4,223	4,223
342	California Independent System Operator	EX	T-12				0	0	4,338,995	6,878,958			(dz) 59,091,032	59,091,032
343	California Independent System Operator	EX	T-11				0	0	0	0			(ea) 32,230,387	32,230,387
344	California Independent System Operator	(av) AD	T-11				0	0	0	0			(eb) 3,778,361	3,778,361
345	Emerald People's Utility District	EX	T-6				0	0	0	832			(ec) 20,806	20,806
346	Idaho Power Company	EX	T-6				0	0	2,085	2,017
347	Idaho Power Company	EX	708				0	0	120,109	90,323
348	Los Angeles Department of Water and Power	EX	OV1				0	0	2,466	0			(ed) 214,443	214,443
349	Milford Wind Corridor Phase I, LLC	EX	OV1				0	0	0	1,644			(ee) 142,962	142,962
350	Milford Wind Corridor Phase II, LLC	EX	OV1				0	0	0	822			(ef) 71,481	71,481
351	NorthWestern Corporation	EX	160				0	0	21,012	0
352	Portland General Electric Company	AD	T-8				0	0	3,228	0
353	Public Utility District No. 1 of Cowlitz County	EX	442				0	0	193,855	189,151
354	Western Area Power Administration	EX	LAS-4				0	0	253,853	79,344			(eg) 1,432,499	1,432,499
355	Western Area Power Administration	(aw) AD	LAS-4				0	0	0	0			(eh) 4,231	4,231
356	Transmission Customer Imbalance Energy	EX	T-11				0	0	213,164	0			(ei) 2,509,299	2,509,299
357	Transmission Customer Imbalance Energy	(ax) AD	T-11				0	0	782	0			(ej) 3,042,242	3,042,242
15	TOTAL						20,835,153		6,286,894	8,376,132	6,483,025	972,605,025	706,348,245	1,685,436,295

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityProvidingPurchasedPower

Nevada Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.

(b) Concept: NameOfCompanyOrPublicAuthorityProvidingPurchasedPower

Sierra Pacific Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.

Under Electric Service Agreement subject to termination upon timely notification.

(d) Concept: StatisticalClassificationCode

Under Electric Service Agreement subject to termination upon timely notification.

(e) Concept: StatisticalClassificationCode

Settlement adjustment.

(f) Concept: StatisticalClassificationCode

Under Electric Service Agreement subject to termination upon timely notification.

(g) Concept: StatisticalClassificationCode

Under Electric Service Agreement subject to termination upon timely notification.

(h) Concept: StatisticalClassificationCode

Settlement adjustment.

(i) Concept: StatisticalClassificationCode

Settlement adjustment.

(j) Concept: StatisticalClassificationCode

Settlement adjustment.

(k) Concept: StatisticalClassificationCode

Settlement adjustment.

(l) Concept: StatisticalClassificationCode

Settlement adjustment.

(m) Concept: StatisticalClassificationCode

Settlement adjustment.

(n) Concept: StatisticalClassificationCode

Settlement adjustment.

(o) Concept: StatisticalClassificationCode

Under Electric Service Agreement subject to termination upon timely notification.

(p) Concept: StatisticalClassificationCode

Under Electric Service Agreement subject to termination upon timely notification.

(q) Concept: StatisticalClassificationCode

Settlement adjustment.

(r) Concept: StatisticalClassificationCode

Settlement adjustment.

(s) Concept: StatisticalClassificationCode

Settlement adjustment.

(t) Concept: StatisticalClassificationCode

Settlement adjustment.

(u) Concept: StatisticalClassificationCode

Settlement adjustment.

(v) Concept: StatisticalClassificationCode

Settlement adjustment.

(w) Concept: StatisticalClassificationCode

Settlement adjustment.

(x) Concept: StatisticalClassificationCode

Settlement adjustment.

(y) Concept: StatisticalClassificationCode

Under Electric Service Agreement subject to termination upon timely notification.

(z) Concept: StatisticalClassificationCode

Settlement adjustment.

(aa) Concept: StatisticalClassificationCode

Settlement adjustment.

(ab) Concept: StatisticalClassificationCode

Settlement adjustment.

(ac) Concept: StatisticalClassificationCode

Portland General Electric Company - contract termination date: When the Round Butte project no longer operates for power production purposes.

(ad) Concept: StatisticalClassificationCode

Settlement adjustment.

(ae) Concept: StatisticalClassificationCode

Settlement adjustment.

(af) Concept: StatisticalClassificationCode

Under Electric Service Agreement subject to termination upon timely notification.

(ag) Concept: StatisticalClassificationCode

Meaningful priority proceeds

(ah) Concept: StatisticalClassificationCode

Settlement adjustment.

(ai) Concept: StatisticalClassificationCode

Settlement adjustment.

(aj) Concept: StatisticalClassificationCode

Settlement adjustment.

(ak) Concept: StatisticalClassificationCode

Settlement adjustment.

(al) Concept: StatisticalClassificationCode

Settlement adjustment.

(am) Concept: StatisticalClassificationCode

Under Electric Service Agreement subject to termination upon timely notification.

(an) Concept: StatisticalClassificationCode

Settlement adjustment.

(ao) Concept: StatisticalClassificationCode

Settlement adjustment.

(ap) Concept: StatisticalClassificationCode

Settlement adjustment.

(aq) Concept: StatisticalClassificationCode

Settlement adjustment.

(ar) Concept: StatisticalClassificationCode

Settlement adjustment.

(as) Concept: StatisticalClassificationCode

Settlement adjustment.

(at) Concept: StatisticalClassificationCode

Settlement adjustment.

(au) Concept: StatisticalClassificationCode

Under Electric Service Agreement subject to termination upon timely notification.

(av) Concept: StatisticalClassificationCode

Under Electric Service Agreement subject to termination upon timely notification.

(aw) Concept: StatisticalClassificationCode

Under Electric Service Agreement subject to termination upon timely notification.

(ax) Concept: StatisticalClassificationCode

Settlement adjustment.

(ay) Concept: OtherChargesOfPurchasedPower

Under Electric Service Agreement subject to termination upon timely notification.

(az) Concept: OtherChargesOfPurchasedPower

Purchase of renewable energy credit certificates for renewable portfolio standard requirements.

(ba) Concept: OtherChargesOfPurchasedPower

Purchases of reactive supply and voltage control, per FERC Docket ER20-2528, effective September 28, 2020.

(bb) Concept: OtherChargesOfPurchasedPower

Reserve share.

(bc) Concept: OtherChargesOfPurchasedPower

Under Electric Service Agreement subject to termination upon timely notification.

(bd) Concept: OtherChargesOfPurchasedPower

Reserve share.

(be) Concept: OtherChargesOfPurchasedPower

Reserve share.

(bf) Concept: OtherChargesOfPurchasedPower

Reserve share.

(bg) Concept: OtherChargesOfPurchasedPower

Line loss.

(bh) Concept: OtherChargesOfPurchasedPower

Reserve share.

(bi) Concept: OtherChargesOfPurchasedPower

Under Electric Service Agreement subject to termination upon timely notification.

(bj) Concept: OtherChargesOfPurchasedPower

Line loss.

(bk) Concept: OtherChargesOfPurchasedPower

Reserve share.

(bl) Concept: OtherChargesOfPurchasedPower

Reserve share.

(bm) Concept: OtherChargesOfPurchasedPower

Purchases of reactive supply and voltage control, per FERC Docket ER20-2528, effective September 28, 2020.

(bn) Concept: OtherChargesOfPurchasedPower

Purchase of renewable energy credit certificates for renewable portfolio standard requirements.

(bo) Concept: OtherChargesOfPurchasedPower

Dominguez Grid Battery Energy Storage agreement capacity charge. Total charge and discharge energy for 2025 were (28,457) and 25,593, respectively.

(bp) Concept: OtherChargesOfPurchasedPower

Reserve share.

(bq) Concept: OtherChargesOfPurchasedPower

Purchase of renewable energy credit certificates for renewable portfolio standard requirements.

(br) Concept: OtherChargesOfPurchasedPower

Purchase of renewable energy credit certificates for renewable portfolio standard requirements.

(bs) Concept: OtherChargesOfPurchasedPower

Grant County Meaningful Priority assignment fees.

(bt) Concept: OtherChargesOfPurchasedPower

Line loss.

(bu) Concept: OtherChargesOfPurchasedPower

Reserve share.

(bv) Concept: OtherChargesOfPurchasedPower

Purchase of renewable energy credit certificates for renewable portfolio standard requirements.

(bw) Concept: OtherChargesOfPurchasedPower

Reserve share.

(bx) Concept: OtherChargesOfPurchasedPower

Line loss.

(by) Concept: OtherChargesOfPurchasedPower

Reserve share.

(bz) Concept: OtherChargesOfPurchasedPower

Line loss.

(ca) Concept: OtherChargesOfPurchasedPower

Purchase of renewable energy credit certificates for renewable portfolio standard requirements.

(cb) Concept: OtherChargesOfPurchasedPower

Purchase of renewable energy credit certificates for renewable portfolio standard requirements.

(cc) Concept: OtherChargesOfPurchasedPower

Reserve share.

(cd) Concept: OtherChargesOfPurchasedPower

Line loss.

(ce) Concept: OtherChargesOfPurchasedPower

Line loss.

(cf) Concept: OtherChargesOfPurchasedPower

Line loss.

(cg) Concept: OtherChargesOfPurchasedPower

Reserve share.

(ch) Concept: OtherChargesOfPurchasedPower

Reserve share.

(ci) Concept: OtherChargesOfPurchasedPower

Compensation for interruptible service and operating reserves.

(cj) Concept: OtherChargesOfPurchasedPower

Purchase of renewable energy credit certificates for renewable portfolio standard requirements.

(ck) Concept: OtherChargesOfPurchasedPower

Line loss.

(cl) Concept: OtherChargesOfPurchasedPower

Line loss.

(cm) Concept: OtherChargesOfPurchasedPower

Reserve share.

(cn) Concept: OtherChargesOfPurchasedPower

Purchase of renewable energy credit certificates for renewable portfolio standard requirements.

(co) Concept: OtherChargesOfPurchasedPower

Reserve share.

(cp) Concept: OtherChargesOfPurchasedPower

Line loss.

(cq) Concept: OtherChargesOfPurchasedPower

Reserve share.

(cr) Concept: OtherChargesOfPurchasedPower

Reserve share.

(cs) Concept: OtherChargesOfPurchasedPower

Grant County Meaningful Priority assignment fees.

(ct) Concept: OtherChargesOfPurchasedPower

Reserve share.

(cu) Concept: OtherChargesOfPurchasedPower

2024 Meaningful Priority award to PacifiCorp of generation output from the Priest Rapids Project from Grant County.

(cv) Concept: OtherChargesOfPurchasedPower

Reserve share.

(cw) Concept: OtherChargesOfPurchasedPower

Grant County Meaningful Priority assignment fees.

(cx) Concept: OtherChargesOfPurchasedPower

Grant County Meaningful Priority assignment fees.

(cy) Concept: OtherChargesOfPurchasedPower

Settlement adjustment.

(cz) Concept: OtherChargesOfPurchasedPower

Reserve share.

(da) Concept: OtherChargesOfPurchasedPower

Reserve share.

(db) Concept: OtherChargesOfPurchasedPower

Reserve share.

(dc) Concept: OtherChargesOfPurchasedPower

Reserve share.

(dd) Concept: OtherChargesOfPurchasedPower

Grant County Meaningful Priority assignment fees.

(de) Concept: OtherChargesOfPurchasedPower

Line loss.

(df) Concept: OtherChargesOfPurchasedPower

Reserve share.

(dg) Concept: OtherChargesOfPurchasedPower

Purchase of renewable energy credit certificates for renewable portfolio standard requirements.

(dh) Concept: OtherChargesOfPurchasedPower

Reserve share.

(di) Concept: OtherChargesOfPurchasedPower

Grant County Meaningful Priority assignment fees.

(dj) Concept: OtherChargesOfPurchasedPower

Compensation curtailment charges.

(dk) Concept: OtherChargesOfPurchasedPower

Line loss.

(dl) Concept: OtherChargesOfPurchasedPower

Reserve share.

(dm) Concept: OtherChargesOfPurchasedPower

Line loss.

(dn) Concept: OtherChargesOfPurchasedPower

Reserve share.

(do) Concept: OtherChargesOfPurchasedPower

Line loss.

(dp) Concept: OtherChargesOfPurchasedPower

Reserve share.

(dq) Concept: OtherChargesOfPurchasedPower

Liquidated damages.

(dr) Concept: OtherChargesOfPurchasedPower

Line loss.

(ds) Concept: OtherChargesOfPurchasedPower

Reduction of inventory for REC sales related to FERC Order No. 898.

(dt) Concept: OtherChargesOfPurchasedPower

Regulatory net power cost and renewable energy credit deferrals.

(du) Concept: OtherChargesOfPurchasedPower

Reflects transactions that did not physically settle.

(dv) Concept: OtherChargesOfPurchasedPower

Reflects transactions that were categorized as trading activities.

(dw) Concept: OtherChargesOfPurchasedPower

Represents the difference between actual purchase expenses for the period as reflected on the individual line items within this schedule and the accruals charged to Account 555, Purchased power, during this period.

(dx) Concept: OtherChargesOfPurchasedPower

Storage and energy exchange charges.

(dy) Concept: OtherChargesOfPurchasedPower

Under Electric Service Agreement subject to termination upon timely notification.

(dz) Concept: OtherChargesOfPurchasedPower

Energy Imbalance Market (EIM) participating resource settlements in EIM.

(ea) Concept: OtherChargesOfPurchasedPower

Energy Imbalance Market (EIM) entity settlements in EIM.

(eb) Concept: OtherChargesOfPurchasedPower

Under Electric Service Agreement subject to termination upon timely notification.

(ec) Concept: OtherChargesOfPurchasedPower

Exchange energy credit.

(ed) Concept: OtherChargesOfPurchasedPower

Station service for a third-party wind project.

(ee) Concept: OtherChargesOfPurchasedPower

Reimbursement for providing station service to a third-party wind project.

(ef) Concept: OtherChargesOfPurchasedPower

Reimbursement for providing station service to a third-party wind project.

(eg) Concept: OtherChargesOfPurchasedPower

Imbalance energy settlements between PacifiCorp merchant function and third-party transmission providers.

(eh) Concept: OtherChargesOfPurchasedPower

Under Electric Service Agreement subject to termination upon timely notification.

(ei) Concept: OtherChargesOfPurchasedPower

Imbalance energy settlements between the PacifiCorp transmission provider and third-party transmission customers.

(ej) Concept: OtherChargesOfPurchasedPower

Settlement adjustment.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")

Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c).
In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.
In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided.
Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract.
Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
Report in column (i) and (j) the total megawatthours received and delivered.
In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity listed in column (a). If no monetary settlement was made, enter zero (0) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively.
Footnote entries and provide explanations following all required data.

TRANSFER OF ENERGY

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

Airport Solar LLC

Portland General Electric Company

(c)

LFP

SA_965

Trona Substation

Red Butte/Mona Sub

100,372

2,441,345

(fd)

386,987

2,828,332

Airport Solar LLC

Portland General Electric Company

(d)

SA_965

Trona Substation

Red Butte/Mona Sub

3,395

(fe)

71,263

Altop Energy Trading LLC

various signatories

SA_1059

various

7,427

165,437

(ff)

7,511

172,948

Altop Energy Trading LLC

various signatories

(e)

SA_1059

various

(fg)

516

Altop Energy Trading LLC

various signatories

SFP

SA_1060

various

2,961

32,988

(fh)

1,503

34,491

Avangrid Renewables, LLC

various signatories

SA_121

various

143,686

2,273,694

(fi)

103,399

2,377,093

Avangrid Renewables, LLC

various signatories

(f)

SA_121

various

20,791

(fj)

280,927

Avangrid Renewables, LLC

various signatories

SFP

SA_122

various

30,499

389,588

(fk)

17,934

407,522

Avangrid Renewables, LLC

various signatories

(g)

SA_122

various

233

(fl)

3,629

Avangrid Renewables, LLC

Avangrid Renewables, LLC and Utah Associated Municipal Power Systems

(h)

SA_476

Long Hollow, WY switching station

(fm)

206,834

Avangrid Renewables, LLC

Avangrid Renewables, LLC and Utah Associated Municipal Power Systems

(i)

SA_476

Long Hollow, WY switching station

(fn)

22,818

Avangrid Renewables, LLC

Exxon Mobil

(b)

Nevada Power Company

(j)

LFP

SA_895

Trona Substation

Red Butte/Mona Sub

45,934

1,525,840

(fo)

69,808

1,595,648

Avangrid Renewables, LLC

Exxon Mobil

Nevada Power Company

(k)

SA_895

Trona Substation

Red Butte/Mona Sub

7,465

(fp)

58,676

Avangrid Renewables, LLC

Exxon Mobil

Nevada Power Company

(l)

SA_279

Trona Substation

Red Butte/Mona Sub

(fq)

238

Avangrid Renewables, LLC

Bonneville Power Administration

Oregon Direct Access

FNO

SA_742

Ponderosa Substation

various

272,084

1,681,826

(fr)

539,534

2,221,360

Avangrid Renewables, LLC

various signatories

(m)

SA_742

Ponderosa Substation

various

24,985

(fs)

35,526

Basin Electric Power Cooperative, Inc.

Western Area Power Administration

Powder River Energy Corporation

FNO

SA_505

Yellowtail Sub

Sheridan Substation

68,373

494,117

(ft)

48,353

542,470

Basin Electric Power Cooperative, Inc.

Western Area Power Administration

Powder River Energy Corporation

(n)

SA_505

Yellowtail Sub

Sheridan Substation

6,522

(fu)

Basin Electric Power Cooperative, Inc.

Western Area Power Administration

Powder River Energy Corporation

SA_607

various

18,460

224,405

(fv)

10,406

234,811

Basin Electric Power Cooperative, Inc.

Western Area Power Administration

Powder River Energy Corporation

(o)

SA_607

various

3,488

(fw)

48,356

Basin Electric Power Cooperative, Inc.

Western Area Power Administration

Powder River Energy Corporation

SFP

SA_606

various

3,615

44,811

(fx)

2,072

46,883

Basin Electric Power Cooperative, Inc.

Western Area Power Administration

Powder River Energy Corporation

(p)

SA_606

various

4,326

(fy)

40,239

Black Hills/Colorado Electric Utility Company, L.P.

various signatories

SFP

SA_563

various

671

(fz)

701

Black Hills Corporation

PacifiCorp

Montana-Dakota Utilities

(q)

SA_347

various

Sheridan Substation

(ga)

843

Black Hills Corporation

PacifiCorp

Black Hills Corporation

(r)

SA_67

various

Wyodak Substation

(gb)

951

Black Hills Corporation

various signatories

SA_768

various

7,811

89,014

(gc)

4,096

93,110

Black Hills Corporation

various signatories

SFP

SA_767

various

5,094

49,046

(gd)

2,203

51,249

Black Hills Power Marketing

various signatories

SA_112

various

178

2,362

(ge)

110

2,472

Black Hills Power Marketing

various signatories

SFP

SA_111

various

725

(gf)

757

Bonneville Power Administration

(s)

RS_237

various

397

972,496

4,411,388

Bonneville Power Administration

(t)

RS_237

various

406

100,569

(gg)

398,475

Bonneville Power Administration

(u)

LFP

SA_656

Lost Creek Hydro Plt

Alvey Substation

202,680

2,848,236

(gh)

48,689

2,896,925

Bonneville Power Administration

(v)

SA_656

Lost Creek Hydro Plt

Alvey Substation

(gi)

116,877

Bonneville Power Administration

Umpqua Indian Utility Cooperative

FNO

SA_229

Bonneville Power Administration

Gazley Substation

22,834

162,002

(gj)

213,065

375,067

Bonneville Power Administration

Umpqua Indian Utility Cooperative

(w)

SA_229

Bonneville Power Administration

Gazley Substation

2,229

(gk)

13,890

Bonneville Power Administration

Benton Rural Electric Association

FNO

SA_539

Bonneville Power Administration

Tieton Substation

5,930

41,424

(gl)

3,700

45,124

Bonneville Power Administration

Benton Rural Electric Association

(x)

SA_539

Bonneville Power Administration

Tieton Substation

908

(gm)

4,851

Bonneville Power Administration

Umatilla Electric Cooperative Association and Columbia Basin Electric Cooperative, Inc.

FNO

SA_538

McNary Substation

Hinkle Substation

1,409

9,028

(gn)

848

9,876

Bonneville Power Administration

Umatilla Electric Cooperative Association and Columbia Basin Electric Cooperative, Inc.

(y)

SA_538

McNary Substation

Hinkle Substation

211

(go)

2,054

Bonneville Power Administration

(z)

RS_368

Malin Substation

424,818

(gp)

232,452

Bonneville Power Administration

(aa)

RS_368

Malin Substation

33,023

(gq)

21,132

Bonneville Power Administration

Yakama Power

FNO

SA_328

Bonneville Power Administration

White Swan/Toppenish Substations

42,341

334,436

(gr)

119,295

453,731

Bonneville Power Administration

Yakama Power

(ab)

SA_328

Bonneville Power Administration

White Swan/Toppenish Substations

4,152

(gs)

513

Bonneville Power Administration

FNO

SA_827

Bonneville Power Administration

Neff Substation

684

1,112

(gt)

275

1,387

Bonneville Power Administration

(ac)

SA_827

Bonneville Power Administration

Neff Substation

(gu)

174

Bonneville Power Administration

FNO

SA_746

Goshen Substation

various

234

1,507,957

11,822,031

(gv)

1,944,470

13,766,501

Bonneville Power Administration

(ad)

SA_746

Goshen Substation

various

297

184,860

(gw)

272,068

Bonneville Power Administration

various signatories

SA_044

various

7,675

99,849

(gx)

4,500

104,349

Bonneville Power Administration

(ae)

SA_044

various

(gy)

4,306

Bonneville Power Administration

various signatories

SFP

SA_720

various

215

(gz)

225

Bonneville Power Administration

various signatories

FNO

SA_747

Goshen Substation

various

719,055

4,817,554

(ha)

639,660

5,457,214

Bonneville Power Administration

various signatories

(af)

SA_747

Goshen Substation

various

121

79,018

(hb)

134,190

Bonneville Power Administration

Public Utility District No. 1 of Clark County

FNO

SA_735

Cardwell-Merwin

Chelatchie/View 115kV

116,885

1,036,428

(hc)

82,162

1,118,590

Bonneville Power Administration

Public Utility District No. 1 of Clark County

(ag)

SA_735

Cardwell-Merwin

Chelatchie/View 115kV

15,195

(hd)

36,670

Bonneville Power Administration

FNO

SA_865

Goshen Substation

various

875

1,820

(he)

368

2,188

Bonneville Power Administration

(ah)

SA_865

Goshen Substation

various

105

(hf)

375

Bonneville Power Administration

FNO

SA_975

Bonneville Power Administration

various

3,839

28,634

(hg)

2,497

31,131

Bonneville Power Administration

(ai)

SA_975

Bonneville Power Administration

various

(hh)

5,924

BP Energy Company

various signatories

SFP

SA_1083

various

3,006

63,185

(hi)

2,825

66,010

Calpine Energy Solutions, LLC

Bonneville Power Administration

Oregon Direct Access

FNO

SA_299

Bonneville Power Administration

various

126,579

895,881

(hj)

106,830

1,002,711

Calpine Energy Solutions, LLC

Bonneville Power Administration

Oregon Direct Access

(aj)

SA_299

Bonneville Power Administration

various

10,304

(hk)

50,228

City of Anaheim

various signatories

SFP

SA_767

various

(hl)

City of Roseville

(ak)

LFP

SA_881

Malin 500 Substation

Round Mountain Sub

2,438,224

(hm)

38,082

2,476,306

City of Roseville

(al)

SA_881

Malin 500 Substation

Round Mountain Sub

(hn)

100,821

Clark County PUD

various signatories

SFP

SA_1089

various

994

27,598

(ho)

1,288

28,886

Clark County PUD

various signatories

SA_1090

various

55,919

1,546,109

(hp)

341,430

1,887,539

Clark County PUD

various signatories

(am)

SA_1090

various

5,674

(hq)

185,325

Clatskanie People's Utility District

(an)

LFP

SA_899

Troutdale Substation

66,376

661,198

(hr)

30,251

691,449

Clatskanie People's Utility District

(ao)

SA_899

Troutdale Substation

various

6,767

(hs)

25,529

Clatskanie People's Utility District

(ap)

SA_901

Troutdale Substation

various

(ht)

CP Energy Marketing (US) Inc.

various signatories

SA_968

various

932

14,892

(hu)

696

15,588

CP Energy Marketing (US) Inc.

various signatories

SFP

SA_967

various

357

3,533

(hv)

165

3,698

Deseret Generation and Transmission Co-operative

(aq)

RS_280

various

158

1,220,623

7,670,230

(hw)

1,540,538

9,210,768

Deseret Generation and Transmission Co-operative

(ar)

RS_280

various

168

106,291

(hx)

393,453

Deseret Generation and Transmission Co-operative

various signatories

SFP

SA_159

various

47,703

547,309

(hy)

24,504

571,813

Dynasty Power Inc.

various signatories

SA_1014

various

66,155

837,940

(hz)

37,828

875,768

Dynasty Power Inc.

various signatories

(as)

SA_1014

various

9,953

(ia)

87,202

Dynasty Power Inc.

various signatories

SFP

SA_1013

various

79,688

1,090,590

(ib)

50,879

1,141,469

Dynasty Power Inc.

various signatories

(at)

SA_1013

various

2,023

(ic)

33,299

Eagle Energy Partners I LP

various signatories

SFP

SA_570

various

45,856

459,972

(id)

21,472

481,444

Energy Keepers, Inc.

various signatories

(au)

SA_1055

various

7,163

(ie)

61,467

Energy Keepers, Inc.

various signatories

SA_814

various

12,408

224,911

(if)

10,200

235,111

Energy Keepers, Inc.

various signatories

(av)

SA_814

various

1,186

(ig)

8,514

Energy Keepers, Inc.

various signatories

SFP

SA_815

various

2,798

26,429

(ih)

1,234

27,663

Evergreen Biopower LLC

NextEra Energy Resources, LLC

various signatories

(aw)

LFP

SA_874

various

Bonneville Power Administration

45,016

508,612

(ii)

66,904

575,516

Evergreen Biopower LLC

NextEra Energy Resources, LLC

Public Utility District No. 2 of Grant County

(ax)

SA_874

various

3,419

(ij)

15,901

Exelon Generation Company, LLC

Bonneville Power Administration

Oregon Direct Access

FNO

SA_943

Bonneville Power Administration

various

5,582

44,626

(ik)

5,058

49,684

Exelon Generation Company, LLC

Bonneville Power Administration

Oregon Direct Access

(ay)

SA_943

Bonneville Power Administration

various

4,893

(il)

1,535

Exelon Generation Company, LLC

various signatories

SA_759

various

237,805

2,237,821

(im)

1,567,660

3,805,481

Exelon Generation Company, LLC

various signatories

(az)

SA_759

various

18,349

(in)

245,984

Exelon Generation Company, LLC

various signatories

SFP

SA_760

various

63,506

189,542

(io)

1,753,732

1,943,274

Exelon Generation Company, LLC

various signatories

(ba)

SA_760

various

4,419

(ip)

165,844

Fall River Rural Electric Cooperative, Inc.

Marysville Hydro Partners

Idaho Power Company

(bb)

FRRE_RS_322

Targhee Substation

Goshen Substation

(iq)

138,699

Fall River Rural Electric Cooperative, Inc.

Marysville Hydro Partners

Idaho Power Company

(bc)

FRRE_RS_322

Targhee Substation

Goshen Substation

(ir)

12,609

Falls Creek H.P. Limited Partnership

Lakeview Airport 10

Portland General Electric

(bd)

LFP

SA_868

Falls Creek H.P. Limited Partnership

Bonneville Power Administration

9,472

208,309

(is)

22,939

231,248

Falls Creek H.P. Limited Partnership

Lakeview Airport 10

Portland General Electric

(be)

SA_868

Falls Creek H.P. Limited Partnership

Bonneville Power Administration

2,023

(it)

3,808

Garrett Solar LLC

Portland General Electric

(bf)

LFP

SA_1142

Wallula Substation

Wala-MIDC path

21,385

415,560

(iu)

67,707

483,267

Garrett Solar LLC

Portland General Electric

(bg)

SA_966

Wallula Substation

Wala-MIDC path

(iv)

56,620

Guzman Energy LLC

various signatories

SA_786

various

51,701

694,729

(iw)

31,681

726,410

100

Guzman Energy LLC

various signatories

(bh)

SA_786

various

2,628

(ix)

41,060

101

Guzman Energy LLC

various signatories

SFP

SA_785

various

12,874

179,901

(iy)

8,206

188,107

102

Guzman Energy LLC

various signatories

(bi)

SA_785

various

512

(iz)

19,928

103

Idaho Power Company

Exxon Mobil

Nevada Power Company

(bj)

LFP

SA_212

Trona Substation

Red Butte/Mona Sub

1,149,928

(ja)

53,679

1,203,607

104

Idaho Power Company

Exxon Mobil

Nevada Power Company

(bk)

SA_212

Trona Substation

Red Butte/Mona Sub

(jb)

290,934

105

Idaho Power Company

Exxon Mobil

Nevada Power Company

(bl)

LFP

SA_1023

Trona Substation

Red Butte/Mona Sub

32,189

4,068,907

(jc)

55,274

4,124,181

106

Idaho Power Company

Exxon Mobil

Nevada Power Company

(bm)

SA_1023

Trona Substation

Red Butte/Mona Sub

(jd)

168,169

107

Idaho Power Company

various signatories

SA_14

various

2,298

30,488

(je)

1,375

31,863

108

Idaho Power Company

various signatories

(bn)

SA_14

various

140

(jf)

2,089

109

Idaho Power Company

various signatories

SFP

SA_154

various

1,635

24,433

(jg)

1,095

25,528

110

Idaho Power Marketing Operations

various signatories

SFP

SA_726

various

(jh)

1,633,575

111

Idaho Power Marketing Operations

various signatories

(bo)

SA_726

various

(ji)

141,931

112

Macquarie Energy LLC

various signatories

SA_755

various

33,787

410,392

(jj)

18,682

429,074

113

Macquarie Energy LLC

various signatories

(bp)

SA_755

various

4,000

(jk)

10,136

114

Macquarie Energy LLC

various signatories

SFP

SA_754

various

9,727

258,394

(jl)

11,617

270,011

115

Macquarie Energy LLC

various signatories

(bq)

SA_754

various

4,372

(jm)

243,018

116

MAG Energy Solutions, Inc.

various signatories

SA_903

various

4,176

114,854

(jn)

5,193

120,047

117

MAG Energy Solutions, Inc.

various signatories

(br)

SA_903

various

721

(jo)

8,434

118

MAG Energy Solutions, Inc.

various signatories

SFP

SA_902

various

10,800

242,931

(jp)

13,332

256,263

119

MAG Energy Solutions, Inc.

various signatories

(bs)

SA_902

various

(jq)

34,022

120

Mercuria Energy America LLC

various signatories

SA_998

various

92,466

1,049,167

(jr)

47,349

1,096,516

121

Mercuria Energy America LLC

various signatories

SFP

SA_997

various

54,025

963,963

(js)

44,946

1,008,909

122

Moon Lake Electric Association Inc.

Moon Lake Electric Association

(bt)

RS_302

Duchesne

20,633

(jt)

18,722

123

Moon Lake Electric Association Inc.

Moon Lake Electric Association

(bu)

RS_302

Duchesne

1,978

(ju)

1,702

124

Montana Dakota Utilities Company

PacifiCorp

Montana-Dakota Utilities

FNO

SA_1097

various

Sheridan Substation

296,489

2,481,687

(jv)

113,718

2,595,405

125

Montana Dakota Utilities Company

PacifiCorp

Montana-Dakota Utilities

(bv)

SA_1097

various

Sheridan Substation

30,484

(jw)

120,722

126

MFT Energy Power

various signatories

SA_1161

various

(jx)

127

Morgan Stanley Capital Group, Inc.

various signatories

(bw)

SA_660

Wallula Substation

Wala-MIDC path

3,023

(jy)

48,619

128

Morgan Stanley Capital Group, Inc.

various signatories

SA_157

various

52,815

435,452

(jz)

19,856

455,308

129

Morgan Stanley Capital Group, Inc.

various signatories

(bx)

SA_157

various

1,047

(ka)

17,345

130

Morgan Stanley Capital Group, Inc.

various signatories

SFP

SA_160

various

123,929

1,715,149

(kb)

80,059

1,795,208

131

Navajo Tribal Utility Authority

FNO

SA_894

Four Corners

Pinto-Four Corners

29,695

216,799

(kc)

384,489

601,288

132

Navajo Tribal Utility Authority

(by)

SA_894

Four Corners

Pinto-Four Corners

3,042

(kd)

24,793

133

Nevada Power Company

various signatories

(bz)

SA_455

various

14,953

(ke)

123,932

134

Nevada Power Company

various signatories

(ca)

SA_454

various

(kf)

135

NextEra Energy Resources, LLC

Public Utility District No. 2 of Grant County

(cb)

LFP

SA_733

Wallula Substation

Wala-MIDC path

(kg)

606,704

136

NextEra Energy Resources, LLC

Public Utility District No. 2 of Grant County

(cc)

SA_733

Wallula Substation

Wala-MIDC path

(kh)

54,998

137

Ormat Nevada

various signatories

SA_1051

various

128

(ki)

134

138

Ormat Nevada

various signatories

(cd)

SA_1051

various

28,605

(kj)

346,431

139

Ormat Nevada

various signatories

SFP

SA_1050

various

8,140

96,328

(kk)

4,301

100,629

140

Pacific Gas & Electric Company

various signatories

SA_338

various

2,676

24,664

(kl)

1,110

25,774

141

Pacific Gas & Electric Company

various signatories

(ce)

SA_338

various

372

(km)

4,190

142

Portland General Electric Company

Operation, maintenance or facility lease services with no receipt or delivery of energy.

(cf)

RS_137

various

(kn)

3,314

143

Phillips 66 Energy Trading

Four Corners

PacifiCorp

(cg)

LFP

SA_1102

Four Corners

Gonder - Pavant

66,031

459,971

(ko)

21,472

481,443

144

Phillips 66 Energy Trading

various signatories

SA_1081

various

197,816

1,680,471

(kp)

75,336

1,755,807

145

Phillips 66 Energy Trading

various signatories

(ch)

SA_1081

various

57,558

(kq)

726,819

146

Phillips 66 Energy Trading

various signatories

SFP

SA_1080

various

521,475

6,314,227

(kr)

284,571

6,598,798

147

Phillips 66 Energy Trading

various signatories

(ci)

SA_1080

various

65,419

(ks)

1,189,903

148

Portland General Electric Company

various signatories

SA_008

various

326

5,061

(kt)

226

5,287

149

Powerex Corporation

Bonneville Power Administration

California Independent System Operator Corporation

(cj)

LFP

SA_169

Bonneville Power Administration

CRAG View Substation

67,023

1,116,627

(ku)

49,857

1,166,484

150

Powerex Corporation

Bonneville Power Administration

California Independent System Operator Corporation

(ck)

SA_169

Bonneville Power Administration

CRAG View Substation

12,070

(kv)

157,105

151

Powerex Corporation

California Independent System Operator Corporation

(cl)

SA_1016

Borah

Red Butte/Mona Sub

(kw)

14,876

152

Powerex Corporation

California Independent System Operator Corporation

(cm)

SA_1017

Borah

Red Butte/Mona Sub

(kx)

14,876

153

Powerex Corporation

California Independent System Operator Corporation

(cn)

LFP

SA_1035

Borah

Red Butte/Mona Sub

104

106,389

5,086,135

(ky)

232,699

5,318,834

154

Powerex Corporation

California Independent System Operator Corporation

(co)

SA_1035

Borah

Red Butte/Mona Sub

104

5,070

(kz)

211,256

155

Powerex Corporation

California Independent System Operator Corporation

(cp)

LFP

SA_1036

Borah

Red Butte/Mona Sub

104

63,739

5,086,135

(la)

232,699

5,318,834

156

Powerex Corporation

California Independent System Operator Corporation

(cq)

SA_1036

Borah

Red Butte/Mona Sub

100

16,419

(lb)

211,256

157

Powerex Corporation

California Independent System Operator Corporation

(cr)

SA_1040

Malin 500 Substation

Round Mountain Sub

(lc)

1,427

158

Powerex Corporation

California Independent System Operator Corporation

(cs)

LFP

SA_700

Malin 500 Substation

Round Mountain Sub

100

1,338,240

(ld)

19,677

1,357,917

159

Powerex Corporation

California Independent System Operator Corporation

(ct)

SA_700

Malin 500 Substation

Round Mountain Sub

100

(le)

201,643

160

Powerex Corporation

California Independent System Operator Corporation

(cu)

LFP

SA_701

Malin 500 Substation

Round Mountain Sub

100

1,338,240

(lf)

19,677

1,357,917

161

Powerex Corporation

California Independent System Operator Corporation

(cv)

SA_701

Malin 500 Substation

Round Mountain Sub

100

(lg)

201,643

162

Powerex Corporation

California Independent System Operator Corporation

(cw)

LFP

SA_702

Malin 500 Substation

Round Mountain Sub

100

1,338,240

(lh)

19,677

1,357,917

163

Powerex Corporation

California Independent System Operator Corporation

(cx)

SA_702

Malin 500 Substation

Round Mountain Sub

100

(li)

201,643

164

Powerex Corporation

California Independent System Operator Corporation

(cy)

LFP

SA_748

Malin 500 Substation

Round Mountain Sub

669,120

(lj)

9,839

678,959

165

Powerex Corporation

California Independent System Operator Corporation

(cz)

SA_748

Malin 500 Substation

Round Mountain Sub

(lk)

100,821

166

Powerex Corporation

California Independent System Operator Corporation

(da)

LFP

SA_749

Malin 500 Substation

Round Mountain Sub

150

2,007,360

(ll)

29,516

2,036,876

167

Powerex Corporation

California Independent System Operator Corporation

(db)

SA_749

Malin 500 Substation

Round Mountain Sub

150

(lm)

302,464

168

Powerex Corporation

California Independent System Operator Corporation

(dc)

LFP

SA_995

Malin 500 Substation

Round Mountain Sub

100

1,338,240

(ln)

19,677

1,357,917

169

Powerex Corporation

California Independent System Operator Corporation

(dd)

SA_995

Malin 500 Substation

Round Mountain Sub

100

(lo)

201,643

170

Powerex Corporation

California Independent System Operator Corporation

(de)

LFP

SA_996

Malin 500 Substation

Round Mountain Sub

100

1,338,240

(lp)

19,677

1,357,917

171

Powerex Corporation

California Independent System Operator Corporation

(df)

SA_996

Malin 500 Substation

Round Mountain Sub

100

(lq)

201,643

172

Powerex Corporation

various signatories

SA_047

various

129,180

159,259

(lr)

7,284

166,543

173

Powerex Corporation

various signatories

(dg)

SA_047

various

419

(ls)

3,450

174

Powerex Corporation

various signatories

Sacramento Municipal Utility District

SFP

SA_151

various

77,829

72,818

(lt)

3,395

76,213

175

Powerex Corporation

various signatories

(dh)

SA_151

various

442

(lu)

2,938

176

Public Service Co of Co

Various signatories to the Volume 11 Point-to-Point Transmission Tariff.

SA_028

Various

5,187

58,489

(lv)

2,716

61,205

177

Public Service Co of Co

Various signatories to the Volume 11 Point-to-Point Transmission Tariff.

SFP

SA_074

Various

16,881

203,959

(lw)

9,356

213,315

178

Public Service Co of Co

Various signatories to the Volume 11 Point-to-Point Transmission Tariff.

(di)

SA_074

Various

930

(lx)

13,182

179

Public Utility District No. 1 of Cowlitz County

PUD No. 1 of Cowlitz County

Bonneville Power Administration

(dj)

RS_234

Swift Unit No. 2

Woodland Substation

(ly)

223,555

180

Public Utility District No. 1 of Cowlitz County

PUD No. 1 of Cowlitz County

Bonneville Power Administration

(dk)

RS_234

Swift Unit No. 2

Woodland Substation

(lz)

20,121

181

Puget Sound Energy

various signatories

SA_693

various

3,784

60,273

(ma)

2,699

62,972

182

Puget Sound Energy

various signatories

SFP

SA_694

various

46,348

37,104

(mb)

1,331,370

1,368,474

183

Rainbow Energy Marketing Corporation

various signatories

SA_316

various

30,651

598,617

(mc)

27,181

625,798

184

Rainbow Energy Marketing Corporation

various signatories

(dl)

SA_316

various

2,233

(md)

40,543

185

Rainbow Energy Marketing Corporation

various signatories

SFP

SA_261

various

1,507

15,303

(me)

3,519

18,822

186

Rainbow Energy Marketing Corporation

various signatories

(dm)

SA_261

various

1,419

(mf)

18,350

187

Sacramento Municipal Utility District

(dn)

LFP

SA_863

Malin Substation

62,025

966,366

(mg)

44,213

1,010,579

188

Sacramento Municipal Utility District

(do)

SA_863

Malin Substation

12,860

(mh)

37,312

189

Salt River Project Agricultural Improvement and Power District

(dp)

LFP

SA_809

Enel Cove Fort

Red Butte Substation

118,034

1,271,535

(mi)

58,175

1,329,710

190

Salt River Project Agricultural Improvement and Power District

(dq)

SA_809

Enel Cove Fort

Red Butte Substation

6,442

(mj)

49,095

191

Seattle City Light

various signatories

SFP

SA_155

various

(mk)

192

Shell Energy North America (US), L.P.

NextEra Energy Resources, LLC

Public Utility District No. 2 of Grant County

(dr)

LFP

SA_791

Wallula Substation

Wala-MIDC path

103

169,740

4,598,301

(ml)

209,973

4,808,274

193

Shell Energy North America (US), L.P.

NextEra Energy Resources, LLC

Public Utility District No. 2 of Grant County

(ds)

SA_791

Wallula Substation

Wala-MIDC path

103

20,628

(mm)

84,180

194

Shell Energy North America (US), L.P.

various signatories

SA_023

various

16,566

667,570

(mn)

125,761

793,331

195

Shell Energy North America (US), L.P.

various signatories

(dt)

SA_023

various

(mo)

10,237

196

Shell Energy North America (US), L.P.

various signatories

SFP

SA_162

various

2,043

18,892

(mp)

875

19,767

197

(a)

Sierra Pacific Power Company

Operation, maintenance or facility lease services with no receipt or delivery of energy.

(du)

RS_674

Sigurd Substation

Utah-Nevada Border

(mq)

33,147

198

Sierra Pacific Power Company

Operation, maintenance or facility lease services with no receipt or delivery of energy.

(dv)

RS_674

Sigurd Substation

Utah-Nevada Border

(mr)

3,013

199

Southern California Edison Company

various signatories

SA_642

various

275,306

3,675,709

(ms)

1,165,806

4,841,515

200

Southern California Edison Company

various signatories

(dw)

SA_642

various

34,674

(mt)

480,993

201

Southern California Edison Company

various signatories

SFP

SA_643

various

859

(mu)

897

202

Southern California Public Power Authority

Powerex Corporation

Southern California Public Power Authority

SA_629

Tieton Substation

various

(mv)

41,422

203

State of South Dakota

Western Area Power Administration

Black Hills Corporation

(dx)

LFP

SA_1137

Yellowtail Sub

Wyodak Substation

16,535

203,446

(mw)

9,309

212,755

204

State of South Dakota

Western Area Power Administration

Black Hills Corporation

(dy)

SA_779

Yellowtail Sub

Wyodak Substation

(mx)

8,702

205

State of South Dakota

various signatories

(dz)

SA_770

various

1,535

(my)

19,441

206

TEC Energy Inc.

various signatories

SA_1001

various

281

15,223

(mz)

688

15,911

207

Tenaska Power Services Co.

various signatories

(ea)

LFP

SA_1100

Wallula Substation

Wala-MIDC path

88,132

916,563

(na)

41,746

958,309

208

Tenaska Power Services Co.

various signatories

(eb)

SA_1100

Wallula Substation

Wala-MIDC path

2,674

(nb)

42,785

209

Tenaska Power Services Co.

various signatories

SA_125

various

21,959

202,902

(nc)

245,297

448,199

210

Tenaska Power Services Co.

various signatories

(ec)

SA_125

various

8,907

(nd)

96,843

211

Tenaska Power Services Co.

various signatories

SFP

SA_126

various

4,991

91,473

(ne)

4,116

95,589

212

Tenaska Power Services Co.

various signatories

(ed)

SA_126

various

3,791

(nf)

54,062

213

The Energy Authority, Inc.

various signatories

SA_310

various

76,645

1,040,885

(ng)

47,386

1,088,271

214

The Energy Authority, Inc.

various signatories

(ee)

SA_310

various

9,512

(nh)

26,466

215

The Energy Authority, Inc.

various signatories

SFP

SA_311

various

3,698

33,962

(ni)

15,826

49,788

216

The Energy Authority, Inc.

various signatories

(ef)

SA_311

various

15,698

(nj)

247,945

217

Thermo No. 1 BE-01, LLC

Thermo Geothermal Project

various signatories

(eg)

LFP

SA_568

South Milford Sub

Mona Substation

49,367

559,476

(nk)

74,016

633,492

218

Thermo No. 1 BE-01, LLC

Thermo Geothermal Project

various signatories

(eh)

SA_568

South Milford Sub

Mona Substation

5,395

(nl)

16,931

219

TransAlta Energy Marketing (U.S.) Inc.

various signatories

SA_127

various

33,835

506,049

(nm)

22,749

528,798

220

TransAlta Energy Marketing (U.S.) Inc.

various signatories

(ei)

SA_127

various

1,093

(nn)

14,088

221

TransAlta Energy Marketing (U.S.) Inc.

various signatories

SFP

SA_128

various

940

13,873

(no)

640

14,513

222

TransAlta Energy Marketing (U.S.) Inc.

various signatories

(ej)

SA_128

various

395

(np)

2,671

223

Tri-State Generation and Transmission Association, Inc.

various signatories

Tri-State Generation and Transmission Association, Inc.

FNO

SA_628

Dave Johnston Sub

Thermopolis Sub

117,413

834,912

(nq)

99,267

934,179

224

Tri-State Generation and Transmission Association, Inc.

various signatories

Tri-State Generation and Transmission Association, Inc.

(ek)

SA_628

Dave Johnston Sub

Thermopolis Sub

12,479

(nr)

192

225

Tri-State Generation and Transmission Association, Inc.

various signatories

SA_033

various

1,001

15,504

(ns)

715

16,219

226

Tri-State Generation and Transmission Association, Inc.

various signatories

SFP

SA_722

various

3,049

32,945

(nt)

1,473

34,418

227

U.S. Bureau of Reclamation

Bonneville Power Administration

U.S. Bureau of Reclamation

FNO

SA_506

Walla Walla Sub

Burbank Pumps

2,316

14,386

(nu)

11,421

25,807

228

U.S. Bureau of Reclamation

Bonneville Power Administration

U.S. Bureau of Reclamation

(el)

SA_506

Walla Walla Sub

Burbank Pumps

(nv)

2,523

229

U.S. Bureau of Reclamation

Western Area Power Administration

Weber Basin Water Conservancy District

(em)

RS_286

various

26,599

(nw)

26,599

230

U.S. Bureau of Reclamation

Western Area Power Administration

Weber Basin Water Conservancy District

(en)

RS_286

various

1,345

(nx)

1,345

231

U.S. Bureau of Reclamation

Bonneville Power Administration

Crooked River Irrigation District

(eo)

RS_67

Redmond Substation

Crooked River Pumps

11,126

11,522

232

Utah Associated Municipal Power

Utah Associated Municipal Power Systems

Utah Associated Municipal Power

(ep)

RS_297

various

663

3,437,677

32,396,323

(ny)

3,834,316

36,230,639

233

Utah Associated Municipal Power

Utah Associated Municipal Power Systems

Utah Associated Municipal Power

(eq)

RS_297

various

449

281,185

(nz)

2,802,500

234

Utah Associated Municipal Power Systems

various signatories

SA_009

various

420

3,677

(oa)

172

3,849

235

Utah Associated Municipal Power Systems

various signatories

SFP

SA_718

various

3,187

39,730

(ob)

1,780

41,510

236

Utah Municipal Power Agency

(er)

RS_637

various

114

912,790

5,501,009

(oc)

510,744

6,011,753

237

Utah Municipal Power Agency

(es)

RS_637

various

138

75,890

(od)

264,660

238

Utah Municipal Power Agency

various signatories

SA_020

various

54,463

566,381

(oe)

25,688

592,069

239

Utah Municipal Power Agency

various signatories

(et)

SA_020

various

16,372

(of)

194,417

240

Utah Municipal Power Agency

various signatories

SFP

SA_135

various

222,969

3,412,456

(og)

158,699

3,571,155

241

Utah Municipal Power Agency

various signatories

(eu)

SA_135

various

10,419

(oh)

123,192

242

Vitol, Inc

various signatories

SA_1027

various

134

(oi)

140

243

Warm Springs Power Enterprises

Portland General Electric

(ev)

RS_591

Pelton Reregulating

Round Butte Sub

63,169

(oj)

109,725

244

Warm Springs Power Enterprises

Portland General Electric

(ew)

RS_591

Pelton Reregulating

Round Butte Sub

6,625

(ok)

9,975

245

Western Area Power Administration

Various Western Area Power Administration customers in PacifiCorp's control area.

(ex)

RS_2436-262L

various

330

1,182,627

1,111,669

2,108,162

(ol)

550,000

2,658,162

246

Western Area Power Administration

Various Western Area Power Administration customers in PacifiCorp's control area.

(ey)

RS_2436-262L

various

330

89,480

84,111

(om)

245,116

247

Western Area Power Administration

Various Western Area Power Administration customers in PacifiCorp's control area.

(ez)

RS_2436-263L

various

30,039

28,214

(on)

32,492

248

Western Area Power Administration

Various Western Area Power Administration customers in PacifiCorp's control area.

(fa)

RS_2436-263L

various

2,849

2,680

(oo)

3,085

249

Western Area Power Administration

FNO

SA_175

Wyoming Distribution

11,278

77,163

(op)

50,553

127,716

250

Western Area Power Administration

Western Area Power Administration Colorado River Storage Project

Western Area Power Administration

(fb)

SA_175

various

Wyoming Distribution

(oq)

11,953

251

Western Area Power Administration

Western Area Power Administration Colorado River Storage Project

various signatories

SA_137

various

766

12,060

(or)

559

12,619

252

Western Area Power Adm CO River

Western Area Power Administration Colorado River Storage Project

various signatories

SA_132

various

1,181

(os)

1,234

253

West Point RNG

various signatories

SA_1130

various

1,289

10,803

(ot)

498

11,301

254

West Point RNG

various signatories

(fc)

SA_1130

various

140

(ou)

1,933

255

Accrual

186,176

187,199

(ov)

25,551,428

TOTAL

7,413

17,411,015

17,331,671

122,992,894

36,451,510

45,359,566

204,803,970

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: PaymentByCompanyOrPublicAuthority

This footnote applies to all occurrences of "Sierra Pacific Power Company" on page 328. Sierra Pacific Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.

(b) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName

This footnote applies to all occurrences of "Nevada Power Company" on page 328. Nevada Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 965) terminating on December 31, 2034.

(d) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 965) terminating on December 31, 2034.

(e) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(f) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(g) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(h) Concept: StatisticalClassificationCode

Ancillary services under the Open Access Transmission Tariff (1st Revised Service Agreement 476) in effect until superseded.

(i) Concept: StatisticalClassificationCode

Ancillary services under the Open Access Transmission Tariff (1st Revised Service Agreement 476) in effect until superseded.

(j) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 895) terminating on December 31, 2028.

(k) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 895) terminating on December 31, 2028.

(l) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (7th Revised Service Agreement 279) terminating on December 31, 2028.

(m) Concept: StatisticalClassificationCode

Network transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 742) terminating no earlier than 12-months from notice by the customer.

(n) Concept: StatisticalClassificationCode

Network transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 505) terminating no earlier than 12-months from notice by the customer.

(o) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(p) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(q) Concept: StatisticalClassificationCode

Network transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 347) terminating on December 31, 2023.

(r) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 67) terminating on December 31, 2023.

(s) Concept: StatisticalClassificationCode

Legacy contract (3rd Revised Rate Schedule 237) executed between PacifiCorp and Bonneville Power Administration ("BPA") for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Contract subject to terminate upon the earlier of the termination of the "Exchange Agreement" between PacifiCorp and BPA or the time of the termination of all deliveries as defined in the agreement.

(t) Concept: StatisticalClassificationCode

(u) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 656) terminating on August 31, 2030.

(v) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 656) terminating on August 31, 2030.

(w) Concept: StatisticalClassificationCode

Network transmission service and distribution delivery service under the Open Access Transmission Tariff (9th Revised Service Agreement 229) terminating on September 30, 2028.

(x) Concept: StatisticalClassificationCode

Network transmission service and distribution delivery service under the Open Access Transmission Tariff (3rd Revised Service Agreement 539) terminating on September 30, 2028.

(y) Concept: StatisticalClassificationCode

Network transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 538) terminating on September 30, 2028.

(z) Concept: StatisticalClassificationCode

Legacy contract (5th Revised Rate Schedule 368) executed between PacifiCorp and Bonneville Power Administration for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Subject to termination upon mutual agreement.

(aa) Concept: StatisticalClassificationCode

(ab) Concept: StatisticalClassificationCode

Network transmission service and distribution delivery service under the Open Access Transmission Tariff (6th Revised Service Agreement 328) terminating on July 31, 2028.

(ac) Concept: StatisticalClassificationCode

Network transmission service under the Open Access Transmission Tariff (2nd Revised Service Agreement 827) terminating on September 30, 2028.

(ad) Concept: StatisticalClassificationCode

Network transmission service and distribution delivery service under the Open Access Transmission Tariff (3rd Revised Service Agreement 746) terminating on June 30, 2028.

(ae) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(af) Concept: StatisticalClassificationCode

Network transmission service and distribution delivery service under the Open Access Transmission Tariff (2nd Revised Service Agreement 747) terminating on June 30, 2028.

(ag) Concept: StatisticalClassificationCode

Network transmission service under the Open Access Transmission Tariff (2nd Revised Service Agreement 735) terminating on September 30, 2028.

(ah) Concept: StatisticalClassificationCode

Network transmission service and distribution delivery service under the Open Access Transmission Tariff (1st Revised Service Agreement 865) terminating on September 30, 2028.

(ai) Concept: StatisticalClassificationCode

Network transmission service and distribution delivery service under the Open Access Transmission Tariff (1st Revised Service Agreement 975) terminating on September 30, 2028.

(aj) Concept: StatisticalClassificationCode

Transmission service under the Open Access Transmission Tariff (12th Revised Service Agreement 299). Service provided pursuant to rules and regulations of Oregon Direct Access. Agreement terminates upon notification pursuant to Oregon Direct Access and Open Access Transmission Tariff.

(ak) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 881) terminating on February 29, 2028.

(al) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 881) terminating on February 29, 2028.

(am) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(an) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 899) terminating on September 30, 2028.

(ao) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 899) terminating on September 30, 2028.

(ap) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 901) terminating on September 30, 2023.

(aq) Concept: StatisticalClassificationCode

Legacy contract executed between PacifiCorp and Deseret Generation and Transmission Co-operative for transmission service over agreed-upon facilities (6th Amended and Restated Transmission Service and Operating Agreement, Rate Schedule 280). Agreement subject to termination upon mutual agreement.

(ar) Concept: StatisticalClassificationCode

(as) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(at) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(au) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 1055) terminating on December 31, 2025.

(av) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(aw) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 874) terminating on December 31, 2032.

(ax) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 874) terminating on December 31, 2032.

(ay) Concept: StatisticalClassificationCode

Transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 943). Service provided pursuant to rules and regulations of Oregon Direct Access. Agreement terminates upon notification pursuant to Oregon Direct Access and Open Access Transmission Tariff.

(az) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(ba) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(bb) Concept: StatisticalClassificationCode

Legacy contract (Rate Schedule 322) executed between PacifiCorp and Fall River Rural Electric Cooperative, Inc. for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Terminating on July 31, 2027.

(bc) Concept: StatisticalClassificationCode

(bd) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 868) terminating on December 31, 2034.

(be) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 868) terminating on December 31, 2034.

(bf) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff Service Agreement 1142) terminating on February 28, 2030.

(bg) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 966) terminating on November 30, 2024.

(bh) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(bi) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(bj) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (10th Revised Service Agreement 212) terminating on May 31, 2029.

(bk) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (10th Revised Service Agreement 212) terminating on May 31, 2029.

(bl) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff Service Agreement 1023) terminating on December 31, 2027.

(bm) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff Service Agreement 1023) terminating on December 31, 2027.

(bn) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(bo) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(bp) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(bq) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(br) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(bs) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(bt) Concept: StatisticalClassificationCode

Legacy contract (3rd Revised Rate Schedule 302) executed between PacifiCorp and Moon Lake Electric Association Inc. for transmission and interconnection service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Either party may terminate the agreement at any time after October 14, 2016, by providing two years written notice.

(bu) Concept: StatisticalClassificationCode

(bv) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(bw) Concept: StatisticalClassificationCode

Transmission resale service under the Open Access Transmission Tariff (Service Agreement 660). Termination upon mutual consent.

(bx) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(by) Concept: StatisticalClassificationCode

Network transmission service under the Open Access Transmission Tariff (Service Agreement 894) terminating on December 31, 2057.

(bz) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(ca) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(cb) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 733) terminating on November 30, 2027.

(cc) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 733) terminating on November 30, 2027.

(cd) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(ce) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(cf) Concept: StatisticalClassificationCode

Legacy contract (1st Revised Rate Schedule 137) executed between PacifiCorp and Portland General Electric Company for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge for the Dalreed Substation, which terminated December 2013.

(cg) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 1102) terminating on October 01, 2030.

(ch) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(ci) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(cj) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 169) terminating on March 31, 2025.

(ck) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 169) terminating on March 31, 2025.

(cl) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 1016) terminating on September 24, 2024.

(cm) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 1017) terminating on September 24, 2024.

(cn) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 1035) terminating on June 30, 2029.

(co) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 1035) terminating on June 30, 2029.

(cp) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 1036) terminating on June 30, 2029.

(cq) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 1036) terminating on June 30, 2029.

(cr) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 1040) terminating on September 30, 2023.

(cs) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 700) terminating on March 31, 2025.

(ct) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 700) terminating on March 31, 2025.

(cu) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 701) terminating on March 31, 2025.

(cv) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 701) terminating on March 31, 2025.

(cw) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 702) terminating on March 31, 2025.

(cx) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 702) terminating on March 31, 2025.

(cy) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised Service Agreement 748) terminating on March 31, 2025.

(cz) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised Service Agreement 748) terminating on March 31, 2025.

(da) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised Service Agreement 749) terminating on March 31, 2025.

(db) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised Service Agreement 749) terminating on March 31, 2025.

(dc) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 995) terminating on December 31, 2025.

(dd) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 995) terminating on December 31, 2025.

(de) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 996) terminating on December 31, 2025.

(df) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 996) terminating on December 31, 2025.

(dg) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(dh) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(di) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(dj) Concept: StatisticalClassificationCode

Legacy contract (Rate Schedule 234) providing for transmission and operation of Swift Hydroelectric plant No. 2 and for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Agreement may be terminated subsequent to the termination of the power contract as defined in the agreement by the customer providing at least six-months written notice and specifying the date on which the customer will assume responsibility of operations and maintenance of Swift Hydroelectric plant No. 2.

(dk) Concept: StatisticalClassificationCode

(dl) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(dm) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(dn) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 863) terminating on June 30, 2027.

(do) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 863) terminating on June 30, 2027.

(dp) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised Service Agreement 809) terminating on October 31, 2030.

(dq) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised Service Agreement 809) terminating on October 31, 2030.

(dr) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 791) terminating upon written notification.

(ds) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised Service Agreement 791) terminating upon written notification.

(dt) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(du) Concept: StatisticalClassificationCode

Legacy contract (Rate Schedule 674) executed between PacifiCorp and Sierra Pacific Power Company for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Terminating in September 2022.

(dv) Concept: StatisticalClassificationCode

(dw) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(dx) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 1137) terminating on December 31, 2029.

(dy) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised Service Agreement 779) terminating on August 31, 2024.

(dz) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(ea) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 1100) terminating on December 31, 2035.

(eb) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (Service Agreement 1100) terminating on December 31, 2035.

(ec) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(ed) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(ee) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(ef) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(eg) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 568) terminating on April 30, 2029.

(eh) Concept: StatisticalClassificationCode

Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised Service Agreement 568) terminating on April 30, 2029.

(ei) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(ej) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(ek) Concept: StatisticalClassificationCode

Network transmission service under the Open Access Transmission Tariff (10th Revised Service Agreement 628) terminating on June 30, 2031.

(el) Concept: StatisticalClassificationCode

Network transmission service and distribution delivery service under the Open Access Transmission Tariff (2nd Revised Service Agreement 506) terminating upon written notification.

(em) Concept: StatisticalClassificationCode

Legacy contract (3rd Revised Rate Schedule 286) executed between PacifiCorp and United States Department of the Interior, Bureau of Reclamation Weber Basin Water Conservancy District for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge for energy deliveries at and below 138kV. Agreement terminates any time after April 1, 2040 with four years written notification.

(en) Concept: StatisticalClassificationCode

(eo) Concept: StatisticalClassificationCode

Legacy contract (3rd Amended Rate Schedule 67) executed between PacifiCorp and United States Department of the Interior, Bureau of Reclamation Crooked River Irrigation District for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Agreement termination with one year written notice.

(ep) Concept: StatisticalClassificationCode

Legacy contract executed between PacifiCorp and Utah Associated Municipal Power Systems for transmission service over agreed-upon facilities (4th Amended and Restated Transmission Service and Operating Agreement, 4th Revised Rate Schedule 297). Agreement subject to termination upon mutual agreement and replacement agreements are in effect.

(eq) Concept: StatisticalClassificationCode

(er) Concept: StatisticalClassificationCode

Legacy contract (5th Revised Rate Schedule 637) executed between PacifiCorp and Utah Municipal Power Agency for transmission service over agreed-upon facilities (Amended and Restated Transmission Service and Operating Agreement). Subject to termination upon mutual agreement and replacement agreements are in effect.

(es) Concept: StatisticalClassificationCode

(et) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(eu) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(ev) Concept: StatisticalClassificationCode

Legacy contract (Rate Schedule 591) executed between PacifiCorp and Warm Springs Power Enterprises for transmission service over agreed-upon facilities and/or subject to sole-use or facilities charge. Terminating on January 31, 2032.

(ew) Concept: StatisticalClassificationCode

(ex) Concept: StatisticalClassificationCode

Legacy contract (Rate Schedule 262) executed between PacifiCorp and Western Area Power Administration for transmission and interconnection service over agreed-upon facilities and/or subject to a sole-use or facilities charge for load service to preferential customers for deliveries of Colorado River Storage Project power and energy. Agreement terminates upon three years after written notice and mutual consent.

(ey) Concept: StatisticalClassificationCode

(ez) Concept: StatisticalClassificationCode

Legacy contract (Rate Schedule 263) executed between PacifiCorp and Western Area Power Administration for transmission and interconnection service over agreed-upon facilities and/or subject to a sole-use or facilities charge for load service to low voltage customers for deliveries of power and energy from Salt Lake City Area Integrated Projects, including the Colorado River Storage Projects, to certain municipalities at service below 138kV. Agreement terminates upon three years after written notice and mutual consent.

(fa) Concept: StatisticalClassificationCode

(fb) Concept: StatisticalClassificationCode

Evergreen network transmission service under the Open Access Transmission Tariff (4th Revised Service Agreement 175).

(fc) Concept: StatisticalClassificationCode

Non-firm or short-term firm transmission service under the Open Access Transmission Tariff between various parties and points.

(fd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service. Generation regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.

(fe) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ff) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(fg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(fh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(fi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.

(fj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(fk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(fl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(fm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.

(fn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(fo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(fp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(fq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(fr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service. Regulation and frequency response service. Generation regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.

(fs) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ft) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Distribution voltage service charge. Primary delivery service. Scheduling, system control and dispatch service. Reactive supply and voltage control service. Regulation and frequency response service.

(fu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(fv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(fw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(fx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(fy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(fz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ga) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(gb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(gc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(gd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ge) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(gf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(gg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(gh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Reactive supply and voltage control service.

(gi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(gj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Distribution voltage service charge. Primary delivery service. Regulation and frequency response service. Reactive supply and voltage control service. Operating reserve - spinning reserve service. Operating Reserve - supplemental reserve service.

(gk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(gl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.

(gm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(gn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.

(go) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(gp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor and/or proportional use as defined in the contract.

(gq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(gr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Distribution voltage service charge. Primary delivery service. Regulation and frequency response service. Reactive supply and voltage control service. Operating reserve - spinning reserve service. Operating Reserve - supplemental reserve service.

(gs) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(gt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(gu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(gv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(gw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(gx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(gy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(gz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ha) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(hb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(hc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.

(hd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(he) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(hf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(hg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(hh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(hi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(hj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(hk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(hl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(hm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service.

(hn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ho) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(hp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(hq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(hr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(hs) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ht) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(hu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(hv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(hw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Distribution voltage service charge. Meter interrogation services. Scheduling, system control and dispatch service. Reactive supply and voltage control service. Regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.

(hx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(hy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(hz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ia) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ib) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ic) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(id) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ie) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Transmission resale - purchase of point-to-point transmission. Scheduling, system control and dispatch service. Reactive supply and voltage control service. Generation regulation and frequency response service.

(if) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ig) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ih) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Transmission resale, amount paid by seller. Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ii) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(ij) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ik) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(il) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(im) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unauthorized use of transmission service. Scheduling, system control and dispatch service. Reactive supply and voltage control service. Generation regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.

(in) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(io) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ip) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(iq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor and/or proportional use as defined in the contract.

(ir) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(is) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(it) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(iu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(iv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(iw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ix) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(iy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(iz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ja) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(jb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(jc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(jd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(je) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(jf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(jg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(jh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ji) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(jj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(jk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(jl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(jm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(jn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(jo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(jp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(jq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(jr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(js) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(jt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor and/or proportional use as defined in the contract.

(ju) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(jv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(jw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(jx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(jy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(jz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ka) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(kb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(kc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(kd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ke) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(kf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(kg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(kh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ki) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(kj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(kk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(kl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(km) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(kn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.

(ko) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(kp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(kq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(kr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ks) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(kt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ku) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(kv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(kw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(kx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ky) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(kz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(la) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(lb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(lc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ld) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service.

(le) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(lf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service.

(lg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(lh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service.

(li) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(lj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service.

(lk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ll) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service.

(lm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ln) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service.

(lo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(lp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service.

(lq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(lr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ls) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(lt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(lu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(lv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(lw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(lx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ly) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor and/or proportional use as defined in the contract.

(lz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ma) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(mb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Transmission resale - purchase of point-to-point transmission. Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(mc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(md) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(me) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(mf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(mg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(mh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(mi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(mj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(mk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ml) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(mm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(mn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(mo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(mp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(mq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.

(mr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ms) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(mt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(mu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(mv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unauthorized use of transmission service. Generation regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.

(mw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(mx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(my) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(mz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(na) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(nb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(nc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(nd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ne) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(nf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ng) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(nh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ni) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(nj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(nk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(nl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(nm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(nn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(no) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(np) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(nq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(nr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ns) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(nt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(nu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(nv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(nw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Energy consumption charge for deliveries at and below 138kV.

(nx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ny) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Distribution voltage service charge. Scheduling, system control and dispatch service. Reactive supply and voltage control service. Generation regulation and frequency response service. Operating reserve - spinning reserve service. Operating reserve - supplemental reserve service.

(nz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(oa) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ob) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(oc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

(od) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(oe) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(of) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(og) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(oh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(oi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(oj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor and/or proportional use as defined in the contract.

(ok) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ol) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Fixed termination fee associated with a contract cancellation applied for the duration of this agreement.

(om) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Fixed termination fee associated with a contract cancellation applied for the duration of this agreement. Prior period adjustment.

(on) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Charges for low-voltage transmission of power and energy.

(oo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Charges for low-voltage transmission of power and energy. Prior period adjustment.

(op) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Distribution voltage service charge. Primary delivery service. Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(oq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(or) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(os) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ot) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Scheduling, system control and dispatch service. Reactive supply and voltage control service.

(ou) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Annual transmission services true-up and prior period charges/refund.

(ov) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Represents the difference between actual wheeling revenues for the period as reflected on the individual line items within this schedule and the accruals credited to Account 456.1, Revenues from transmission of electricity for others, during the period.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

TRANSMISSION OF ELECTRICITY BY ISO/RTOs
Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO � Firm Network Service for Others, FNS � Firm Network Transmission Service for Self, LFP � Long-Term Firm Point-to-Point Transmission Service, OLF � Other Long-Term Firm Transmission Service, SFP � Short-Term Firm Point-to-Point Transmission Reservation, NF � Non-Firm Transmission Service, OS � Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or �true-ups� for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided. In column (d) report the revenue amounts as shown on bills or vouchers. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line No.	Payment Received by (Transmission Owner Name) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Total Revenue by Rate Schedule or Tariff (d)	Total Revenue (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
40	TOTAL

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. Enter ""TOTAL"" in column (a) as the last line. Footnote entries and provide explanations following all required data.
			TRANSFER OF ENERGY		EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.	NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	TransmissionOfElectricityByOthersEnergyReceived MegaWatt Hours Received (c)	TransmissionOfElectricityByOthersEnergyDelivered MegaWatt Hours Delivered (d)	DemandChargesTransmissionOfElectricityByOthers Demand Charges ($) (e)	EnergyChargesTransmissionOfElectricityByOthers Energy Charges ($) (f)	OtherChargesTransmissionOfElectricityByOthers Other Charges ($) (g)	ChargesForTransmissionOfElectricityByOthers Total Cost of Transmission ($) (h)
1	Adams Solar Center, LLC	(d) LFP					(cg) 91,967	91,967
2	American Gilsonite Company	(e) LFP					(ch) 124,458	124,458
3	Arizona Public Service Company	(f) AD					(ci) 2,915	2,915
4	Arizona Public Service Company	(g) NF	4,530	4,530	34,612		(cj) 226	34,838
5	Arizona Public Service Company	(h) OS					(ck) 8,311	8,311
6	Arizona Public Service Company	(i) SFP	1,018,663	1,018,663	9,854,633		(cl) 44,906	9,899,539
7	Ashland, City of	FNS	2,290	2,290		22,907		22,907
8	Avista Corporation	(j) AD					(cm) 193	193
9	Avista Corporation	FNS			194,990			194,990
10	Avista Corporation	NF	11,158	11,158	88,483			88,483
11	Avista Corporation	(k) OS					(cn) 1,539	1,539
12	Avista Corporation	SFP	7,176	7,176	37,913			37,913
13	Basin Electric Power Cooperative, Inc.	(l) NF	10,831	10,831	16,406		(co) 5,297	21,703
14	Big Horn Rural Electric Company	(m)(n) OLF	35,525	35,525			(cp) 160,279	160,279
15	Black Hills Power, Inc.	(o) AD					(cq) 10,902	10,902
16	Black Hills Power, Inc.	(p) NF	3,081	3,081	2,721		(cr) 1,443	4,164
17	Black Hills Power, Inc.	(q) SFP	58,299	58,299	455,259		(cs) 32,710	487,969
18	Bonneville Power Administration	(r) AD					(ct) 192,912	192,912
19	Bonneville Power Administration	(s) FNS	3,946	3,930	8,530,149		(cu) 1,633,327	10,163,476
20	Bonneville Power Administration	(t)(u) LFP	5,398,159	5,376,791	76,978,314		(cv) 15,527,352	92,505,666
21	Bonneville Power Administration	(v) NF	519,994	517,916	8,608,231		(cw) 1,626,571	10,234,802
22	Bonneville Power Administration	(w)(x)(y)(z) OLF	2,177,730	2,169,092	2,724,600		(cx)(cy) 953,618	3,678,218
23	Bonneville Power Administration	(aa) OS					(cz) 289,473	289,473
24	Bonneville Power Administration	(ab) SFP	19,013	18,937	116,180		(da) 22,297	138,477
25	Caerus Uinta LLC	(ac) LFP					(db) 373,374	373,374
26	California Independent System Operator Corporation	(ad) AD					(dc) 1,699,222	1,699,222
27	California Independent System Operator Corporation	(ae) SFP				289,126	(dd) 12,914,366	13,203,492
28	Chipeta Gas Processing LLC	(af) LFP					(de) 1,089,009	1,089,009
29	Deseret Generation & Transmission Cooperative	(ag) LFP	665,760	665,760	2,346,822			2,346,822
30	Deseret Generation & Transmission Cooperative	NF	17,053	17,053	87,959			87,959
31	Elbe Solar Center, LLC	(ah) LFP					(df) 321,306	321,306
32	Flathead Electric Cooperative, Inc.	(ai) OS					(dg) 70,432	70,432
33	(a) Hermiston Generating Company, L.P.	(aj) OS					(dh) 257,291	257,291
34	Idaho Power Company	(ak) AD					(di) 5,312	5,312
35	Idaho Power Company	(al) FNS			13,657		(dj) 1,387	15,044
36	Idaho Power Company	(am) LFP	4,516,632	4,516,632	16,423,479			16,423,479
37	Idaho Power Company	NF	586,843	586,843	2,272,068			2,272,068
38	Idaho Power Company	(an)(ao) OLF					(dk) 29,759	29,759
39	Idaho Power Company	(ap) OS					(dl) 23,847	23,847
40	Idaho Power Company	SFP	16,368	16,368	322,585			322,585
41	Los Angeles Department of Water and Power	(aq) AD					(dm) 273	273
42	Los Angeles Department of Water and Power	(ar) NF	23,740	23,740	165,409		(dn) 16,595	182,004
43	Los Angeles Department of Water and Power	(as) OS					(do) 4,082	4,082
44	Los Angeles Department of Water and Power	SFP	335	335	1,347			1,347
45	Moon Lake Electric Association, Inc.	(at) FNS	24	24			(dp) 293,981	293,981
46	Morgan City Corporation	(au) AD					(dq) 2,457	2,457
47	Morgan City Corporation	(av) LFP				2,158		2,158
48	(b) Nevada Power Company	(aw) AD					(dr) 25	25
49	Nevada Power Company	(ax) NF	55,506	55,506	223,198		(ds) 5,760	228,958
50	Nevada Power Company	(ay) OS					(dt) 416	416
51	Nevada Power Company	(az) SFP	526,035	526,035	1,822,250		(du) 61,501	1,883,751
52	NorthWestern Corporation	(ba) AD					(dv) 1,004	1,004
53	NorthWestern Corporation	(bb) NF	11,160	11,160	68,310		(dw) 1,303	69,613
54	NorthWestern Corporation	(bc) OS					(dx) 163,043	163,043
55	NorthWestern Corporation	(bd) SFP	10,104	31,116	61,253		(dy) 1,263	62,516
56	Open Access Technology International, Inc.	SFP			28			28
57	Platte River Power Authority	(be)(bf) LFP	219,000	219,000	1,149,534		(dz) 49,249	1,198,783
58	Platte River Power Authority	(bg) NF	39	39	225		(ea) 115	340
59	Portland General Electric Company	(bh) AD					(eb) 5	5
60	Portland General Electric Company	(bi)(bj) LFP	105,120	105,120	163,094		(ec) 14,491	177,585
61	Portland General Electric Company	(bk) NF	13,620	13,620	23,732		(ed) 15	23,747
62	Portland General Electric Company	(bl)(bm) OLF		3,235			(ee) 729	729
63	Portland General Electric Company	SFP	5,280	5,280	9,065			9,065
64	Public Service Company of Colorado	(bn) AD					(ef) 92,722	92,722
65	Public Service Company of Colorado	(bo)(bp) LFP	441,297	441,297	3,077,722		(eg) 190,157	3,267,879
66	Public Service Company of Colorado	(bq) NF	145,120	145,120	1,528,084		(eh) 85,288	1,613,372
67	Public Service Company of Colorado	SFP	37,553	37,553	183,532			183,532
68	(c) Sierra Pacific Power Company	(br) NF	26,230	26,230	150,914		(ei) 3,512	154,426
69	Surprise Valley Electrification Corp.	(bs)(bt) OLF					(ej) 8,509	8,509
70	Tri-State Generation and Transmission Association, Inc.	(bu)(bv) LFP	376,300	376,300	1,247,800		(ek) 14,477	1,262,277
71	Tri-State Generation and Transmission Association, Inc.	(bw) NF	28,753	28,753	330,193		(el) 16,649	346,842
72	Tucson Electric Power Company	(bx) NF	285	285	955		(em) 159	1,114
73	Tucson Electric Power Company	(by) SFP	20	20	96		(en) 12	108
74	Umatilla Electric Cooperative	(bz) LFP	2,119,920	2,119,920	1,887,600			1,887,600
75	Western Area Power Administration	(ca)(cb)(cc) FNS	916,698	916,698	5,547,504		(eo)(ep) 651,281	6,198,785
76	Western Area Power Administration	(cd) NF	967,422	967,422	3,287,617		(eq) 138,280	3,425,897
77	Western Area Power Administration	(ce) OS					(er) 1,382	1,382
78	Western Area Power Administration	(cf) SFP	106,896	106,896	295,540		(es) 21	295,561
79	Accrual True-Up						(et) 1,752,657	1,752,657
	TOTAL		21,209,508	21,201,579	150,334,063	314,191	36,851,536	187,499,790

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers

Hermiston Generating Company, L.P. operates the Hermiston Generating Plant, which is jointly owned. PacifiCorp owns 50% of the plant.

(b) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers

This footnote applies to all occurrences of "Nevada Power Company" on page 332. Nevada Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.

Sierra Pacific Power Company is a principal subsidiary of NV Energy, Inc. which is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, Pacificorp's indirect parent company.

(d) Concept: StatisticalClassificationCode

Reimbursement for third-party services.

(e) Concept: StatisticalClassificationCode

Reimbursement for third-party services.

(f) Concept: StatisticalClassificationCode

Settlement adjustment.

(g) Concept: StatisticalClassificationCode

Ancillary services.

(h) Concept: StatisticalClassificationCode

Ancillary services.

(i) Concept: StatisticalClassificationCode

Ancillary services.

(j) Concept: StatisticalClassificationCode

Settlement adjustment.

(k) Concept: StatisticalClassificationCode

Ancillary services.

(l) Concept: StatisticalClassificationCode

Ancillary services.

(m) Concept: StatisticalClassificationCode

Big Horn Rural Electric Company - contract termination date: March 10, 2027.

(n) Concept: StatisticalClassificationCode

Use of facilities.

(o) Concept: StatisticalClassificationCode

Settlement adjustment.

(p) Concept: StatisticalClassificationCode

Ancillary services.

(q) Concept: StatisticalClassificationCode

Ancillary services.

(r) Concept: StatisticalClassificationCode

Settlement adjustment.

(s) Concept: StatisticalClassificationCode

Ancillary services.

(t) Concept: StatisticalClassificationCode

Ancillary services.

(u) Concept: StatisticalClassificationCode

Bonneville Power Administration - Contract Termination Dates: February 2026, April 2026, July 2026, September 2026, November 2026, December 2026, January 2027, March 2027, April 2027, July 2027, October 2027, November 2027, March 2028, July 2028, October 2028, December 2028, January 2029, July 2029, September 2029, October 2029, November 2029, October 2030, November 2030, January 2031, November 2033, December 2041, and Evergreen.

(v) Concept: StatisticalClassificationCode

Ancillary services.

(w) Concept: StatisticalClassificationCode

Ancillary services.

(x) Concept: StatisticalClassificationCode

Bonneville Power Administration - Contract Termination Dates: September 30, 2027, November 30, 2041, and evergreen.

(y) Concept: StatisticalClassificationCode

Bonneville Power Administration - Legacy Contract executed between PacifiCorp and Bonneville Power Administration concerning the exchange of transmission services over agreed-upon facilities ("Midpoint-Meridian Transmission Agreement", Rate Schedule 369). This agreement runs concurrently with the AC Intertie Agreement (Rate Schedule 368), which terminates when the facilities subject to that agreement are taken out of service. See also page 328, Transmission of electricity for others in this Form 1.

(z) Concept: StatisticalClassificationCode

Use of facilities.

(aa) Concept: StatisticalClassificationCode

Ancillary services.

(ab) Concept: StatisticalClassificationCode

Ancillary services.

(ac) Concept: StatisticalClassificationCode

Reimbursement for third-party services.

(ad) Concept: StatisticalClassificationCode

Settlement adjustment.

(ae) Concept: StatisticalClassificationCode

Ancillary services.

(af) Concept: StatisticalClassificationCode

Reimbursement for third-party services.

(ag) Concept: StatisticalClassificationCode

Deseret Generation & Transmission Cooperative - Contract termination date: November 1, 2034.

(ah) Concept: StatisticalClassificationCode

Reimbursement for third-party services.

(ai) Concept: StatisticalClassificationCode

Use of facilities.

(aj) Concept: StatisticalClassificationCode

Use of facilities.

(ak) Concept: StatisticalClassificationCode

Settlement adjustment.

(al) Concept: StatisticalClassificationCode

Ancillary services.

(am) Concept: StatisticalClassificationCode

Idaho Power Company - contract termination dates: July 1, 2029 and May 1, 2030.

(an) Concept: StatisticalClassificationCode

Use of facilities.

(ao) Concept: StatisticalClassificationCode

Idaho Power Company - Contract termination date of August 31, 2022 and shall automatically renew for each successive one-year period thereafter unless or until the earlier of (i) one year following Department of Energy�s receipt of written notice by PacifiCorp if due to a re-configuration of its transmission system, PacifiCorp no longer needs use of the Department of Energy Scoville Facilities; or (ii) upon mutual agreement of the parties.

(ap) Concept: StatisticalClassificationCode

Ancillary services.

(aq) Concept: StatisticalClassificationCode

Settlement adjustment.

(ar) Concept: StatisticalClassificationCode

Ancillary services.

(as) Concept: StatisticalClassificationCode

Ancillary services.

(at) Concept: StatisticalClassificationCode

Use of facilities.

(au) Concept: StatisticalClassificationCode

Settlement adjustment.

(av) Concept: StatisticalClassificationCode

Morgan City Corporation - contract rermination date: evergreen.

(aw) Concept: StatisticalClassificationCode

Settlement adjustment.

(ax) Concept: StatisticalClassificationCode

Ancillary services.

(ay) Concept: StatisticalClassificationCode

Ancillary services.

(az) Concept: StatisticalClassificationCode

Ancillary services.

(ba) Concept: StatisticalClassificationCode

Settlement adjustment.

(bb) Concept: StatisticalClassificationCode

Ancillary services.

(bc) Concept: StatisticalClassificationCode

Ancillary services.

(bd) Concept: StatisticalClassificationCode

Ancillary services.

(be) Concept: StatisticalClassificationCode

Ancillary services.

(bf) Concept: StatisticalClassificationCode

Platte River Power Authority - contract termination date: October 31, 2027.

(bg) Concept: StatisticalClassificationCode

Ancillary services.

(bh) Concept: StatisticalClassificationCode

Settlement adjustment.

(bi) Concept: StatisticalClassificationCode

Ancillary services.

(bj) Concept: StatisticalClassificationCode

Portland General Electric Company - contract termination date: April 1, 2027.

(bk) Concept: StatisticalClassificationCode

Ancillary services.

(bl) Concept: StatisticalClassificationCode

Use of facilities.

(bm) Concept: StatisticalClassificationCode

Portland General Electric Company - contract termination date: Upon two years written notice.

(bn) Concept: StatisticalClassificationCode

Settlement adjustment.

(bo) Concept: StatisticalClassificationCode

Ancillary services.

(bp) Concept: StatisticalClassificationCode

Public Service Company of Colorado - contract termination dates: The date that all generating plants comprising PacifiCorp resources associated with this agreement have been retired from service or interests transferred; and December 31, 2028.

(bq) Concept: StatisticalClassificationCode

Ancillary services.

(br) Concept: StatisticalClassificationCode

Ancillary services.

(bs) Concept: StatisticalClassificationCode

Use of facilities.

(bt) Concept: StatisticalClassificationCode

Surprise Valley Electrification Corp. - Contract Termination Date: Evergreen.

(bu) Concept: StatisticalClassificationCode

Ancillary services.

(bv) Concept: StatisticalClassificationCode

Tri-State Generation and Transmission Association, Inc. - contract termination date: The date that all generating plants comprising PacifiCorp resources associated with this agreement have been retired from service or interests transferred.

(bw) Concept: StatisticalClassificationCode

Ancillary services.

(bx) Concept: StatisticalClassificationCode

Ancillary services.

(by) Concept: StatisticalClassificationCode

Ancillary services.

(bz) Concept: StatisticalClassificationCode

Umatilla Electric Cooperative - Contract Termination Date: July 31, 2029, and it shall automatically renew for successive five year periods until terminated by either party.

(ca) Concept: StatisticalClassificationCode

Ancillary services.

(cb) Concept: StatisticalClassificationCode

Use of facilities.

(cc) Concept: StatisticalClassificationCode

Western Area Power Administration - Legacy contract (Rate Schedule 684) executed between PacifiCorp and Western Area Power Administration for transmission services over agreed-upon facilities. The contract is subject to terminate upon the earlier of five years after written notice and mutual agreement or June 30, 2042.

(cd) Concept: StatisticalClassificationCode

Ancillary services.

(ce) Concept: StatisticalClassificationCode

Ancillary services.

(cf) Concept: StatisticalClassificationCode

Ancillary services.

(cg) Concept: OtherChargesTransmissionOfElectricityByOthers

Reimbursement for third-party services.

(ch) Concept: OtherChargesTransmissionOfElectricityByOthers

Reimbursement for third-party services.

(ci) Concept: OtherChargesTransmissionOfElectricityByOthers

Settlement adjustment.

(cj) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(ck) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(cl) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(cm) Concept: OtherChargesTransmissionOfElectricityByOthers

Settlement adjustment.

(cn) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(co) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(cp) Concept: OtherChargesTransmissionOfElectricityByOthers

Use of facilities.

(cq) Concept: OtherChargesTransmissionOfElectricityByOthers

Settlement adjustment.

(cr) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(cs) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(ct) Concept: OtherChargesTransmissionOfElectricityByOthers

Settlement adjustment.

(cu) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(cv) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(cw) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(cx) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(cy) Concept: OtherChargesTransmissionOfElectricityByOthers

Use of facilities.

(cz) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(da) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(db) Concept: OtherChargesTransmissionOfElectricityByOthers

Reimbursement for third-party services.

(dc) Concept: OtherChargesTransmissionOfElectricityByOthers

Settlement adjustment.

(dd) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(de) Concept: OtherChargesTransmissionOfElectricityByOthers

Reimbursement for third-party services.

(df) Concept: OtherChargesTransmissionOfElectricityByOthers

Reimbursement for third-party services.

(dg) Concept: OtherChargesTransmissionOfElectricityByOthers

Use of facilities.

(dh) Concept: OtherChargesTransmissionOfElectricityByOthers

Use of facilities.

(di) Concept: OtherChargesTransmissionOfElectricityByOthers

Settlement adjustment.

(dj) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(dk) Concept: OtherChargesTransmissionOfElectricityByOthers

Use of facilities.

(dl) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(dm) Concept: OtherChargesTransmissionOfElectricityByOthers

Settlement adjustment.

(dn) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(do) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(dp) Concept: OtherChargesTransmissionOfElectricityByOthers

Use of facilities.

(dq) Concept: OtherChargesTransmissionOfElectricityByOthers

Settlement adjustment.

(dr) Concept: OtherChargesTransmissionOfElectricityByOthers

Settlement adjustment.

(ds) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(dt) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(du) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(dv) Concept: OtherChargesTransmissionOfElectricityByOthers

Settlement adjustment.

(dw) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(dx) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(dy) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(dz) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(ea) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(eb) Concept: OtherChargesTransmissionOfElectricityByOthers

Settlement adjustment.

(ec) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(ed) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(ee) Concept: OtherChargesTransmissionOfElectricityByOthers

Use of facilities.

(ef) Concept: OtherChargesTransmissionOfElectricityByOthers

Settlement adjustment.

(eg) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(eh) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(ei) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(ej) Concept: OtherChargesTransmissionOfElectricityByOthers

Use of facilities.

(ek) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(el) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(em) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(en) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(eo) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(ep) Concept: OtherChargesTransmissionOfElectricityByOthers

Use of facilities.

(eq) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(er) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(es) Concept: OtherChargesTransmissionOfElectricityByOthers

Ancillary services.

(et) Concept: OtherChargesTransmissionOfElectricityByOthers

Represents the difference between actual wheeling expenses for the period as reflected on the individual line items within this schedule and the accruals charged to Account 565, Transmission of electricity by others, during this period.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.	Description (a)	Amount (b)
1	IndustryAssociationDues Industry Association Dues	2,073,122
2	NuclearPowerResearchExpenses Nuclear Power Research Expenses
3	OtherExperimentalAndGeneralResearchExpenses Other Experimental and General Research Expenses
4	PublicationAndDistributionExpensesForSecuritiesToStockholders Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities
5	OtherMiscellaneousGeneralExpenses Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
6	Business & Economic Development and Corporate Memberships & Subscriptions:
7	Advance Casper	10,000
8	Arlington Club	10,000
9	Carbon County Economic Development Corporation	5,000
10	Chamber West	7,500
11	Clatsop Economic Development Resources	5,000
12	Economic Development for Central Oregon	10,000
13	Greater Yakima Chamber of Commerce	5,000
14	Idaho Association of Commerce Industry	15,645
15	Jordan River Commission	7,500
16	Klamath County Economic Development Association	5,000
17	Lander Chamber of Commerce	5,000
18	Laramie Chamber of Business Alliance	5,000
19	Ogden-Weber Chamber of Commerce	6,000
20	Oregon Business Council	27,240
21	Portland Business Alliance	35,245
22	Redmond Economic Development, Inc.	7,500
23	Roseburg Rotary International	5,000
24	Salt Lake Chamber	27,000
25	Siskiyou County JOB Council	5,000
26	South Valley Chamber	5,500
27	Sport Oregon	7,500
28	Umpqua Economic Development Partnership	5,000
29	University of Wyoming	10,000
30	Utah Manufacturers Association	8,785
31	Utah Taxpayers Association	19,635
32	Utah Valley Chamber of Commerce	10,000
33	Walla Walla Valley Chamber of Commerce	10,000
34	Wyoming Association of Municipalities	15,000
35	Wyoming Business Alliance	5,000
36	Wyoming Construction Coalition, Inc.	5,500
37	Wyoming County Commissioners Association	10,000
38	Wyoming Taxpayers Association	11,250
39	Yakima County Development	7,500
40	Other (Individually < $5,000)	108,109
41	Rating Agency and Trustee Fees:
42	Computershare Shareowner Services, LLC	12,001
43	Moody's Investors Service	256,085
44	Standard and Poor's Financial Services, LLC	299,162
45	The Bank of New York Mellon	142,635
46	U.S. Bank National Association	16,945
46	MiscellaneousGeneralExpenses TOTAL	3,242,359

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403); (c) Depreciation Expense for Asset Retirement Costs (Account 403.1); (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405). Report in Section B the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year. Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used. In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used. For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification listed in column (a). If plant mortality studies are prepared to assist in estimating average service lives, show in column (f) the type of mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related.
	A. Summary of Depreciation and Amortization Charges
Line No.	FunctionalClassificationAxis Functional Classification (a)	DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments Depreciation Expense (Account 403) (b)	DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	AmortizationOfLimitedTermPlantOrProperty Amortization of Limited Term Electric Plant (Account 404) (d)	AmortizationOfOtherElectricPlant Amortization of Other Electric Plant (Acc 405) (e)	DepreciationAndAmortization Total (f)
1	Intangible Plant			(a) 8,850,201		8,850,201
2	Steam Production Plant	396,240,730				396,240,730
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional	33,855,200		314,733		34,169,933
5	Hydraulic Production Plant-Pumped Storage
5.1	Solar Production Plant	29,246				29,246
5.2	Wind Production Plant	163,614,362				163,614,362
5.3	Other Renewable Production Plant	5,486,040				5,486,040
6	Other Production Plant	72,008,684		102,526		72,111,210
7	Transmission Plant	(b) 206,445,094				206,445,094
8	Distribution Plant	267,936,340				267,936,340
9	Regional Transmission and Market Operation
9.1	Energy Storage Plant
10	General Plant	100,337,635		289,883		100,627,518
11	Common Plant-Electric
12	TOTAL	(c) 1,245,953,331	(d) 0	9,557,343		1,255,510,674

B. Basis for Amortization Charges
The Amortization of Limited-Term Electric Plant is based on straight-line amortization over the life of the asset.

	C. Factors Used in Estimating Depreciation Charges
Line No.	AccountNumberFactorsUsedInEstimatingDepreciationCharges Account No. (a)	DepreciablePlantBase Depreciable Plant Base (in Thousands) (b)	UtilityPlantEstimatedAverageServiceLife Estimated Avg. Service Life (c)	UtilityPlantNetSalvageValuePercentage Net Salvage (Percent) (d)	UtilityPlantAppliedDepreciationRate Applied Depr. Rates (Percent) (e)	MortalityCurveType Mortality Curve Type (f)	UtilityPlantWeightedAverageRemainingLife Average Remaining Life (g)
12	STEAM PRODUCTION PLANT: ALL PLANTS: 315.3	18.74			4.3
13	STEAM PRODUCTION PLANT: ALL PLANTS: 315.35	0.403			9.09
14	STEAM PRODUCTION PLANT: ALL PLANTS: 315.1	0.383			20
15	STEAM PRODUCTION PLANT: ALL PLANTS: 315.2	0.078			20
16	HYDRO PRODUCTION PLANT: ALL PLANTS: 334.3	14.568			4.3
17	HYDRO PRODUCTION PLANT: ALL PLANTS: 334.35	0.064			9.09
18	HYDRO PRODUCTION PLANT: ALL PLANTS: 334.1	0.039			20
19	HYDRO PRODUCTION PLANT: ALL PLANTS: 334.2	0.023			20
20	WIND PRODUCTION PLANT: CEDAR SPRINGS: 338.21	16.395			3.44
21	WIND PRODUCTION PLANT: CEDAR SPRINGS: 338.23	155.177			3.43
22	WIND PRODUCTION PLANT: CEDAR SPRINGS: 338.24	41.008			3.43
23	WIND PRODUCTION PLANT: CEDAR SPRINGS: 338.26	28.417			3.49
24	WIND PRODUCTION PLANT: CEDAR SPRINGS: 338.27	2.05			3.49
25	WIND PRODUCTION PLANT: CEDAR SPRINGS: 338.29	0.951			3.49
26	WIND PRODUCTION PLANT: CEDAR SPRINGS: 338.33	1.523			3.37
27	WIND PRODUCTION PLANT: CEDAR SPRINGS: 338.37	12.592			3.85
28	WIND PRODUCTION PLANT: DUNLAP: 338.19	5.366
29	WIND PRODUCTION PLANT: DUNLAP: 338.21	21.3			2.33
30	WIND PRODUCTION PLANT: DUNLAP: 338.23	119.573			5.34
31	WIND PRODUCTION PLANT: DUNLAP: 338.24	47.642			5.34
32	WIND PRODUCTION PLANT: DUNLAP: 338.26	9.336			2.43
33	WIND PRODUCTION PLANT: DUNLAP: 338.27	3.23			2.43
34	WIND PRODUCTION PLANT: DUNLAP: 338.29	0.236			2.43
35	WIND PRODUCTION PLANT: DUNLAP: 338.33	0.164			2.46
36	WIND PRODUCTION PLANT: DUNLAP: 338.37	10.152			7.72
37	WIND PRODUCTION PLANT: EKOLA FLATS: 338.21	20.583			3.47
38	WIND PRODUCTION PLANT: EKOLA FLATS: 338.23	192.929			3.47
39	WIND PRODUCTION PLANT: EKOLA FLATS: 338.24	52.875			3.47
40	WIND PRODUCTION PLANT: EKOLA FLATS: 338.26	27.015			3.53
41	WIND PRODUCTION PLANT: EKOLA FLATS: 338.27	2.644			3.53
42	WIND PRODUCTION PLANT: EKOLA FLATS: 338.29	0.46			3.53
43	WIND PRODUCTION PLANT: EKOLA FLATS: 338.33	2.984			3.37
44	WIND PRODUCTION PLANT: EKOLA FLATS: 338.37	15.891			3.85
45	WIND PRODUCTION PLANT: FOOTE CREEK I-II: 338.20	5.656			3.2
46	WIND PRODUCTION PLANT: FOOTE CREEK I-II: 338.21	5.678			4.94
47	WIND PRODUCTION PLANT: FOOTE CREEK I-II: 338.23	43.776			4.11
48	WIND PRODUCTION PLANT: FOOTE CREEK I-II: 338.27	0.601			5.01
49	WIND PRODUCTION PLANT: FOOTE CREEK I-II: 338.29	0.076			5.01
50	WIND PRODUCTION PLANT: FOOTE CREEK I-II: 338.33	0.49			4.2
51	WIND PRODUCTION PLANT: FOOTE CREEK I-II: 338.37	3.599			5.52
52	WIND PRODUCTION PLANT: FOOTE CREEK III-IV: 338.20	4.048			3.35
53	WIND PRODUCTION PLANT: FOOTE CREEK III-IV: 338.21	6.943			3.35
54	WIND PRODUCTION PLANT: FOOTE CREEK III-IV: 338.23	43.552			3.35
55	WIND PRODUCTION PLANT: FOOTE CREEK III-IV: 338.24	12.265			3.35
56	WIND PRODUCTION PLANT: FOOTE CREEK III-IV: 338.26	2.412			3.35
57	WIND PRODUCTION PLANT: FOOTE CREEK III-IV: 338.27	0.612			3.35
58	WIND PRODUCTION PLANT: FOOTE CREEK III-IV: 338.28	1.224			3.35
59	WIND PRODUCTION PLANT: FOOTE CREEK III-IV: 338.33	1.017			3.35
60	WIND PRODUCTION PLANT: FOOTE CREEK III-IV: 338.37	3.678			3.35
61	WIND PRODUCTION PLANT: GLENROCK/ROLLING HILLS: 338.19	0.703
62	WIND PRODUCTION PLANT: GLENROCK/ROLLING HILLS: 338.20	0.023			3.39
63	WIND PRODUCTION PLANT: GLENROCK/ROLLING HILLS: 338.21	63.002			2.39
64	WIND PRODUCTION PLANT: GLENROCK/ROLLING HILLS: 338.23	261.677			4.26
65	WIND PRODUCTION PLANT: GLENROCK/ROLLING HILLS: 338.24	94.35			4.26
66	WIND PRODUCTION PLANT: GLENROCK/ROLLING HILLS: 338.26	24.458			2.34
67	WIND PRODUCTION PLANT: GLENROCK/ROLLING HILLS: 338.27	6.137			2.34
68	WIND PRODUCTION PLANT: GLENROCK/ROLLING HILLS: 338.29	3.132			2.34
69	WIND PRODUCTION PLANT: GLENROCK/ROLLING HILLS: 338.33	1.673			3.02
70	WIND PRODUCTION PLANT: GLENROCK/ROLLING HILLS: 338.37	19.802			5.94
71	WIND PRODUCTION PLANT: GOODNOE HILLS: 338.21	24.643			2.21
72	WIND PRODUCTION PLANT: GOODNOE HILLS: 338.23	80.038			5.83
73	WIND PRODUCTION PLANT: GOODNOE HILLS: 338.24	33.311			5.83
74	WIND PRODUCTION PLANT: GOODNOE HILLS: 338.26	8.464			3.89
75	WIND PRODUCTION PLANT: GOODNOE HILLS: 338.27	1.331			3.89
76	WIND PRODUCTION PLANT: GOODNOE HILLS: 338.29	0.825			3.89
77	WIND PRODUCTION PLANT: GOODNOE HILLS: 338.33	0.237			2.33
78	WIND PRODUCTION PLANT: GOODNOE HILLS: 338.37	6.986			7.1
79	WIND PRODUCTION PLANT: HIGH PLAINS COMMON/MCFADDEN: 338.19	0.03
80	WIND PRODUCTION PLANT: HIGH PLAINS COMMON/MCFADDEN: 338.21	21.881			2.28
81	WIND PRODUCTION PLANT: HIGH PLAINS COMMON/MCFADDEN: 338.23	134.984			5.47
82	WIND PRODUCTION PLANT: HIGH PLAINS COMMON/MCFADDEN: 338.24	56.797			5.47
83	WIND PRODUCTION PLANT: HIGH PLAINS COMMON/MCFADDEN: 338.26	10.649			2.39
84	WIND PRODUCTION PLANT: HIGH PLAINS COMMON/MCFADDEN: 338.27	4.338			2.39
85	WIND PRODUCTION PLANT: HIGH PLAINS COMMON/MCFADDEN: 338.29	0.814			2.39
86	WIND PRODUCTION PLANT: HIGH PLAINS COMMON/MCFADDEN: 338.33	0.114			2.54
87	WIND PRODUCTION PLANT: HIGH PLAINS COMMON/MCFADDEN: 338.37	11.343			7.5
88	WIND PRODUCTION PLANT: LEANING JUNIPER: 338.21	16.769			2
89	WIND PRODUCTION PLANT: LEANING JUNIPER: 338.23	93.367			4.96
90	WIND PRODUCTION PLANT: LEANING JUNIPER: 338.24	46.541			4.96
91	WIND PRODUCTION PLANT: LEANING JUNIPER: 338.26	8.479			2.43
92	WIND PRODUCTION PLANT: LEANING JUNIPER: 338.27	1.431			2.43
93	WIND PRODUCTION PLANT: LEANING JUNIPER: 338.29	1.591			2.43
94	WIND PRODUCTION PLANT: LEANING JUNIPER: 338.33	0.089			2.4
95	WIND PRODUCTION PLANT: LEANING JUNIPER: 338.37	8.529			9.48
96	WIND PRODUCTION PLANT: MARENGO: 338.21	30.221			2.06
97	WIND PRODUCTION PLANT: MARENGO: 338.23	181.568			4.98
98	WIND PRODUCTION PLANT: MARENGO: 338.24	72.41			4.98
99	WIND PRODUCTION PLANT: MARENGO: 338.26	16.392			2.77
100	WIND PRODUCTION PLANT: MARENGO: 338.27	3.887			2.77
101	WIND PRODUCTION PLANT: MARENGO: 338.29	1.94			3
102	WIND PRODUCTION PLANT: MARENGO: 338.33	0.392			2.24
103	WIND PRODUCTION PLANT: MARENGO: 338.37	16.539			6.72
104	WIND PRODUCTION PLANT: PRYOR MOUNTAIN: 338.19	1.675
105	WIND PRODUCTION PLANT: PRYOR MOUNTAIN: 338.20	0.079			3.45
106	WIND PRODUCTION PLANT: PRYOR MOUNTAIN: 338.21	45.397			3.45
107	WIND PRODUCTION PLANT: PRYOR MOUNTAIN: 338.23	233.325			3.45
108	WIND PRODUCTION PLANT: PRYOR MOUNTAIN: 338.24	63.262			3.45
109	WIND PRODUCTION PLANT: PRYOR MOUNTAIN: 338.26	35.341			3.45
110	WIND PRODUCTION PLANT: PRYOR MOUNTAIN: 338.27	3.888			3.45
111	WIND PRODUCTION PLANT: PRYOR MOUNTAIN: 338.29	0.498			3
112	WIND PRODUCTION PLANT: PRYOR MOUNTAIN: 338.33	1.528			3.45
113	WIND PRODUCTION PLANT: PRYOR MOUNTAIN: 338.37	19.244			3.45
114	WIND PRODUCTION PLANT: PRYOR MOUNTAIN: 338.38
115	WIND PRODUCTION PLANT: ROCK CREEK 1: 338.21	79.443			3.35
116	WIND PRODUCTION PLANT: ROCK CREEK 1: 338.23	192.859			3
117	WIND PRODUCTION PLANT: ROCK CREEK 1: 338.24	53.739			3.35
118	WIND PRODUCTION PLANT: ROCK CREEK 1: 338.26	27.927			3.35
119	WIND PRODUCTION PLANT: ROCK CREEK 1: 338.27	5.616			3.35
120	WIND PRODUCTION PLANT: ROCK CREEK 1: 338.28	2.929			3.35
121	WIND PRODUCTION PLANT: ROCK CREEK 1: 338.33	0.625			3.35
122	WIND PRODUCTION PLANT: ROCK CREEK 1: 338.37	16.363			3.35
123	WIND PRODUCTION PLANT: ROCK CREEK 2: 338.21	143.114			3.35
124	WIND PRODUCTION PLANT: ROCK CREEK 2: 338.23	388.567			3.35
125	WIND PRODUCTION PLANT: ROCK CREEK 2: 338.24	108.681			3.35
126	WIND PRODUCTION PLANT: ROCK CREEK 2: 338.26	76.676			3.35
127	WIND PRODUCTION PLANT: ROCK CREEK 2: 338.27	11.357			3.35
128	WIND PRODUCTION PLANT: ROCK CREEK 2: 338.28	5.923			3
129	WIND PRODUCTION PLANT: ROCK CREEK 2: 338.33	1.575			3.35
130	WIND PRODUCTION PLANT: ROCK CREEK 2: 338.37	33.094			3.35
131	WIND PRODUCTION PLANT: ROCK RIVER: 338.20	2.969			3.35
132	WIND PRODUCTION PLANT: ROCK RIVER: 338.21	6.505			3.35
133	WIND PRODUCTION PLANT: ROCK RIVER: 338.23	52.581			3
134	WIND PRODUCTION PLANT: ROCK RIVER: 338.24	14.713			3.35
135	WIND PRODUCTION PLANT: ROCK RIVER: 338.26	7.583			3.35
136	WIND PRODUCTION PLANT: ROCK RIVER: 338.27	1.967			3.35
137	WIND PRODUCTION PLANT: ROCK RIVER: 338.28	1.494			3.35
138	WIND PRODUCTION PLANT: ROCK RIVER: 338.33	1.409			3.35
139	WIND PRODUCTION PLANT: ROCK RIVER: 338.37	4.728			3
140	WIND PRODUCTION PLANT: SEVEN MILE HILL: 338.21	23.027			2.28
141	WIND PRODUCTION PLANT: SEVEN MILE HILL: 338.23	129.159			5.23
142	WIND PRODUCTION PLANT: SEVEN MILE HILL: 338.24	48.759			5.23
143	WIND PRODUCTION PLANT: SEVEN MILE HILL: 338.26	10.566			2.36
144	WIND PRODUCTION PLANT: SEVEN MILE HILL: 338.27	2.971			2
145	WIND PRODUCTION PLANT: SEVEN MILE HILL: 338.29	0.812			2.36
146	WIND PRODUCTION PLANT: SEVEN MILE HILL: 338.33	0.814			2.54
147	WIND PRODUCTION PLANT: SEVEN MILE HILL: 338.37	10.835			7.4
148	WIND PRODUCTION PLANT: TB FLATS: 338.21	32.728			3.44
149	WIND PRODUCTION PLANT: TB FLATS: 338.23	374.851			3
150	WIND PRODUCTION PLANT: TB FLATS: 338.24	101.484			3.43
151	WIND PRODUCTION PLANT: TB FLATS: 338.26	46.117			3.49
152	WIND PRODUCTION PLANT: TB FLATS: 338.27	5.137			3.49
153	WIND PRODUCTION PLANT: TB FLATS: 338.29	1.594			3.49
154	WIND PRODUCTION PLANT: TB FLATS: 338.33	3.77			3.34
155	WIND PRODUCTION PLANT: TB FLATS: 338.37	30.447			3.85
156	WIND PRODUCTION PLANT: ALL PLANTS: 338.30	0.418			20
157	WIND PRODUCTION PLANT: ALL PLANTS: 338.31	0.311			20
158	WIND PRODUCTION PLANT: ALL PLANTS: 338.32	2.979			4.3
159	WIND PRODUCTION PLANT: ALL PLANTS: 338.35	0.072			9.09
160	OTHER RENEWABLES PLANT: BLUNDELL COMMON: 339.00	0.214
161	OTHER RENEWABLES PLANT: BLUNDELL COMMON: 339.02	0.957			4.4
162	OTHER RENEWABLES PLANT: BLUNDELL COMMON: 339.03	0.293			6.28
163	OTHER RENEWABLES PLANT: BLUNDELL COMMON: 339.08	0.042			4.78
164	OTHER RENEWABLES PLANT: BLUNDELL UNIT 1: 339.02	6.649			3
165	OTHER RENEWABLES PLANT: BLUNDELL UNIT 1: 339.03	12.322			3.41
166	OTHER RENEWABLES PLANT: BLUNDELL UNIT 1: 339.04	2.605			3.41
167	OTHER RENEWABLES PLANT: BLUNDELL UNIT 1: 339.06	17.999			3.76
168	OTHER RENEWABLES PLANT: BLUNDELL UNIT 1: 339.08	4.98			2.82
169	OTHER RENEWABLES PLANT: BLUNDELL UNIT 1: 339.12	0.681			3.92
170	OTHER RENEWABLES PLANT: BLUNDELL UNIT 2: 339.02	0.703			4.23
171	OTHER RENEWABLES PLANT: BLUNDELL UNIT 2: 339.03	8.468			4.58
172	OTHER RENEWABLES PLANT: BLUNDELL UNIT 2: 339.06	17.972			4.45
173	OTHER RENEWABLES PLANT: BLUNDELL UNIT 2: 339.08	2.454			4.08
174	OTHER RENEWABLES PLANT: BLUNDELL UNIT 2: 339.12	0.545			4.61
175	OTHER RENEWABLES PLANT: BLUNDELL STEAM FIELD: 339.01	40.982			1.69
176	OTHER RENEWABLES PLANT: BLUNDELL STEAM FIELD: 339.02	0.251			3.87
177	OTHER RENEWABLES PLANT: BLUNDELL STEAM FIELD: 339.03	37.494			4.57
178	OTHER RENEWABLES PLANT: BLUNDELL STEAM FIELD: 339.08	1.079			4.84
179	OTHER RENEWABLES PLANT: BLUNDELL STEAM FIELD: 339.12	0.125			5.24
180	OTHER RENEWABLES PLANT: ALL PLANTS: 339.09	0.005			20
181	OTHER RENEWABLES PLANT: ALL PLANTS: 339.10	0.007			20
182	OTHER RENEWABLES PLANT: ALL PLANTS: 339.11	0.984			4.3
183	OTHER RENEWABLES PLANT: ALL PLANTS: 339.15	0.022			9.09
184	OTHER PRODUCTION PLANT: ALL PLANTS: 345.1	0.239			20
185	OTHER PRODUCTION PLANT: ALL PLANTS: 345.2	0.023			20
186	OTHER PRODUCTION PLANT: ALL PLANTS: 345.3	2.639			4.3
187	OTHER PRODUCTION PLANT: ALL PLANTS: 345.35	0.067			9.09
188	SOLAR PRODUCTION PLANT: OREGON HIGH DESERT: 338.04	0.056
189	SOLAR PRODUCTION PLANT: SMALL SOLAR (MULTIPLE): 338.00	0.075
190	SOLAR PRODUCTION PLANT: SMALL SOLAR (MULTIPLE): 338.02	0.073			4.21
191	SOLAR PRODUCTION PLANT: SMALL SOLAR (MULTIPLE): 338.04	0.292			4.65
192	SOLAR PRODUCTION PLANT: SMALL SOLAR (MULTIPLE): 338.05	0.134			4.63
193	SOLAR PRODUCTION PLANT: SMALL SOLAR (MULTIPLE): 338.07	0.038			4
194	SOLAR PRODUCTION PLANT: SMALL SOLAR (MULTIPLE): 338.08	0.028			5
195	SOLAR PRODUCTION PLANT: ALL PLANTS: 338.11	0.083			4.3
196	TRANSMISSION PLANT: 351.2	0.039			20
197	TRANSMISSION PLANT: 351.21	66.386			20
198	TRANSMISSION PLANT: 351.3	174.106			4.3
199	TRANSMISSION PLANT: 351.35	0.03			9.09
200	DISTRIBUTION PLANT: ALL STATES: 363.1	2.752			20
201	DISTRIBUTION PLANT: ALL STATES: 363.2	0.297			20
202	DISTRIBUTION PLANT: ALL STATES: 363.21	51.638			20
203	DISTRIBUTION PLANT: ALL STATES: 363.3	172.718			4.3
204	DISTRIBUTION PLANT: ALL STATES: 363.35	0.814			9.09
205	GENERAL PLANT: IDAHO: 392.19	0.08			5.19
206	GENERAL PLANT: ALL STATES: 397.91	71.043			20
207	GENERAL PLANT: ALL STATES: 397.92	30.06			20
208	GENERAL PLANT: ALL STATES: 397.93	752.884			20
209	GENERAL PLANT: ALL STATES: 397.94	144.107			4.3
210	GENERAL PLANT: ALL STATES: 397.95	0.053			9.09
211	(e) FERC Sub-Accounts
212	(f) Account 403 - Provisions

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: AmortizationOfLimitedTermPlantOrProperty

As a result of the adpoption of FERC Order No. 898 on January 1, 2025, the depreciation of software assets is included in FERC Account 403, Depreciation Expense.

(b) Concept: DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments


Functional Classification	Depreciation Expense
(a)	(b)
Transmission	$	206,445,094
Add: Depreciation on disallowance of Oregon's share of transmission wildfire investments (1)	152,500
Revised Transmission	$	206,597,594

(1) In December 2024, the Oregon Public Utility Commission issued an order in PacifiCorp's general rate case imposing a partial disallowance for a portion of Oregon's share of wildfire mitigation investments. This adjustment reinstates the depreciation on the disallowed amount for purposes of PacifiCorp's Formula Rate.

Depreciation expense associated with transportation equipment is generally charged to operations and maintenance expense and construction work in progress. During the year ended December 31, 2025, depreciation expense associated with transportation equipment was $23,521,291.

(d) Concept: DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments

Generally, PacifiCorp records the depreciation expense of asset retirement obligations as a regulatory asset or liability.

(e) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges


FERC Sub Acct			Description
315.35			Communication Equipment - Mobile Radios - Steam
334.35			Communication Equipment - Mobile Radios - Hydro
338.00			Land - Solar
338.02			Structures And Improvements - Solar
338.04			Solar Panels
338.05			Collector System - Solar
338.07			Inverters - Solar
338.08			Accessory Electric Equipment - Solar
338.19			Land - Wind
338.35			Communication Equipment - Mobile Radios - Wind
338.37			Wind Turbines - Generators
338.38			Water Rights - Wind
339.00			Land - Other Renewables
339.01			Land Rights - Other Renewables
339.02			Structures And Improvements - Other Renewables
339.03			Fuel Holders - Other Renewables
339.04			Boiler Plant Equipment - Other Renewables
339.06			Generators - Other Renewables
339.08			Accessory Electric Equipment - Other Renewables
339.09			Computer Hardware - Other Renewables
339.15			Communication Equipment - Mobile Radios - Other Renewables
345.35			Communication Equipment - Mobile Radios - Other Production
351.21			Computer Software (Major) - Transmission
351.35			Comm Equip - Mobile Radios - Transmission
363.21			Computer Software (Major) - Distribution
363.35			Communication Equipment - Mobile Radios - Distribution
392.19			Over-The-Road Semi-Tractors
397.91			Computer Hardware - General
397.92			Computer Software (Minor) - General
397.93			Computer Software (Major) - General
397.94			Communication Equipment - General
397.95			Communication Equipment - Mobile Radios - General

(f) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges

For a discussion on provisions for depreciation that were made during the year, refer to Note 3 of Notes to Financial Statements in this Form No. 1.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

REGULATORY COMMISSION EXPENSES
Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization. List in columns (f), (g), and (h), expenses incurred during the year which were charged currently to income, plant, or other accounts. Minor items (less than $25,000) may be grouped.
						EXPENSES INCURRED DURING YEAR				AMORTIZED DURING YEAR
						CURRENTLY CHARGED TO
Line No.	RegulatoryCommissionDescription Description (Furnish name of regulatory commission or body the docket or case number and a description of the case) (a)	RegulatoryExpensesAssessedByRegulatoryCommission Assessed by Regulatory Commission (b)	RegulatoryExpensesOfUtility Expenses of Utility (c)	RegulatoryCommissionExpensesAmount Total Expenses for Current Year (b) + (c) (d)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 at Beginning of Year (e)	NameOfDepartmentRegulatoryCommissionExpensesCharged Department (f)	AccountNumberRegulatoryCommissionExpensesCharged Account No. (g)	RegulatoryComissionExpensesIncurredAndCharged Amount (h)	RegulatoryCommissionExpensesDeferredToOtherRegulatoryAssets Deferred to Account 182.3 (i)	DeferredRegulatoryCommissionExpensesAmortizedInContraAccount Contra Account (j)	DeferredRegulatoryCommissionExpensesAmortized Amount (k)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 End of Year (l)
1	Utah Public Service Commission: Annual Fee	6,917,842		6,917,842		Electric	928	6,917,842
2	Utah Public Service Commission: Rate Cases and Proceedings		1,663,540	1,663,540		Electric	928	1,663,540
3	Oregon Public Utility Commission: Annual Fee	8,008,821		8,008,821		Electric	928	8,008,821
4	Oregon Public Utility Commission: Rate Cases and Proceedings		2,036,402	2,036,402		Electric	928	2,036,402
5	Oregon Public Utility Commission: Deferred Intervenor Funding Grants				833,017				450,977	928	2,691,826	1,407,832
6	Wyoming Public Service Commission: Annual Fee	2,366,166		2,366,166		Electric	928	2,366,166
7	Wyoming Public Service Commission: Rate Cases and Proceedings		1,045,591	1,045,591		Electric	928	1,045,591
8	Washington Utilities and Transportation Commission: Annual Fee	1,860,870		1,860,870		Electric	928	1,860,870
9	Washington Utilities and Transportation Commission: Rate Cases and Proceedings		626,938	626,938		Electric	928	626,938
10	Washington Utilities and Transportation Commission: Deferred Intervenor Funding Grants				178,376				148,240	928		326,616
11	Idaho Public Utilities Commission: Annual Fee	721,502		721,502		Electric	928	721,502
12	Idaho Public Utilities Commission: Rate Cases and Proceedings		82,779	82,779		Electric	928	82,779
13	Idaho Public Utilities Commission: Deferred Intervenor Funding Grants				40,000				27,247		10,000	57,247
14	California Public Utilities Commission: Annual Fee	4,626		4,626		Electric	928	4,626
15	California Public Utilities Commission: Rate Cases and Proceedings		2,690,612	2,690,612		Electric	928	2,690,612
16	California Public Utilities Commission: Deferred Intervenor Funding Grants				538,229				26,660	928	49,472	515,417
17	California Environmental Protection Agency: Industry Compliance Fee		31,995	31,995		Electric	928	31,995
18	Multi-State: Rate Cases and Proceedings		35,409	35,409		Electric	928	35,409
19	Multi-State: Other Regulatory		230,035	230,035		Electric	928	230,035
20	Federal Energy Regulatory Commission: Annual Fee	3,452,899		3,452,899		Electric	928	3,452,899
21	Federal Energy Regulatory Commission: Annual Fee - Hydroelectric Plants	3,596,844		3,596,844		Electric	928	3,596,844
22	Federal Energy Regulatory Commission: Transmission Rate Cases		202,193	202,193		Electric	928	202,193
23	Federal Energy Regulatory Commission: Other Regulatory		1,464,227	1,464,227		Electric	928	1,464,227
46	TOTAL	26,929,570	10,045,731	36,975,301	1,589,622			36,975,301	653,124		2,751,298	508,552

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D and D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts). Indicate in column (a) the applicable classification, as shown below: Classifications: Electric R, D and D Performed Internally: Generation hydroelectric Recreation fish and wildlife Other hydroelectric Fossil-fuel steam Internal combustion or gas turbine Nuclear Solar Wind Other renewable Unconventional generation Siting and heat rejection Transmission Overhead Underground Distribution Regional Transmission and Market Operation Energy Storage Environment (other than equipment) Other (Classify and include items in excess of $50,000.) Total Cost Incurred Electric, R, D and D Performed Externally: Research Support to the electrical Research Council or the Electric Power Research Institute Research Support to Edison Electric Institute Research Support to Nuclear Power Groups Research Support to Others (Classify) Total Cost Incurred Include in column (c) all R, D and D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D and D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D and D activity. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e). Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year. If costs have not been segregated for R, D and D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by ""Est."" Report separately research and related testing facilities operated by the respondent.
					AMOUNTS CHARGED IN CURRENT YEAR
Line No.	ResearchDevelopmentAndDemonstrationClassification Classification (a)	ResearchDevelopmentAndDemonstrationDescription Description (b)	ResearchDevelopmentAndDemonstrationCostsIncurredInternally Costs Incurred Internally Current Year (c)	ResearchDevelopmentAndDemonstrationCostsIncurredExternally Costs Incurred Externally Current Year (d)	AccountNumberForResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Account (e)	ResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Amount (f)	ResearchDevelopmentAndDemonstrationExpenditures Unamortized Accumulation (g)
1	A. Electric R, D & D Performed Internally:

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used.
Line No.	Classification (a)	Direct Payroll Distribution (b)	Allocation of Payroll Charged for Clearing Accounts (c)	Total (d)
1	SalariesAndWagesElectricAbstract Electric
2	SalariesAndWagesElectricOperationAbstract Operation
3	SalariesAndWagesElectricOperationProduction Production	106,810,157
4	SalariesAndWagesElectricOperationTransmission Transmission	20,239,321
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
5.1	SalariesAndWagesElectricOperationEnergyStorage Energy Storage
6	SalariesAndWagesElectricOperationDistribution Distribution	53,300,624
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	36,375,391
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	10,764,361
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	52,305,707
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	279,795,561
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	46,949,630
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	15,878,612
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
15.1	SalariesAndWagesElectricMaintenanceEnergyStorage Energy Storage
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	88,795,444
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	1,763,653
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	153,387,339
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	153,759,787
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	36,117,933
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
22.1	SalariesAndWagesElectricEnergyStorage Energy Storage (Enter Total of Lines 5.1 and 15.1)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	142,096,068
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	36,375,391
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	10,764,361
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	54,069,360
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	433,182,900		433,182,900
29	SalariesAndWagesGasAbstract Gas
30	SalariesAndWagesGasOperationAbstract Operation
31	SalariesAndWagesGasOperationProductionManufacturedGas Production - Manufactured Gas
32	SalariesAndWagesGasOperationProductionNaturalGas Production-Nat. Gas (Including Expl. And Dev.)
33	SalariesAndWagesGasOperationOtherGasSupply Other Gas Supply
34	SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing Storage, LNG Terminaling and Processing
35	SalariesAndWagesGasOperationTransmission Transmission
36	SalariesAndWagesGasOperationDistribution Distribution
37	SalariesAndWagesGasCustomerAccounts Customer Accounts
38	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational
39	SalariesAndWagesGasSales Sales
40	SalariesAndWagesGasOperationAdministrativeAndGeneral Administrative and General
41	SalariesAndWagesGasOperation TOTAL Operation (Enter Total of lines 31 thru 40)
42	SalariesAndWagesGasMaintenanceAbstract Maintenance
43	SalariesAndWagesGasMaintenanceProductionManufacturedGas Production - Manufactured Gas
44	SalariesAndWagesGasMaintenanceProductionNaturalGas Production-Natural Gas (Including Exploration and Development)
45	SalariesAndWagesGasMaintenanceOtherGasSupply Other Gas Supply
46	SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing
47	SalariesAndWagesGasMaintenanceTransmission Transmission
48	SalariesAndWagesGasMaintenanceDistribution Distribution
49	SalariesAndWagesGasMaintenanceAdministrativeAndGeneral Administrative and General
50	SalariesAndWagesGasMaintenance TOTAL Maint. (Enter Total of lines 43 thru 49)
51	SalariesAndWagesGasOperationAndMaintenanceAbstract Total Operation and Maintenance
52	SalariesAndWagesGasProductionManufacturedGas Production-Manufactured Gas (Enter Total of lines 31 and 43)
53	SalariesAndWagesGasProductionNaturalGas Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54	SalariesAndWagesGasOtherGasSupply Other Gas Supply (Enter Total of lines 33 and 45)
55	SalariesAndWagesGasStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing (Total of lines 31 thru
56	SalariesAndWagesGasTransmission Transmission (Lines 35 and 47)
57	SalariesAndWagesGasDistribution Distribution (Lines 36 and 48)
58	SalariesAndWagesGasCustomerAccounts Customer Accounts (Line 37)
59	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational (Line 38)
60	SalariesAndWagesGasSales Sales (Line 39)
61	SalariesAndWagesGasAdministrativeAndGeneral Administrative and General (Lines 40 and 49)
62	SalariesAndWagesGasOperationAndMaintenance TOTAL Operation and Maint. (Total of lines 52 thru 61)
63	SalariesAndWagesOtherUtilityDepartmentsAbstract Other Utility Departments
64	SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance Operation and Maintenance
65	SalariesAndWagesOperationsAndMaintenance TOTAL All Utility Dept. (Total of lines 28, 62, and 64)	433,182,900		433,182,900
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	232,493,789		232,493,789
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	232,493,789		232,493,789
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	17,082,389		17,082,389
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	17,082,389		17,082,389
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription Other Accounts (Specify, provide details in footnote):
79	SalariesAndWagesOtherAccountsDescription Fuel Stock	7,415,033		7,415,033
80	SalariesAndWagesOtherAccountsDescription Miscellaneous Other Income Deductions	439,056		439,056
81	SalariesAndWagesOtherAccountsDescription Miscellaneous Non-Operating and Non-Utility	710,214		710,214
82	SalariesAndWagesOtherAccountsDescription Charges to Affiliates	11,578,928		11,578,928
83	SalariesAndWagesOtherAccountsDescription
84	SalariesAndWagesOtherAccountsDescription
85	SalariesAndWagesOtherAccountsDescription
86	SalariesAndWagesOtherAccountsDescription
87	SalariesAndWagesOtherAccountsDescription
88	SalariesAndWagesOtherAccountsDescription
89	SalariesAndWagesOtherAccountsDescription
90	SalariesAndWagesOtherAccountsDescription
91	SalariesAndWagesOtherAccountsDescription
92	SalariesAndWagesOtherAccountsDescription
93	SalariesAndWagesOtherAccountsDescription
94	SalariesAndWagesOtherAccountsDescription
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	20,143,231		20,143,231
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	702,902,309		702,902,309

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

COMMON UTILITY PLANT AND EXPENSES
Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Electric Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation. Give date of approval by the Commission for use of the common utility plant classification and reference to the order of the Commission or other authorization.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchase Power, respectively.
Line No.	Description of Item(s) (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1	Energy
2	Net Purchases (Account 555)		104,255	635,358	1,325,237
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)
4	Transmission Rights
5	Ancillary Services
6	Other Items (list separately)
7	Energy Imbalance Market (Account 555)	39,718,032	51,253,125	74,938,104	95,099,780
46	TOTAL	39,718,032	51,148,870	74,302,746	93,774,543

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff. In columns for usage, report usage-related billing determinant and the unit of measure. On Line 1 columns (b), (c), (d), and (e) report the amount of ancillary services purchased and sold during the year. On Line 2 columns (b), (c), (d), and (e) report the amount of reactive supply and voltage control services purchased and sold during the year. On Line 3 columns (b), (c), (d), and (e) report the amount of regulation and frequency response services purchased and sold during the year. On Line 4 columns (b), (c), (d), and (e) report the amount of energy imbalance services purchased and sold during the year. On Lines 5 and 6, columns (b), (c), (d), and (e) report the amount of operating reserve spinning and supplement services purchased and sold during the period. On Line 7 columns (b), (c), (d), and (e) report the total amount of all other types ancillary services purchased or sold during the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
		Amount Purchased for the Year			Amount Sold for the Year
		Usage - Related Billing Determinant			Usage - Related Billing Determinant
Line No.	Type of Ancillary Service (a)	Number of Units (b)	Unit of Measure (c)	Dollar (d)	Number of Units (e)	Unit of Measure (f)	Dollars (g)
1	Scheduling, System Control and Dispatch				151,492,854	MWh	14,740,058
2	Reactive Supply and Voltage	124,343,629	MWh	8,685,015	157,853,702	MWh	10,312,195
3	Regulation and Frequency Response	159,132,042	MWh	33,020,400	180,931,725	MWh	40,377,257
4	Energy Imbalance				2,430,892	MWh	80,543,940
5	Operating Reserve - Spinning	112,634,800	MWh	18,922,647	126,308,024	MWh	21,215,646
6	Operating Reserve - Supplement	112,634,800	MWh	18,922,647	128,418,571	MWh	21,569,585
7	Other
8	Total (Lines 1 thru 7)	508,745,271	MWh	79,550,709	747,435,768	MWh	188,758,681

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Firm Network Service for Self (e)	Firm Network Service for Others (f)	Long-Term Firm Point-to-point Reservations (g)	Other Long-Term Firm Service (h)	Short-Term Firm Point-to-point Reservation (i)	Other Service (j)
	NAME OF SYSTEM: 0
1	January	16,729	23	8	9,184	696	3,443		1,948	1,458
2	February	17,841	12	8	9,496	707	3,443		2,806	1,389
3	March	15,239	18	8	8,132	527	3,453		1,925	1,202
4	Total for Quarter 1				26,812	1,930	10,339		6,679	4,049
5	April	14,112	1	9	7,905	468	4,200		395	1,144
6	May	17,394	30	18	9,542	398	4,200		1,517	1,737
7	June	20,167	30	18	11,222	474	4,831		1,587	2,053
8	Total for Quarter 2				28,669	1,340	13,231		3,499	4,934
9	July	21,038	14	18	11,393	506	4,827		2,248	2,064
10	August	20,480	12	17	11,284	496	4,827		1,866	2,007
11	September	19,322	2	17	10,327	440	4,826		1,869	1,860
12	Total for Quarter 3				33,004	1,442	14,480		5,983	5,931
13	October	15,390	2	18	7,823	355	4,756		1,110	1,346
14	November	15,220	24	18	8,176	462	4,622		769	1,191
15	December	16,108	29	18	8,606	619	4,622		1,028	1,233
16	Total for Quarter 4				24,605	1,436	14,000		2,907	3,770
17	Total				(a) 113,090	(b) 6,148	(c) 52,050		(d) 19,068	(e) 18,684

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: FirmNetworkServiceForSelf

For the year being reported, the Net System Load information was compiled using metering and/or scheduling data. Reflects actual peak net system load for self at time of Transmission System Peak. Peak load includes behind-the-meter generation.

(b) Concept: FirmNetworkServiceForOther

For the year being reported, the Net System Load information was compiled using metering and/or scheduling data. Reflects actual peak of customers' load at time of Transmission System Peak.

For the year being reported, the Net System Load information was compiled using reservations in OASIS at time of Transmission System Peak. Long-term firm point-to-point reservations have been adjusted so that the monthly megawatt reservations represent an amount at system input as measured by the transmission system loss factor. This adjustment has been made to ensure that transmission rates are designed fairly and in a non-discriminatory manner and is consistent with the system input measurement utilized for other long-term firm users of PacifiCorp�s transmission system, including network service.

(d) Concept: ShortTermFirmPointToPointReservations

For the year being reported, the Net System Load information was compiled using reservations in OASIS at time of Transmission System Peak.

(e) Concept: OtherService

For the year being reported, the Net System Load information was compiled using metering, scheduling and/or contractual data. Reflects actual peak and/or contractual demands of customers' load at time of Transmission System Peak.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

Monthly ISO/RTO Transmission System Peak Load
Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (i) by month the system�s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f). Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Import into ISO/RTO (e)	Exports from ISO/RTO (f)	Through and Out Service (g)	Network Service Usage (h)	Point-to-Point Service Usage (i)	Total Usage (j)
	NAME OF SYSTEM: 0
1	January
2	February
3	March
4	Total for Quarter 1				0	0	0	0	0	0
5	April
6	May
7	June
8	Total for Quarter 2				0	0	0	0	0	0
9	July
10	August
11	September
12	Total for Quarter 3				0	0	0	0	0	0
13	October
14	November
15	December
16	Total for Quarter 4				0	0	0	0	0	0
17	Total Year to Date/Year				0	0	0	0	0	0

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

2026-04-14

Year/Period of Report

End of:

2025

ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line No.	Item (a)	MegaWatt Hours (b)	Line No.	Item (a)	MegaWatt Hours (b)
1	SOURCES OF ENERGY		21	DISPOSITION OF ENERGY
2	Generation (Excluding Station Use):		22	Sales to Ultimate Consumers (Including Interdepartmental Sales)	59,211,862
3	Steam	29,953,836	23	Requirements Sales for Resale (See instruction 4, page 311.)	319,696
4	Nuclear		24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	4,034,199
5	Hydro-Conventional	2,573,354	25	Energy Furnished Without Charge
6	Hydro-Pumped Storage		26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)	(a) 201,242
6.1	Solar		27	Total Energy Losses	4,576,801
6.2	Wind		27.1	Total Energy Stored
6.3	Other Renewable		28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	68,343,800
7	Other	16,987,270
8	Less Energy for Pumping	3,850
9	Net Generation (Enter Total of lines 3 through 8)	49,510,610
10	Purchases (other than for Energy Storage)	20,835,153
10.1	Purchases for Energy Storage
11	Power Exchanges:
12	Received	6,286,894
13	Delivered	8,376,132
14	Net Exchanges (Line 12 minus line 13)	2,089,238
15	Transmission For Other (Wheeling)
16	Received	17,411,015
17	Delivered	17,331,671
18	Net Transmission for Other (Line 16 minus line 17)	79,344
19	Transmission By Others Losses	7,931
20	TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)	68,343,800

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

2026-04-14

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: InternalUseEnergy

For metered locations only.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

MONTHLY PEAKS AND OUTPUT
Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. Report in column (b) by month the system�s output in Megawatt hours for each month. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. Report in column (d) by month the system�s monthly maximum megawatt load (60 minute integration) associated with the system. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.	MonthAxis Month (a)	EnergyActivity Total Monthly Energy (b)	NonRequiredSalesForResaleEnergy Monthly Non-Requirement Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak - Megawatts (d)	DayOfMonthlyPeak Monthly Peak - Day of Month (e)	HourOfMonthlyPeak Monthly Peak - Hour (f)
	NAME OF SYSTEM: 0
29	January	6,087,196	328,550	8,979	28	8
30	February	5,379,077	257,858	9,302	12	8
31	March	5,428,899	367,215	7,941	18	8
32	April	4,866,601	186,438	7,743	1	9
33	May	5,258,312	188,631	9,352	30	18
34	June	5,804,978	202,643	11,042	30	18
35	July	6,648,539	307,801	11,263	14	18
36	August	6,377,201	286,686	11,108	12	18
37	September	5,442,306	292,860	10,159	2	18
38	October	5,575,767	603,434	7,655	2	18
39	November	5,437,244	446,681	7,973	24	18
40	December	6,037,680	565,402	8,463	1	18
41	Total	68,343,800	4,034,199

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

Steam Electric Generating Plant Statistics

1. Report data for plant in Service only.
2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.
3. Indicate by a footnote any plant leased or operated as a joint facility.
4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.
5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant.
6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mcf.
7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.
8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
9. Items under Cost of Plant are based on USofA accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.
10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants.
11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.
12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.

Line No.	Item (a)	Plant Name: Chehalis	Plant Name: (a) Colstrip	Plant Name: (b) Craig	Plant Name: Currant Creek	Plant Name: Dave Johnston	Plant Name: Gadsby Peakers	Plant Name: Gadsby Steam	Plant Name: (c) Hayden	Plant Name: (d) Hermiston	Plant Name: (e) Hunter - Total Plant	Plant Name: (f) Hunter Unit No. 1	Plant Name: (g) Hunter Unit No. 2	Plant Name: Hunter Unit No. 3	Plant Name: Huntington	Plant Name: (h) Jim Bridger	Plant Name: Lake Side	Plant Name: Lake Side 2	Plant Name: (i) Naughton	Plant Name: (j) Wyodak
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)	Combined Cycle	Steam	Steam	Combined Cycle	Steam	Gas Turbine	Steam	Steam	Combined Cycle	Steam	Steam	Steam	Steam	Steam	Steam	Combined Cycle	Combined Cycle	Steam	Steam
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)	Outdoor	Conventional	Outdoor Boiler	Outdoor	Semi-Outdoor	Outdoor	Outdoor	Outdoor Boiler	Outdoor	Outdoor Boiler	Outdoor Boiler	Outdoor Boiler	Outdoor Boiler	Outdoor Boiler	Outdoor Boiler	Outdoor	Outdoor	Outdoor Boiler	Conventional
3	YearPlantOriginallyConstructed Year Originally Constructed	2003	1984	1979	2005	1959	2002	1951	1965	1996	1978	1978	1980	1983	1974	1974	2007	2014	1963	1978
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	2003	1986	1980	2006	1972	2002	1955	1976	1996	1983	1978	1980	1983	1977	1979	2007	2014	1971	1978
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)	593.30	155.61	172.13	566.90	816.77	181.05	251.64	81.25	279.56	1,247.78	457.73	294.46	495.59	1,015.50	1,550.65	591.30	655.20	707.20	289.66
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)	475	152	147	557	710	101	204	74	235	1,110	408	264	439	890	1,406	564	627	642	266
7	PlantHoursConnectedToLoad Plant Hours Connected to Load	7,936	8,493	8,760	8,429	8,687	240	3,463	8,009	8,184	8,760	8,595	8,564	8,234	8,760	8,760	6,764	8,614	8,760	7,742
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)	518	148	161	550	755	120	238	77	237	1,158	418	269	471	909	1,413	558	645	647	268
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water	506	148	161	556	755	122	238	77	240	1,158	418	269	471	909	1,413	562	656	647	268
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water	477	148	161	524	745	119	238	77	231	1,158	418	269	471	909	1,413	546	631	647	266
11	PlantAverageNumberOfEmployees Average Number of Employees	18	(k) 0	(l) 0	17	175	(m) 0	28	(n) 0	(o) 0	184	(p) 0	(q) 0	(r) 0	139	238	33	(s) 0	102	56
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh	2,337,422,000	883,917,000	853,405,000	2,803,076,000	4,273,471,000	1,551,000	228,499,000	406,209,000	1,564,991,000	5,962,783,000	2,188,257,000	1,509,733,000	2,264,793,000	4,260,189,000	5,139,624,000	2,510,959,000	3,538,613,000	2,281,351,000	1,618,240,000
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights	3,730,527	1,788,644	137,086	3,403,277	10,447,572		1,252,090	683,069	796,929	29,626,009	9,679,900	9,679,900	10,266,209	2,377,564	1,193,761	14,532,275	16,794,626	1,440,823	210,526
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements	24,849,316	70,095,163	38,880,237	44,436,060	170,501,958	4,270,571	15,564,798	18,024,330	12,921,287	220,252,713	66,745,232	56,095,530	97,411,951	132,009,072	193,028,134	35,844,247	53,395,841	88,077,027	54,403,801
15	CostOfEquipmentSteamProduction Equipment Costs	341,696,908	182,904,393	187,489,033	314,116,348	936,190,297	84,563,327	77,637,600	98,962,546	176,295,549	1,162,569,044	414,413,472	267,603,602	480,551,970	812,867,499	1,273,395,896	398,018,061	592,021,219	380,678,828	431,778,701
16	AssetRetirementCostsSteamProduction Asset Retirement Costs	3,567,817	6,514,320	4,535,419	324,422	27,130,792		1,503,779	2,459,846	2,296,269	7,972,500	2,657,500	2,657,500	2,657,500	6,419,189	31,322,862			6,339,505	677,254
17	CostOfPlant Total Cost (10-23)	373,844,568	261,302,520	231,041,775	362,280,107	1,144,270,619	88,833,898	95,958,267	120,129,791	192,310,034	1,420,420,266	493,496,104	336,036,532	590,887,630	953,673,324	1,498,940,653	448,394,583	662,211,686	476,536,183	487,070,282
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including	630.111	1,679.214	1,342.252	639.055	1,400.970	490.659	381.332	1,478.521	687.903	1,138.358	1,078.138	1,141.196	1,192.291	939.117	966.653	758.320	1,010.702	673.835	1,681.524
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr	179,547	44,524	338,726	65,192	18,559		145,203	156,539		196	71	46	80	4,818	15,033,665	121,252	140,121	398,346	10,654
20	FuelSteamPowerGeneration Fuel	112,847,095	(t) 21,214,405	23,545,930	82,958,883	61,283,761	391,873	16,956,032	12,154,052	26,436,759	222,303,016	82,854,503	55,065,696	84,382,818	184,992,664	(u) 203,345,468	77,196,708	103,611,998	86,265,730	30,789,474
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)
22	SteamExpensesSteamPowerGeneration Steam Expenses		986,033	2,680,870		646,656		290,049	1,561,906		25,315,220	8,524,574	7,171,686	9,618,959	14,652,395	14,738,916			7,501,143	5,735,193
23	SteamFromOtherSources Steam From Other Sources
24	SteamTransferredCredit Steam Transferred (Cr)
25	ElectricExpensesSteamPowerGeneration Electric Expenses	2,803,158	5,944	798,670	2,542,598		657,722		366,071	6,676,092	12,839	73,512	111,702	51,029			3,068,845	5,596,317	8,648
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses	689,262	4,176,655	882,253	675,558	22,343,002		5,381,200	247,233	196,405	6,715,737	2,583,245	293,364	3,839,128	12,407,541	18,831,827	549,980	636,168	11,503,487	4,047,943
27	RentsSteamPowerGeneration Rents					78,848									3,145	341,893	16,590	19,172	14,349	29,031
28	Allowances Allowances
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering		310,472	561,290					177,762		116,218	41,959	26,993	47,265	991,632	563,824			1,072,645
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures	109,496	605,216	278,525	516,262	4,099,251	61,886	141,866	177,505		2,897,342	984,238	815,994	1,097,110	2,405,994	7,222,093	976,522	897,686	1,833,516	130,130
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant		5,154,465	2,204,847		13,564,325		1,982,840	794,916		11,411,166	3,645,219	2,872,547	4,893,400	6,923,808	23,540,990			8,933,055	3,137,736
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant	3,644,343	884,595	225,224	1,849,312	11,105,494	378,797	1,748,563	263,119	1,096,466	3,302,534	1,216,366	906,266	1,179,903	3,201,218	10,475,571	11,241,818	384,255	4,870,606	1,240,650
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant		782,299	696,110	64,079	2,341,443	130,882	1,019,915	268,014		2,713,459	897,254	613,650	1,202,555	1,021,364	2,772,878	15,997	12,271	3,296,020	100,842
34	PowerProductionExpensesSteamPower Total Production Expenses	120,272,901	34,152,720	32,212,445	88,671,884	115,481,339	1,621,160	27,665,668	16,167,117	34,405,722	274,761,657	100,673,775	67,877,852	106,210,029	226,604,579	259,203,471	93,187,712	110,529,478	125,697,545	45,221,653
35	ExpensesPerNetKilowattHour Expenses per Net kWh	0.0515	0.0386	0.0377	0.0316	0.0270	1.0452	0.1211	0.0398	0.0220	0.0461	0.0460	0.0450	0.0469	0.0532	0.0504	0.0371	0.0312	0.0551	0.0279

35	FuelKindAxis Plant Name	Chehalis	Colstrip	Colstrip	Craig	Craig	Craig	Currant Creek	Dave Johnston	Dave Johnston	Gadsby Peakers	Gadsby Steam	Hayden	Hayden	Hermiston	Hunter - Total Plant	Hunter - Total Plant	Hunter Unit No. 1	Hunter Unit No. 1	Hunter Unit No. 2	Hunter Unit No. 2	Hunter Unit No. 3	Hunter Unit No. 3	Huntington	Huntington	Jim Bridger	Jim Bridger	Jim Bridger	Lake Side	Lake Side 2	Naughton	Naughton	Wyodak	Wyodak
36	FuelKind Fuel Kind	Gas	Coal	(v) Oil	Coal	Gas	(w) Oil	Gas	Coal	(x) Oil	Gas	Gas	Coal	(y) Oil	Gas	Coal	(z) Oil	Coal	(aa) Oil	Coal	(ab) Oil	Coal	(ac) Oil	Coal	(ad) Oil	Coal	Gas	(ae) Oil	Gas	Gas	Coal	Gas	Coal	(af) Oil
37	FuelUnit Fuel Unit	Mcf	T	Boe	T	Mcf	Boe	Mcf	T	Boe	Mcf	Mcf	T	Boe	Mcf	T	Boe	T	Boe	T	Boe	T	Boe	T	Boe	T	Mcf	Boe	Mcf	Mcf	T	Mcf	T	Boe
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned	16,074,133	554,841	992	475,956	888		19,873,526	2,889,680	12,961	82,473	3,613,754	197,591	1,285	11,236,946	2,746,378	20,391	1,031,724	1,588	687,219	497	1,027,435	18,306	2,044,741	4,616	2,025,698	20,175,688	13,139	17,366,484	24,274,990	998,198	6,778,442	1,330,590	4,963
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)	1,104	8,637	140,000	9,650		133,709	1,056	8,278	138,000	1,044	1,045	11,268	129,256	1,050	11,557	138,000	11,579	138,000	11,660	138,000	11,466	138,000	11,526	138,000	9,163	1,030	138,000	1,050	1,050	10,037	1,048	8,035	138,000
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year	7.020	35.075	158.547	44.238			4.174	20.377	113.542	4.752	4.692	50.653	118.746	2.353	80.141	109.079							88.677	122.073	55.494	3.835	126.490	4.445	4.268	53.368	4.704	22.608	118.709
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned	7.020	37.952	158.547	49.462			4.174	20.699	113.542	4.752	4.692	60.739	118.746	2.353	80.134	109.079	80.139		80.051		80.185		90.197	122.073	61.368	3.835	126.490	4.445	4.268	54.481	4.704	22.697	118.709
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	6.357	2.197	26.964	2.563	4.510		3.953	1.250	19.590	4.552	4.491	2.695	21.873	2.241	3.467	18.820	3.461	18.814	3.433	18.353	3.497	18.833	3.913	21.061	3.349	3.725	21.824	4.233	4.065	2.714	4.490	1.412	20.481
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen	0.048	0.024		0.028			0.030	0.014		0.253	0.074	0.030		0.017	0.037		0.038		0.036		0.036	0.001	0.043		0.024	0.015		0.031	0.029	0.024	0.014	0.019
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation	7,594.738	10,843.585	6.596	10,763.914			7,487.567	11,194.659	17.579	55,503.546	16,522.768	10,961.792	17.168	7,539.499	10,645.859	19.821	10,918.645	4.206	10,614.790	1.909	10,403.002	46.849	11,063.812	6.281	7,223.172	4,041.741	14.817	7,262.075	7,203.537	8,783.281	3,112.758	13,214.128	17.776

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: PlantName

The Colstrip Plant is operated by Talen Montana, LLC and is jointly owned. PacifiCorp owns a 10.0% share of Colstrip Plant Unit Nos. 3 and 4. Data reported represents PacifiCorp's share.

(b) Concept: PlantName

The Craig Plant is operated by Tri-State Generation and Transmission Association, Inc. and is jointly owned. PacifiCorp owns a 19.28% share of Craig Plant Unit Nos. 1 and 2 and 12.86% of common facilities. Data reported represents PacifiCorp's share.

The Hayden Plant is operated by Public Service Company of Colorado and is jointly owned. PacifiCorp owns a 24.5% (45 MWh) share of Hayden Unit No. 1, a 12.6% (33 MWh) share of Hayden Unit No. 2 and 17.5% of common facilities. Data reported represents PacifiCorp's share.

(d) Concept: PlantName

The Hermiston Plant is operated by Hermiston Generating Company, L.P. and is jointly owned. PacifiCorp owns a 50.0% share of the Hermiston Plant. Data reported represents PacifiCorp's share.

(e) Concept: PlantName

Refer to Hunter Unit Nos. 1, 2 and 3 for each unit's plant statistics.

(f) Concept: PlantName

Hunter Unit No. 1 is operated by PacifiCorp and is jointly owned by PacifiCorp and Utah Municipal Power Agency with an undivided interest of 93.75% and 6.25%, respectively. Data reported represents PacifiCorp's share. Costs that were billed to minority owners for the operations and maintenance (excluding fuel) of this unit for calendar year 2025 were $1.4 million and were primarily credited to Account 506, Miscellaneous steam power expenses.

(g) Concept: PlantName

Hunter Unit No. 2 is operated by PacifiCorp and is jointly owned by PacifiCorp, Deseret Power Electric Cooperative and Utah Associated Municipal Power Systems, each with an undivided interest of 60.31%, 25.108% and 14.582%, respectively. Data reported represents PacifiCorp's share. Costs that were billed to minority owners for the operations and maintenance (excluding fuel) of this unit for calendar year 2025 were $8.2 million and were primarily credited to Account 506, Miscellaneous steam power expenses.

(h) Concept: PlantName

The Jim Bridger Plant is operated by PacifiCorp and is jointly owned by PacifiCorp and Idaho Power Company with an undivided interest of 66.67% and 33.33%, respectively. Data reported represents PacifiCorp's share. Costs that were billed to minority owners for the operations and maintenance (excluding fuel) of this plant for calendar year 2025 were $28.2 million and were primarily credited to Account 506, Miscellaneous steam power expenses.

(i) Concept: PlantName

Naughton Units 1 and 2 were removed from service as coal-fueled generating resources on December 31, 2025 and will be converted to natural gas-fueled generation resources that are expected to be completed in 2026.

(j) Concept: PlantName

The Wyodak Plant is operated by PacifiCorp and is jointly owned by PacifiCorp and Black Hills Corporation with an undivided interest of 80% and 20%, respectively. Data reported represents PacifiCorp's share. Costs that were billed to minority owners for the operations and maintenance (excluding fuel) of this plant for calendar year 2025 were $4.4 million and were primarily credited to Account 506, Miscellaneous steam power expenses.

(k) Concept: PlantAverageNumberOfEmployees

PacifiCorp does not have employees at this plant.

(l) Concept: PlantAverageNumberOfEmployees

PacifiCorp does not have employees at this plant.

(m) Concept: PlantAverageNumberOfEmployees

Refer to the Gadsby Steam Plant for the average number of employees.

(n) Concept: PlantAverageNumberOfEmployees

PacifiCorp does not have employees at this plant.

(o) Concept: PlantAverageNumberOfEmployees

PacifiCorp does not have employees at this plant.

(p) Concept: PlantAverageNumberOfEmployees

Refer to Hunter - Total Plant for the average number of employees.

(q) Concept: PlantAverageNumberOfEmployees

Refer to Hunter - Total Plant for the average number of employees.

(r) Concept: PlantAverageNumberOfEmployees

Refer to Hunter - Total Plant for the average number of employees.

(s) Concept: PlantAverageNumberOfEmployees

Refer to Lake Side Plant for the average number of employees.

(t) Concept: FuelSteamPowerGeneration

Amount includes intercompany profits.

(u) Concept: FuelSteamPowerGeneration

Amount includes intercompany profits.

(v) Concept: FuelKind

Fuel oil is used for start-up purposes.

(w) Concept: FuelKind

Fuel oil is used for start-up purposes.

(x) Concept: FuelKind

Fuel oil is used for start-up purposes.

(y) Concept: FuelKind

Fuel oil is used for start-up purposes.

(z) Concept: FuelKind

Fuel oil is used for start-up purposes.

(aa) Concept: FuelKind

Fuel oil is used for start-up purposes.

(ab) Concept: FuelKind

Fuel oil is used for start-up purposes.

(ac) Concept: FuelKind

Fuel oil is used for start-up purposes.

(ad) Concept: FuelKind

Fuel oil is used for start-up purposes.

(ae) Concept: FuelKind

Fuel oil is used for start-up purposes.

(af) Concept: FuelKind

Fuel oil is used for start-up purposes.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

Renewable Generating Plant Statistics

1. Report data for plant in Service only.
2. Report in this page renewable plants of 10,000 Kw or more.
3. Indicate by a footnote any plant leased or operated as a joint facility.
4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.
5. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.

Line No.	Item (a)	Plant Name: Blundell	Plant Name: Cedar Springs II	Plant Name: Dunlap Ranch 1	Plant Name: Ekola Flats	Plant Name: Foote Creek I	Plant Name: Foote Creek III	Plant Name: Foote Creek IV	Plant Name: Glenrock	Plant Name: Glenrock III	Plant Name: Goodnoe Hills	Plant Name: High Plains	Plant Name: Leaning Juniper 1	Plant Name: Marengo	Plant Name: Marengo II	Plant Name: McFadden Ridge I	Plant Name: Pryor Mountain	Plant Name: Rock Creek I	Plant Name: Rock Creek II	Plant Name: Rock River I	Plant Name: Rolling Hills	Plant Name: Seven Mile Hill	Plant Name: Seven Mile Hill II	Plant Name: TB Flats
1	PlantKind Kind of Plant (Solar, Wind, Biomass, etc.)	Steam - Geothermal	(a) Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind	Wind
2	PlantConstructionType Type of Constr (PV Tracking, Offshore, Boiler, etc)	Indoor	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore	Onshore
3	YearPlantOriginallyConstructed Year Originally Constructed	1984	2020	2010	2020	1999	2023	2023	2008	2009	2008	2009	2006	2007	2008	2009	2021	2025	2025	2024	2009	2008	2008	2021
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	2007	2020	2020	2020	2021	2023	2023	2019	2019	2019	2019	2019	2020	2020	2019	2021	2025	2025	2024	2019	2019	2019	2021
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)	38.10	198.88	136.90	250.90	48.00	25.20	21.00	119.30	46.00	103.40	122.10	110.38	156.00	78.00	35.15	239.80	195.20	402.60	53.58	115.80	122.10	24.05	503.20
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)	37	238	111	189	50	23	17	108	44	95	103	101	154	77	33	191	187	371	53	106	105	23	468
7	PlantHoursConnectedToLoad Plant Hours Connected to Load	8,609	8,230	7,400	7,308	8,064	7,955	7,853	7,982	7,625	7,074	7,467	6,353	6,506	6,813	7,139	7,841	7,404	2,646	8,083	7,830	7,522	7,173	7,622
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)	32	199	111	250	43	25	17	100	39	94	99	100	156	78	29	240	190	400	50	100	99	20	500
9	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - KWh	271,209,000	652,391,000	416,651,000	736,070,000	195,112,000	104,161,000	81,749,000	340,991,000	128,234,000	268,258,000	341,222,000	269,522,000	400,192,000	212,433,000	104,770,000	750,811,000	407,378,000	241,554,000	235,293,000	295,088,000	378,180,000	80,281,000	1,361,919,000
10	CostOfLandAndLandRightsRenewableProduction Cost of Plant: Land and Land Rights	41,195,596		5,366,045		5,656,118	2,208,061	1,840,051	308,387	118,909		23,248				6,692	1,754,573			2,968,990	299,340
11	CostOfStructuresAndImprovementsRenewableProduction Structures and Improvements	8,524,406	16,389,616	21,298,125	20,570,505	5,963,613	3,628,921	3,027,658	21,563,815	11,885,681	24,642,776	17,585,812	16,766,767	17,474,856	12,746,211	4,295,472	45,396,618	79,443,039	143,114,335	6,505,303	29,549,324	18,745,022	4,282,192	32,724,681
12	CostOfSolarPanelsWindTurbinesAndGeneratorsRenewableProduction Solar Panels, Wind Turbines and Generators	35,970,982	208,629,324	177,332,208	261,625,752	59,328,743	32,439,887	27,054,581	158,722,147	63,521,800	120,335,142	158,782,584	148,343,217	179,538,964	90,977,698	44,225,234	315,749,336	262,961,118	530,342,405	72,019,263	153,366,141	157,067,100	31,526,600	506,649,688
13	CostOfFuelHoldersRenewableProduction Fuel Holders	58,511,077
14	CostOfBoilersRenewableProduction Boilers	2,604,945
15	CostOfCollectorSystemRenewableProduction Collector System		28,416,936	9,336,353	27,015,111	9,536,646	1,316,092	1,095,558	9,224,116	4,654,000	8,463,521	8,099,980	8,479,170	11,849,426	4,542,535	2,548,736	35,340,863	27,927,100	76,676,045	7,583,216	10,580,367	8,618,429	1,944,013	46,117,161
16	CostOfGeneratorStepupTransformersRenewableProduction Generator Step-up Transformers (GSU)		2,050,414	3,230,052	2,643,725	601,089	334,358	277,446	2,423,350	1,126,834	1,331,499	3,389,629	1,431,464	2,445,166	1,441,439	948,426	3,887,745	5,615,709	11,357,213	1,966,719	2,578,256	2,390,172	581,032	5,137,148
17	CostOfInvertersRenewableProduction Inverters						668,717	554,893										2,928,767	5,923,140	1,493,950
18	CostOfOtherAccessoryElectricalEquipmentRenewableProduction Other Accessory Electrical Equipment	8,552,453	938,685	236,371	460,113	75,577			1,104,811	405,036	825,042	745,038	1,588,904	1,406,432	533,569	62,491	496,557				1,622,107	674,091	137,541	1,567,087
19	CostOfComputerHardwareRenewableProduction Computer Hardware	5,051	72,396	11,338	7,982	11,306	5,936	4,946			21,840	9,064	15,066	10,786	5,393	2,609	93,269							7,987
20	CostOfComputerSoftwareRenewableProduction Computer Software	7,387	228,553		31,252															4,907
21	CostOfCommunicationEquipmentRenewableProduction Communication Equipment	1,006,471	80,336	487,585	86,820	118,848			76,232	29,394	127,464	383,882	170,999	115,688	98,189	97,175	286,245			605,144	73,995	103,122	20,312	89,720
22	CostOfMiscellaneousPowerPlantEquipmentRenewableProduction Miscellaneous Power Plant Equipment	1,351,533	1,523,374	164,087	2,984,390	1,008,148	272,145	226,787	716,768	84,483	237,218	88,221	89,109	145,597	246,420	25,397	1,528,147	625,081	1,574,869	1,408,852	872,174	678,017	135,618	3,770,493
23	AssetRetirementCostsRenewableProduction Asset Retirement Costs	6,002,449	5,517,145	3,089,468	4,578,037	1,514,402	278,647	232,205	3,174,596	1,175,030	2,030,231	2,671,162	2,919,366	2,592,416	1,288,287	888,281	6,519,738	1,643,162	2,814,438	1,277,344	2,861,539	2,047,931	403,380	8,773,468
24	CostOfPlant Total Cost (10-23)	163,732,350	263,846,779	220,551,632	320,003,687	83,814,490	41,152,764	34,314,125	197,314,222	83,001,167	158,014,733	191,778,620	179,804,062	215,579,331	111,879,741	53,100,513	411,053,091	381,143,976	771,802,445	95,833,688	201,803,243	190,323,884	39,030,688	604,837,433
25	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 24/5) Including	4,297	1,327	1,611	1,275	1,746	1,633	1,634	1,654	1,804	1,528	1,571	1,629	1,382	1,434	1,511	1,714	1,953	1,917	1,789	1,743	1,559	1,623	1,202
26	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr					10,149
27	GenerationAndOtherPlantOperatingExpensesRenewableProduction Generation and Other Plant Operating Expenses		291,503	338,464	240,318	80,127	16,588	11,260	318,738	156,962	196,124	106,555	296,152	352,532	165,482	29,864	272,376	1,687		103,530	75,101	192,618	42,773	162,952
28	FuelRenewableGeneration Fuel
29	SteamExpensesRenewableGeneration Steam Expenses	5,669,107
30	ElectricExpensesRenewableGeneration Electric Expenses
31	MiscellaneousSteamPowerExpensesRenewableGeneration Misc Steam Power Expenses	1,694,376
32	RentsRenewableGeneration Rents					380,057			147,975		497,105		534,422	1,165,565	676,920					227,982
33	EnvironmentalCreditsRenewableGeneration Environmental Credits
34	MaintenanceSupervisionAndEngineeringRenewableGeneration Maintenance Supervision and Engineering
35	MaintenanceOfStructuresAndEquipmentRenewableGeneration Maintenance of Structures and Equipment	2,721				1,092,928					1,701,219		1,819,717							899,389
36	MaintenanceOfBoilerPlantRenewableGeneration Maintenance of Boiler Plant	910
37	MaintenanceOfElectricPlantRenewableGeneration Maintenance of Electric Plant	10,264
38	MaintenanceOfComputerHardwareRenewableGeneration Maintenance of Computer Hardware																161
39	MaintenanceOfComputerSoftwareRenewableGeneration Maintenance of Computer Software
40	MaintenanceOfCommunicationEquipmentRenewableGeneration Maintenance of Communication Equipment			1,244	443	9,190			147,658	122		5,716	11,112	1,329	664	1,645	1,207			902		944	186	443
41	MaintenanceOfMiscellaneousRenewablePlant Maintenance of Misc Plant	1,377,868	5,261,405	2,134,970	3,594,837	401,441	1		2,517,949	1,003,498	65,091	3,614,583	51,870	2,686,643	1,343,321	1,025,733	4,928,484	1,429,827		13,457	1,761,653	2,055,117	404,796	8,995,855
42	PowerProductionExpensesRenewable Total Production Expenses	8,749,804	5,552,908	2,474,678	3,835,598	1,973,892	16,589	11,260	2,837,004	1,160,582	2,459,539	3,726,854	2,713,273	4,203,411	2,185,059	1,057,242	5,202,228	1,431,514		1,245,260	1,836,754	2,248,679	447,755	9,159,250
43	ExpensesPerNetKilowattHour Expenses per Net KWh

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: PlantKind

This footnote applies to all wind-powered generating facilities with current generation. Common costs for the operation of these facilities are allocated to each plant based upon the unit�s name plate rating. All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

Hydroelectric Generating Plant Statistics

Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings).
If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number.
If net peak demand for 60 minutes is not available, give that which is available specifying period.
If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant.
The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.

Line No.	Item (a)	FERC Licensed Project No. 1927 Plant Name: (a) Clearwater No. 1	FERC Licensed Project No. 1927 Plant Name: Clearwater No. 2	FERC Licensed Project No. 1927 Plant Name: Fish Creek	FERC Licensed Project No. 1927 Plant Name: Lemolo No. 1	FERC Licensed Project No. 1927 Plant Name: Lemolo No. 2	FERC Licensed Project No. 1927 Plant Name: Slide Creek	FERC Licensed Project No. 1927 Plant Name: Soda Springs	FERC Licensed Project No. 1927 Plant Name: Toketee	FERC Licensed Project No. 20 Plant Name: Grace	FERC Licensed Project No. 20 Plant Name: Oneida	FERC Licensed Project No. 20 Plant Name: Soda	FERC Licensed Project No. 2071 Plant Name: Yale	FERC Licensed Project No. 2111 Plant Name: Swift No. 1	FERC Licensed Project No. 2420 Plant Name: Cutler	FERC Licensed Project No. 2630 Plant Name: Prospect No. 2	FERC Licensed Project No. 935 Plant Name: Merwin
1	PlantKind Kind of Plant (Run-of-River or Storage)	(b) Run-of-River	(c) Run-of-River	(d) Run-of-River	(e) Storage	(f) Run-of-River	Run-of-River	Storage (Re-Reg)	(g) Storage	Storage	Storage	Storage	Storage	Storage	Storage	(h) Run-of-River	Storage (Re-Reg)
2	PlantConstructionType Plant Construction type (Conventional or Outdoor)	Outdoor	Outdoor	Outdoor	Outdoor	Outdoor	Outdoor	Outdoor	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional	Conventional
3	YearPlantOriginallyConstructed Year Originally Constructed	1953	1953	1952	1955	1956	1951	1952	1949	1908	1915	1924	1953	1958	1927	1928	1931
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	1953	1953	1952	1955	1956	1951	1952	1950	1923	1920	1924	1953	1958	1927	1928	1958
5	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)	15	26	11	31.99	38.50	18	11	42.50	33	30	14.45	134	240	30	32	136
6	NetPeakDemandOnPlant Net Peak Demand on Plant-Megawatts (60 minutes)	8	13	11	27	28	16	12	31	27	14	8	159	246	21	32	141
7	PlantHoursConnectedToLoad Plant Hours Connect to Load	7,748	7,179	3,742	7,801	7,987	8,009	8,607	8,511	8,419	8,753	5,908	5,387	4,384	4,123	8,760	8,760
8	NetPlantCapabilityAbstract Net Plant Capability (in megawatts)
9	NetPlantCapabilityUnderMostFavorableOperatingConditions (a) Under Most Favorable Oper Conditions	18	31	10	32	39	18	12	45	33	28	14	164	264	29	36	151
10	NetPlantCapabilityUnderMostAdverseOperatingConditions (b) Under the Most Adverse Oper Conditions	18	31	10	32	39	18	12	45	33	28	14	164	264	29	36	151
11	PlantAverageNumberOfEmployees Average Number of Employees	1	1	1	1	1	1	2	1	3	2	3	2	2	3	1	2
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh	34,973,000	30,491,000	29,212,000	120,111,000	149,510,000	57,046,000	51,902,000	208,430,000	82,687,000	39,401,000	16,262,000	472,460,000	534,663,000	41,192,000	180,089,000	422,567,000
13	CostOfPlantAbstract Cost of Plant
14	CostOfLandAndLandRightsHydroelectricProduction Land and Land Rights									74,674	309,259	511,083	8,363,013	20,287,495	3,507,754	105,168	1,955,029
15	CostOfStructuresAndImprovementsHydroelectricProduction Structures and Improvements	1,698,494	2,515,352	1,772,619	3,178,981	6,717,637	2,466,091	4,392,287	5,772,608	4,620,324	3,040,582	1,429,710	28,799,977	80,594,386	5,381,293	6,173,208	117,259,021
16	CostOfReservoirsDamsAndWaterwaysHydroelectricProduction Reservoirs, Dams, and Waterways	6,303,881	15,461,080	13,117,025	16,847,684	37,164,234	15,198,465	91,998,148	15,067,409	18,288,504	9,181,324	11,267,298	39,673,326	62,170,880	11,656,060	37,691,466	41,572,555
17	EquipmentCostsHydroelectricProduction Equipment Costs	1,604,927	2,328,400	3,348,182	7,502,793	12,292,325	9,151,002	3,003,197	7,303,525	18,530,854	16,297,564	7,193,556	21,608,778	28,174,837	15,993,758	7,860,272	23,088,538
18	CostOfRoadsRailroadsAndBridgesHydroelectricProduction Roads, Railroads, and Bridges	50,817	250,151	533,015	531,801	1,820,580	623,855	2,089,012	1,166,818	948,522	984,864		6,937,227	1,215,512	1,086,176	686,471	5,919,122
19	AssetRetirementCostsHydroelectricProduction Asset Retirement Costs
20	CostOfPlant Total Cost (10-23)	9,658,119	20,554,983	18,770,841	28,061,259	57,994,776	27,439,413	101,482,644	29,310,360	42,462,878	29,813,593	20,401,647	105,382,321	192,443,110	37,625,041	52,516,585	189,794,265
21	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 20 / 5)	643.875	790.576	1,706.440	877.188	1,506.358	1,524.412	9,225.695	689.656	1,286.754	993.786	1,411.879	786.435	801.846	1,254.168	1,641.143	1,395.546
22	ProductionExpensesAbstract Production Expenses
23	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering	137,999	149,629	61,442	273,513	304,942	161,887	61,508	299,359	247,077	217,859	106,186	2,372,360	4,244,489	329,898	537,429	2,435,959
24	WaterForPower Water for Power	926	1,604	679	1,974	2,376	1,321	679	2,623				1,053	1,886		16,395	1,069
25	HydraulicExpenses Hydraulic Expenses	40,551	70,288	29,737	86,481	104,080	48,661	184,719	114,896	47,224	42,931	20,034	1,073,474	2,137,272	158,235	2,882	1,089,496
26	ElectricExpensesHydraulicPowerGeneration Electric Expenses
27	MiscellaneousHydraulicPowerGenerationExpenses Misc Hydraulic Power Generation Expenses	427,202	493,789	272,967	790,122	892,470	398,227	367,116	824,768	1,523,797	595,320	1,010,306	427,769	327,438	1,843,795	736,877	659,415
28	RentsHydraulicPowerGeneration Rents	82,521	143,037	60,516	175,990	211,804	99,163	60,516	233,816	25,505	23,186	10,820	175,176	313,749	72,448	73,560	177,791
29	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration Maintenance Supervision and Engineering															261
30	MaintenanceOfStructuresHydraulicPowerGeneration Maintenance of Structures	23,005	40,559	18,075	49,179	59,658	28,046	20,654	67,353	12,188			4,621	6,721	483	5,423	150,883
31	MaintenanceOfReservoirsDamsAndWaterways Maintenance of Reservoirs, Dams, and Waterways	4,643	10,574	3,917	11,872	36,054	8,952	19,500	20,457	6,703	7,341	2,162	23,881	30,340	7,671	58,760	28,809
32	MaintenanceOfElectricPlantHydraulicPowerGeneration Maintenance of Electric Plant	8,031	9,652	2,467	39,719	6,584	30,915	4,667	18,423	33,700	52,191	19,055	1,057	165,201	13,335	61,777	170,953
33	MaintenanceOfMiscellaneousHydraulicPlant Maintenance of Misc Hydraulic Plant	43,604	75,581	31,976	92,993	113,490	52,325	31,976	123,548	135,332	121,927	56,899	878,624	1,574,664	379,907	313,559	922,740
34	PowerProductionExpensesHydraulicPower Total Production Expenses (total 23 thru 33)	768,482	994,713	481,776	1,521,843	1,731,458	829,497	751,335	1,705,243	2,031,526	1,060,755	1,225,462	4,955,901	8,801,760	2,805,772	1,806,923	5,637,115
35	ExpensesPerNetKilowattHour Expenses per net kWh	0.022	0.033	0.016	0.013	0.012	0.015	0.014	0.008	0.025	0.027	0.075	0.010	0.016	0.068	0.010	0.013

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: PlantName

This footnote applies to all hydroelectric generating facilities with current generation. All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities.

(b) Concept: PlantKind

Clearwater No. 1 - Forebay for peaking

Clearwater No. 2 - Forebay for peaking

(d) Concept: PlantKind

Fish Creek - Forebay for peaking

(e) Concept: PlantKind

Lemolo No. 1 - Storage, Lemolo Lake

(f) Concept: PlantKind

Lemolo No. 2 - Storage, Lemolo Lake

(g) Concept: PlantKind

Toketee - Pondage for peaking - storage, Lemolo Lake

(h) Concept: PlantKind

Prospect No. 2 - Forebay for peaking

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

Pumped Storage Generating Plant Statistics
Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings). If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number. If net peak demand for 60 minutes is not available, give that which is available, specifying period. If a group of employees attends more than one generating plant, report on Line 8 the approximate average number of employees assignable to each plant. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses." Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
Line No.	Item (a)	FERC Licensed Project No. 0 Plant Name: 0
1	PlantConstructionType Type of Plant Construction (Conventional or Outdoor)
2	YearPlantOriginallyConstructed Year Originally Constructed
3	YearLastUnitOfPlantInstalled Year Last Unit was Installed
4	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)
5	NetPeakDemandOnPlant Net Peak Demaind on Plant-Megawatts (60 minutes)	0
6	PlantHoursConnectedToLoad Plant Hours Connect to Load While Generating	0
7	NetContinuousPlantCapability Net Plant Capability (in megawatts)	0
8	PlantAverageNumberOfEmployees Average Number of Employees
9	NetGenerationExcludingPlantUse Generation, Exclusive of Plant Use - kWh	0
10	EnergyUsedForPumping Energy Used for Pumping
11	NetOutputForLoad Net Output for Load (line 9 - line 10) - Kwh	0
12	CostOfPlantAbstract Cost of Plant
13	CostOfLandAndLandRightsPumpedStoragePlant Land and Land Rights
14	CostOfStructuresAndImprovementsPumpedStoragePlant Structures and Improvements	0
15	CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant Reservoirs, Dams, and Waterways	0
16	CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant Water Wheels, Turbines, and Generators	0
17	CostOfAccessoryElectricEquipmentPumpedStoragePlant Accessory Electric Equipment	0
18	CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant Miscellaneous Powerplant Equipment	0
19	CostOfRoadsRailroadsAndBridgesPumpedStoragePlant Roads, Railroads, and Bridges	0
20	AssetRetirementCostsPumpedStoragePlant Asset Retirement Costs	0
21	CostOfPlant Total Cost (10-23)
22	CostPerKilowattOfInstalledCapacity Cost per KW of installed cap (line 21 / 4)
23	ProductionExpensesAbstract Production Expenses
24	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering	0
25	WaterForPower Water for Power	0
26	PumpedStorageExpenses Pumped Storage Expenses	0
27	ElectricExpensesPumpedStoragePlant Electric Expenses	0
28	MiscellaneousPumpedStoragePowerGenerationExpenses Misc Pumped Storage Power generation Expenses	0
29	RentsPumpedStoragePlant Rents	0
30	MaintenanceSupervisionAndEngineeringPumpedStoragePlant Maintenance Supervision and Engineering	0
31	MaintenanceOfStructuresPumpedStoragePlant Maintenance of Structures	0
32	MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant Maintenance of Reservoirs, Dams, and Waterways	0
33	MaintenanceOfElectricPlantPumpedStoragePlant Maintenance of Electric Plant	0
34	MaintenanceOfMiscellaneousPumpedStoragePlant Maintenance of Misc Pumped Storage Plant	0
35	PowerProductionExpenseBeforePumpingExpenses Production Exp Before Pumping Exp (24 thru 34)
36	PumpingExpenses Pumping Expenses
37	PowerProductionExpensesPumpedStoragePlant Total Production Exp (total 35 and 36)
38	ExpensesPerNetKilowattHour Expenses per kWh (line 37 / 9)
39	ExpensesPerNetKilowattHourGenerationAndPumping Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))	0

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

GENERATING PLANT STATISTICS (Small Plants)
Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants, pumped storage plants, and renewable plants of less than 10,000 Kw installed capacity (name plate rating). Designate any plant leased from others, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give project number in footnote. List plants appropriately under subheadings for steam, hydro, nuclear, renewable, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 402. If net peak demand for 60 minutes is not available, give the which is available, specifying period. If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
									Production Expenses
Line No.	PlantName Name of Plant (a)	YearPlantOriginallyConstructed Year Orig. Const. (b)	InstalledCapacityOfPlant Installed Capacity Name Plate Rating (MW) (c)	NetPeakDemandOnPlant Net Peak Demand MW (60 min) (d)	NetGenerationExcludingPlantUse Net Generation Excluding Plant Use (e)	CostOfPlant Cost of Plant (f)	PlantCostPerMw Plant Cost (Incl Asset Retire. Costs) Per MW (g)	OperatingExpensesExcludingFuel Operation Exc'l. Fuel (h)	FuelProductionExpenses Fuel Production Expenses (i)	MaintenanceProductionExpenses Maintenance Production Expenses (j)	FuelKind Kind of Fuel (k)	FuelCostPerMmbtus Fuel Costs (in cents (per Million Btu) (l)	GenerationType Generation Type (m)
1	Ashton (Licensed Project No. 2381)	1917	6.85	7.0	28,012,000	34,916,968	5,097,368	508,140		131,521	Water		(i) Hydro
2	Bend	1913	1.11	1.0	797,000	5,383,956	4,850,411	152,629		6,783	Water		Hydro
3	Big Fork (Licensed Project No. 2652)	1910	4.15	5.0	24,572,000	14,081,125	3,393,042	677,757		70,943	Water		Hydro
4	Eagle Point	1957	2.81	3.0	14,777,000	4,378,750	1,558,274	389,160		73,507	Water		Hydro
5	(a) East Side (Licensed Project No. 2082)	1924	3.20	0.0		1,735,600	542,375	67,308		57,076	Water		Hydro
6	Fall Creek (Licensed Project No. 2082)	1903	2.20	2.0	5,886,000	37,005,331	16,820,605	1,825,496		30,091	Water		Hydro
7	Granite	1896	2.00	1.2	4,219,592	6,269,929	3,134,965	301,044		18,991	Water		Hydro
8	Gunlock	1917	0.75	0.3	881,090	690,253	920,337	49,917		8,833	Water		Hydro
9	Last Chance	1983	1.73	1.2	3,488,684	3,229,864	1,866,973	206,760		15,873	Water		Hydro
10	(b) Paris (Licensed Project No. 703)	1910	0.72	0.6	1,416,613	6,528	9,067	42,680		3,445	Water		Hydro
11	Pioneer (Licensed Project No. 2722)	1897	5.00	4.8	10,505,474	13,610,304	2,722,061	839,269		107,196	Water		Hydro
12	Prospect No. 1 (Licensed Project No. 2630)	1912	3.76	0.0		5,749,329	1,529,077	160,049		64,479	Water		Hydro
13	Prospect No. 3 (Licensed Project No. 2337)	1932	7.20	0.0	168,000	13,873,354	1,926,855	386,022		101,307	Water		Hydro
14	Prospect No. 4 (Licensed Project No. 2630)	1944	1.00	0.0	83,000	2,841,570	2,841,570	39,854		15,831	Water		Hydro
15	Sand Cove	1926	0.80	0.3	725,743	1,179,395	1,474,244	61,695		5,562	Water		Hydro
16	Stairs (Licensed Project No. 597)	1895	1.00	1.3	4,150,890	3,268,037	3,268,037	263,841		5,423	Water		Hydro
17	Veyo	1920	0.50	0.0		946,248	1,892,496	41,003		225,296	Water		Hydro
18	Viva Naughton	1986	0.74	0.1	507,000	1,625,540	2,196,676	77,126		270,916	Water		Hydro
19	Wallowa Falls (Licensed Project No. 308)	1921	1.10	2.0	2,854,000	5,850,598	5,318,725	191,842		12,962	Water		Hydro
20	Weber (Licensed Project No. 1744)	1911	3.85	0.0	178,442	4,067,390	1,056,465	434,458		22,349	Water		Hydro
21	(c) West Side (Licensed Project No. 2082)	1908	0.60	0.0	6,000	577,347	962,245	8,451		7,411	Water		Hydro
22	(d) Upper Klamath Lake (Licensed Project No. 2082)					55,815							Hydro
23	(e) North Umpqua (Licensed Project No. 1927)					22,448,939							Hydro
24	(f)(g) Lifton Pumping Plant	1917				22,342,889	7,979,603	289,055		42,708	Water		Hydro
25	(h) Black Cap	2012	2.00	1.9	3,337,458	770,480	385,240	454,032			Solar		Solar

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: PlantName

The East Side plant was significantly curtailed pursuant to Section 6.2 of the Klamath Hydroelectric Settlement Agreement in FERC Docket No. P-2082-000.

(b) Concept: PlantName

Paris ceased operations in September 2025 and was decommissioned in December 2025.

The West Side Pant was significantly curtailed pursuant to Section 6.2 of the Klamath Hydroelectric Settlement Agreement in FERC Docket P-2082-000

(d) Concept: PlantName

Storage reservoir for two remaining plants on the Klamath River (East Side and West Side). Also refer to Note 14 of Notes to Financial Statements in this Form No. 1 and Docket No. AC23-26-000 filed with the FERC for further discussion on the Lower Klamath Hydroelectric Project.

(e) Concept: PlantName

Represents facilities that support the North Umpqua River system projects. All common roads, employee houses, control equipment, etc. are included in this account.

(f) Concept: PlantName


Installed Capacity Name Plate Rating (In MW)	Net Peak Demand MW (60 min.)	Net Generation Excluding Plant Use
(c)	(d)	(e)
(2.80)	0.0	(3,850,000)

(g) Concept: PlantName

Used in regulating the release of water from Bear Lake and in maintaining proper water surface level in the Bear River near St. Charles, Idaho.

(h) Concept: PlantName

PacifiCorp has an agreement with Citizens Asset Finance, Inc. to lease the Black Cap Solar generating facility. The lease has a 16-year term from October 2012 to October 2028 and is accounted for as an operating lease.

(i) Concept: GenerationType

This footnote applies to all hydroelectric generating facilities with current generation. Common river system costs for the operation of these facilities are allocated to each plant based upon the unit�s name plate rating. All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

ENERGY STORAGE OPERATIONS (Large Plants)
Large Plants are plants of 10,000 Kw or more. In columns (a) and (b) report the name of the energy storage project and location. In column (c), report Megawatt hours (MWH) purchased, generated, or received in exchange transactions for storage. In column (d) report MWHs delivered to the grid to support production, transmission and distribution. The amount reported in column (c) should include MWHs delivered/provided to a generator�s own load requirements or used for the provision of ancillary services. In column (e) report MWHs lost during conversion, storage and discharge of energy. In column (f) report the MWHs sold. In column (g), report revenues from energy storage operations. In a footnote, disclose the revenue accounts and revenue amounts related to the income generating activity. In column (h), report the cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. In columns (i) and (j), report fuel costs for storage operations associated with self-generated power and other costs associated with self-generated power. In column (l) report the total project plant costs including but not exclusive of land and land rights, structures and improvements, energy storage equipment, turbines, compressors, generators, switching and conversion equipment, lines and equipment whose primary purpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property accounts listed.

Line No.	Name of the Energy Storage Project (a)	Location of the Project (b)	MWHs (c)	MWHs delivered to the grid (d)	MWHs Lost During Conversion, Storage and Discharge of Energy (e)	MWHs Sold (f)	Revenues from Energy Storage Operations (g)	Power Purchased for Storage Operations (555.1) (Dollars) (h)	Fuel Costs from associated fuel accounts for Storage Operations Associated with Self-Generated Power (Dollars) (i)	Other Costs Associated with Self-Generated Power (Dollars) (j)	Account for Project Costs (k)	Total Project Plant Costs (l)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35	TOTAL		0	0	0	0	0	0	0	0		0

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

ENERGY STORAGE OPERATIONS (Small Plants)
Small Plants are plants less than 10,000 Kw. In columns (a) and (b) report the name of the energy storage project, and location. In column (c), report project plant cost including but not exclusive of land and land rights, structures and improvements, energy storage equipment and any other costs associated with the energy storage project. In column (d), report operation expenses excluding fuel, (e), maintenance expenses, (f) fuel costs for storage operations and (g) cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. If any other expenses, report in column (h) and footnote the nature of the item(s).
				Plant Operating Expenses
Line No.	Name of the Energy Storage Project (a)	Location of the Project (b)	Project Cost (c)	Operations (Excluding Fuel used in Storage Operations) (d)	Maintenance (e)	Cost of fuel used in storage operations (f)	Account No. 555.1, Power Purchased for Storage Operations (g)	Other Expenses (h)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36	TOTAL		0	0	0	0	0	0

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

TRANSMISSION LINE STATISTICS
Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. If required by a State commission to report individual lines for all voltages, do so but do not group totals for each voltage under 132 kilovolts. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated. Do not report the same transmission line structure twice. Report lower voltage lines and higher voltage lines as one line. Designate in a footnote if you do not include lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g). Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. Designate any transmission line leased to another company and give name of lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
	DESIGNATION		VOLTAGE (KV) - (Indicate where other than 60 cycle, 3 phase)			LENGTH (Pole miles) - (In the case of underground lines report circuit miles)				COST OF LINE (Include in column (j) Land, Land rights, and clearing right-of-way)			EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	OperatingVoltageOfTransmissionLine Operating	DesignedVoltageOfTransmissionLine Designated	SupportingStructureOfTransmissionLineType Type of Supporting Structure	LengthForStandAloneTransmissionLines On Structure of Line Designated	LengthForTransmissionLinesAggregatedWithOtherStructures On Structures of Another Line	NumberOfTransmissionCircuits Number of Circuits	SizeOfConductorAndMaterial Size of Conductor and Material	CostOfLandAndLandRightsTransmissionLines Land	ConstructionAndOtherCostsTransmissionLines Construction Costs	OverallCostOfTransmissionLine Total Costs	OperatingExpensesOfTransmissionLine Operation Expenses	MaintenanceExpensesOfTransmissionLine Maintenance Expenses	RentExpensesOfTransmissionLine Rents	OverallExpensesOfTransmissionLine Total Expenses
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)
1	(a) See footnote
2	AEOLUS, WY	ANTICLINE, WY	500.00	500.00	Steel Tower	137.70		1	3-1272 ACSR 45/7
3	AEOLUS, WY	CLOVER, UT	500.00	500.00	Steel Tower	414.90		1	3-1272 ACSR 45/7
4	(b) ALVEY, OR	DIXONVILLE 500KV, OR	500.00	500.00	Steel Tower	57.95		1	3-1272 ACSR 54/19
5	(c) BROADVIEW, MT	COLSTRIP A, MT	500.00	500.00	Steel Tower	112.70		1	3-795 ACSR 26/7
6	(d) BROADVIEW, MT	COLSTRIP B, MT	500.00	500.00	Steel Tower	115.80		1	3-795 ACSR 26/7
7	(e) BROADVIEW, MT	TOWNSEND A, MT	500.00	500.00	Steel Tower	133.00		1	3-795 ACSR 26/7
8	(f) BROADVIEW, MT	TOWNSEND B, MT	500.00	500.00	Steel Tower	133.00		1	3-795 ACSR 26/7
9	CAPTAIN JACK, OR	MALIN, OR	500.00	500.00	Steel Tower	6.93		1	3-1272 ACSR 36/1
10	(g) DIXONVILLE 500KV, OR	MERIDIAN, OR	500.00	500.00	Steel Tower	73.70		1	3-1272 ACSR 54/19
11	(h) HEMINGWAY, ID	SUMMER LAKE, OR	500.00	500.00	Steel Tower	241.62		1	3-1272 ACSR 36/1
12	KLAMATH COGEN, OR	SNOW GOOSE, OR	500.00	500.00	Steel Tower	2.89		1	3-1272 ACSR 36/1
13	MALIN, OR	INDIAN SPRINGS, CA	500.00	500.00	Steel Tower	47.50		1	2-1852 ACSR 51/27
14	MERIDIAN, OR	KLAMATH COGEN, OR	500.00	500.00	Steel Tower	57.99		1	3-1272 ACSR 36/1
15	(i) MIDPOINT, ID	HEMINGWAY, ID	500.00	500.00	Steel Tower	129.77		1	3-1272 ACSR 36/1
16	SNOW GOOSE, OR	CAPTAIN JACK, OR	500.00	500.00	Steel Tower	24.52		1	3-1272 ACSR 36/1
17	SUMMER LAKE, OR	MALIN, OR	500.00	500.00	Steel Tower	75.12		1	3-1272 ACSR 36/1
18	500kV Costs and Expenses									123,225,377	2,055,813,313	2,179,038,690	161,594	3,688,019	479,884	4,329,497
19	90TH SOUTH, UT	CAMP WILLIAMS #3, UT	345.00	345.00	Steel - SP	11.00		1	2-1557.4 ACSR/TW 36/7
20	90TH SOUTH, UT	CAMP WILLIAMS #4, UT	345.00	345.00	Steel - SP		10.77	1	2-1557.4 ACSR/TW 36/7
21	90TH SOUTH, UT	CAMP WILLIAMS #1, UT	345.00	345.00	Steel - SP	11.00		1	2-1272 ACSR 45/7
22	90TH SOUTH, UT	TERMINAL, UT	345.00	345.00	Steel - SP		15.80	1	2-1272 ACSR 45/7
23	ANTICLINE, WY	JIM BRIDGER, WY	345.00	345.00	Steel - H	5.10		1	3-1272 ACSR 45/7
24	BEN LOMOND, UT	POPULUS #1, ID	345.00	345.00	Steel - SP		82.17	1	2-1272 ACSR 45/7
25	BEN LOMOND, UT	POPULUS #2, ID	345.00	345.00	Steel - SP	86.00		1	2-1272 ACSR 45/7
26	BEN LOMOND, UT	CAMP WILLIAMS, UT	345.00	345.00	Steel - SP	69.00		1	2-1272 ACSR 45/7
27	BEN LOMOND, UT	TERMINAL #2, UT	345.00	345.00	Steel - SP	47.00		1	2-1272 ACSR 45/7
28	BEN LOMOND, UT	TERMINAL #1, UT	345.00	345.00	Steel - SP		46.60	1	2-1272 ACSR 45/7
29	(j) BORAH, ID	MIDPOINT #1, ID	345.00	345.00	Wood - H	83.00		1	2-1272 ACSR 45/7
30	(k) BORAH, ID	MIDPOINT #2, ID	345.00	345.00	Wood - H	78.00		1	2-1272 ACSR 45/7
31	CAMP WILLIAMS, UT	CLOVER, UT	345.00	345.00	Wood - H	50.00		1	2-954 ACSR 45/7
32	CAMP WILLIAMS, UT	MONA #1, UT	345.00	345.00	Wood - H	47.00		1	2-1272 ACSR 45/7
33	CAMP WILLIAMS, UT	MONA #2, UT	345.00	345.00	Steel Tower	48.00		1	2-954 ACSR 45/7
34	CAMP WILLIAMS, UT	MONA #4, UT	345.00	345.00	Steel Tower	5.00	43.00	1	2-954 ACSR 54/7
35	CLOVER, UT	OQUIRRH, UT	345.00	345.00	Steel Tower	99.60		1	3-1949 ACSR 45/7
36	FUTURE LIMBER, UT	OQUIRRH, UT	345.00	345.00	Steel - SP		10.39	1	2-1272 ACSR 45/7
37	CURRANT CREEK, UT	MONA, UT	345.00	345.00	Steel - SP	0.37		1	2-954 ACSR 54/7
38	EMERY, UT	CAMP WILLIAMS, UT	345.00	345.00	Steel Tower	120.78		1	2-954 ACSR 54/7
39	EMERY, UT	HUNTINGTON, UT	345.00	345.00	Wood - H	19.57		1	2-954 ACSR 45/7
40	EMERY, UT	SIGURD #1, UT	345.00	345.00	Steel - H	74.43		1	2-954 ACSR 54/7
41	EMERY, UT	SIGURD #2, UT	345.00	345.00	Steel - H	74.81		1	2-954 ACSR 54/7
42	FOUR CORNERS, NM	PINTO, UT	345.00	345.00	Wood - H	100.82		1	2-795 ACSR 45/7
43	(l) GOSHEN, ID	KINPORT, ID	345.00	345.00	Wood - H	41.00		1	2-795 ACSR/SD 22/7
44	HUNTINGTON, UT	HUNT PLANT 1, UT	345.00	345.00	Steel Tower	0.51		1	1-2156 ACSR 8419
45	HUNTINGTON, UT	HUNT PLANT 2, UT	345.00	345.00	Steel Tower	0.54		1	1-2156 ACSR 8419
46	HUNTINGTON, UT	PINTO, UT	345.00	345.00	Steel - SP	158.63		1	2-795 ACSR 45/7
47	HUNTINGTON, UT	SPANISH FORK, UT	345.00	345.00	Steel Tower	78.47		1	2-954 ACSR 54/7
48	(m) JIM BRIDGER, WY	GOSHEN, ID	345.00	345.00	Steel Tower	227.43		1	2-1272 ACSR 36/1
49	(n) JIM BRIDGER, WY	BORAH, ID	345.00	345.00	Steel Tower	240.69		1	2-1272 ACSR 36/1
50	(o) JIM BRIDGER, WY	KINPORT, ID	345.00	345.00	Steel - SP	234.56		1	2-1272 ACSR 36/1
51	(p) KINPORT, ID	MIDPOINT, ID	345.00	345.00	Steel - SP	112.50		1	2-1272 ACSR 45/7
52	MONA, UT	SIGURD #1, UT	345.00	345.00	Wood - H	69.00		1	2-795 ACSR 45/7
53	MONA, UT	SIGURD #2, UT	345.00	345.00	Steel - SP		69.22	1	2-954 ACSR 45/7
54	CLOVER, UT	HUNTINGTON, UT	345.00	345.00	Steel - SP	57.37		1	2-954 ACSR 45/7
55	RED BUTTE, UT	SIGURD, UT	345.00	345.00	Steel - H	171.00		1	2-954 ACSR 54/7
56	SIGURD, UT	UT/NV STATE LINE, UT	345.00	345.00	Steel Tower	190.00		1	2-954 ACSR/SD 13/8/7
57	SPANISH FORK, UT	CAMP WILLIAMS, UT	345.00	345.00	Steel - SP		35.00	1	2-1272 ACSR 45/7
58	TERMINAL, UT	BORAH, ID	345.00	345.00	Wood - H	138.00		1	2-954 ACSR/SD 21/7
59	TERMINAL, UT	BORAH, ID	345.00	345.00	Steel - SP		46.60	1	2-954 ACSR/SD 21/7
60	TERMINAL, UT	CAMP WILLIAMS #2, UT	345.00	345.00	Steel - SP	16.00	10.00	1	2-1272 ACSR 45/7
61	TERMINAL, UT	CAMP WILLIAMS, UT	345.00	345.00	Steel Tower		22.63	1	2-1272 ACSR 45/7
62	OQUIRRH, UT	TERMINAL #3, UT	345.00	345.00	Steel - SP	14.40		1	2-1272 ACSR 45/7
63	OQUIRRH, UT	TERMINAL #4, UT	345.00	345.00	Steel - SP		14.40	1	2-1272 ACSR 45/7
64	MERCER, UT	META #1	345.00	345.00	Steel - SP	0.57		1	2-1272 ACSR 45/7
65	MERCER, UT	META #2	345.00	345.00	Steel - SP	0.54	0.54	1	2-1272 ACSR 45/7
66	LAKESIDE 2, UT	STEEL MILL, UT	345.00	345.00	Steel - 3P	0.19		1	2-954 ACSR 54/7
67	MIDPOINT 500, ID	MIDPOINT, ID	345.00	345.00	Steel	0.25		1	2-1272 ACSR 36/1
68	MERCER	QTS #1 (CUST)	345.00	345.00		0.46		1	1272 ACSR 45/7
69	MERCER	QTS #2 (CUST)	345.00	345.00		0.46		1	1272 ACSR 45/7
70	345 kV Costs and Expenses									174,641,744	1,785,859,146	1,960,500,890	67,570	1,911,779	313,111	2,292,460
71	AEOLUS, WY	EKOLA FLATS, WY	230.00	230.00	Steel - H	0.96		1	1-795 ACSR 26/7
72	AEOLUS, WY	FREEZEOUT, WY	230.00	230.00	Steel - H	4.10		1	2-1272 ACSR 45/7
73	AEOLUS, WY	FREEZEOUT, WY	230.00	230.00		4.04		1	2-1158 ACSS /25
74	AEOLUS, WY	SHIRLEY BASIN #1, WY	230.00	230.00	Steel - H	15.90		1	2-1158 ACSS /25
75	AEOLUS, WY	SHIRLEY BASIN #2, WY	230.00	230.00	Steel - H	16.70		1	2-1158 ACSS /25
76	ALVEY, OR	DIXONVILLE, OR	230.00	230.00	Wood - H	59.40		1	1-1272 ACSR 36/1
77	ANTELOPE, ID	ANACONDA, MT	230.00	230.00	Wood - H	75.72		1	1-1272 ACSR 45/7
78	ANTELOPE, ID	LOST RIVER, ID	230.00	230.00	Wood - H	20.03		1	1-795 ACSR 45/7
79	ARROWHEAD, WY	FIREHOLE, WY	230.00	230.00	Wood - H	8.90		1	1-795 ACSR 26/7
80	ATLANTIC CITY, WY	COLUMBIA GENEVA, WY	230.00	230.00	Wood - H	0.91		1	1-1272 ACSR 36/1
81	BEN LOMOND, UT	NAUGHTON #1, WY	230.00	230.00	Wood - H	88.06		1	2-795 ACSR 26/7
82	BEN LOMOND, UT	NAUGHTON #2, WY	230.00	230.00	Wood - H	87.86		1	2-795 ACSR 26/7
83	BIRCH CREEK, UT	RAILROAD, WY	230.00	230.00	Wood - H	19.21		1	1-954 ACSR 54/7
84	BITTER CREEK, WY	MONELL, WY	230.00	230.00	Wood - H	2.83		1	1-795 ACSR 26/7
85	BRIDGER PUMP, WY	MANS FACE, WY	230.00	230.00	Wood - H	0.65		1	1-1272 ACSR 36/1
86	BUFFALO, WY	CASPER, WY	230.00	230.00	Wood - H	107.70		1	1-795 ACSR 26/7
87	(q) CASPER, WY	DAVE JOHNSTON, WY	230.00	230.00	Wood - H	36.69		1	1-1557 ACSS/TW 36/7
88	CASPER, WY	RIVERTON, WY	230.00	230.00	Wood - H	110.42		1	1-1272 ACSR 36/1
89	CHAPPEL CREEK, WY	CRAVEN CREEK, WY	230.00	230.00	Steel - SP	29.95		1	1-954 ACSR 54/7
90	CHAPPEL CREEK, WY	JONAH GAS, WY	230.00	230.00	Wood - H	32.13		1	1-1272 ACSR 45/7
91	CHAPPEL CREEK, WY	RILEY RIDGE, WY	230.00	230.00	Wood - H	29.00	6.00	1	1-1272 ACSR 45/7
92	CORRAL, OR	OCHOCO #1, OR	230.00	230.00	Wood - H	9.86		1	1-1557 ACSS/TW 36/7
93	CORRAL, OR	OCHOCO #2, OR	230.00	230.00	Wood - H	9.23		1	1-1557.4 ACSR/TW 36/7
94	CRAVEN CREEK, WY	PIONEER, WY	230.00	230.00	Wood - H	2.15		1	1-1272 ACSR 45/7
95	DAVE JOHNSTON, WY	SPENCE, WY	230.00	230.00	Wood - H	31.40		1	1-1557 ACSS/TW 36/7
96	DAVE JOHNSTON, WY	WYODAK, WY	230.00	230.00	Wood - H	68.46		1	1-1272 ACSR 36/1
97	DIXONVILLE 500kV, OR	DIXONVILLE 230kV, OR	230.00	230.00	Wood - H	1.45		1	1-1158 ACSS /25
98	DIXONVILLE, OR	RESTON (BPA), OR	230.00	230.00	Wood - H	17.40		1	1-795 ACSR 26/7
99	FAIRVIEW (BPA), OR	ISTHMUS, OR	230.00	230.00	Wood - H	11.87		1	1-1272 ACSR 36/1
100	FIREHOLE, WY	MONUMENT, WY	230.00	230.00	Wood - H	49.15		1	1-1272 ACSR 36/1
101	FRIEND, OR	OCHOCO #1, OR	230.00	230.00	Steel - SP	1.00		2	1-1557.4 ACSR/TW 36/7
102	FRIEND, OR	OCHOCO #2, OR	230.00	230.00	Steel - SP		0.97	2	1-1557.4 ACSR/TW 36/7
103	FRY, OR	BETHEL, OR	230.00	230.00	Wood - H	26.38		1	1-1272 ACSR 36/1
104	FRY, OR	ALVEY, OR	230.00	230.00	Wood - H	44.94		1	1-1272 ACSR 36/1
105	GLEN CANYON, AZ	SIGURD, UT	230.00	230.00	Wood - H	159.45		1	1-954 ACSR 45/7
106	GONDER, UT - NV STATE	PAVANT, UT	230.00	230.00	Wood - H	97.70		1	1-795 ACSR 45/7
107	DIXONVILLE, OR	GRANTS PASS, OR	230.00	230.00	Wood - H	61.74		1	1-1272 ACSR 36/1
108	HIGH PLAINS, WY	STANDPIPE, WY	230.00	230.00	Wood - H	38.62		1	1-1272 ACSR 45/7
109	(r) HURRICANE, OR	WALLA WALLA, WA	230.00	230.00	Wood - H	77.65		1	1-1272 ACSR 45/7
110	JIM BRIDGER, WY	ROCK SPRINGS, WY	230.00	230.00	Wood - H	34.93		1	1-1272 ACSR 45/7
111	JIM BRIDGER, WY	SPENCE, WY	230.00	230.00	Wood - H	149.15		1	1-1272 ACSR 36/1
112	KLAMATH FALLS, OR	MALIN, OR	230.00	230.00	Wood - H	35.31		1	1-1272 ACSR 36/1
113	KLAMATH FALLS, OR	SNOW GOOSE, OR	230.00	230.00	Steel - SP	4.17		1	1-1511 ACCC 36/1
114	LIMA, WY	ROBERSON, WY	230.00	230.00	Wood - H	1.60		1	1-1272 ACSR 45/7
115	LONE PINE, OR	KLAMATH FALLS, OR	230.00	230.00	Wood - H	76.02		1	1-795 ACSR 26/7
116	LONE PINE, OR	MERIDIAN #1, OR	230.00	230.00	Steel - SP	5.23		1	1-1272 ACSR 45/7
117	LONE PINE, OR	MERIDIAN #2, OR	230.00	230.00	Steel - SP	5.35		1	1-1272 ACSR 54/19
118	MCNARY (BPA), OR	WALLA WALLA, WA	230.00	230.00	Wood - H	56.30		1	1-1272 ACSR 36/1
119	MCNARY (BPA), OR	WALLULA, WA	230.00	230.00	Wood - H	29.30		1	1-1158 ACSS /25
120	MERIDIAN, OR	GRANTS PASS, OR	230.00	230.00	Wood - H	35.05		1	1-1272 ACSR 36/1
121	MONUMENT, WY	EXXON, WY	230.00	230.00	Wood - H	12.72		1	1-1272 ACSR 36/1
122	MONUMENT, WY	CRAVEN CREEK, WY	230.00	230.00	Wood - H	19.80		1	1-1272 ACSR 45/7
123	NAUGHTON, WY	TREASURETON, ID	230.00	230.00	Wood - H	79.58		1	1-1272 ACSR 45/7
124	NAUGHTON, WY	MONUMENT, WY	230.00	230.00	Wood - H	30.17		1	1-1272 ACSR 36/1
125	NAUGHTON, WY	CRAVEN CREEK, WY	230.00	230.00	Wood - H	15.88		1	1-954 ACSR 54/7
126	PALISADES SS, WY	BLUE RIM, WY	230.00	230.00	Wood - H	4.14		1	1-1272 ACSR 36/1
127	PAROWAN VALLEY, UT	SIGURD, UT	230.00	230.00	Wood - H	94.29		1	1-795 ACSR 45/7
128	PAROWAN VALLEY, UT	WEST CEDAR, UT	230.00	230.00	Wood - H	25.65		1	1-795 ACSR 45/7
129	PAVANT, UT	SIGURD, UT	230.00	230.00	Wood - H	43.03		1	1-795 ACSR 45/7
130	POINT OF ROCKS, WY	FREEZEOUT, WY	230.00	230.00	Wood - H	132.53		1	1-1272 ACSR 36/1
131	POMONA, WA	VANTAGE, WA	230.00	230.00	Wood - H	40.40		1	1-1272 ACSR 45/7
132	PONDEROSA (BPA), OR	CORRAL, OR	230.00	230.00	Steel - SP	0.50	0.50	1	1-1557.4 ACSR/TW 36/7
133	POMONA, WA	UNION GAP, WA	230.00	230.00	Wood - H	7.42		1	1-1272 ACSR 36/1
134	RIVERTON, WY	ROCK SPRINGS, WY	230.00	230.00	Wood - H	118.05		1	1-1272 ACSR 36/1
135	RIVERTON, WY	THERMOPOLIS, WY	230.00	230.00	Wood - H	50.81		1	1-1272 ACSR 36/1
136	ROCK SPRINGS, WY	FLAMING GORGE, UT	230.00	230.00	Wood - H	54.63		1	1-1272 ACSR 36/1
137	ROCK SPRINGS, WY	JIM BRIDGER, WY	230.00	230.00	Wood - H	35.29		1	1-1272 ACSR 36/1
138	ROCK SPRINGS, WY	MONUMENT, WY	230.00	230.00	Wood - H	41.07		1	1-1272 ACSR 36/1
139	SHERIDAN (MDU), WY	BUFFALO, WY	230.00	230.00	Wood - H	39.77		1	1-795 ACSR 26/7
140	SHERIDAN (MDU), WY	YELLOWTAIL, MT	230.00	230.00	Wood - H	62.20		1	1-795 ACSR 26/7
141	SHIRLEY BASIN, WY	DUNLAP RANCH, WY	230.00	230.00	Wood - H	11.70		1	1-795 ACSR 26/7
142	SHIRLEY BASIN, WY	WINDSTAR, WY	230.00	230.00	Steel - H	59.87		1	2-1272 ACSR 45/7
143	SHIRLEY BASIN, WY	DAVE JOHNSTON, WY	230.00	230.00	Steel - H	57.57		1	2-1272 ACSR 45/7
144	Specialized (PAC), OR	Rockpile Switchyard (UEC), OR #1	230.00	230.00	Steel - SP	1.18		1	2-1158 ACSS /25
145	Specialized (PAC), OR	Rockpile Switchyard (UEC), OR #2	230.00	230.00	Steel - SP	1.18		1	2-1158 ACSS /25
146	SWIFT No. 1, WA	SWIFT No. 2, WA	230.00	230.00	Wood - H	2.00		1	1-954 ACSR 45/7
147	SWIFT No. 2, WA	WOODLAND (BPA) SS, WA	230.00	230.00	Wood - H	23.00		1	1-954 ACSR 45/7
148	TALBOT, WA	MARENGO II, WA	230.00	230.00	Wood - H	7.25		1	1-795 ACSR 26/7
149	TAP TO HANNA, OR	NICKEL MOUNTAIN, OR	230.00	230.00	Wood - H	9.02		1	1-795 ACSR 26/7
150	THERMOPOLIS, WY	YELLOWTAIL, MT	230.00	230.00	Wood - H	175.71		1	1-1272 ACSR 36/1
151	TREASURETON, ID	BRADY, ID	230.00	230.00	Wood - H	66.49		1	1-795 ACSR 26/7
152	TROUTDALE (BPA), OR	GRESHAM (PGE), OR	230.00	230.00	Steel Tower	6.35		1	1-954 ACSR 45/7
153	TROUTDALE (BPA), OR	LINNEMAN (PGE), OR	230.00	230.00	Steel Tower		6.48	1	1-900 ACSS 54/7
154	UNION GAP, WA	MIDWAY (BPA), WA	230.00	230.00	Wood - H	39.43		1	1-954 ACSR 45/7
155	WALLA WALLA, WA	LEWISTON (AVISTA), ID	230.00	230.00	Wood - H	44.88		1	1-1272 ACSR 36/1
156	WALLA WALLA, WA	WANAPUM (GPUD), WA	230.00	230.00	Wood - H	33.33		1	1-1272 ACSR 36/1
157	WANAPUM (GPUD), WA	POMONA, WA	230.00	230.00	Wood - H	37.37		1	1-1272 ACSR 36/1
158	WINDSTAR, WY	GLENROCK, WY	230.00	230.00	Wood - H	13.04		1	1-1272 ACSR 45/7
159	WYODAK, WY	BUFFALO, WY	230.00	230.00	Wood - H	69.14		1	1-1272 ACSR 36/1
160	YAMSAY (BPA), OR	KLAMATH FALLS, OR	230.00	230.00	Wood - H	62.64		1	1-795 ACSR 26/7
161	STANDPIPE, WY	MINERS, WY	230.00	230.00		0.60		1	1-1272 ACSR 36/1
162	FREEZEOUT, WY	SEVEN MILE HILL, WY	230.00	230.00		0.08		1	1-1272 ACSR 45/7
163	ECHO SPRINGS, WY	WILLIAMS FIELD SERVICES, WY	230.00	230.00		0.01		1	1-795 ACSR 26/7
164	WYODAK PLANT, WY	WYODAK, WY	230.00	230.00		0.17		1	1-1272 ACSR 36/1
165	OREGON BASIN (PACIFICORP), WY	OREGON BASIN (MARTHN OIL), WY	230.00	230.00		0.06		1	1-1272 ACSR 45/7
166	RIVERTON, WY	RIVERTON (TSGT), WY	230.00	230.00		0.07		1	2-1272 ACSR 45/7
167	PICKETT, OR	SKYSOL, OR	230.00	230.00		0.07		1	1-795 ACSR 26/7
168	COVE, OR	ROUND BUTTE (PGE), OR	230.00	230.00		0.10	0.15	1	1-1272 ACSR 45/7
169	JONES CANYON (BPA), OR	LEANING JUNIPER, OR	230.00	230.00		0.02		1	1-954 AAC /37
170	ROCK CREEK (BPA), WA	GOODNOE HILLS, WA	230.00	230.00		0.20		1	1-795 ACSR 26/7
171	TAP TO DALREED, OR	TAP TO DALREED No. 2, OR	230.00	230.00		0.15		1	1-795 ACSR 26/7
172	APEX, OR	LITESPEED, OR #1	230.00	230.00	Steel	0.12		1	2-1158 ACSS /25
173	APEX, OR	LITESPEED, OR #2	230.00	230	Steel	0.12		1	2-1158 ACSS /25
174	HEWARD, WY	DIFFICULTY (TSGT), WY	230.00	230.00		0.05		1	1-1272 ACSR 45/7; 1-1272 ACSR 36/1
175	230kV Costs and Expenses									49,872,038	1,073,173,270	1,123,045,308	427,945	6,766,076	327,897	7,521,918
176	(s) ANTELOPE, ID	GOSHEN, ID	161.00	161.00	Wood - H	44.65		1	1-397.5 ACSR 26/7
177	(t) BIG GRASSY, ID	JEFFERSON, ID	161.00	161.00	Wood - H		20.54	1	1-250HH CU /7
178	BONNEVILLE, ID	EAGLEROCK, ID	161.00	161.00	Wood - SP	8.58		1	1-954 ACSR 45/7
179	EAGLEROCK, ID	GOSHEN, ID	161.00	161.00	Wood - H	14.63		1	1-1272 ACSR 45/7
180	GOSHEN, ID	GRACE, ID	161.00	161.00	Wood - H	57.22		1	1-1272 ACSR 45/7
181	(u) GOSHEN, ID	JEFFERSON, ID	161.00	161.00	Wood - H		28.89	1	1-795 ACSR 26/7
182	GOSHEN, ID	RIGBY, ID	161.00	161.00	Wood - H	31.53		1	1-397.5 ACSR 26/7
183	GOSHEN, ID	SUGARMILL, ID	161.00	161.00	Wood - SP	16.54		1	1-477 ACSS 26/7
184	GOSHEN, ID	SUGARMILL, ID	161.00	161.00	Wood - SP	25.70		1	1-1557.4 ACSR/TW 36/7
185	RIGBY, ID	REXBURG, ID	161.00	161.00	Wood - SP	12.40		1	1-1272 ACSR 45/7
186	RIGBY, ID	JEFFERSON, ID	161.00	161.00	Wood - SP	17.51		1	1-397.5 ACSR 26/7
187	RIGBY, ID	SUGARMILL, ID	161.00	161.00	Wood - SP	21.47		1	1-1557.4 ACSR/TW 36/7
188	SUGARMILL, ID	RIGBY, ID	161.00	161.00	Wood - SP	16.69		1	1-397.5 ACSR 26/7
189	TAP TO PAYNE, ID	PAYNE, ID	161.00	161.00	Wood - SP	3.40		1	1-1557.4 ACSR/TW 36/7
190	YELLOWTAIL, MT	RIMROCK, MT	161.00	161.00	Wood - H	45.53		1	1-556.5 ACSR 26/7
191	161 kV Costs and Expenses									5,464,203	90,984,872	96,449,075	40,987	288,300	162	329,449
192	90TH SOUTH, UT	DUMAS #1, UT	138.00	138.00	Wood - H	11.73		1	1-795 AAC /37
193	90TH SOUTH, UT	DUMAS #2, UT	138.00	138.00	Wood - H	5.98		1	1-1272 ACSR 45/7
194	90TH SOUTH, UT	OQUIRRH, UT	138.00	138.00	Wood - SP	12.47		1	1-1020 ACCC/TW BARE
195	90TH SOUTH, UT	SANDY, UT	138.00	138.00	Steel - SP	1.49		1	1-795 AAC /37
196	ABAJO, UT	PINTO, UT	138.00	138.00	Wood - H	44.31		1	1-397.5 ACSR 26/7
197	ABAJO, UT	SAN JUAN, UT	138.00	138.00	Wood - SP	10.04		1	1-795 ACSR 26/7
198	AGRIUM, UT	THREEMILE KNOLL, ID	138.00	138.00	Wood - H	3.74		1	1-397.5 ACSR 26/7
199	ANSCHTZ CO-GEN, WY	EVANSTON, WY	138.00	138.00	Wood - H	21.52		1	1-795 ACSR 26/7
200	(v) ANTELOPE, ID	SCOVILLE #1, ID	138.00	138.00	Wood - H	0.50		1	1-397.5 ACSR 26/7
201	(w) ANTELOPE, ID	SCOVILLE #2, ID	138.00	138.00	Wood - H	0.50		1	1-397.5 ACSR 26/7
202	ASHGROVE, UT	CLOVER, UT	138.00	138.00	Wood - H	25.95		1	1-397.5 ACSR 26/7
203	ASHLEY, UT	CARBON, UT	138.00	138.00	Wood - H	101.61		1	1-397.5 ACSR 26/7
204	ASHLEY, UT	VERNAL, UT	138.00	138.00	Wood - H	11.88		1	1-397.5 ACSR 26/7
205	BEN LOMOND, UT	ANGEL, UT	138.00	138.00	Steel - SP	27.61		1	1-250 CUHD /12
206	BEN LOMOND, UT	BRIGHAM CITY, UT	138.00	138.00	Wood - H	13.78		1	1-250 CUHD /12
207	BEN LOMOND #1, UT	EL MONTE, UT	138.00	138.00	Steel - SP	14.03		1	1-795 ACSR 26/7
208	BEN LOMOND #2, UT	EL MONTE, UT	138.00	138.00	Wood - H		13.43	1	1-795 ACSR 26/7
209	BEN LOMOND, UT	HONEYVILLE, UT	138.00	138.00	Steel Tower	22.42		1	1-250 CUHD /12
210	BEN LOMOND, UT	SYRACUSE #2, UT	138.00	230.00	Steel Tower	7.00	13.00	1	2-250 CUHD /12
211	BEN LOMOND, UT	SYRACUSE, UT	138.00	138.00	Steel Tower	57.88		1	1-1272 ACSR 45/7
212	BEN LOMOND, UT	W ZIRCONIUM, UT	138.00	138.00	Wood - SP	14.35		1	1-795 AAC /37
213	BEN LOMOND, UT	WHEELON, UT	138.00	138.00	Steel Tower	41.98		1	1-250 CUHD /12
214	BONANZA, UT	CHAPITA, UT	138.00	138.00	Wood - H	8.50		1	1-795 ACSR 26/7
215	BRIDGERLAND, UT	GREEN CANYON, UT	138.00	138.00	Wood - SP	16.59		1	1-1272 ACSR 45/7
216	BRIGHAM CITY, UT	WHEELON, UT	138.00	138.00	Wood - H	23.82		1	1-250 CUHD /12
217	BUTLERVILLE, UT	90TH SOUTH, UT	138.00	138.00	Steel - SP	8.64		1	1-795 AAC /37
218	CAMERON, UT	MILFORD, UT	138.00	138.00	Wood - SP	24.98		1	1-795 ACSR 26/7
219	CAMERON, UT	PAROWAN, UT	138.00	138.00	Wood - H	34.56		1	1-397.5 ACSR 26/7
220	CAMERON, UT	SIGURD, UT	138.00	138.00	Wood - H	64.77		1	1-397.5 ACSR 26/7
221	CANYON COMP, WY	STR 204, WY	138.00	138.00	Wood - H	12.17		1	1-795 ACSR 26/7
222	CARBON, UT	HELPER #2, UT	138.00	138.00	Wood - H	1.84		1	1-556.5 ACSR 26/7
223	CARBON, UT	MOAB, UT	138.00	138.00	Wood - H	120.65		1	1-397.5 ACSR 26/7
224	CARBON, UT	SPANISH FORK #1, UT	138.00	138.00	Steel Tower	53.68		1	1-4/0 COMP /19
225	CARBON, UT	SPANISH FORK #2, UT	138.00	138.00	Steel Tower	52.08		1	1-795 ACSR 26/7
226	(x) CENTRAL (UAMPS) #2, UT	SAINT GEORGE, UT	138.00	138.00	Steel - SP	20.37		1	2-1272 ACSR 45/7
227	(y) CENTRAL (UAMPS) #3, UT	SAINT GEORGE, UT	138.00	138.00	Steel - SP		20.09	1	2-1272 ACSR 45/7
228	CLEAR CREEK, WY	PAINTER, UT	138.00	138.00	Wood - SP	5.45		1	1-795 ACSR 26/7
229	CLOVER, UT	BURRASTON PONDS, UT	138.00	138.00	Wood - SP	2.12		1	1-397.5 ACSR 26/7
230	CLOVER, UT	NEBO, UT	138.00	138.00	Wood - SP	7.65		1	1-397.5 ACSR 26/7
231	COLUMBIA, UT	SUNNYSIDE, UT	138.00	138.00	Wood - H	2.24		1	1-397.5 ACSR 26/7
232	COTTONWOOD, UT	HAMMER, UT	138.00	138.00	Wood - SP	5.03		1	1-795 AAC /37
233	COTTONWOOD, UT	MCCLELLAND, UT	138.00	138.00	Steel - SP	5.83		1	1-795 AAC /37
234	COTTONWOOD, UT	SILVER CREEK, UT	138.00	138.00	Wood - SP	30.54		1	2-795 ACSR 26/7
235	CUTLER, UT	WHEELON, UT	138.00	138.00	Wood - SP	0.33		1	1-397.5 ACSR 26/7
236	DANIEL, UT	MIDWAY, UT	138.00	138.00	Wood - SP	3.73		1	1-1272 ACSR 45/7
237	DRY CREEK, UT	SPANISH FORK, UT	138.00	138.00	Steel - SP	4.83		1	1-1272 ACSR 45/7
238	DUMAS, UT	WESTFIELD, UT	138.00	138.00	Wood - SP	18.93		1	1-1272 ACSR 45/7
239	DYNAMO, UT	TRI-CITY #1, UT	138.00	138.00	Steel - SP	2.42		1	2-795 ACSR 26/7
240	DYNAMO, UT	TRI-CITY #2, UT	138.00	138.00	Steel - SP		2.61	1	2-795 ACSR 26/7
241	EAGLE MOUNTAIN, UT	PONY EXPRESS, UT	138.00	138.00	Wood - SP	9.65		1	1-795 ACSR 26/7
242	EAST LAYTON, UT	105 TAP, UT	138.00	138.00	Steel - SP	14.91		1	1-795 ACSR 26/7
243	EBAY TAP, UT	OQUIRRH, UT	138.00	138.00	Wood - SP	1.13		1	1-795 ACSR 26/7
244	EL MONTE, UT	PIONEER, UT	138.00	138.00	Steel - SP	0.98		1	1-1272 ACSR 45/7
245	EL MONTE, UT	STR30B, UT	138.00	138.00	Steel - SP	9.19		1	1-1272 ACSR 45/7
246	EMERY, UT	CLAWSON, UT	138.00	138.00	Wood - SP		3.59	2	1-397.5 ACSR 26/7
247	EVANSTON, WY	RAILROAD, UT	138.00	138.00	Wood - SP	3.28		1	1-795 ACSR 45/7
248	FORT DOUGLAS, UT	MCCLELLAND, UT	138.00	138.00	Wood - SP	3.08		1	1-1557.4 ACSR/TW 36/7
249	FRANKLIN, ID	GREEN CANYON, UT	138.00	138.00	Wood - SP	25.05		1	1-397.5 ACSR 26/7
250	FRANKLIN, ID	TREASURETON, ID	138.00	138.00	Wood - SP	10.43		1	1-795 ACSR 45/7
251	GADSBY, UT	JORDAN, UT	138.00	138.00	Wood - SP	0.35		1	1-1272 AAC /61
252	GADSBY, UT	TERMINAL, UT	138.00	138.00	Wood - SP	5.80		1	1-1272 ACSR 45/7
253	GADSBY, UT	THIRD WEST, UT	138.00	138.00	Wood - SP	1.61		1	1-1272 AAC /61
254	GRAPHITE, UT	MOUNTAIN VIEW, UT	138.00	138.00	Wood - SP	0.75		1	1-397.5 ACSR 26/7
255	GREEN CANYON, UT	NIBLEY, UT	138.00	138.00	Wood - SP	7.02		1	1-1272 ACSR 45/7
256	GREEN CANYON, UT	WHEELON, UT	138.00	138.00	Wood - SP	18.83		1	1-397.5 ACSR 26/7
257	GRINDING, UT	OQUIRRH, UT	138.00	138.00	Wood - SP	6.90		1	1-795 ACSR 45/7
258	GRINDING, UT	TOOELE, UT	138.00	138.00	Wood - SP	14.27		1	1-795 ACSR 45/7
259	HALE, UT	MIDWAY, UT	138.00	138.00	Wood - H	19.09		1	1-397.5 ACSR 26/7
260	HALE, UT	SPANISH FORK, UT	138.00	138.00	Wood - H	18.17		1	1-1272 ACSR 45/7
261	HALE, UT	TANNER, UT	138.00	138.00	Wood - H	7.11		1	1-1272 ACSR 45/7
262	HAMMER, UT	BUTLERVILLE, UT	138.00	138.00	Wood - SP		2.36	1	1-795 ACSR 26/7
263	HIGHLAND, UT	BULL RIVER (LEHI #5), UT	138.00	138.00	Wood - SP	8.56		1	1-1272 ACSR 45/7
264	HONEYVILLE, UT	LAMPO, UT	138.00	138.00	Wood - H	25.24		1	1-397.5 ACSR 26/7
265	HONEYVILLE, UT	WHEELON, UT	138.00	138.00	Steel Tower		13.81	1	1-250 CUHD /12
266	HUNTINGTON, UT	MCFADDEN, UT	138.00	138.00	Wood - H	7.16		1	1-397.5 ACSR 26/7
267	JERUSALEM, UT	NEBO, UT	138.00	138.00	Wood - H	26.14		1	1-397.5 ACSR 26/7
268	JORDAN, UT	MCCLELLAND, UT	138.00	138.00	Wood - SP	4.56		1	1-795 AAC /37
269	JORDAN, UT	TERMINAL, UT	138.00	138.00	Wood - SP	6.28		1	1-1272 ACSR 45/7
270	JORDAN, UT	THIRD WEST, UT	138.00	138.00	Wood - SP	3.74		1	1-1272 AAC /61
271	KEARNS, UT	TAYLORSVILLE, UT	138.00	138.00	Wood - SP	2.73		1	1-795 ACSR 26/7
272	KEARNS, UT	WEST VALLEY, UT	138.00	138.00	Wood - SP	2.45		1	1-795 ACSR 26/7
273	LONE PEAK, UT	CAMP WILLIAMS, UT	138.00	138.00	Steel - SP		8.25	1	1-795 ACSR 26/7
274	MCCLELLAND, UT	MIDVALLEY, UT	138.00	138.00	Wood - SP	6.39		1	1-795 ACSR 26/7
275	MCFADDEN, UT	BLACKHAWK, UT	138.00	138.00	Wood - H	10.56		1	1-795 ACSR 26/7
276	MID VALLEY, UT	90TH SOUTH, UT	138.00	138.00	Wood - H	9.15		1	1-1272 ACSR 45/7
277	MID VALLEY #2, UT	COTTONWOOD, UT	138.00	138.00	Wood - SP	5.03		1	1-1557.4 ACSR/TW 36/7
278	MID VALLEY #1, UT	COTTONWOOD, UT	138.00	138.00	Wood - SP	5.43		1	1-1557.4 ACSR/TW 36/7
279	MID VALLEY, UT	TAYLORSVILLE, UT	138.00	138.00	Wood - SP	4.00	2.00	1	1-1272 AAC /61
280	MIDDLETON, UT	ST. GEORGE, UT	138.00	138.00	Wood - H	0.28		1	1-397.5 ACSR 26/7
281	MOAB, UT	PINTO, UT	138.00	138.00	Wood - H	68.25		1	1-397.5 ACSR 26/7
282	NAUGHTON, WY	CANYON COMP, WY	138.00	138.00	Wood - H	35.32		1	1-795 ACSR 26/7
283	NAUGHTON, WY	PAINTER, WY	138.00	138.00	Wood - H	44.01		1	1-795 ACSR 26/7
284	NEBO, UT	DRY CREEK, UT	138.00	138.00	Wood - H	32.98		1	1-397.5 ACSR 26/7
285	NUCOR STEEL, UT	WHEELON, UT	138.00	138.00	Wood - H	10.71		1	1-795 AAC /37
286	ONEIDA, ID	OVID, UT	138.00	138.00	Wood - H	22.85		1	1-336.4 ACSR 26/7
287	ONIEDA, ID	GRACE, ID	138.00	138.00	Wood - H	18.83		1	1-1272 ACSR 45/7
288	OQUIRRH, UT	BARNEY, UT	138.00	138.00	Wood - H	5.27		1	1-795 ACSR 26/7
289	OQUIRRH, UT	BINGHAM CANYON, UT	138.00	138.00	Wood - H	8.20		1	1-397.5 ACSR 26/7
290	OQUIRRH, UT	TOOELE, UT	138.00	138.00	Steel - SP	22.93		1	2-1272 ACSR 45/7
291	OQUIRRH, UT	WILDFLOWER TAP, UT	138.00	138.00	Wood - H		1.45	1	1-1557.4 ACSR/TW 36/7
292	WILDFLOWER TAP, UT	WILDFLOWER, UT	138.00	138.00	Wood - H	1.05		1	1-397.5 ACSR 26/7
293	PAINTER, UT	RAILROAD, UT	138.00	138.00	Wood - H	7.15		1	1-1272 ACSR 45/7
294	PARRISH #105, UT	TERMINAL, UT	138.00	138.00	Steel - SP	23.63		1	1-250 CUHD /12
295	PAROWAN, UT	WEST CEDAR, UT	138.00	138.00	Wood - H	21.07		1	1-397.5 ACSR 26/7
296	PARRISH, UT	TAP TO N. SALT LAKE, UT	138.00	138.00	Steel - SP	1.00	11.00	1	1-954 ACSR 54/7
297	PARRISH, UT	TERMINAL #1, UT	138.00	138.00	Steel - SP	15.83		1	1-250 CUHD /12
298	PARRISH, UT	TERMINAL #2, UT	138.00	138.00	Steel - SP		14.06	1	1-250 CUHD /12
299	RAILROAD, UT	CANYON COMP, WY	138.00	138.00	Wood - H	17.38		1	1-795 ACSR 26/7
300	ST GEORGE, UT	PURGATORY FLAT, UT	138.00	138.00	Wood - SP	10.02		2	1-1272 ACSR 45/7
301	RED BUTTE, UT	WEST CEDAR, UT	138.00	138.00	Wood - H	48.98		1	1-397.5 ACSR 26/7
302	RIVERDALE, UT	EAST LAYTON, UT	138.00	138.00	Steel - SP	1.00	6.00	1	1-795 ACSR 26/7
303	SHICK, UT	PARRISH, UT	138.00	138.00	Wood - H		10.02	1	1-250 CUHD /12
304	SILVER CREEK, UT	DANIEL, UT	138.00	138.00	Wood - SP	17.08		1	1-795 ACSR 26/7
305	SILVER CREEK, UT	RAILROAD, UT	138.00	138.00	Wood - SP	72.43		1	1-1272 ACSR 45/7
306	SPANISH FORK, UT	TANNER, UT	138.00	138.00	Wood - H	10.01		1	1-959.6 ACSS/TW
307	SUNRISE, UT	OQUIRRH, UT	138.00	138.00	Wood - SP		2.37	1	1-1557.4 ACSR/TW 36/7
308	SYRACUSE, UT	ANGEL #1, UT	138.00	138.00	Wood - SP		6.53	1	2-250 CUHD /12
309	SYRACUSE, UT	CLEARFIELD SOUTH, UT	138.00	138.00	Steel - SP	4.94		1	1-959.6 ACSS/TW
310	SYRACUSE, UT	PARRISH, UT	138.00	138.00	Steel Tower	15.09		1	1-1272 ACSR 45/7
311	TAP TO ANGEL NORTH, UT	TAP TO PARRISH, UT	138.00	138.00	Wood - H	12.67		1	1-250 CUHD /12
312	TAYLORSVILLE, UT	90TH SOUTH, UT	138.00	138.00	Wood - SP	6.00	2.00	1	1-1557.4 ACSR/TW 36/7
313	TERMINAL, UT	KENNECOTT, UT	138.00	138.00	Steel - SP	15.08		1	1-795 ACSR 26/7
314	TERMINAL, UT	MIDVALLEY #1, UT	138.00	138.00	Wood - H	7.47		1	1-1272 ACSR 45/7
315	TERMINAL, UT	MIDVALLEY #2, UT	138.00	138.00	Wood - H	6.77		1	1-1272 AAC /61
316	TERMINAL, UT	ROWLEY, UT	138.00	138.00	Wood - H	53.42		1	1-795 AAC /37
317	TERMINAL, UT	TOOELE, UT	138.00	138.00	Wood - H	26.00	8.00	1	1-397.5 ACSR 26/7
318	TERMINAL, UT	WEST VALLEY, UT	138.00	138.00	Wood - SP	6.77		1	1-1557.4 ACSR/TW 36/7
319	THREEMILE KNOLL, ID	GRACE #1, ID	138.00	138.00	Wood - H	17.47		1	1-250 CUHD /12
320	THREEMILE KNOLL, ID	GRACE #2, ID	138.00	138.00	Wood - H	17.35		1	1-1272 ACSR 45/7
321	THREEMILE KNOLL, ID	MONSANTO #1, ID	138.00	138.00	Wood - H	1.77		1	1-1272 ACSR 45/7
322	THREEMILE KNOLL, ID	MONSANTO #2, ID	138.00	138.00	Steel - SP	1.76		1	1-1272 ACSR 45/7
323	TIMP #1, UT	DYNAMO, UT	138.00	138.00	Steel - SP	2.22		1	1-1557.4 ACSR/TW 36/7
324	TIMP #2, UT	DYNAMO, UT	138.00	138.00	Steel - SP		2.22	1	1-1557.4 ACSR/TW 36/7
325	TIMP, UT	HALE, UT	138.00	138.00	Steel - SP	4.32		1	1-1557.4 ACSR/TW 36/7
326	TIMP, UT	SPANISH FORK, UT	138.00	138.00	Wood - H	23.29		1	1-1272 ACSR 45/7
327	TIMP, UT	VINEYARD, UT	138.00	138.00	Wood - SP	2.42		1	1-1272 ACSR 45/7
328	TREASURETON, ID	GRACE, ID	138.00	138.00	Steel Tower	25.15		1	1-250 CUHD /12
329	TREASURETON, ID	GRACE #2, ID	138.00	138.00	Steel Tower		25.22	1	1-250 CUHD /12
330	TREASURETON, ID	ONEIDA, ID	138.00	138.00	Wood - H	6.29		1	1-1272 ACSR 45/7
331	TRI-CITY, UT	OQUIRRH, UT	138.00	138.00	Wood - SP	3.00	19.00	1	1-1557.4 ACSR/TW 36/7
332	TRI-CITY, UT	SUNRISE, ID	138.00	138.00	Wood - SP	22.52		1	1-1557.4 ACSR/TW 36/7
333	TRI-CITY, UT	WESTFIELD, UT	138.00	138.00	Wood - H	14.53		1	1-1272 ACSR 45/7
334	VERNAL (WAPA), UT	NAPLES, UT	138.00	138.00	Wood - SP	0.27		1	1-1557.4 ACSR/TW 36/7
335	WEST CEDAR, UT	THREE PEAKS, UT	138.00	138.00	Wood - SP	19.76		1	1-795 ACSR 45/7
336	WEST VALLEY, UT	OQUIRRH, UT	138.00	138.00	Wood - H	9.00		1	1-1557.4 ACSR/TW 36/7
337	WESTFIELD, UT	HALE, UT	138.00	138.00	Wood - H	13.25		1	1-795 ACSR 26/7
338	(z) WHEELON, UT	AMERICAN FALLS, ID	138.00	138.00	Wood - H	87.50		1	1-250 CUHD /12
339	WHEELON #1, UT	TREASURETON, ID	138.00	138.00	Steel Tower	29.24		1	1-250 CUHD /12
340	WHEELON #2, UT	TREASURETON, ID	138.00	138.00	Steel Tower		29.25	1	1-250 CUHD /12
341	WHEELON #3, UT	TREASURETON, ID	138.00	138.00	Wood - H	29.24		1	1-250 CUHD /12
342	TOOELE, UT	GRANTSVILLE, UT	138.00	138.00	Wood - SP	13.48		1	1-397.5 ACSR 26/7
343	WEST VALLEY, UT	WEST VALLEY G1, UT	138.00	138.00		0.13		1	1-1272 ACSR 45/7
344	WEST VALLEY, UT	WEST VALLEY G2, UT	138.00	138.00		0.11		1	1-1272 ACSR 45/7
345	WEST VALLEY, UT	WEST VALLEY G3, UT	138.00	138.00		0.08		1	1-1272 ACSR 45/7
346	WEST VALLEY, UT	WEST VALLEY G4, UT	138.00	138.00		0.06		1	1-1272 ACSR 45/7
347	WEST VALLEY, UT	WEST VALLEY G5, UT	138.00	138.00		0.14		1	1-1272 ACSR 45/7
348	EMERY, UT	HUNTER STARTUP #1 & #2, UT	138.00	138.00		0.10		1	1-795 ACSR 26/7
349	EMERY, UT	HUNTER STARTUP #3, UT	138.00	138.00		0.26		1	1-397.5 ACSR 26/7
350	ANGEL, UT	SMITHS, UT	138.00	138.00		0.10		1	1-397.5 ACSR 26/7
351	WEST VALLEY, UT	WEST VALLEY DISTRIBUTION, UT	138.00	138.00		0.20		1	1-795 ACSR 26/7
352	EAGLE MOUNTAIN, UT	WESTSIDE (UAMPS), UT	138.00	138.00		0.02		1	1-795 ACSR 26/7
353	ENTERPRISE, UT	COVE MOUNTAIN, UT	138.00	138.00		0.10		1	1-795 ACSR 26/7
354	EMERY, UT	HTR 3 STRTUP, UT	138.00	138.00		0.61		1	1-250 CCHC /1
355	RED BUTTE, UT	ST GEORGE, UT	138.00	138.00		0.28		1	1-1272 ACSR 45/7
356	HUNTINGTON, UT	STARTUP LINE, UT	138.00	138.00		0.40		1	1-795 ACSR 45/7
357	CARBON, UT	KETCHUM METERING, UT	138.00	138.00		0.62		1	1-397.5 ACSR 26/7
358	EMERY, UT	EMERY, UT #1	138.00	138.00		0.23		1	3-1272 ACSR 45/7
359	EMERY, UT	EMERY, UT #2	138.00	138.00		0.16		1	3-1272 ACSR 45/7
360	PAINTER, WY	PAINTER TAP, WY	138.00	138.00		0.15		1	1-1272 ACSR 45/7
361	SARATOGA, UT	SARATOGA TAP, UT	138.00	138.00		3.70		1	1272 ACSR 45/7
362	OQUIRRH, UT	OQUIRRH, UT #1	138.00	138.00		0.25		1	2-1557 ACSS/TW 36/7
363	OQUIRRH, UT	OQUIRRH, UT #2	138.00	138.00		0.11		1	2-1557 ACSS/TW 36/7
364	138 kV Costs and Expenses									44,560,059	475,161,078	519,721,137	494,449	2,552,457	96,722	3,143,628
365	All 115kV Lines					1,687.87				10,378,400	375,875,878	386,254,278	111,818	9,525,728	627,639	10,265,185
366	All 69kV Lines					2,901.12				10,976,750	460,147,311	471,124,061	134,863	5,718,589	360,808	6,214,260
367	All 57kV Lines					77.53				139,945	15,494,074	15,634,019	5,541	161,132	2,029	168,702
368	All 46kV Lines					2,517.69				12,835,892	371,318,750	384,154,642	185,597	3,340,942	34,351	3,560,890
36	TOTAL					17,880.77	686.91	362		432,094,408	6,703,827,692	7,135,922,100	1,630,364	33,953,022	2,242,603	37,825,989

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: TransmissionLineStartPoint

Certain transmission lines reported on pages 422-423 are part of exchange agreements with various third parties. For further discussion, see also page 328-330, Transmission of electricity for others in this Form No. 1.

(b) Concept: TransmissionLineStartPoint

The Alvey - Dixonville 500kV line is jointly owned by PacifiCorp and Bonneville Power Administration, each with an undivided interest of 50.0%. Plant cost reported for this line represents PacifiCorp's 50.0% share. Operations and maintenance costs are shared between the two parties and responsibility is as follows: PacifiCorp 58.0% and the Bonneville Power Administration 42.0%.

The Broadview - Colstrip A 500kV line is jointly owned by PacifiCorp, NorthWestern Energy, Puget Sound Energy, Avista Corporation and Portland General Electric Company, in which PacifiCorp owns 6.8% of the line. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp's share.

(d) Concept: TransmissionLineStartPoint

The Broadview - Colstrip B 500kV line is jointly owned by PacifiCorp, NorthWestern Energy, Puget Sound Energy, Avista Corporation and Portland General Electric Company, in which PacifiCorp owns 6.8% of the line. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp's share.

(e) Concept: TransmissionLineStartPoint

The Broadview - Townsend A 500kV line is jointly owned by PacifiCorp, NorthWestern Energy, Puget Sound Energy, Avista Corporation and Portland General Electric Company, in which PacifiCorp owns 8.1% of the line. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp's share.

(f) Concept: TransmissionLineStartPoint

The Broadview - Townsend B 500kV line is jointly owned by PacifiCorp, NorthWestern Energy, Puget Sound Energy, Avista Corporation and Portland General Electric Company, in which PacifiCorp owns 8.1% of the line. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp's share.

(g) Concept: TransmissionLineStartPoint

The Dixonville - Meridian 500kV line is jointly owned by PacifiCorp and Bonneville Power Administration, each with an undivided interest of 50.0%. Plant cost reported for this line represents PacifiCorp's 50.0% share. Operations and maintenance costs are shared between the two parties and responsibility is as follows: PacifiCorp 58.0% and the Bonneville Power Administration 42.0%.

(h) Concept: TransmissionLineStartPoint

The Hemingway - Summer Lake 500kV line is jointly owned by PacifiCorp and Idaho Power Company with an undivided interest of 78.0% and 22.0%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

(i) Concept: TransmissionLineStartPoint

The Midpoint - Hemingway 500kV line is jointly owned by PacifiCorp and Idaho Power Company with an undivided interest of 63.0% and 37.0%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

(j) Concept: TransmissionLineStartPoint

The Borah - Midpoint #1 345kV line is jointly owned by PacifiCorp and Idaho Power Company. Ownership of the line designation Borah - Adelaide - Midpoint #1 is as follows: PacifiCorp 35.6%, Idaho Power Company 64.4%. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

(k) Concept: TransmissionLineStartPoint

The Borah - Midpoint #2 345kV line is jointly owned by PacifiCorp and Idaho Power Company. Ownership of the line designation Borah - Adelaide - Midpoint #2 is as follows: PacifiCorp 35.6%, Idaho Power Company 64.4%. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

(l) Concept: TransmissionLineStartPoint

The Goshen - Kinport 345kV line is jointly owned by PacifiCorp and Idaho Power Company with an undivided interest of 81.7% and 18.3%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

(m) Concept: TransmissionLineStartPoint

The Jim Bridger - Goshen 345kV line is jointly owned by PacifiCorp and Idaho Power Company with an undivided interest of 70.8% and 29.2%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

(n) Concept: TransmissionLineStartPoint


The Jim Bridger - Borah 345kV line is jointly owned by PacifiCorp and Idaho Power Company. Ownership of the line designation is as follows:
Designation	PacifiCorp	Idaho Power Company
Jim Bridger - Populus #1	71.0%	29.0%
Populus - Borah #1	71.0%	29.0%
Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

(o) Concept: TransmissionLineStartPoint


The Jim Bridger - Kinport 345kV line is jointly owned by PacifiCorp and Idaho Power Company. Ownership of the line designation is as follows:
Designation	PacifiCorp	Idaho Power Company
Jim Bridger - Populus #2	71.0%	29.0%
Populus - Kinport	71.0%	29.0%
Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

(p) Concept: TransmissionLineStartPoint

The Kinport - Midpoint 345kV line is jointly owned by PacifiCorp and Idaho Power Company with an undivided interest of 26.8% and 73.2%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

(q) Concept: TransmissionLineStartPoint

A 1.5 mile segment of the Casper - Dave Johnston 230kV line is jointly owned by PacifiCorp and Black Hills Power with an undivided interest of 43.75% and 56.25%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp's share.

(r) Concept: TransmissionLineStartPoint

The Hurricane - Walla Walla 230kV line is jointly owned by PacifiCorp and Idaho Power Company with an undivided interest of 59.2% and 40.8%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

(s) Concept: TransmissionLineStartPoint

The Antelope - Goshen 161kV line is jointly owned by PacifiCorp and Idaho Power Company with an undivided interest of 78.1% and 21.9%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

(t) Concept: TransmissionLineStartPoint

The Big Grassy - Jefferson 161kV line is jointly owned by PacifiCorp and Idaho Power company with an undivided interest of 62.2% and 37.8%, respectively. Plant costs and operations and maintenance costs reported for this line represents PacifiCorp's share.

(u) Concept: TransmissionLineStartPoint

The Goshen - Jefferson 161kV line is jointly owned by PacifiCorp and Idaho Power Company with an undivided interest of 77.0% and 23.0%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

(v) Concept: TransmissionLineStartPoint

The Antelope - Scoville #1 138kV line is jointly owned by PacifiCorp and Idaho Power Company with an undivided interest of 33.3% and 66.7%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

(w) Concept: TransmissionLineStartPoint

The Antelope - Scoville #2 138kV line is jointly owned by PacifiCorp and Idaho Power Company with an undivided interest of 33.3% and 66.7%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

(x) Concept: TransmissionLineStartPoint

The Central #2 - Saint George 138kV line is jointly owned by PacifiCorp and Utah Associated Municipal Power Systems with an undivided interest of 43.26% and 56.74%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp's share.

(y) Concept: TransmissionLineStartPoint

The Central #3 - Saint George 138kV line is jointly owned by PacifiCorp and Utah Associated Municipal Power Systems with an undivided interest of 43.26% and 56.74%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp's share.

(z) Concept: TransmissionLineStartPoint

The Wheelon - American Falls 138kV line is jointly owned by PacifiCorp and Idaho Power Company with an undivided interest of 96.4% and 3.6%, respectively. Plant cost and operations and maintenance costs reported for this line represents PacifiCorp�s share.

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

TRANSMISSION LINES ADDED DURING YEAR

Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines.
Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic.

LINE DESIGNATION

SUPPORTING STRUCTURE

CIRCUITS PER STRUCTURE

CONDUCTORS

LINE COST

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

(o)

(p)

(q)

AEOLUS, WY

ROCK CREEK WIND II, WY

38.35

Wood/Steel

8.00

1-1272

ACSR 45/7

TI400 (24'-6")

230

52,297,950

31,352,002

83,649,952

Overground

TOTAL

38.35

8.00

52,297,950

31,352,002

83,649,952

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

SUBSTATIONS
Report below the information called for concerning substations of the respondent as of the end of the year. Substations which serve only one industrial or street railway customer should not be listed below. Substations with capacities of Less than 10 MVA except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
		Character of Substation		VOLTAGE (In MVa)						Conversion Apparatus and Special Equipment
Line No.	SubstationNameAndLocation Name and Location of Substation (a)	SubstationCharacterDescription Transmission or Distribution (b)	SubstationCharacterAttendedOrUnattended Attended or Unattended (b-1)	PrimaryVoltageLevel Primary Voltage (In MVa) (c)	SecondaryVoltageLevel Secondary Voltage (In MVa) (d)	TertiaryVoltageLevel Tertiary Voltage (In MVa) (e)	SubstationInServiceCapacity Capacity of Substation (In Service) (In MVa) (f)	NumberOfTransformersInService Number of Transformers In Service (g)	Number of Spare Transformers (h)	ConversionApparatusAndSpecialEquipmentType Type of Equipment (i)	NumberOfConversionApparatusAndSpecialEquipmentUnits Number of Units (j)	CapacityOfConversionApparatusAndSpecialEquipment Total Capacity (In MVa) (k)
1	BELMONT, CA	Distribution	UNATTENDED	69.00	12.47		25	1
2	BIG SPRINGS, CA	Distribution	UNATTENDED	69.00	12.47		6	1
3	CASTELLA, CA	Distribution	UNATTENDED	69.00	2.40		2	3
4	CLEAR LAKE, CA	Distribution	UNATTENDED	69.00	12.47		6	4
5	DOG CREEK, CA	Distribution	UNATTENDED	69.00	2.40		0	1
6	DORRIS, CA	Distribution	UNATTENDED	69.00	12.47		8	3
7	FORT JONES, CA	Distribution	UNATTENDED	69.00	12.47		6	1
8	GASQUET, CA	Distribution	UNATTENDED	115.00	12.47		9	1
9	GREENHORN, CA	Distribution	UNATTENDED	69.00	12.47		13	1
10	HAMBURG, CA	Distribution	UNATTENDED	69.00	2.40		1	1
11	HAPPY CAMP, CA	Distribution	UNATTENDED	69.00	12.47		8	3
12	HORNBROOK, CA	Distribution	UNATTENDED	69.00	12.47		4	3
13	INTERNATIONAL PAPER, CA	Distribution	UNATTENDED	69.00	2.40		6	3
14	LAKE EARL, CA	Distribution	UNATTENDED	69.00	12.47		13	1
15	LASSEN, CA	Distribution	UNATTENDED	115.00	12.47		25	1
16	LITTLE SHASTA, CA	Distribution	UNATTENDED	69.00	7.20	2.40	2	3
17	LUCERNE, CA	Distribution	UNATTENDED	115.00	12.47		9	1
18	MACDOEL, CA	Distribution	UNATTENDED	69.00	20.80		37	2	1
19	MCCLOUD, CA	Distribution	UNATTENDED	69.00	12.47		6	1
20	MILLER REDWOOD, CA	Distribution	UNATTENDED	69.00	12.47		4	3
21	MONTAGUE, CA	Distribution	UNATTENDED	69.00	12.47		6	1
22	MORRISON CREEK, CA	Distribution	UNATTENDED	69.00	12.47		14	1
23	MOUNT SHASTA, CA	Distribution	UNATTENDED	69.00	12.47		16	4
24	NEWELL, CA	Distribution	UNATTENDED	69.00	12.47		13	1
25	NORTH DUNSMUIR, CA	Distribution	UNATTENDED	69.00	12.47		6	6
26	NORTHCREST, CA	Distribution	UNATTENDED	69.00	12.47		19	4
27	NUTGLADE, CA	Distribution	UNATTENDED	69.00	2.40		2	3
28	PATRICKS CREEK, CA	Distribution	UNATTENDED	115.00	7.20		1	1
29	PEREZ, CA	Distribution	UNATTENDED	69.00	12.47		2	3
30	REDWOOD, CA	Distribution	UNATTENDED	69.00	12.47		14	1
31	SCOTT BAR, CA	Distribution	UNATTENDED	69.00	12.47		2	3
32	SEIAD, CA	Distribution	UNATTENDED	69.00	12.47		2	3
33	SHASTINA, CA	Distribution	UNATTENDED	69.00	20.80		6	3
34	SHOTGUN CREEK, CA	Distribution	UNATTENDED	69.00	12.47		1	1
35	SMITH RIVER, CA	Distribution	UNATTENDED	69.00	12.47		5	3
36	SNOW BRUSH, CA	Distribution	UNATTENDED	69.00	7.20		1	3
37	SOUTH DUNSMUIR, CA	Distribution	UNATTENDED	69.00	4.16		2	3
38	TULELAKE, CA	Distribution	UNATTENDED	69.00	12.47		20	1
39	TUNNEL, CA	Distribution	UNATTENDED	69.00	12.47	2.40	6	6
40	WALKER BRYAN, CA	Distribution	UNATTENDED	69.00	12.47		8	3
41	YUBA, CA	Distribution	UNATTENDED	69.00	12.47		4	3
42	YUROK, CA	Distribution	UNATTENDED	69.00	12.47		4	3
43	AGER, CA	Transmission	UNATTENDED	115.00	69.00	12.47	5	3
44	ALTURAS, CA	Transmission	UNATTENDED	115.00	69.00	12.47	43	2
45	COPCO #2, CA	Transmission	ATTENDED	115.00	69.00	12.47	52	4	1
46	COPCO #2 230KV, CA	Transmission	ATTENDED	230.00	115.00	12.47	514	3
47	CRAG VIEW, CA	Transmission	UNATTENDED	115.00	69.00	12.47	19	3
48	DEL NORTE, CA	Transmission	UNATTENDED	115.00	69.00	13.20	150	2
49	WEED, CA	Transmission	UNATTENDED	115.00	69.00		75	2
50	YREKA, CA	Transmission	UNATTENDED	115.00	69.00	12.47	145	3
51	ALEXANDER, ID	Distribution	UNATTENDED	46.00	12.47		4	1
52	AMMON, ID	Distribution	UNATTENDED	161.00	13.20		30	1
53	ANDERSON, ID	Distribution	UNATTENDED	69.00	12.47		20	1
54	ARCO, ID	Distribution	UNATTENDED	69.00	12.47		6	1
55	ARIMO, ID	Distribution	UNATTENDED	46.00	12.47		8	1
56	ASHTON, ID	Distribution	ATTENDED	46.00	12.47	2.40	13	2
57	BANCROFT, ID	Distribution	UNATTENDED	46.00	12.47		4	1
58	BELSON, ID	Distribution	UNATTENDED	69.00	12.47		14	1
59	BERENICE, ID	Distribution	UNATTENDED	69.00	12.47		11	1
60	CAMAS, ID	Distribution	UNATTENDED	69.00	12.47		14	1
61	CANYON CREEK, ID	Distribution	UNATTENDED	69.00	24.90		20	1
62	CHESTERFIELD, ID	Distribution	UNATTENDED	46.00	12.47		5	1
63	CINDER BUTTE, ID	Distribution	UNATTENDED	161.00	12.47		30	1
64	CLEMENTS, ID	Distribution	UNATTENDED	69.00	12.47		13	1
65	CLIFTON, ID	Distribution	UNATTENDED	46.00	12.47		11	1
66	COVE, ID	Distribution	UNATTENDED	46.00	12.47		6	1
67	DOWNEY, ID	Distribution	UNATTENDED	46.00	12.47		5	1
68	DUBOIS, ID	Distribution	UNATTENDED	69.00	12.47		13	1
69	EASTMONT, ID	Distribution	UNATTENDED	69.00	12.47		14	1
70	EGIN, ID	Distribution	UNATTENDED	69.00	12.47		14	1
71	EIGHT MILE, ID	Distribution	UNATTENDED	46.00	12.47		4	1
72	GEORGETOWN, ID	Distribution	UNATTENDED	69.00	12.47		6	1
73	GRACE CITY, ID	Distribution	UNATTENDED	46.00	12.47		14	1
74	HAMER, ID	Distribution	UNATTENDED	69.00	12.47		14	1
75	HAYES, ID	Distribution	UNATTENDED	69.00	12.47		9	1
76	HENRY, ID	Distribution	UNATTENDED	46.00	12.47		1	1
77	HOLBROOK, ID	Distribution	UNATTENDED	69.00	12.47		6	1
78	HOOPES, ID	Distribution	UNATTENDED	69.00	12.47		14	1	1
79	HORSLEY, ID	Distribution	UNATTENDED	46.00	12.47		4	1
80	IDAHO FALLS, ID	Distribution	UNATTENDED	46.00	12.47		20	1
81	INDIAN CREEK, ID	Distribution	UNATTENDED	69.00	7.20		3	1
82	JEFFCO, ID	Distribution	UNATTENDED	69.00	24.90		22	1
83	KETTLE, ID	Distribution	UNATTENDED	69.00	24.90		14	1
84	LAVA, ID	Distribution	UNATTENDED	46.00	12.47		6	1
85	LUND, ID	Distribution	UNATTENDED	46.00	12.47		5	1
86	MCCAMMON, ID	Distribution	UNATTENDED	46.00	12.47		4	1
87	MENAN, ID	Distribution	UNATTENDED	69.00	12.47		11	1
88	MERRILL, ID	Distribution	UNATTENDED	69.00	12.47		20	1
89	MILLER, ID	Distribution	UNATTENDED	69.00	12.47		5	1
90	MONTPELIER, ID	Distribution	UNATTENDED	69.00	12.47		11	1
91	MOODY, ID	Distribution	UNATTENDED	69.00	24.90		14	1
92	MUD LAKE, ID	Distribution	UNATTENDED	69.00	12.47		14	1
93	NEWDALE, ID	Distribution	UNATTENDED	69.00	12.47		20	1
94	OSGOOD, ID	Distribution	UNATTENDED	69.00	12.47		20	1
95	PRESTON, ID	Distribution	UNATTENDED	46.00	12.47		13	1
96	RAYMOND, ID	Distribution	UNATTENDED	69.00	12.47		6	1
97	RENO, ID	Distribution	UNATTENDED	69.00	12.47		20	1
98	ROBERTS, ID	Distribution	UNATTENDED	69.00	12.47		8	1
99	RUBY, ID	Distribution	UNATTENDED	69.00	12.47		14	1
100	SAND CREEK, ID	Distribution	UNATTENDED	69.00	12.47		40	2
101	SANDUNE, ID	Distribution	UNATTENDED	69.00	24.90		30	1
102	SHELLEY, ID	Distribution	UNATTENDED	46.00	12.47		20	1
103	SMITH, ID	Distribution	UNATTENDED	69.00	12.47		20	1
104	SOUTH FORK, ID	Distribution	UNATTENDED	69.00	12.47		14	1
105	SPUD, ID	Distribution	UNATTENDED	46.00	12.47		8	1
106	ST CHARLES, ID	Distribution	UNATTENDED	69.00	12.47		5	1
107	SUGAR CITY, ID	Distribution	UNATTENDED	69.00	12.47		13	1
108	SUNNYDELL, ID	Distribution	UNATTENDED	69.00	12.47		13	1
109	TANNER, ID	Distribution	ATTENDED	46.00	12.47		4	1
110	TARGHEE, ID	Distribution	UNATTENDED	46.00	12.47		4	1
111	THORNTON, ID	Distribution	UNATTENDED	69.00	12.47		7	1
112	UCON, ID	Distribution	UNATTENDED	69.00	12.47		7	1
113	WATKINS, ID	Distribution	UNATTENDED	69.00	24.90		14	1
114	WEBSTER, ID	Distribution	UNATTENDED	69.00	12.47		20	1
115	WESTON, ID	Distribution	UNATTENDED	46.00	12.47		4	1
116	WESTWOOD, ID	Distribution	UNATTENDED	161.00	13.20		30	1
117	WINSPER, ID	Distribution	UNATTENDED	69.00	24.90		22	1
118	AMPS, ID	Transmission	UNATTENDED	230.00	69.00	12.47	75	1
119	(a) ANTELOPE, ID	Transmission	UNATTENDED	230.00	161.00	13.80	419	3	1
120	(b) BIG GRASSY, ID	Transmission	UNATTENDED	161.00	69.00	12.47	67	1
121	BONNEVILLE, ID	Transmission	UNATTENDED	161.00	69.00	6.60	67	1
122	CONDA, ID	Transmission	UNATTENDED	138.00	46.00	12.47	67	1
123	FISHCREEK, ID	Transmission	UNATTENDED	161.00	46.00	6.60	25	3	1
124	FRANKLIN, ID	Transmission	UNATTENDED	138.00	69.00	13.80	75	1
125	(c) GOSHEN, ID	Transmission	UNATTENDED	345.00	161.00	13.80	1608	5
126	GRACE, ID	Transmission	ATTENDED	161.00	138.00	12.47	217	2
127	(d) JEFFERSON, ID	Transmission	UNATTENDED	161.00	69.00	6.60	133	(s) 2
128	MALAD, ID	Transmission	UNATTENDED	138.00	69.00	6.60	39	4	1
129	(e) MIDPOINT, ID	Transmission	UNATTENDED	500.00	345.00	34.50	1500	3	1
130	OVID, ID	Transmission	UNATTENDED	138.00	69.00	12.47	105	2
131	REXBURG, ID	Transmission	UNATTENDED	161.00	69.00	12.47	210	3
132	RIGBY, ID	Transmission	UNATTENDED	161.00	69.00	13.80	229	4	1
133	SAINT ANTHONY, ID	Transmission	UNATTENDED	69.00	46.00	2.40	33	2
134	SCOVILLE, ID	Transmission	UNATTENDED	138.00	69.00	13.80	67	1
135	SUGARMILL, ID	Transmission	UNATTENDED	161.00	69.00	12.47	268	4
136	(f) THREEMILE KNOLL, ID	Transmission	UNATTENDED	345.00	138.00	13.20	775	2
137	TREASURETON, ID	Transmission	UNATTENDED	230.00	138.00	13.80	534	2	1
138	(g) COLSTRIP, MT	Transmission	ATTENDED	500.00	230.00		68	2
139	(h) BROADVIEW, MT	Transmission	UNATTENDED	500.00	230.00		32	2
140	YELLOWTAIL, MT	Transmission	UNATTENDED	230.00	161.00	13.20	100	1
141	26TH STREET, OR	Distribution	UNATTENDED	20.80	4.16		5	1
142	35TH STREET, OR	Distribution	UNATTENDED	20.80	2.40		15	3
143	AGNESS AVE, OR	Distribution	UNATTENDED	115.00	12.47		25	1
144	ALBINA, OR	Distribution	UNATTENDED	115.00	12.47		120	2
145	ALDERWOOD, OR	Distribution	UNATTENDED	69.00	12.47		45	2
146	ARLINGTON, OR	Distribution	UNATTENDED	69.00	12.47		5	1
147	ASHLAND, OR	Distribution	UNATTENDED	115.00	12.47		20	1
148	ATHENA, OR	Distribution	UNATTENDED	69.00	12.47		9	1
149	BANDON TIE, OR	Distribution	UNATTENDED	20.80	12.47		8	3	1
150	BEACON, OR	Distribution	UNATTENDED	69.00	12.47		9	3
151	BEALL LANE, OR	Distribution	UNATTENDED	115.00	12.47		25	1
152	BEATTY, OR	Distribution	UNATTENDED	69.00	12.47		6	1
153	BEND, OR	Distribution	ATTENDED	69.00	12.47		31	3
154	BLALOCK, OR	Distribution	UNATTENDED	69.00	12.47		2	3
155	BLOSS, OR	Distribution	UNATTENDED	115.00	12.47		32	2
156	BLY, OR	Distribution	UNATTENDED	69.00	12.47		6	3
157	BOISE CASCADE, OR	Distribution	UNATTENDED	69.00	12.47	4.16	3	1
158	BONANZA, OR	Distribution	UNATTENDED	69.00	12.47		8	3
159	BOND, OR	Distribution	UNATTENDED	69.00	12.47		25	1
160	BROOKHURST, OR	Distribution	UNATTENDED	115.00	12.47		50	2
161	BROWNSVILLE, OR	Distribution	UNATTENDED	69.00	20.80		13	1
162	BRYANT, OR	Distribution	UNATTENDED	69.00	12.47		40	2
163	BUCHANAN, OR	Distribution	UNATTENDED	115.00	20.80		45	2
164	BUCKAROO, OR	Distribution	UNATTENDED	69.00	12.47		34	2
165	CAMPBELL, OR	Distribution	UNATTENDED	115.00	12.47		45	2
166	CANNON BEACH, OR	Distribution	UNATTENDED	115.00	12.47		13	1
167	CANYONVILLE, OR	Distribution	UNATTENDED	115.00	12.47		25	1
168	CARNES, OR	Distribution	UNATTENDED	69.00	12.47		9	3
169	CASEBEER, OR	Distribution	UNATTENDED	69.00	20.80		20	1
170	CAVEMAN, OR	Distribution	UNATTENDED	115.00	12.47		45	2
171	CHERRY LANE, OR	Distribution	UNATTENDED	69.00	12.47		25	1
172	CHILOQUIN MARKET, OR	Distribution	UNATTENDED	69.00	12.47		9	3
173	CHINA HAT, OR	Distribution	UNATTENDED	69.00	12.47		25	1
174	CIRCLE BLVD, OR	Distribution	UNATTENDED	115.00	20.80		80	2
175	CLEVELAND AVE, OR	Distribution	UNATTENDED	69.00	12.47		45	2
176	CLOAKE, OR	Distribution	UNATTENDED	69.00	20.80		20	1
177	COBURG, OR	Distribution	UNATTENDED	69.00	20.80	2.40	10	3
178	COLISEUM, OR	Distribution	UNATTENDED	20.80	4.16		12	2
179	CONSER ROAD, OR	Distribution	UNATTENDED	115.00	20.80		30	1	1
180	COOS RIVER, OR	Distribution	UNATTENDED	115.00	20.80		20	1
181	COQUILLE, OR	Distribution	UNATTENDED	115.00	20.80		40	2
182	CREEK, OR	Distribution	UNATTENDED	69.00	34.50		5	1
183	CROOKED RIVER RANCH, OR	Distribution	UNATTENDED	69.00	20.80		23	2
184	CROWFOOT, OR	Distribution	UNATTENDED	115.00	20.80		20	1
185	CULLY, OR	Distribution	UNATTENDED	115.00	12.47		25	1
186	CULVER, OR	Distribution	UNATTENDED	69.00	12.47	7.20	13	1
187	DAIRY, OR	Distribution	UNATTENDED	69.00	12.47		25	1
188	DALLAS, OR	Distribution	UNATTENDED	115.00	20.80		50	2
189	DALREED, OR	Distribution	UNATTENDED	230.00	34.50	13.20	95	4	1
190	DEVILS LAKE, OR	Distribution	UNATTENDED	115.00	20.80		50	2
191	DIXON, OR	Distribution	UNATTENDED	115.00	4.16	7.20	7	1
192	DODGE BRIDGE, OR	Distribution	UNATTENDED	69.00	20.80		25	2
193	DOWELL, OR	Distribution	UNATTENDED	115.00	12.47		25	1
194	EASY VALLEY, OR	Distribution	UNATTENDED	115.00	12.47		45	2
195	EMPIRE, OR	Distribution	UNATTENDED	115.00	20.80		20	1
196	ENTERPRISE, OR	Distribution	UNATTENDED	69.00	20.80	12.47	19	2
197	FERN HILL, OR	Distribution	UNATTENDED	115.00	12.47	7.20	13	1
198	FIELDER CREEK, OR	Distribution	UNATTENDED	115.00	20.80		20	1
199	FOOTHILLS, OR	Distribution	UNATTENDED	69.00	12.47		21	4
200	FRALEY, OR	Distribution	UNATTENDED	69.00	12.47		4	3
201	GARDEN VALLEY, OR	Distribution	UNATTENDED	69.00	20.80		20	1
202	GLENDALE, OR	Distribution	UNATTENDED	230.00	12.47		25	2	1
203	GLENEDEN, OR	Distribution	UNATTENDED	20.80	4.16		6	1
204	GLIDE, OR	Distribution	UNATTENDED	115.00	12.47		13	1
205	GOLD HILL, OR	Distribution	UNATTENDED	69.00	12.47		11	3
206	GORDON HOLLOW, OR	Distribution	UNATTENDED	69.00	20.80		6	1
207	GOSHEN, OR	Distribution	UNATTENDED	115.00	20.80		20	1
208	GRANT STREET, OR	Distribution	UNATTENDED	115.00	20.80		45	2
209	GREEN, OR	Distribution	UNATTENDED	69.00	12.47		25	1
210	GRIFFIN CREEK, OR	Distribution	UNATTENDED	115.00	12.47		20	1
211	HAMAKER, OR	Distribution	UNATTENDED	69.00	12.47		8	3
212	HARRISBURG, OR	Distribution	UNATTENDED	69.00	20.80		13	1
213	HENLEY, OR	Distribution	UNATTENDED	69.00	12.47		6	3
214	HERMISTON, OR	Distribution	UNATTENDED	69.00	12.47		20	1
215	HILLVIEW, OR	Distribution	UNATTENDED	115.00	20.80		45	2
216	HINKLE, OR	Distribution	UNATTENDED	69.00	12.47		20	1
217	HOLLADAY, OR	Distribution	UNATTENDED	115.00	12.47		75	3
218	HOLLYWOOD, OR	Distribution	UNATTENDED	115.00	12.47		50	2
219	HOOD RIVER, OR	Distribution	UNATTENDED	69.00	12.47		40	2
220	HORNET, OR	Distribution	UNATTENDED	69.00	12.47		20	1
221	HUMBUG, OR	Distribution	UNATTENDED	69.00	12.47		9	1
222	HUNTERS CIRCLE, OR	Distribution	UNATTENDED	69.00	12.47		13	1	1
223	ILLAHEE FLATS, OR	Distribution	UNATTENDED	115.00	7.20		2	1
224	INDEPENDENCE, OR	Distribution	UNATTENDED	69.00	20.80		45	2
225	JEFFERSON, OR	Distribution	UNATTENDED	69.00	20.80		25	1
226	JEROME PRAIRIE, OR	Distribution	UNATTENDED	115.00	12.47		25	1
227	JORDAN POINT, OR	Distribution	UNATTENDED	115.00	12.47		20	1
228	JOSEPH, OR	Distribution	UNATTENDED	20.80	12.47		6	1	1
229	JUNCTION CITY, OR	Distribution	UNATTENDED	69.00	20.80		22	2
230	KENNEDY, OR	Distribution	UNATTENDED	115.00	13.20		30	1
231	KENWOOD, OR	Distribution	UNATTENDED	69.00	12.47		3	3
232	KILLINGSWORTH, OR	Distribution	UNATTENDED	69.00	12.47		40	2
233	KNAPPA SVENSEN, OR	Distribution	UNATTENDED	115.00	12.47	4.16	6	1
234	LAKEPORT, OR	Distribution	UNATTENDED	69.00	12.47		50	2
235	LANCASTER, OR	Distribution	UNATTENDED	69.00	20.80		13	3
236	LEBANON, OR	Distribution	UNATTENDED	115.00	20.80		45	2
237	LEMOLO 1, OR	Distribution	ATTENDED	12.47	7.20		2	3
238	LINCOLN, OR	Distribution	UNATTENDED	115.00	12.47		105	3
239	LOCKHART STREET, OR	Distribution	UNATTENDED	115.00	20.80		40	2
240	LYONS, OR	Distribution	UNATTENDED	69.00	20.80		25	2
241	MADRAS, OR	Distribution	UNATTENDED	69.00	12.47	7.20	25	2
242	MALLORY, OR	Distribution	UNATTENDED	115.00	12.47		25	1
243	MARYS RIVER, OR	Distribution	UNATTENDED	115.00	20.80		20	1
244	MCKAY, OR	Distribution	UNATTENDED	69.00	12.47	2.40	25	1
245	MEDCO, OR	Distribution	UNATTENDED	115.00	12.47		20	1
246	MEDFORD, OR	Distribution	UNATTENDED	115.00	12.47		67	8
247	MERLIN, OR	Distribution	UNATTENDED	115.00	12.47		45	2
248	MERRILL, OR	Distribution	UNATTENDED	69.00	12.47		15	6
249	MINAM, OR	Distribution	UNATTENDED	69.00	12.47		0	1
250	MODOC, OR	Distribution	UNATTENDED	69.00	12.47		6	3
251	MURDER CREEK, OR	Distribution	UNATTENDED	115.00	20.80		100	4
252	MYRTLE CREEK, OR	Distribution	UNATTENDED	69.00	12.47		14	1
253	MYRTLE POINT, OR	Distribution	UNATTENDED	115.00	20.80		9	1
254	NEW DESCHUTES, OR	Distribution	UNATTENDED	69.00	12.47		25	1
255	NEW O'BRIEN, OR	Distribution	UNATTENDED	115.00	12.47		9	1
256	OAK KNOLL, OR	Distribution	UNATTENDED	115.00	12.47		45	2
257	OAKLAND, OR	Distribution	UNATTENDED	115.00	12.47		8	1
258	OREMET, OR	Distribution	UNATTENDED	115.00	20.80		75	3
259	OVERPASS, OR	Distribution	UNATTENDED	69.00	12.47	7.20	45	2
260	PALLETTE, OR	Distribution	UNATTENDED	69.00	20.80		1	1	1
261	PARK STREET, OR	Distribution	UNATTENDED	115.00	12.47		40	2
262	PARKROSE, OR	Distribution	UNATTENDED	115.00	12.47		42	2
263	PENDLETON, OR	Distribution	UNATTENDED	69.00	12.47		43	6	1
264	PILOT ROCK, OR	Distribution	UNATTENDED	69.00	12.47		22	2
265	POWELL BUTTE, OR	Distribution	UNATTENDED	115.00	12.47		13	1
266	PRINEVILLE, OR	Distribution	UNATTENDED	115.00	12.47		75	3
267	PROVOLT, OR	Distribution	UNATTENDED	69.00	12.47		8	3
268	QUEEN AVE, OR	Distribution	UNATTENDED	69.00	20.80		50	2
269	RED BLANKET, OR	Distribution	UNATTENDED	69.00	4.16		2	3
270	REDMOND, OR	Distribution	UNATTENDED	115.00	12.47		50	2
271	RIDDLE VENEER, OR	Distribution	UNATTENDED	115.00	12.47	7.20	25	1
272	ROGUE RIVER, OR	Distribution	UNATTENDED	69.00	12.47		13	1
273	ROSEBURG, OR	Distribution	UNATTENDED	115.00	20.80		50	2
274	ROSS AVENUE, OR	Distribution	UNATTENDED	69.00	12.47		8	3
275	ROXY ANN, OR	Distribution	UNATTENDED	115.00	12.47		25	1
276	RUCH, OR	Distribution	UNATTENDED	69.00	12.47		9	1
277	RUNNING Y, OR	Distribution	UNATTENDED	69.00	20.80		9	1
278	RUSSELLVILLE, OR	Distribution	UNATTENDED	115.00	12.47		45	2
279	SAGE ROAD, OR	Distribution	UNATTENDED	115.00	12.47		40	2
280	SCIO, OR	Distribution	UNATTENDED	69.00	12.47		8	1
281	SEASIDE, OR	Distribution	UNATTENDED	115.00	12.47		40	2
282	SELMA, OR	Distribution	UNATTENDED	115.00	12.47		9	1
283	SHEVLIN PARK, OR	Distribution	UNATTENDED	69.00	12.47	7.20	50	2
284	SIMTAG BOOSTER PUMP, OR	Distribution	UNATTENDED	34.50	4.16		19	2
285	SOUTH DUNES, OR	Distribution	UNATTENDED	115.00	12.47		9	1
286	SOUTHGATE, OR	Distribution	UNATTENDED	69.00	20.80		20	1
287	SPRAGUE RIVER, OR	Distribution	UNATTENDED	69.00	12.47		7	3
288	STATE STREET, OR	Distribution	UNATTENDED	115.00	20.80		40	2
289	STAYTON, OR	Distribution	UNATTENDED	69.00	20.80		55	2
290	STEAMBOAT, OR	Distribution	UNATTENDED	115.00	7.20		0	1
291	STEVENS ROAD, OR	Distribution	UNATTENDED	115.00	20.80		50	2
292	SUTHERLIN, OR	Distribution	UNATTENDED	115.00	12.47		25	1
293	SWEET HOME, OR	Distribution	UNATTENDED	115.00	20.80		42	2
294	TAKELMA, OR	Distribution	UNATTENDED	115.00	20.80		13	1
295	TALENT, OR	Distribution	UNATTENDED	115.00	12.47		50	2
296	TEXUM, OR	Distribution	UNATTENDED	69.00	12.47		25	1
297	TILLER, OR	Distribution	UNATTENDED	115.00	12.47		5	1	1
298	TOLO, OR	Distribution	UNATTENDED	69.00	12.47		11	1
299	TURKEY HILL, OR	Distribution	UNATTENDED	69.00	12.47		13	3
300	UMAPINE, OR	Distribution	UNATTENDED	69.00	12.47		20	1
301	UMATILLA, OR	Distribution	UNATTENDED	69.00	12.47		25	2
302	VERNON, OR	Distribution	UNATTENDED	115.00	12.47	7.20	50	2
303	VILAS, OR	Distribution	UNATTENDED	115.00	12.47		25	1
304	VILLAGE GREEN, OR	Distribution	UNATTENDED	115.00	20.80		40	2
305	VINE STREET, OR	Distribution	UNATTENDED	69.00	20.80		30	1
306	WALLOWA, OR	Distribution	UNATTENDED	69.00	12.47		7	1
307	WARM SPRINGS, OR	Distribution	UNATTENDED	69.00	20.80		13	3
308	WARRENTON, OR	Distribution	UNATTENDED	115.00	12.47		38	2
309	WASCO, OR	Distribution	UNATTENDED	20.80	4.16		2	3
310	WECOMA BEACH, OR	Distribution	UNATTENDED	20.80	4.16		3	1
311	WESTON, OR	Distribution	UNATTENDED	69.00	12.47		25	1
312	WESTSIDE, OR	Distribution	ATTENDED	69.00	12.47		23	9
313	WEYERHAEUSER, OR	Distribution	UNATTENDED	69.00	12.47		40	2
314	WHITE CITY, OR	Distribution	UNATTENDED	115.00	12.47		65	3
315	WILLOW COVE, OR	Distribution	UNATTENDED	34.50	4.16		28	3
316	WINSTON, OR	Distribution	UNATTENDED	69.00	12.47		8	3
317	YEW AVENUE, OR	Distribution	UNATTENDED	115.00	12.47		50	2
318	YOUNGS BAY, OR	Distribution	UNATTENDED	115.00	12.47		37	2
319	APPLEGATE, OR	Transmission	UNATTENDED	115.00	69.00	12.47	65	2
320	BELKNAP, OR	Transmission	UNATTENDED	115.00	69.00	13.20	90	3
321	CALAPOOYA, OR	Transmission	UNATTENDED	230.00	69.00	20.80	88	2
322	CAVE JUNCTION, OR	Transmission	UNATTENDED	115.00	69.00	13.20	70	2
323	CHILOQUIN, OR	Transmission	UNATTENDED	230.00	115.00	12.47	131	5
324	COLD SPRINGS, OR	Transmission	UNATTENDED	230.00	69.00		150	1	3
325	COLUMBIA, OR	Transmission	UNATTENDED	115.00	69.00	12.47	128	3	1
326	COVE, OR	Transmission	UNATTENDED	230.00	69.00	2.40	127	3
327	DIAMOND HILL, OR	Transmission	UNATTENDED	230.00	69.00	12.47	75	1
328	DIXONVILLE 230, OR	Transmission	UNATTENDED	230.00	115.00	13.80	338	6
329	(i) DIXONVILLE 500, OR	Transmission	UNATTENDED	500.00	230.00	34.50	650	3	1
330	FISH HOLE, OR	Transmission	UNATTENDED	115.00	69.00	12.47	19	3
331	FRIEND, OR	Transmission	UNATTENDED	230.00	115.00	12.47	500	2
332	FRY, OR	Transmission	UNATTENDED	230.00	115.00	12.47	500	2	3
333	GRANTS PASS, OR	Transmission	UNATTENDED	230.00	115.00	12.47	583	4
334	HAZELWOOD, OR	Transmission	UNATTENDED	115.00	69.00	12.47	154	3
335	(j) HURRICANE, OR	Transmission	UNATTENDED	230.00	69.00		29	2	1
336	ISTHMUS, OR	Transmission	UNATTENDED	230.00	115.00	13.80	250	1
337	JACKSONVILLE, OR	Transmission	UNATTENDED	115.00	69.00	13.20	75	2
338	KLAMATH FALLS, OR	Transmission	UNATTENDED	230.00	69.00	13.80	400	7
339	KNOTT, OR	Transmission	UNATTENDED	115.00	57.00	12.47	172	5
340	LONE PINE, OR	Transmission	UNATTENDED	230.00	115.00	69.00	625	5	1
341	(k) MALIN, OR	Transmission	UNATTENDED	500.00	230.00	13.80	775	4	1
342	(l) MERIDIAN, OR	Transmission	UNATTENDED	500.00	230.00	34.50	1300	6	1
343	MILE HI, OR	Transmission	UNATTENDED	115.00	69.00	12.47	39	4
344	MONPAC, OR	Transmission	UNATTENDED	115.00	69.00	13.20	50	1
345	NICKEL MOUNTAIN, OR	Transmission	UNATTENDED	230.00	115.00	12.47	125	1
346	PARRISH GAP, OR	Transmission	ATTENDED	230.00	69.00	12.47	150	1
347	PILOT BUTTE, OR	Transmission	UNATTENDED	230.00	69.00		400	4	1
348	PONDEROSA, OR	Transmission	UNATTENDED	230.00	115.00	12.47	500	2
349	PROSPECT CENTRAL, OR	Transmission	UNATTENDED	115.00	69.00	12.47	45	3	1
350	RIDDLE, OR	Transmission	UNATTENDED	115.00	69.00	12.47	75	2
351	ROBERTS CREEK, OR	Transmission	UNATTENDED	115.00	69.00	13.20	50	1
352	(m) ROUNDUP SUB, OR	Transmission	UNATTENDED	230.00	69.00		67	2
353	(n) SANTIAM TIE, OR	Transmission	UNATTENDED	230.00	69.00	12.47	75	1
354	SCENIC, OR	Transmission	UNATTENDED	115.00	69.00	13.20	70	3
355	SNOW GOOSE, OR	Transmission	UNATTENDED	500.00	230.00	34.50	650	4	2
356	SPECIALIZED, OR	Transmission	UNATTENDED	230.00	34.50	12.47	474	5	1
357	TROUTDALE, OR	Transmission	UNATTENDED	230.00	115.00	13.20	500	3
358	TUCKER, OR	Transmission	UNATTENDED	115.00	69.00	12.47	100	2
359	WHETSTONE, OR	Transmission	UNATTENDED	230.00	115.00	12.47	250	1	1
360	WINCHESTER, OR	Transmission	UNATTENDED	115.00	69.00	12.47	65	5
361	106TH SOUTH, UT	Distribution	UNATTENDED	138.00	12.47		30	1
362	118TH SOUTH, UT	Distribution	UNATTENDED	138.00	12.47		30	1
363	126TH SOUTH, UT	Distribution	UNATTENDED	138.00	12.47		66	2
364	23RD STREET, UT	Distribution	UNATTENDED	46.00	12.47		13	1
365	70TH SOUTH, UT	Distribution	UNATTENDED	138.00	12.47		30	1
366	ALTAVIEW, UT	Distribution	UNATTENDED	46.00	12.47		45	2
367	AMALGA, UT	Distribution	UNATTENDED	46.00	12.47		11	1
368	AMERICAN FORK, UT	Distribution	UNATTENDED	138.00	12.47		63	2
369	ANGEL, UT	Distribution	UNATTENDED	138.00	46.00	12.47	135	3
370	APPLE VALLEY, UT	Distribution	UNATTENDED	69.00	12.47		6	1
371	ARAGONITE, UT	Distribution	UNATTENDED	46.00	12.47		1	1
372	AURORA, UT	Distribution	UNATTENDED	46.00	12.47		3	1
373	BANGERTER, UT	Distribution	UNATTENDED	138.00	13.20		63	2
374	BDO, UT	Distribution	UNATTENDED	138.00	12.47		63	2
375	BEAR RIVER, UT	Distribution	UNATTENDED	138.00	12.47		33	1
376	BENJAMIN, UT	Distribution	UNATTENDED	46.00	12.47		4	1
377	BINGHAM, UT	Distribution	UNATTENDED	46.00	13.20		25	1
378	BLACK MOUNTAIN, UT	Distribution	UNATTENDED	46.00	7.20		1	1
379	BLUE CREEK, UT	Distribution	UNATTENDED	46.00	12.47		2	3
380	BLUFF, UT	Distribution	UNATTENDED	69.00	12.47		2	3
381	BLUFFDALE, UT	Distribution	UNATTENDED	46.00	12.47		14	1
382	BOTHWELL, UT	Distribution	UNATTENDED	46.00	12.47		4	1
383	BRIAN HEAD, UT	Distribution	UNATTENDED	34.50	12.47		14	1
384	BRIGHTON, UT	Distribution	UNATTENDED	46.00	24.90		29	2
385	BROOKLAWN, UT	Distribution	UNATTENDED	46.00	12.47		6	1
386	BRUNSWICK, UT	Distribution	UNATTENDED	46.00	12.47		42	2
387	BURTON, UT	Distribution	UNATTENDED	34.50	12.47		11	3
388	BUSH, UT	Distribution	UNATTENDED	46.00	12.47		14	1
389	CANNON, UT	Distribution	UNATTENDED	46.00	12.47	7.20	13	1
390	CANYONLANDS, UT	Distribution	UNATTENDED	69.00	12.47		1	1
391	CAPITOL, UT	Distribution	UNATTENDED	46.00	12.47		20	1
392	CARBIDE, UT	Distribution	UNATTENDED	69.00	12.47		3	1
393	CARBONVILLE, UT	Distribution	UNATTENDED	46.00	12.47		6	1
394	CARLISLE, UT	Distribution	UNATTENDED	138.00	12.47		30	1
395	CASTO, UT	Distribution	UNATTENDED	46.00	12.47		28	1
396	CENTENNIAL, UT	Distribution	UNATTENDED	138.00	12.47		40	2
397	CENTERVILLE, UT	Distribution	UNATTENDED	46.00	12.47		24	1
398	CENTRAL, UT	Distribution	UNATTENDED	46.00	12.47		9	1
399	CHAPEL HILL, UT	Distribution	UNATTENDED	138.00	12.47		30	1
400	CHERRYWOOD, UT	Distribution	UNATTENDED	138.00	12.47		55	2
401	CIRCLEVILLE, UT	Distribution	UNATTENDED	69.00	12.47		3	1
402	CLEAR CREEK, UT	Distribution	UNATTENDED	46.00	12.47		4	1
403	CLEAR LAKE, UT	Distribution	UNATTENDED	69.00	12.47		0	3
404	CLEARFIELD SOUTH, UT	Distribution	UNATTENDED	138.00	12.47		60	2
405	CLINTON, UT	Distribution	UNATTENDED	138.00	12.47		50	2
406	CLIVE, UT	Distribution	UNATTENDED	46.00	12.47		4	1
407	COALVILLE, UT	Distribution	UNATTENDED	138.00	12.47		22	1
408	COLD WATER CANYON, UT	Distribution	UNATTENDED	138.00	12.47		30	1
409	COLTON WELL, UT	Distribution	UNATTENDED	46.00	2.40		1	3
410	COMMERCE, UT	Distribution	UNATTENDED	138.00	12.47		30	1
411	COPPER HILLS, UT	Distribution	UNATTENDED	138.00	13.20		63	2
412	CORRINE, UT	Distribution	UNATTENDED	46.00	12.47		3	1
413	COVE FORT, UT	Distribution	UNATTENDED	46.00	12.47		2	3
414	COZYDALE, UT	Distribution	UNATTENDED	138.00	12.47		30	1
415	CRANER FLAT, UT	Distribution	UNATTENDED	138.00	7.20		20	1
416	CROSS HOLLOW, UT	Distribution	UNATTENDED	138.00	12.47		20	1	1
417	CUDAHY, UT	Distribution	UNATTENDED	138.00	12.47		61	2
418	DAMMERON VALLEY, UT	Distribution	UNATTENDED	34.50	12.47		5	1
419	DAYBREAK, UT	Distribution	UNATTENDED	138.00	13.20		33	1
420	DECADE, UT	Distribution	UNATTENDED	138.00	13.20		60	2
421	DECKER LAKE, UT	Distribution	UNATTENDED	138.00	12.47		55	2
422	DELLE, UT	Distribution	UNATTENDED	46.00	12.47		6	1
423	DEWEYVILLE, UT	Distribution	UNATTENDED	46.00	12.47		14	1
424	DIMPLE DELL, UT	Distribution	UNATTENDED	138.00	12.47		60	2
425	DRAPER, UT	Distribution	UNATTENDED	138.00	13.20		60	2
426	DUMAS, UT	Distribution	UNATTENDED	138.00	12.47		60	2
427	EAST BENCH, UT	Distribution	UNATTENDED	138.00	12.47		30	1
428	EAST HYRUM, UT	Distribution	UNATTENDED	46.00	12.47		6	1
429	EAST LAYTON, UT	Distribution	UNATTENDED	138.00	12.47		60	2
430	EAST MILLCREEK, UT	Distribution	UNATTENDED	46.00	12.47		20	1
431	EDEN, UT	Distribution	UNATTENDED	46.00	12.47		19	2
432	ELBERTA, UT	Distribution	UNATTENDED	46.00	12.47		5	1
433	ELK MEADOWS, UT	Distribution	UNATTENDED	46.00	12.47		3	1
434	ELSINORE, UT	Distribution	UNATTENDED	46.00	12.47		14	1
435	EMERY CITY, UT	Distribution	UNATTENDED	69.00	12.47		3	3
436	EMIGRATION, UT	Distribution	UNATTENDED	46.00	12.47		25	1
437	ENOCH, UT	Distribution	UNATTENDED	138.00	12.47		14	1
438	ENTERPRISE VALLEY, UT	Distribution	UNATTENDED	138.00	12.47		14	1
439	EUREKA, UT	Distribution	UNATTENDED	46.00	12.47		3	1
440	FARMINGTON, UT	Distribution	UNATTENDED	138.00	13.20		60	2
441	FAYETTE, UT	Distribution	UNATTENDED	46.00	12.47		1	2
442	FERRON, UT	Distribution	UNATTENDED	69.00	12.47		5	1
443	FIELDING, UT	Distribution	UNATTENDED	46.00	12.47		6	1
444	FIFTH WEST, UT	Distribution	UNATTENDED	138.00	13.20		60	2
445	FLUX, UT	Distribution	UNATTENDED	46.00	12.47		4	1
446	FOOL CREEK, UT	Distribution	UNATTENDED	46.00	12.47		4	1
447	FORT DOUGLAS, UT	Distribution	UNATTENDED	138.00	13.20		40	1
448	FOUNTAIN GREEN, UT	Distribution	UNATTENDED	46.00	12.47		7	1
449	FREEDOM, UT	Distribution	UNATTENDED	46.00	7.20		0	1
450	FRUIT HEIGHTS, UT	Distribution	UNATTENDED	46.00	12.47		22	1
451	GARDEN CITY, UT	Distribution	UNATTENDED	69.00	12.47		20	1
452	GATEWAY, UT	Distribution	UNATTENDED	69.00	12.47		14	1	2
453	GOLD RUSH, UT	Distribution	UNATTENDED	138.00	13.20		30	1
454	GORDON AVENUE, UT	Distribution	UNATTENDED	138.00	12.47		30	1
455	GOSHEN UTAH, UT	Distribution	UNATTENDED	46.00	12.47		7	1
456	GRANGER, UT	Distribution	UNATTENDED	46.00	12.47		50	2
457	GRANTSVILLE, UT	Distribution	UNATTENDED	138.00	12.47		33	1
458	GRAVEL PIT, UT	Distribution	UNATTENDED	46.00	12.47		3	1
459	GROW, UT	Distribution	UNATTENDED	138.00	12.47		78	3
460	GUNNISON, UT	Distribution	UNATTENDED	46.00	12.47		20	1
461	HAMMER, UT	Distribution	UNATTENDED	138.00	12.47		60	2
462	HAVASU, UT	Distribution	UNATTENDED	69.00	12.47		3	1
463	HELPER CITY, UT	Distribution	UNATTENDED	46.00	4.16		3	3
464	HERRIMAN, UT	Distribution	UNATTENDED	138.00	13.20		60	2
465	HIGHLAND DISTRIBUTION, UT	Distribution	UNATTENDED	46.00	12.47		25	1
466	HOGGARD, UT	Distribution	UNATTENDED	138.00	12.47		63	2
467	HOLDEN, UT	Distribution	UNATTENDED	46.00	12.47		4	1
468	HOLLADAY, UT	Distribution	UNATTENDED	46.00	12.47		32	2
469	HUNTER, UT	Distribution	UNATTENDED	46.00	12.47		22	1
470	HUNTINGTON CITY, UT	Distribution	UNATTENDED	69.00	12.47		7	1	1
471	IRON MOUNTAIN, UT	Distribution	UNATTENDED	34.50	12.47		1	3
472	IRONTON, UT	Distribution	UNATTENDED	46.00	12.47		2	1
473	IVINS, UT	Distribution	UNATTENDED	69.00	12.47		63	2
474	JORDAN NARROWS, UT	Distribution	UNATTENDED	46.00	2.40		14	2
475	JORDAN PARK, UT	Distribution	UNATTENDED	138.00	12.47		30	1
476	JORDANELLE, UT	Distribution	UNATTENDED	138.00	12.47		30	1
477	JUAB, UT	Distribution	UNATTENDED	46.00	12.47		4	1
478	JUDGE, UT	Distribution	UNATTENDED	46.00	12.47		22	1
479	JUMBERS POINT, UT	Distribution	UNATTENDED	138.00	46.00	12.47	14	1
480	JUNCTION, UT	Distribution	UNATTENDED	69.00	12.47		3	1
481	KAIBAB, UT	Distribution	UNATTENDED	69.00	12.47		5	1
482	KAMAS, UT	Distribution	UNATTENDED	46.00	12.47		11	1
483	KEARNS, UT	Distribution	UNATTENDED	138.00	12.47		60	2
484	KENSINGTON, UT	Distribution	UNATTENDED	46.00	4.16		7	1
485	KYUNE, UT	Distribution	UNATTENDED	46.00	7.20		0	1
486	LAKE PARK, UT	Distribution	UNATTENDED	138.00	12.47		86	3
487	LAYTON, UT	Distribution	UNATTENDED	46.00	12.47		40	2
488	LEE CREEK, UT	Distribution	UNATTENDED	138.00	13.20		30	1
489	LEGRANDE, UT	Distribution	UNATTENDED	46.00	12.47		2	1
490	LEWISTON, UT	Distribution	UNATTENDED	46.00	7.20		22	1
491	LINCOLN, UT	Distribution	UNATTENDED	46.00	12.47		20	1
492	LINDON, UT	Distribution	UNATTENDED	46.00	12.47		25	1
493	LISBON, UT	Distribution	UNATTENDED	69.00	12.47		3	1
494	LOAFER, UT	Distribution	UNATTENDED	46.00	7.20		0	1
495	LOGAN CANYON, UT	Distribution	UNATTENDED	46.00	7.20		1	1
496	LONE TREE, UT	Distribution	UNATTENDED	34.50	12.47		20	1
497	LOWER BEAVER, UT	Distribution	UNATTENDED	46.00	13.20		0	1
498	LYNNDYL, UT	Distribution	UNATTENDED	46.00	12.47		4	1
499	MAESER, UT	Distribution	UNATTENDED	69.00	12.47		20	1
500	MAGNA, UT	Distribution	UNATTENDED	138.00	12.47		60	2
501	MANILA, UT	Distribution	UNATTENDED	138.00	12.47		30	1
502	MANTUA, UT	Distribution	UNATTENDED	46.00	12.47		3	1
503	MAPLETON, UT	Distribution	UNATTENDED	46.00	12.47		25	1
504	MARRIOTT, UT	Distribution	UNATTENDED	46.00	12.47		20	1
505	MARYSVALE, UT	Distribution	UNATTENDED	46.00	12.47		3	1
506	MATHIS, UT	Distribution	UNATTENDED	46.00	12.47		9	1
507	MAYFLOWER, UT	Distribution	UNATTENDED	138.00	13.20		66	2
508	MCCORNICK, UT	Distribution	UNATTENDED	46.00	12.47		6	1
509	MCKAY, UT	Distribution	UNATTENDED	46.00	12.47		28	1
510	MEADOWBROOK, UT	Distribution	UNATTENDED	138.00	12.47		42	2
511	MEDICAL, UT	Distribution	UNATTENDED	46.00	12.47		56	3
512	MIDLAND, UT	Distribution	UNATTENDED	138.00	12.47		30	1
513	MIDVALE, UT	Distribution	UNATTENDED	46.00	12.47		25	1
514	MILFORD TV, UT	Distribution	UNATTENDED	46.00	13.20		0	1
515	MINERSVILLE, UT	Distribution	UNATTENDED	46.00	12.47		2	1
516	MOAB CITY, UT	Distribution	UNATTENDED	69.00	12.47		39	3
517	MOORE, UT	Distribution	UNATTENDED	69.00	12.47		3	1
518	MORGAN, UT	Distribution	UNATTENDED	46.00	12.47		5	1
519	MORONI, UT	Distribution	UNATTENDED	46.00	12.47		6	1
520	MORTON COURT, UT	Distribution	UNATTENDED	138.00	12.47		65	2
521	MOUNTAIN DELL, UT	Distribution	UNATTENDED	46.00	12.47		5	1
522	MOUNTAIN GREEN, UT	Distribution	UNATTENDED	46.00	12.47		9	1
523	MYTON, UT	Distribution	UNATTENDED	69.00	12.47		6	1
524	NAPLES, UT	Distribution	UNATTENDED	138.00	13.20		30	1
525	NEW HARMONY, UT	Distribution	UNATTENDED	69.00	12.47		7	1
526	NEWGATE, UT	Distribution	UNATTENDED	46.00	12.47		16	1
527	NEWTON, UT	Distribution	UNATTENDED	46.00	12.47		5	1
528	NIBLEY, UT	Distribution	UNATTENDED	138.00	24.90		103	2
529	NORTH BENCH, UT	Distribution	UNATTENDED	46.00	12.47		25	1
530	NORTH FIELDS, UT	Distribution	UNATTENDED	46.00	12.47		3	1
531	NORTH LOGAN, UT	Distribution	UNATTENDED	46.00	12.47		25	1
532	NORTH OGDEN, UT	Distribution	UNATTENDED	46.00	12.47		22	1
533	NORTH SALT LAKE, UT	Distribution	UNATTENDED	46.00	13.20		25	1
534	NORTHEAST, UT	Distribution	UNATTENDED	46.00	12.47		45	2
535	NORTHRIDGE, UT	Distribution	UNATTENDED	46.00	12.47		14	1
536	OAKLAND AVENUE, UT	Distribution	UNATTENDED	46.00	12.47		22	1
537	OAKLEY, UT	Distribution	UNATTENDED	46.00	12.47		6	1
538	OLYMPUS, UT	Distribution	UNATTENDED	46.00	12.47		22	1
539	OPHIR, UT	Distribution	UNATTENDED	46.00	12.47		3	1
540	ORANGE, UT	Distribution	UNATTENDED	46.00	12.47		33	1
541	ORANGEVILLE, UT	Distribution	UNATTENDED	69.00	12.47		14	1
542	OREM, UT	Distribution	UNATTENDED	46.00	12.47		48	2
543	PANGUITCH, UT	Distribution	UNATTENDED	69.00	12.47		5	1
544	PARIETTE, UT	Distribution	UNATTENDED	69.00	24.90		14	1
545	PARK CITY, UT	Distribution	UNATTENDED	46.00	12.47		42	2
546	PARKSIDE, UT	Distribution	UNATTENDED	138.00	12.47		60	2
547	PARKWAY, UT	Distribution	UNATTENDED	138.00	12.47		50	2
548	PARLEYS, UT	Distribution	UNATTENDED	46.00	12.47		16	2
549	PELICAN POINT, UT	Distribution	UNATTENDED	46.00	12.47		6	1
550	PETERSON, UT	Distribution	UNATTENDED	46.00	12.47		30	1
551	PINE CANYON, UT	Distribution	UNATTENDED	138.00	12.47		55	2
552	PINE CREEK, UT	Distribution	UNATTENDED	46.00	12.47		6	1
553	PINNACLE, UT	Distribution	UNATTENDED	46.00	12.47		14	1
554	PIONEER PLANT, UT	Distribution	ATTENDED	138.00	12.47		30	1
555	PLAIN CITY, UT	Distribution	UNATTENDED	138.00	12.47		22	1
556	PLEASANT GROVE, UT	Distribution	UNATTENDED	138.00	12.47		30	1
557	PLEASANT VIEW, UT	Distribution	UNATTENDED	46.00	12.47		14	1
558	PONY EXPRESS, UT	Distribution	UNATTENDED	138.00	12.47		60	2
559	PORTER ROCKWELL, UT	Distribution	UNATTENDED	138.00	13.20		60	2
560	PROMONTORY, UT	Distribution	UNATTENDED	46.00	12.47		2	1
561	QUAIL CREEK, UT	Distribution	UNATTENDED	69.00	12.47		14	1
562	QUARRY, UT	Distribution	UNATTENDED	138.00	12.47		60	2
563	QUICHAPA, UT	Distribution	UNATTENDED	34.50	12.47	7.20	14	1
564	RAINS, UT	Distribution	UNATTENDED	46.00	7.20		0	1
565	RANDOLPH, UT	Distribution	UNATTENDED	46.00	12.47		2	1
566	RASMUSON, UT	Distribution	UNATTENDED	46.00	12.47		2	1	1
567	RATTLESNAKE, UT	Distribution	UNATTENDED	69.00	24.90		14	1
568	REDWOOD, UT	Distribution	UNATTENDED	46.00	12.47		45	2
569	RESEARCH PARK, UT	Distribution	UNATTENDED	46.00	12.47		45	2
570	RICH, UT	Distribution	UNATTENDED	69.00	12.47		5	1
571	RICHFIELD, UT	Distribution	UNATTENDED	46.00	12.47		35	2
572	RICHMOND, UT	Distribution	UNATTENDED	46.00	12.47		11	1
573	RIDGELAND, UT	Distribution	UNATTENDED	138.00	12.47		40	2
574	RITER, UT	Distribution	UNATTENDED	46.00	12.47		20	1
575	ROCK CANYON, UT	Distribution	UNATTENDED	69.00	12.47		5	1
576	ROCKVILLE, UT	Distribution	UNATTENDED	34.50	12.47		4	1
577	ROCKY POINT, UT	Distribution	UNATTENDED	138.00	12.47		30	1
578	ROSE PARK, UT	Distribution	UNATTENDED	46.00	12.47		42	2
579	ROYAL, UT	Distribution	UNATTENDED	46.00	4.16		0	3
580	SALINA, UT	Distribution	UNATTENDED	46.00	12.47		11	1
581	SANDY, UT	Distribution	UNATTENDED	138.00	12.47		60	2
582	SARATOGA, UT	Distribution	UNATTENDED	138.00	13.20		60	2
583	SCHOO MINE, UT	Distribution	UNATTENDED	46.00	12.47		9	1
584	SCIPIO, UT	Distribution	UNATTENDED	46.00	12.47		2	3
585	SCOFIELD, UT	Distribution	UNATTENDED	46.00	12.47		1	3
586	SCOFIELD RESERVOIR, UT	Distribution	UNATTENDED	46.00	7.20		1	1
587	SEGO CANYON, UT	Distribution	UNATTENDED	69.00	12.47		14	1
588	SEVEN MILE, UT	Distribution	UNATTENDED	69.00	12.47		5	1	1
589	SHARON, UT	Distribution	UNATTENDED	46.00	12.47		20	1
590	SHORELINE, UT	Distribution	UNATTENDED	138.00	13.20		60	2
591	SIXTH SOUTH, UT	Distribution	UNATTENDED	46.00	12.47		20	1
592	SKULL VALLEY, UT	Distribution	UNATTENDED	46.00	12.47		2	1
593	SKYPARK, UT	Distribution	UNATTENDED	138.00	13.20		73	2
594	SNARR, UT	Distribution	UNATTENDED	46.00	12.47		20	1
595	SNOWVILLE, UT	Distribution	UNATTENDED	69.00	12.47		5	1
596	SOLDIER SUMMIT, UT	Distribution	UNATTENDED	46.00	12.47		2	1
597	SOUTH JORDAN, UT	Distribution	UNATTENDED	138.00	12.47		60	2
598	SOUTH MILFORD, UT	Distribution	UNATTENDED	46.00	24.90		28	2
599	SOUTH MOUNTAIN, UT	Distribution	UNATTENDED	138.00	12.47		60	2
600	SOUTH OGDEN, UT	Distribution	UNATTENDED	46.00	12.47		25	1
601	SOUTH PARK, UT	Distribution	UNATTENDED	138.00	12.47		30	1
602	SOUTH WEBER, UT	Distribution	UNATTENDED	138.00	12.47		22	1
603	SOUTHEAST, UT	Distribution	UNATTENDED	138.00	12.47		60	2
604	SOUTHWEST, UT	Distribution	UNATTENDED	46.00	12.47		33	2
605	SPANISH VALLEY, UT	Distribution	UNATTENDED	69.00	12.47		14	1
606	SPRINGDALE, UT	Distribution	UNATTENDED	34.50	12.47		14	1
607	ST JOHN, UT	Distribution	UNATTENDED	46.00	12.47		8	1
608	STANSBURY, UT	Distribution	UNATTENDED	138.00	12.47		33	1
609	SUMMIT CREEK, UT	Distribution	UNATTENDED	138.00	13.80		30	1
610	SUMMIT PARK, UT	Distribution	UNATTENDED	46.00	12.47		7	1
611	SUNRISE, UT	Distribution	UNATTENDED	138.00	12.47		60	2
612	SUTHERLAND, UT	Distribution	UNATTENDED	46.00	24.90		14	1
613	TAMARISK, UT	Distribution	UNATTENDED	138.00	12.47		20	1
614	TAYLOR, UT	Distribution	UNATTENDED	46.00	12.47		33	1
615	THIEF CREEK, UT	Distribution	UNATTENDED	138.00	24.90		14	1
616	THIRD WEST, UT	Distribution	UNATTENDED	138.00	13.20		100	2
617	THIRTEENTH SOUTH, UT	Distribution	UNATTENDED	46.00	12.47		22	1
618	TOOELE DEPOT, UT	Distribution	UNATTENDED	46.00	12.47		25	1
619	TOQUERVILLE, UT	Distribution	UNATTENDED	69.00	34.50		34	2
620	TRAPPER, UT	Distribution	UNATTENDED	138.00	13.20		30	1
621	TRI-CITY, UT	Distribution	UNATTENDED	138.00	12.47		30	1	3
622	UINTAH, UT	Distribution	UNATTENDED	46.00	12.47		39	2
623	UNION, UT	Distribution	UNATTENDED	46.00	12.47		50	2
624	VALLEY CENTER, UT	Distribution	UNATTENDED	46.00	12.47		22	1
625	VERMILLION, UT	Distribution	UNATTENDED	46.00	12.47		3	1
626	VERNAL, UT	Distribution	UNATTENDED	69.00	12.47		33	2
627	VICKERS, UT	Distribution	UNATTENDED	46.00	12.47		4	1
628	VINEYARD, UT	Distribution	UNATTENDED	138.00	13.20		30	1
629	WALLSBURG, UT	Distribution	UNATTENDED	138.00	12.47		13	1
630	WALNUT GROVE, UT	Distribution	UNATTENDED	138.00	12.47		30	1
631	WARREN, UT	Distribution	UNATTENDED	138.00	12.47		63	2
632	WASATCH STATE PARK, UT	Distribution	UNATTENDED	46.00	12.47		2	3
633	WASHAKIE, UT	Distribution	UNATTENDED	138.00	4.16		14	1
634	WELBY, UT	Distribution	UNATTENDED	46.00	12.47		42	2
635	WELFARE, UT	Distribution	UNATTENDED	46.00	12.47		11	1
636	WEST COMMERCIAL, UT	Distribution	UNATTENDED	46.00	12.47		22	1
637	WEST JORDAN, UT	Distribution	UNATTENDED	138.00	12.47		28	1
638	WEST OGDEN, UT	Distribution	UNATTENDED	138.00	12.47		60	2
639	WEST POINT, UT	Distribution	UNATTENDED	138.00	13.20		40	1
640	WEST ROY, UT	Distribution	UNATTENDED	46.00	12.47		25	1
641	WEST TEMPLE, UT	Distribution	UNATTENDED	46.00	7.20		53	3
642	WEST VALLEY, UT	Distribution	ATTENDED	138.00	12.47		63	2
643	WESTFIELD, UT	Distribution	UNATTENDED	138.00	12.47		20	1
644	WESTWATER, UT	Distribution	UNATTENDED	69.00	12.47		5	1
645	WHITE ROCK, UT	Distribution	UNATTENDED	138.00	13.20		30	1
646	WILLOWCREEK, UT	Distribution	UNATTENDED	46.00	12.47		1	1
647	WILLOWRIDGE, UT	Distribution	UNATTENDED	46.00	12.47		25	1
648	WINCHESTER HILLS, UT	Distribution	UNATTENDED	34.50	12.47		4	1
649	WINKLEMAN, UT	Distribution	UNATTENDED	46.00	7.20		0	1
650	WOLF CREEK, UT	Distribution	UNATTENDED	69.00	12.47	4.16	6	1
651	WOODRUFF, UT	Distribution	UNATTENDED	46.00	12.47		2	1
652	WOODS CROSS, UT	Distribution	UNATTENDED	46.00	12.47		20	1
653	90TH SOUTH, UT	Transmission	UNATTENDED	345.00	138.00	12.47	1604	6
654	ABAJO, UT	Transmission	UNATTENDED	138.00	69.00	13.80	67	2
655	ASHLEY, UT	Transmission	UNATTENDED	138.00	69.00	12.47	134	2
656	BEN LOMOND, UT	Transmission	UNATTENDED	345.00	230.00	13.80	2202	6
657	BLACK ROCK, UT	Transmission	UNATTENDED	230.00	69.00	13.20	75	1
658	BLACKHAWK, UT	Transmission	UNATTENDED	138.00	69.00	7.20	100	2
659	BRIDGERLAND, UT	Transmission	UNATTENDED	345.00	138.00		700	1
660	BUTLERVILLE, UT	Transmission	UNATTENDED	138.00	46.00	13.80	205	4
661	CAMERON, UT	Transmission	UNATTENDED	138.00	46.00	12.47	100	4
662	CAMP WILLIAMS, UT	Transmission	UNATTENDED	345.00	138.00	13.20	200	2
663	CLOVER, UT	Transmission	UNATTENDED	500.00	345.00	138.00	3600	7	1
664	COLEMAN, UT	Transmission	UNATTENDED	138.00	69.00	6.60	119	4
665	COLUMBIA, UT	Transmission	UNATTENDED	138.00	46.00	6.60	71	2
666	COTTONWOOD, UT	Transmission	UNATTENDED	138.00	46.00	12.47	301	6	1
667	CROYDON, UT	Transmission	UNATTENDED	138.00	46.00	12.47	81	2
668	CUTLER, UT	Transmission	ATTENDED	138.00	46.00	6.60	50	1
669	DELTA, UT	Transmission	UNATTENDED	69.00	46.00	13.20	48	3
670	EL MONTE, UT	Transmission	UNATTENDED	138.00	46.00	12.47	313	3
671	EMERY, UT	Transmission	ATTENDED	345.00	138.00	12.47	411	3
672	EMMA PARK, UT	Transmission	UNATTENDED	138.00	12.47		8	1
673	GADSBY, UT	Transmission	ATTENDED	138.00	46.00	13.80	168	1
674	GARKANE, UT	Transmission	UNATTENDED	69.00	46.00	2.40	33	1
675	GREEN CANYON, UT	Transmission	UNATTENDED	138.00	46.00	6.60	67	2
676	HALE, UT	Transmission	UNATTENDED	138.00	46.00	12.47	114	2
677	HELPER, UT	Transmission	UNATTENDED	138.00	46.00	12.47	77	2
678	HIGHLAND, UT	Transmission	UNATTENDED	138.00	46.00	12.47	97	2
679	HONEYVILLE, UT	Transmission	UNATTENDED	138.00	46.00	6.60	35	1
680	HORSESHOE, UT	Transmission	UNATTENDED	138.00	46.00	6.60	80	2
681	HUNTINGTON, UT	Transmission	UNATTENDED	345.00	138.00	12.47	270	4
682	JERUSALEM, UT	Transmission	UNATTENDED	138.00	46.00	6.60	67	1
683	JORDAN, UT	Transmission	UNATTENDED	138.00	46.00	12.47	228	5
684	LAMPO, UT	Transmission	UNATTENDED	138.00	46.00	12.47	75	1
685	MATHINGTON, UT	Transmission	UNATTENDED	138.00	46.00	13.20	75	1
686	MCCLELLAND, UT	Transmission	UNATTENDED	138.00	46.00	13.80	340	3
687	MCFADDEN, UT	Transmission	UNATTENDED	138.00	69.00	13.80	45	1
688	MIDDLETON, UT	Transmission	UNATTENDED	138.00	69.00	6.60	137	3
689	MIDVALLEY, UT	Transmission	UNATTENDED	345.00	138.00	13.80	1150	2
690	MIDWAY CITY, UT	Transmission	UNATTENDED	138.00	46.00	12.47	67	1
691	MILFORD, UT	Transmission	UNATTENDED	138.00	46.00	13.20	89	2
692	MINERAL PRODUCTS, UT	Transmission	UNATTENDED	69.00	46.00	6.60	13	1
693	MOAB, UT	Transmission	UNATTENDED	138.00	69.00	6.60	67	1
694	NEBO, UT	Transmission	UNATTENDED	138.00	46.00	6.60	67	1
695	OQUIRRH, UT	Transmission	UNATTENDED	345.00	138.00	13.80	835	4
696	PAROWAN VALLEY, UT	Transmission	UNATTENDED	230.00	138.00	13.80	138	2
697	PARRISH, UT	Transmission	UNATTENDED	138.00	46.00	13.80	97	2
698	PAVANT, UT	Transmission	UNATTENDED	230.00	46.00	13.80	133	2
699	PINTO, UT	Transmission	UNATTENDED	345.00	138.00	13.80	257	(t) 3
700	PURGATORY FLAT, UT	Transmission	UNATTENDED	138.00	69.00	12.47	300	2
701	RED BUTTE, UT	Transmission	UNATTENDED	345.00	138.00	24.90	414	2
702	RIVERDALE, UT	Transmission	UNATTENDED	138.00	46.00	6.60	180	3
703	SEVIER, UT	Transmission	UNATTENDED	138.00	46.00	6.60	38	2
704	SIGURD, UT	Transmission	UNATTENDED	345.00	230.00	13.80	1125	(u) 6
705	SILVER CREEK, UT	Transmission	UNATTENDED	138.00	46.00	13.80	100	2
706	SMITHFIELD, UT	Transmission	UNATTENDED	138.00	46.00	6.60	63	2
707	SNYDERVILLE, UT	Transmission	UNATTENDED	138.00	46.00	13.80	127	3
708	SPANISH FORK, UT	Transmission	UNATTENDED	345.00	138.00	13.80	1433	3	1
709	SYRACUSE, UT	Transmission	UNATTENDED	345.00	138.00	13.80	1300	6
710	TAYLORSVILLE, UT	Transmission	UNATTENDED	138.00	46.00	12.47	358	4
711	TERMINAL, UT	Transmission	UNATTENDED	345.00	138.00	12.47	1624	6
712	THREE PEAKS, UT	Transmission	UNATTENDED	345.00	138.00	12.47	450	1
713	TIMP, UT	Transmission	UNATTENDED	138.00	46.00	7.20	163	3
714	TOOELE, UT	Transmission	UNATTENDED	138.00	46.00	13.20	249	3
715	ATTALIA, WA	Distribution	UNATTENDED	69.00	12.47		25	1
716	WEST CEDAR, UT	Transmission	UNATTENDED	230.00	138.00	12.47	147	2
717	BOWMAN, WA	Distribution	UNATTENDED	69.00	12.47		45	2
718	CASCADE KRAFT, WA	Distribution	UNATTENDED	69.00	12.47		151	7
719	CENTRAL, WA	Distribution	UNATTENDED	69.00	12.47		14	1
720	CLINTON, WA	Distribution	UNATTENDED	115.00	12.47		25	1
721	DAYTON, WA	Distribution	UNATTENDED	69.00	12.47		23	2
722	DODD ROAD, WA	Distribution	UNATTENDED	69.00	20.80		43	2
723	FLINT SUBSTATION, WA	Distribution	UNATTENDED	115.00	13.20		30	1
724	GROMORE, WA	Distribution	UNATTENDED	115.00	12.47		25	1
725	HOPLAND, WA	Distribution	UNATTENDED	115.00	12.47		50	2
726	MILL CREEK, WA	Distribution	UNATTENDED	69.00	12.47		45	2
727	NACHES, WA	Distribution	UNATTENDED	115.00	12.47		25	1
728	NOB HILL, WA	Distribution	UNATTENDED	115.00	12.47		40	2
729	NORTH PARK, WA	Distribution	UNATTENDED	115.00	12.47		45	2
730	ORCHARD, WA	Distribution	UNATTENDED	115.00	12.47		50	2
731	PACIFIC, WA	Distribution	UNATTENDED	115.00	12.47		28	3
732	POMEROY, WA	Distribution	UNATTENDED	69.00	12.47		9	1
733	PROSPECT POINT, WA	Distribution	UNATTENDED	69.00	12.47		40	2
734	PUNKIN CENTER, WA	Distribution	UNATTENDED	115.00	13.20		44	3
735	RIVER ROAD, WA	Distribution	UNATTENDED	115.00	12.47		76	5
736	SELAH, WA	Distribution	UNATTENDED	115.00	12.47		45	2
737	SULPHUR CREEK, WA	Distribution	UNATTENDED	115.00	12.47		25	1
738	SUNNYSIDE, WA	Distribution	UNATTENDED	115.00	12.47		45	2
739	TIETON, WA	Distribution	UNATTENDED	115.00	34.50		29	2	1
740	TOPPENISH, WA	Distribution	UNATTENDED	115.00	12.47		50	2
741	TOUCHET, WA	Distribution	UNATTENDED	69.00	12.47		13	1
742	VOELKER, WA	Distribution	UNATTENDED	115.00	12.47		25	1
743	WAITSBURG, WA	Distribution	UNATTENDED	69.00	12.47		9	1
744	WAPATO, WA	Distribution	UNATTENDED	115.00	12.47		45	2
745	WENAS, WA	Distribution	UNATTENDED	115.00	12.47		25	2
746	WHITE SWAN, WA	Distribution	UNATTENDED	115.00	12.47		22	2
747	WILEY, WA	Distribution	UNATTENDED	115.00	12.47		45	2
748	(o) DRY GULCH, WA	Transmission	UNATTENDED	115.00	69.00		50	1
749	GRANDVIEW, WA	Transmission	UNATTENDED	115.00	69.00	12.47	78	3
750	OUTLOOK, WA	Transmission	UNATTENDED	230.00	115.00	12.47	250	1
751	PASCO, WA	Transmission	UNATTENDED	115.00	69.00	7.20	34	9
752	POMONA HEIGHTS, WA	Transmission	UNATTENDED	230.00	115.00	12.47	325	3
753	UNION GAP, WA	Transmission	UNATTENDED	230.00	115.00	13.20	595	5
754	(p) WALLA WALLA, WA	Transmission	UNATTENDED	230.00	69.00		300	2
755	WALLULA, WA	Transmission	UNATTENDED	230.00	69.00		300	2
756	WINE COUNTRY, WA	Transmission	UNATTENDED	230.00	115.00		250	1
757	ANTELOPE MINE, WY	Distribution	UNATTENDED	230.00	34.50	13.20	25	1
758	ARROWHEAD, WY	Distribution	UNATTENDED	230.00	34.50	13.20	150	2
759	ASTLE STREET, WY	Distribution	UNATTENDED	34.50	13.20		13	1
760	BAILEY DOME, WY	Distribution	UNATTENDED	57.00	4.16		2	1
761	BAR X, WY	Distribution	UNATTENDED	230.00	34.50	13.20	25	1
762	BARR NUNN, WY	Distribution	UNATTENDED	115.00	12.47		30	1
763	BATTLE SPRINGS, WY	Distribution	UNATTENDED	34.50	13.80		2	1
764	BELLAMY 2, WY	Distribution	UNATTENDED	69.00	4.16		5	1
765	BIG MUDDY, WY	Distribution	UNATTENDED	69.00	12.47		7	1
766	BIG PINEY, WY	Distribution	UNATTENDED	69.00	24.90		14	1
767	BLACKS FORK, WY	Distribution	UNATTENDED	230.00	34.50	13.20	225	3	1
768	BRIDGER PUMP, WY	Distribution	UNATTENDED	230.00	34.50	7.20	74	4
769	BRYAN, WY	Distribution	UNATTENDED	115.00	12.47		25	1
770	BUFFALO, WY	Distribution	UNATTENDED	230.00	20.80		20	1	1
771	BYRON, WY	Distribution	UNATTENDED	34.50	4.16		2	3
772	CASSA, WY	Distribution	UNATTENDED	57.00	20.80		2	6
773	CENTER STREET, WY	Distribution	UNATTENDED	115.00	12.47		13	1
774	CHAPMAN, WY	Distribution	UNATTENDED	46.00	12.47		4	1
775	CHUKAR, WY	Distribution	UNATTENDED	12.47	4.16		1	3
776	COKEVILLE, WY	Distribution	UNATTENDED	46.00	24.90		8	1
777	COLUMBIA GENEVA, WY	Distribution	UNATTENDED	230.00	12.47		45	2
778	COMMUNITY PARK, WY	Distribution	UNATTENDED	115.00	12.47		50	2
779	CROOKS GAP, WY	Distribution	UNATTENDED	34.50	12.47		6	1
780	DEAVER, WY	Distribution	UNATTENDED	34.50	4.16		0	3
781	DEER CREEK, WY	Distribution	UNATTENDED	69.00	12.47		9	1
782	DJ COAL MINE, WY	Distribution	UNATTENDED	69.00	34.50		13	1
783	DRY FORK, WY	Distribution	UNATTENDED	69.00	4.16		9	1
784	ELK BASIN, WY	Distribution	UNATTENDED	34.50	7.20		5	1
785	ELK HORN, WY	Distribution	UNATTENDED	115.00	12.47		25	1
786	EMIGRANT, WY	Distribution	UNATTENDED	115.00	12.47		13	1
787	EVANS, WY	Distribution	UNATTENDED	115.00	12.47		9	1
788	EVANSTON, WY	Distribution	UNATTENDED	138.00	12.47		40	2
789	FIREHOLE, WY	Distribution	UNATTENDED	230.00	34.50	13.20	50	2
790	FORT CASPER, WY	Distribution	UNATTENDED	69.00	12.47		28	1
791	FORT SANDERS, WY	Distribution	UNATTENDED	115.00	13.20		20	1
792	FRANNIE, WY	Distribution	UNATTENDED	230.00	34.50	2.40	50	2
793	FRONTIER, WY	Distribution	UNATTENDED	69.00	4.16		6	1
794	GARLAND, WY	Distribution	UNATTENDED	230.00	34.50	13.20	45	2
795	GRASS CREEK, WY	Distribution	UNATTENDED	230.00	34.50	13.20	25	1
796	GREAT DIVIDE, WY	Distribution	UNATTENDED	115.00	34.50		20	1
797	GREEN MOUNTAIN, WY	Distribution	UNATTENDED	34.50	4.16		5	1
798	GREYBULL, WY	Distribution	UNATTENDED	34.50	4.16		3	1
799	HANNA, WY	Distribution	UNATTENDED	34.50	13.20		6	1
800	HILLTOP, WY	Distribution	UNATTENDED	115.00	34.50	13.20	45	2	1
801	HOLLY SUGAR, WY	Distribution	UNATTENDED	34.50	4.16		5	1
802	JACKALOPE, WY	Distribution	UNATTENDED	115.00	13.20		55	2
803	KEMMERER, WY	Distribution	UNATTENDED	69.00	24.90		14	1
804	KIRBY CREEK, WY	Distribution	UNATTENDED	34.50	4.16		2	3
805	KIRBY CREEK PUMPING, WY	Distribution	UNATTENDED	34.50	2.40		2	3
806	LABARGE, WY	Distribution	UNATTENDED	69.00	24.90		18	4
807	LANDER, WY	Distribution	UNATTENDED	34.50	12.47		33	2
808	LARAMIE, WY	Distribution	UNATTENDED	115.00	13.20		50	2
809	LINCH, WY	Distribution	UNATTENDED	69.00	13.80		12	1
810	LITTLE MOUNTAIN, WY	Distribution	UNATTENDED	230.00	34.50		20	1
811	LOVELL, WY	Distribution	UNATTENDED	34.50	4.16		4	1
812	MANSFACE, WY	Distribution	UNATTENDED	230.00	34.50	2.40	20	1
813	MILL IRON, WY	Distribution	UNATTENDED	34.50	13.80		12	1
814	MILLS, WY	Distribution	UNATTENDED	12.47	4.16		2	3
815	MINERS, WY	Distribution	UNATTENDED	230.00	34.50	7.20	20	1
816	MOUNTAIN GAS, WY	Distribution	UNATTENDED	34.50	12.47	4.16	3	1
817	MURPHY DOME, WY	Distribution	UNATTENDED	34.50	12.47		13	1
818	NAUGHTON CONSTRUCTION, WY	Distribution	UNATTENDED	69.00	12.47		2	3
819	NUGGETT, WY	Distribution	UNATTENDED	69.00	7.20		0	1
820	OPAL, WY	Distribution	UNATTENDED	69.00	24.90		8	1
821	ORIN, WY	Distribution	UNATTENDED	34.50	7.20		1	1	1
822	OWL CREEK PUMP #1, WY	Distribution	UNATTENDED	34.50	4.16		2	3
823	PARADISE, WY	Distribution	UNATTENDED	69.00	24.90		30	1
824	PARCO, WY	Distribution	UNATTENDED	34.50	13.20		3	1
825	PHILLIPS GAS PLANT PIPELINE, WY	Distribution	UNATTENDED	12.47	2.40		1	3
826	PINEDALE, WY	Distribution	UNATTENDED	69.00	24.90		20	1
827	PITCHFORK, WY	Distribution	UNATTENDED	69.00	24.90		11	3	1
828	PLATTE PIPE BYRON, WY	Distribution	UNATTENDED	34.50	4.16		2	3
829	PLATTE PIPE OREGON BASIN, WY	Distribution	UNATTENDED	34.50	4.16		2	3
830	PLATTE RIVER DJ, WY	Distribution	UNATTENDED	69.00	7.20		2	3
831	POISON SPIDER, WY	Distribution	UNATTENDED	69.00	2.40		3	1
832	RAINBOW, WY	Distribution	UNATTENDED	34.50	13.20		13	1
833	RAVEN, WY	Distribution	UNATTENDED	230.00	34.50	12.47	200	2
834	RED BUTTE, WY	Distribution	UNATTENDED	115.00	13.20		30	1
835	REFINERY, WY	Distribution	UNATTENDED	115.00	12.47		45	2
836	RIVERTON, WY	Distribution	UNATTENDED	230.00	34.50	13.20	77	4
837	ROCK SPRINGS 230, WY	Distribution	UNATTENDED	230.00	34.50	13.20	50	2	2
838	SAGE HILL, WY	Distribution	UNATTENDED	34.50	13.20		9	1
839	SHOSHONI, WY	Distribution	UNATTENDED	34.50	2.40		2	3
840	SINCLAIR PIPELINE, WY	Distribution	UNATTENDED	34.50	4.16		5	1
841	SLATE CREEK, WY	Distribution	UNATTENDED	69.00	13.80		1	1
842	SOUTH CODY, WY	Distribution	UNATTENDED	69.00	24.90		14	3	1
843	SOUTH ELK BASIN, WY	Distribution	UNATTENDED	34.50	4.16		2	6
844	SOUTH TRONA, WY	Distribution	UNATTENDED	230.00	34.50	13.20	150	2
845	SPRING CREEK, WY	Distribution	UNATTENDED	115.00	13.20		28	1
846	SVILAR, WY	Distribution	UNATTENDED	34.50	4.16		2	3
847	TEN MILE, WY	Distribution	UNATTENDED	69.00	12.47		5	1
848	THERMOPOLIS TOWN, WY	Distribution	UNATTENDED	34.50	4.16		5	1
849	THERMOPOLIS(WAPA), WY	Distribution	UNATTENDED	115.00	34.50		25	1
850	THUNDER CREEK, WY	Distribution	UNATTENDED	69.00	12.47		14	1
851	VETERANS, WY	Distribution	UNATTENDED	34.50	13.20		25	2
852	WAMSUTTER AMOCO, WY	Distribution	UNATTENDED	34.50	4.16		2	3
853	WARM SPRINGS SPL, WY	Distribution	UNATTENDED	115.00	4.16		9	1
854	WERTZ SINCLAIR, WY	Distribution	UNATTENDED	57.00	4.16		3	6
855	WEST ADAMS, WY	Distribution	UNATTENDED	34.50	4.16		3	1
856	WESTVACO, WY	Distribution	UNATTENDED	230.00	34.50		25	1
857	WHISKEY GULCH, WY	Distribution	UNATTENDED	57.00	12.47		9	1
858	WORLAND TOWN, WY	Distribution	UNATTENDED	34.50	4.16		4	1
859	WYCO BEAR CREEK, WY	Distribution	UNATTENDED	20.80	2.40		1	3
860	WYCO STROUD, WY	Distribution	UNATTENDED	13.20	4.16		2	3
861	WYOPO, WY	Distribution	UNATTENDED	230.00	34.50		20	1	1
862	YELLOWCAKE, WY	Distribution	UNATTENDED	230.00	34.50	13.20	100	2
863	AEOLUS, WY	Transmission	UNATTENDED	500.00	230.00	34.50	5330	10	1
864	ANTICLINE, WY	Transmission	UNATTENDED	500.00	345.00	34.50	1600	(v) 5	1
865	BAIROIL, WY	Transmission	UNATTENDED	115.00	69.00	13.20	53	3
866	CASPER, WY	Transmission	UNATTENDED	230.00	115.00	13.80	575	4
867	CHAPPEL CREEK, WY	Transmission	UNATTENDED	230.00	69.00	12.47	75	1
868	CHIMNEY BUTTE, WY	Transmission	UNATTENDED	230.00	69.00	12.47	75	1
869	(q) DAVE JOHNSTON, WY	Transmission	ATTENDED	230.00	115.00	13.20	316	3	1
870	FOOTE CREEK, WY	Transmission	UNATTENDED	230.00	34.50	12.47	196	2
871	GLENDO AUTO, WY	Transmission	UNATTENDED	69.00	57.00		8	1	1
872	(r) JIM BRIDGER, WY	Transmission	ATTENDED	345.00	230.00	34.50	1250	5	1
873	LATHAM, WY	Transmission	UNATTENDED	230.00	46.00	7.20	575	3
874	MIDWEST, WY	Transmission	UNATTENDED	230.00	69.00	13.20	158	3
875	MUSTANG, WY	Transmission	UNATTENDED	230.00	115.00	13.20	100	1
876	NAUGHTON, WY	Transmission	ATTENDED	230.00	138.00	13.80	661	4
877	OREGON BASIN, WY	Transmission	UNATTENDED	230.00	69.00	13.20	100	2
878	PLATTE, WY	Transmission	UNATTENDED	230.00	115.00	13.20	140	3
879	POINT OF ROCKS, WY	Transmission	UNATTENDED	230.00	34.50	13.20	25	1
880	RAILROAD, WY	Transmission	UNATTENDED	230.00	138.00	24.90	448	1
881	ROCK CREEK COLLECTOR I, WY	Transmission	UNATTENDED	230.00	34.50		300	2
882	ROCK CREEK WIND II, WY	Transmission	UNATTENDED	230.00	34.50		450	3
883	SAGE, WY	Transmission	UNATTENDED	69.00	46.00	2.40	22	1
884	STANDPIPE, WY	Transmission	UNATTENDED	230.00	12.47		75	1
885	THERMOPOLIS, WY	Transmission	UNATTENDED	230.00	115.00	12.47	184	2	1
887	TotalDistributionSubstationAttendedMember						166
888	TotalDistributionSubstationUnttendedMember						16,557
889	TotalTransmissionSubstationAttendedMember						3,857
890	TotalTransmissionSubstationUnattendedMember						53,017
891	Total						73,597					0

Name of Respondent:

PacifiCorp

This report is:

(1)

? An Original

(2)

? A Resubmission

Date of Report:

04/14/2026

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: SubstationNameAndLocation

Substation is jointly owned by PacifiCorp and Idaho Power Company. Ownership and operations and maintenance costs vary by type of asset as defined in the Joint Ownership and Operating Agreement. 100% of the capacity is reported.

(b) Concept: SubstationNameAndLocation

(d) Concept: SubstationNameAndLocation

(e) Concept: SubstationNameAndLocation

(f) Concept: SubstationNameAndLocation

(g) Concept: SubstationNameAndLocation

Substation is jointly owned by PacifiCorp, NorthWestern Energy, Puget Sound Energy, Inc., Portland General Electric Company and Avista Corporation. Ownership and operations and maintenance costs vary by type of asset as defined in the Transmission Agreement. 100% of the capacity is reported.

(h) Concept: SubstationNameAndLocation

(i) Concept: SubstationNameAndLocation

Substation is jointly owned by PacifiCorp and Bonneville Power Administration, each with an undivided interest of 50.0%. Operations and maintenance costs are shared between the two parties and responsibility is as follows: PacifiCorp 58.0% and Bonneville Power Administration 42.0%. 100% of the capacity is reported.

(j) Concept: SubstationNameAndLocation

(k) Concept: SubstationNameAndLocation

Substation is jointly owned by PacifiCorp, Bonneville Power Administration and Portland General Electric Company. Ownership and operations and maintenance costs vary by type of asset as defined in the operations and maintenance agreement. 100% of the capacity is reported.

(l) Concept: SubstationNameAndLocation

(m) Concept: SubstationNameAndLocation

Substation property is owned by PacifiCorp and Bonneville Power Administration as defined in the facility sharing agreement where operations and maintenance costs vary by type of asset and performance responsibility. 100% of the capacity is reported.

(n) Concept: SubstationNameAndLocation

(o) Concept: SubstationNameAndLocation

Substation property is jointly owned by PacifiCorp and Avista Corporation as defined in the interconnection agreement where operations and maintenance costs vary by type of asset and performance responsibility. 100% of the capacity is reported.

(p) Concept: SubstationNameAndLocation

(q) Concept: SubstationNameAndLocation

Substation is jointly owned by PacifiCorp and Black Hills Power with an undivided interest of 85.0% and 15.0%, respectively. Operations and maintenance costs are shared between the two parties based on a fixed amount derived as a factor of the percentage owned of the original installed substation. 100% of the capacity is reported.

(r) Concept: SubstationNameAndLocation

(s) Concept: NumberOfTransformersInService

Includes one 3-phase transformer

(t) Concept: NumberOfTransformersInService

Represents three phase shifters at the substation, which does not change the voltage and reports a 3-phase bank as three transformers.

(u) Concept: NumberOfTransformersInService

Includes one 3-phase transformer

(v) Concept: NumberOfTransformersInService

Represents four phase shifters at the substation, which does not change the voltage and reports a 3-phase bank as three transformers.

Schedules	Pages
Comparative Balance Sheet	110-113
Statement of Income	114-117
Statement of Retained Earnings	118-119
Statement of Cash Flows	120-121
Notes to Financial Statements	122-123

GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general corporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the general corporate books are kept. M. Ryan Weems Senior Vice President, Chief Financial Officer and Treasurer 825 N.E. Multnomah Street, Suite 1900, Portland, OR 97232
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized. PacifiCorp was initially incorporated in 1910 under the laws of the state of Maine under the name Pacific Power & Light Company. In 1984, Pacific Power & Light Company changed its name to PacifiCorp. In 1989, it merged with Utah Power and Light Company, a Utah corporation, in a transaction wherein both corporations merged into a newly formed Oregon corporation. The resulting Oregon corporation was re-named PacifiCorp, which is the operating entity today. State of Incorporation: Date of Incorporation: Incorporated Under Special Law:
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased. Not applicable. (a) Name of Receiver or Trustee Holding Property of the Respondent: (b) Date Receiver took Possession of Respondent Property: (c) Authority by which the Receivership or Trusteeship was created: (d) Date when possession by receiver or trustee ceased:
4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated. PacifiCorp is a United States regulated electric utility company headquartered in Oregon that serves approximately 2.1 million retail electric customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp is principally engaged in the business of generating, transmitting, distributing and selling electricity. In addition to retail sales, PacifiCorp buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp delivers electricity to customers in Utah, Wyoming and Idaho under the trade name Rocky Mountain Power and to customers in Oregon, Washington and California under the trade name Pacific Power.
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant for your previous year's certified financial statements? (1) ? Yes (2) ? No

CORPORATIONS CONTROLLED BY RESPONDENT
Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests. Definitions See the Uniform System of Accounts for a definition of control. Direct control is that which is exercised without interposition of an intermediary. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line No.	NameOfCompanyControlledByRespondent Name of Company Controlled (a)	CompanyControlledByRespondentKindOfBusinessDescription Kind of Business (b)	VotingStockOwnedByRespondentPercentage Percent Voting Stock Owned (c)	FootnoteReferences Footnote Ref. (d)
1	Energy West Mining Company	Mining	100	(a) See footnote
2	Pacific Minerals, Inc.	Management services	100	(b) See footnote
3	Bridger Coal Company	Mining	66.67	(c) See footnote
4	Trapper Mining Inc.	Mining	29.14	(d) See footnote
5	PacifiCorp Foundation	Non-profit foundation		(e) See footnote

OFFICERS
Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made.
Line No.	OfficerTitle Title (a)	OfficerName Name of Officer (b)	OfficerSalary Salary for Year (c)	DateOfficerIncumbencyStarted Date Started in Period (d)	DateOfficerIncumbencyEnded Date Ended in Period (e)
1	(a) Executive Officers for the year ended December 31, 2025:
2	(b) Chief Executive Officer, PacifiCorp	Darin M. Carroll	136,364	2025-11-12
3	(c) Chair of the Board of Directors and Former Chief Executive Officer, PacifiCorp	Cindy A. Crane	2,875,007		2025-11-12
4	President, Pacific Power (Division)	Ryan L. Flynn	465,651
5	President, Rocky Mountain Power (Division)	Richard J. Garlish	465,783
6	(d) Senior Vice President, Chief Financial Officer and Treasurer	M. Ryan Weems	304,336	2025-12-15
7	(e) Former Senior Vice President and Chief Financial Officer	Nikki L. Kobliha	444,136		2025-12-15

DIRECTORS
Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), name and abbreviated titles of the directors who are officers of the respondent. Provide the principle place of business in column (b), designate members of the Executive Committee in column (c), and the Chairman of the Executive Committee in column (d).
Line No.	NameAndTitleOfDirector Name (and Title) of Director (a)	PrincipalBusinessAddress Principal Business Address (b)	MemberOfTheExecutiveCommittee Member of the Executive Committee (c)	ChairmanOfTheExecutiveCommittee Chairman of the Executive Committee (d)
1	Cindy A. Crane (Chair of the Board of Directors)	825 N.E. Multnomah Street, Suite 2000, Portland, OR 97232	false	false
2	(a) Darin M. Carroll (Chief Executive Officer)	1407 West North Temple, Suite 310, Salt Lake City, UT 84116	false	false
3	Ryan L. Flynn (President, Pacific Power Division)	825 N.E. Multnomah Street, Suite 2000, Portland, OR 97232	false	false
4	Richard J. Garlish (President, Rocky Mountain Power Division)	1407 West North Temple, Suite 320, Salt Lake City, UT 84116	false	false
5	(b) M. Ryan Weems (Senior Vice President, Chief Financial Officer and Treasurer)	825 N.E. Multnomah Street, Suite 1900, Portland, OR 97232	false	false
6	(c) Nikki L. Kobliha (Former Senior Vice President and Chief Financial Officer)	825 N.E. Multnomah Street, Suite 1900, Portland, OR 97232	false	false
7	Charles C. Chang	1615 Locust Street, Des Moines, IA 50309	false	false
8	Natalie L. Hocken	825 N.E. Multnomah Street, Suite 2000, Portland, OR 97232	false	false

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

Purpose

Who Must Submit

What and Where to Submit

When to Submit

Where to Send Comments on Public Reporting Burden.

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES




FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and 18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and other sanctions as provided by law. The Federal Energy Regulatory Commission does not consider these reports to be of confidential nature

LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line No.	Title of Schedule (a)	Reference Page No. (b)	Remarks (c)
	ScheduleIdentificationAbstract Identification	1
	ScheduleListOfSchedulesAbstract List of Schedules	2
1	ScheduleGeneralInformationAbstract General Information	101
2	ScheduleControlOverRespondentAbstract Control Over Respondent	102
3	ScheduleCorporationsControlledByRespondentAbstract Corporations Controlled by Respondent	103
4	ScheduleOfficersAbstract Officers	104
5	ScheduleDirectorsAbstract Directors	105
6	ScheduleInformationOnFormulaRatesAbstract Information on Formula Rates	106
7	ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Year	108
8	ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet	110
9	ScheduleStatementOfIncomeAbstract Statement of Income for the Year	114
10	ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Year	118
12	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120
12	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122
13	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Other Comp Income, Comp Income, and Hedging Activities	122a
14	ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep	200
15	ScheduleNuclearFuelMaterialsAbstract Nuclear Fuel Materials	202	N/A
16	ScheduleElectricPlantInServiceAbstract Electric Plant in Service	204
17	ScheduleElectricPropertyLeasedToOthersAbstract Electric Plant Leased to Others	213	N/A
18	ScheduleElectricPlantHeldForFutureUseAbstract Electric Plant Held for Future Use	214
19	ScheduleConstructionWorkInProgressElectricAbstract Construction Work in Progress-Electric	216
20	ScheduleAccumulatedProvisionForDepreciationOfElectricUtilityPlantAbstract Accumulated Provision for Depreciation of Electric Utility Plant	219
21	ScheduleInvestmentsInSubsidiaryCompaniesAbstract Investment of Subsidiary Companies	224
22	ScheduleMaterialsAndSuppliesAbstract Materials and Supplies	227
23	ScheduleAllowanceInventoryAbstract Allowances and Environmental Credits	228
24	ScheduleExtraordinaryPropertyLossesAbstract Extraordinary Property Losses	230a	N/A
25	ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract Unrecovered Plant and Regulatory Study Costs	230b	N/A
26	ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract Transmission Service and Generation Interconnection Study Costs	231
27	ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets	232
28	ScheduleMiscellaneousDeferredDebitsAbstract Miscellaneous Deferred Debits	233
29	ScheduleAccumulatedDeferredIncomeTaxesAbstract Accumulated Deferred Income Taxes	234
30	ScheduleCapitalStockAbstract Capital Stock	250
31	ScheduleOtherPaidInCapitalAbstract Other Paid-in Capital	253
32	ScheduleCapitalStockExpenseAbstract Capital Stock Expense	254b
33	ScheduleLongTermDebtAbstract Long-Term Debt	256
34	ScheduleReconciliationOfReportedNetIncomeWithTaxableIncomeForFederalIncomeTaxesAbstract Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax	261
35	ScheduleTaxesAccruedPrepaidAndChargedDuringYearDistributionOfTaxesChargedAbstract Taxes Accrued, Prepaid and Charged During the Year	262
36	ScheduleAccumulatedDeferredInvestmentTaxCreditsAbstract Accumulated Deferred Investment Tax Credits	266
37	ScheduleOtherDeferredCreditsAbstract Other Deferred Credits	269
38	ScheduleAccumulatedDeferredIncomeTaxesAcceleratedAmortizationPropertyAbstract Accumulated Deferred Income Taxes-Accelerated Amortization Property	272
39	ScheduleAccumulatedDeferredIncomeTaxesOtherPropertyAbstract Accumulated Deferred Income Taxes-Other Property	274
40	ScheduleAccumulatedDeferredIncomeTaxesOtherAbstract Accumulated Deferred Income Taxes-Other	276
41	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278
42	ScheduleElectricOperatingRevenuesAbstract Electric Operating Revenues	300
43	ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1)	302	N/A
44	ScheduleSalesOfElectricityByRateSchedulesAbstract Sales of Electricity by Rate Schedules	304
45	ScheduleSalesForResaleAbstract Sales for Resale	310
46	ScheduleElectricOperationsAndMaintenanceExpensesAbstract Electric Operation and Maintenance Expenses	320
47	SchedulePurchasedPowerAbstract Purchased Power	326
48	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
49	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331	N/A
50	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
51	ScheduleMiscellaneousGeneralExpensesAbstract Miscellaneous General Expenses-Electric	335
52	ScheduleDepreciationDepletionAndAmortizationAbstract Depreciation and Amortization of Electric Plant (Account 403, 404, 405)	336
53	ScheduleRegulatoryCommissionExpensesAbstract Regulatory Commission Expenses	350
54	ScheduleResearchDevelopmentOrDemonstrationExpendituresAbstract Research, Development and Demonstration Activities	352	N/A
55	ScheduleDistributionOfSalariesAndWagesAbstract Distribution of Salaries and Wages	354
56	ScheduleCommonUtilityPlantAndExpensesAbstract Common Utility Plant and Expenses	356	N/A
57	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts included in ISO/RTO Settlement Statements	397
58	SchedulePurchasesSalesOfAncillaryServicesAbstract Purchase and Sale of Ancillary Services	398
59	ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load	400
60	ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load	400a	N/A
61	ScheduleElectricEnergyAccountAbstract Electric Energy Account	401a
62	ScheduleMonthlyPeakAndOutputAbstract Monthly Peaks and Output	401b
63	ScheduleSteamElectricGeneratingPlantStatisticsAbstract Steam Electric Generating Plant Statistics	402
63.1	ScheduleRenewableGeneratingPlantStatisticsAbstract Renewable Generating Plant Statistics	404
64	ScheduleHydroelectricGeneratingPlantStatisticsAbstract Hydroelectric Generating Plant Statistics	406
65	SchedulePumpedStorageGeneratingPlantStatisticsAbstract Pumped Storage Generating Plant Statistics	408	N/A
66	ScheduleGeneratingPlantStatisticsAbstract Generating Plant Statistics Pages	410
66.1	ScheduleEnergyStorageOperationsLargePlantsAbstract Energy Storage Operations (Large Plants)	414	N/A
66.2	ScheduleEnergyStorageOperationsSmallPlantsAbstract Energy Storage Operations (Small Plants)	419	N/A
67	ScheduleTransmissionLineStatisticsAbstract Transmission Line Statistics Pages	422
68	ScheduleTransmissionLinesAddedAbstract Transmission Lines Added During Year	424
69	ScheduleSubstationsAbstract Substations	426
70	ScheduleTransactionsWithAssociatedAffiliatedCompaniesAbstract Transactions with Associated (Affiliated) Companies	429
71	FootnoteDataAbstract Footnote Data	450
	StockholdersReportsAbstract Stockholders' Reports (check appropriate box)
	Stockholders' Reports Check appropriate box: ? Two copies will be submitted ? No annual report to stockholders is prepared

INFORMATION ON FORMULA RATES
Does the respondent have formula rates?		? Yes ? No
Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No) accepting the rate(s) or changes in the accepted rate.
Line No.	RateScheduleTariffNumber FERC Rate Schedule or Tariff Number (a)	ProceedingDocketNumber FERC Proceeding (b)
1	FERC Electric Tariff Volume No. 11, Attachment H-1	ER25-2221

INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent) filings containing the inputs to the formula rate(s)?			? Yes ? No
If yes, provide a listing of such filings as contained on the Commission's eLibrary website.
Line No.	AccessionNumber Accession No. (a)	DocumentDate Document Date / Filed Date (b)	DocketNumber Docket No. (c)	DescriptionOfFiling Description (d)	RateScheduleTariffNumber Formula Rate FERC Rate Schedule Number or Tariff Number (e)
1	20250116-5113	01/16/2025	ER25-951-000	(a) See footnote	PacifiCorp's Volume No. 11 Open Access Transmission Tariff
2	20250317-5087	03/17/2025	ER25-1652-000	(b) See footnote	PacifiCorp's Volume No. 11 Open Access Transmission Tariff
3	20250514-5149	05/14/2025	ER25-2221-000	(c) See footnote	PacifiCorp's Volume No. 11 Open Access Transmission Tariff

INFORMATION ON FORMULA RATES - Formula Rate Variances
If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from amounts reported in the Form 1. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the Form 1. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line No.	PageNumberOfFormulaRateVariances Page No(s). (a)	ScheduleOfFormulaRateVariances Schedule (b)	ColumnOfFormulaRateVariances Column (c)	LineNumberOfFormulaRateVariances Line No. (d)
1	204-207	Electric Plant in Service	(b)	46
2	204-207	Electric Plant in Service	(g)	46
3	204-207	Electric Plant in Service	(b)	58
4	204-207	Electric Plant in Service	(g)	58
5	204-207	Electric Plant in Service	(b)	75
6	204-207	Electric Plant in Service	(g)	75
7	204-207	Electric Plant in Service	(b)	99
8	204-207	Electric Plant in Service	(g)	99
9	204-207	Electric Plant in Service	(b)	104
10	204-207	Electric Plant in Service	(g)	104
11	219	Accumulated Provision for Depreciation of Electric Utility Plant	(c)	20
12	219	Accumulated Provision for Depreciation of Electric Utility Plant	(c)	22
13	219	Accumulated Provision for Depreciation of Electric Utility Plant	(c)	23.1
14	219	Accumulated Provision for Depreciation of Electric Utility Plant	(c)	23.2
15	219	Accumulated Provision for Depreciation of Electric Utility Plant	(c)	23.3
16	219	Accumulated Provision for Depreciation of Electric Utility Plant	(c)	24
17	219	Accumulated Provision for Depreciation of Electric Utility Plant	(c)	25
18	219	Accumulated Provision for Depreciation of Electric Utility Plant	(c)	26
19	219	Accumulated Provision for Depreciation of Electric Utility Plant	(c)	28
20	219	Accumulated Provision for Depreciation of Electric Utility Plant	(c)	29
21	232	Other Regulatory Assets	(e)	18
22	232	Other Regulatory Assets	(e)	22
23	232	Other Regulatory Assets	(e)	34
24	232	Other Regulatory Assets	(e)	71
25	232	Other Regulatory Assets	(e)	79
26	232	Other Regulatory Assets	(e)	80
27	232	Other Regulatory Assets	(e)	81
28	320-323	Electric Operation and Maintenance Expenses	(b)	181
29	320-323	Electric Operation and Maintenance Expenses	(b)	184
30	320-323	Electric Operation and Maintenance Expenses	(b)	185
31	320-323	Electric Operation and Maintenance Expenses	(b)	186
32	320-323	Electric Operation and Maintenance Expenses	(b)	187
33	320-323	Electric Operation and Maintenance Expenses	(b)	193
34	320-323	Electric Operation and Maintenance Expenses	(b)	196
35	320-323	Electric Operation and Maintenance Expenses	(b)	197

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlant Utility Plant (101-106, 114)	200	41,110,603,213	38,155,394,721
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	3,305,302,836	3,480,932,688
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		44,415,906,049	41,636,327,409
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	14,475,856,318	13,997,879,081
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		29,940,049,731	27,638,448,328
7	NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)	202
8	NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
9	NuclearFuelAssembliesInReactorMajorOnly Nuclear Fuel Assemblies in Reactor (120.3)
10	SpentNuclearFuelMajorOnly Spent Nuclear Fuel (120.4)
11	NuclearFuelUnderCapitalLeases Nuclear Fuel Under Capital Leases (120.6)
12	AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)	202
13	NuclearFuelNet Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
14	UtilityPlantAndNuclearFuelNet Net Utility Plant (Enter Total of lines 6 and 13)		29,940,049,731	27,638,448,328
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		21,396,846	22,725,917
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		3,256,980	3,313,253
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)		69,928	69,928
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	121,927,231	110,614,113
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances and Environmental Credits	228	62,450,828
24	OtherInvestments Other Investments (124)		122,177,780	116,401,525
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)		190,589,810	168,343,042
29	SpecialFunds Special Funds (Non Major Only) (129)
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)			22,515
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		515,355,443	414,863,787
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		8,326,712	20,419,589
36	SpecialDeposits Special Deposits (132-134)		34,305	78,926
37	WorkingFunds Working Fund (135)
38	TemporaryCashInvestments Temporary Cash Investments (136)		54,227,905	21,069,354
39	NotesReceivable Notes Receivable (141)		1,297,000	1,395,148
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		688,043,612	652,829,359
41	OtherAccountsReceivable Other Accounts Receivable (143)		169,487,267	217,838,570
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		20,035,004	21,911,623
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		(a) 117,778,797	(b) 30,013,788
45	FuelStock Fuel Stock (151)	227	307,771,791	270,978,352
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227
47	Residuals Residuals (Elec) and Extracted Products (153)	227
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	612,027,820	557,149,099
49	Merchandise Merchandise (155)	227
50	OtherMaterialsAndSupplies Other Materials and Supplies (156)	227
51	NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157)	202/227
52	AllowanceInventoryAndWithheld Allowances and Environmental Credits (158.1, 158.2, 158.3, and 158.4)	228	121,703,614	2,677,526
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances and Environmental Credits	228	62,450,828
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227
55	GasStoredCurrent Gas Stored Underground - Current (164.1)
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57	Prepayments Prepayments (165)		92,277,997	324,807,839
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)		3,055,500	2,904,673
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		380,479,000	328,006,000
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		4,714,095	9,033,345
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)			22,515
65	DerivativeInstrumentAssetsHedges Derivative Instrument Assets - Hedges (176)
66	DerivativeInstrumentAssetsHedgesLongTerm (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
67	CurrentAndAccruedAssets Total Current and Accrued Assets (Lines 34 through 66)		2,478,739,583	2,417,267,430
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		82,055,302	78,200,282
70	ExtraordinaryPropertyLosses Extraordinary Property Losses (182.1)	230a
71	UnrecoveredPlantAndRegulatoryStudyCosts Unrecovered Plant and Regulatory Study Costs (182.2)	230b
72	OtherRegulatoryAssets Other Regulatory Assets (182.3)	232	2,487,233,113	2,844,837,159
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		25,280,117	20,770,921
74	PreliminaryNaturalGasSurveyAndInvestigationChargesAndOtherPreliminarySurveyAndInvestigationCharges Preliminary Natural Gas Survey and Investigation Charges 183.1)
75	OtherPreliminarySurveyAndInvestigationCharges Other Preliminary Survey and Investigation Charges (183.2)
76	ClearingAccounts Clearing Accounts (184)
77	TemporaryFacilities Temporary Facilities (185)		158,130	105,375
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	156,847,459	167,419,699
79	DeferredLossesFromDispositionOfUtilityPlant Def. Losses from Disposition of Utility Plt. (187)
80	ResearchDevelopmentAndDemonstrationExpenditures Research, Devel. and Demonstration Expend. (188)	352
81	UnamortizedLossOnReacquiredDebt Unamortized Loss on Reaquired Debt (189)		1,429,638	1,672,786
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	903,260,908	957,142,003
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		3,656,264,667	4,070,148,225
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		36,590,409,424	34,540,727,770

COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	ProprietaryCapitalAbstract PROPRIETARY CAPITAL
2	CommonStockIssued Common Stock Issued (201)	250	3,417,945,896	3,417,945,896
3	PreferredStockIssued Preferred Stock Issued (204)	250		2,397,600
4	CapitalStockSubscribed Capital Stock Subscribed (202, 205)
5	StockLiabilityForConversion Stock Liability for Conversion (203, 206)
6	PremiumOnCapitalStock Premium on Capital Stock (207)
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	1,102,063,956	1,102,063,956
8	InstallmentsReceivedOnCapitalStock Installments Received on Capital Stock (212)	252
9	DiscountOnCapitalStock (Less) Discount on Capital Stock (213)	254
10	CapitalStockExpense (Less) Capital Stock Expense (214)	254b	41,101,061	41,101,061
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	6,612,635,392	5,985,858,857
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	65,582,520	54,269,402
13	ReacquiredCapitalStock (Less) Reacquired Capital Stock (217)	250
14	NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218)
15	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	122(a)(b)	9,985,387	9,115,257
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		11,147,141,316	10,512,319,393
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	13,400,000,000	13,701,700,000
19	ReacquiredBonds (Less) Reacquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256	850,000,000
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		34,099,993	36,057,304
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		14,215,900,007	13,665,642,696
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		400,235,959	29,953,621
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)		1,088,727	878,641
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		426,749,108	1,289,236,654
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		49,657,914	50,706,654
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)		24,217,590	26,585,705
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities		23,058,603	16,840,883
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		518,345,642	426,887,234
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		1,443,353,543	1,841,089,392
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)		1,000,000,000	240,500,000
38	AccountsPayable Accounts Payable (232)		1,112,555,060	1,219,363,802
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)			(b) 127,700
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		253,580,686	212,484,358
41	CustomerDeposits Customer Deposits (235)		37,870,537	28,033,595
42	TaxesAccrued Taxes Accrued (236)	262	(a) 60,904,052	(c) 51,234,269
43	InterestAccrued Interest Accrued (237)		260,174,942	239,029,281
44	DividendsDeclared Dividends Declared (238)			40,475
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		33,185,756	31,487,478
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		1,015,000,199	427,658,426
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		41,078,561	5,150,075
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		70,408,061	99,747,083
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities		23,058,603	16,840,883
52	DerivativeInstrumentLiabilitiesHedges Derivative Instrument Liabilities - Hedges (245)
53	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54	CurrentAndAccruedLiabilities Total Current and Accrued Liabilities (lines 37 through 53)		3,861,699,251	2,538,015,659
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)		310,735,389	308,544,692
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	10,535,571	10,431,425
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	354,618,476	346,062,811
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	1,017,126,814	1,096,048,745
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reacquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272	95,276,897	111,057,724
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		3,450,848,187	3,345,774,488
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		683,173,973	765,740,745
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		5,922,315,307	5,983,660,630
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		36,590,409,424	34,540,727,770

STATEMENT OF INCOME
Quarterly Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k) the quarter to date amounts for other utility function for the current year quarter. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l) the quarter to date amounts for other utility function for the prior year quarter. If additional columns are needed, place them in a footnote. Annual or Quarterly if applicable Do not report fourth quarter data in columns (e) and (f) Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility column in a similar manner to a utility department. Spread the amount(s) over Lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above. Use page 122 for important notes regarding the statement of income for any account thereof. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year affected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases. Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases, and a summary of the adjustments made to balance sheet, income, and expense accounts. If any notes appearing in the report to stockholders are applicable to the Statement of Income, such notes may be included at page 122. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line No.	Title of Account (a)	(Ref.) Page No. (b)	Total Current Year to Date Balance for Quarter/Year (c)	Total Prior Year to Date Balance for Quarter/Year (d)	Current 3 Months Ended - Quarterly Only - No 4th Quarter (e)	Prior 3 Months Ended - Quarterly Only - No 4th Quarter (f)	Electric Utility Current Year to Date (in dollars) (g)	Electric Utility Previous Year to Date (in dollars) (h)	Gas Utiity Current Year to Date (in dollars) (i)	Gas Utility Previous Year to Date (in dollars) (j)	Other Utility Current Year to Date (in dollars) (k)	Other Utility Previous Year to Date (in dollars) (l)
1	UtilityOperatingIncomeAbstract UTILITY OPERATING INCOME
2	OperatingRevenues Operating Revenues (400)	300	7,440,615,463	6,587,229,882			7,440,615,463	6,587,229,882
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	4,473,188,770	4,097,168,720			4,473,188,770	4,097,168,720
5	MaintenanceExpense Maintenance Expenses (402)	320	620,364,485	607,876,783			620,364,485	607,876,783
6	DepreciationExpense Depreciation Expense (403)	336	(a) 1,245,953,331	1,045,757,086			1,245,953,331	1,045,757,086
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336	(b) 0				(e) 0
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	9,557,343	69,382,163			9,557,343	69,382,163
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336	376,987	376,987			376,987	376,987
10	AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11	AmortizationOfConversionExpenses Amort. of Conversion Expenses (407.2)
12	RegulatoryDebits Regulatory Debits (407.3)		15,902,911	17,315,768			15,902,911	17,315,768
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		8,825,033	5,873,329			8,825,033	5,873,329
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	(c) 238,675,192	217,834,522			238,675,192	217,834,522
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	193,604,485	275,783,696			193,604,485	275,783,696
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	9,235,745	516,609			9,235,745	516,609
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	1,232,872,672	1,201,774,956			1,232,872,672	1,201,774,956
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	1,269,721,282	1,204,598,391			1,269,721,282	1,204,598,391
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	202,611	471,299			202,611	471,299
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)			18,357				18,357
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)		25,281,286	83			25,281,286	83
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)		(d) 0
24.1	GainsFromDispositionOfEnvironmentalCredits (Less) Gains from Disposition of Environmental Credits (411.11)		24,294,876				24,294,876
24.2	LossesFromDispositionOfEnvironmentalCredits Losses from Disposition of Environmental Credits (411.12)
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24.2)		6,324,197,863	5,770,225,221			6,324,197,863	5,770,225,221
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		1,116,417,600	817,004,661			1,116,417,600	817,004,661
28	OtherIncomeAndDeductionsAbstract Other Income and Deductions
29	OtherIncomeAbstract Other Income
30	NonutilityOperatingIncomeAbstract Nonutilty Operating Income
31	RevenuesFromMerchandisingJobbingAndContractWork Revenues From Merchandising, Jobbing and Contract Work (415)		3,600,138	7,047,062
32	CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)		4,383,648	7,792,908
33	RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417)		300
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		27,519	18,023
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		51,355	62,494
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	11,357,123	7,996,585
37	InterestAndDividendIncome Interest and Dividend Income (419)		113,032,946	188,938,984
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		119,886,497	203,117,652
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		10,819,723	2,418,271
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		11,603,800	3,477,908
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		265,940,715	405,248,025
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		5,210	21,315
44	MiscellaneousAmortization Miscellaneous Amortization (425)		1,424,361	1,419,634
45	Donations Donations (426.1)		2,927,265	3,111,435
46	LifeInsurance Life Insurance (426.2)		9,835,884	11,198,507
47	Penalties Penalties (426.3)		1,331,624	43,853
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		1,719,518	1,833,428
49	OtherDeductions Other Deductions (426.5)		19,430,229	9,011,027
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		17,002,323	4,242,185
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	386,270	401,523
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	21,519,796	35,751,635
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	4,873,638	8,096,757
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	59,516,897	97,851,579
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	58,728,060	97,395,433
57	InvestmentTaxCreditAdjustmentsNonutilityOperations Investment Tax Credit Adj.-Net (411.5)
58	InvestmentTaxCredits (Less) Investment Tax Credits (420)		1,393,463	198,727
59	TaxesOnOtherIncomeAndDeductions TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)		26,175,078	44,507,334
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		222,763,314	356,498,506
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		733,259,008	696,924,773
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		7,217,613	7,245,225
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		243,148	325,025
65	AmortizationOfPremiumOnDebtCredit (Less) Amort. of Premium on Debt-Credit (429)
66	AmortizationOfGainOnReacquiredDebtCredit (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67	InterestOnDebtToAssociatedCompanies Interest on Debt to Assoc. Companies (430)			267,961
68	OtherInterestExpense Other Interest Expense (431)		49,533,071	49,671,179
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		91,212,582	119,854,967
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		699,040,258	634,579,196
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		640,140,656	538,923,971
72	ExtraordinaryItemsAbstract Extraordinary Items
73	ExtraordinaryIncome Extraordinary Income (434)
74	ExtraordinaryDeductions (Less) Extraordinary Deductions (435)
75	NetExtraordinaryItems Net Extraordinary Items (Total of line 73 less line 74)
76	IncomeTaxesExtraordinaryItems Income Taxes-Federal and Other (409.3)	262	0
77	ExtraordinaryItemsAfterTaxes Extraordinary Items After Taxes (line 75 less line 76)
78	NetIncomeLoss Net Income (Total of line 71 and 77)		640,140,656	538,923,971

STATEMENT OF RETAINED EARNINGS
Do not report Lines 49-53 on the quarterly report. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436-439 inclusive). Show the contra primary account affected in column (b). State the purpose and amount for each reservation or appropriation of retained earnings. List first Account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items, in that order. Show dividends for each class and series of capital stock. Show separately the State and Federal income tax effect of items shown for Account 439, Adjustments to Retained Earnings. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated. If any notes appearing in the report to stockholders are applicable to this statement, attach them at page 122.
Line No.	Item (a)	Contra Primary Account Affected (b)	Current Quarter/Year Year to Date Balance (c)	Previous Quarter/Year Year to Date Balance (d)
	UnappropriatedRetainedEarningsAbstract UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1	UnappropriatedRetainedEarnings Balance-Beginning of Period		5,921,459,369	5,336,726,250
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
10.1	AdjustmentsToRetainedEarningsDebit Preferred Stock Redemption Adjustments		2,051,003
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)		2,051,003
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		628,783,533	530,927,386
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)
23	DividendsDeclaredPreferredStockAbstract Dividends Declared-Preferred Stock (Account 437)
23.1	DividendsDeclaredPreferredStock Preferred Stock, various series and rates	238		(c) 161,902
29	DividendsDeclaredPreferredStock TOTAL Dividends Declared-Preferred Stock (Acct. 437)			161,902
30	DividendsDeclaredCommonStockAbstract Dividends Declared-Common Stock (Account 438)
30.1	DividendsDeclaredCommonStock Common Stock
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)
37	TransfersFromUnappropriatedUndistributedSubsidiaryEarnings Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings		(a) 44,005	(d) 53,967,635
38	UnappropriatedRetainedEarnings Balance - End of Period (Total 1,9,15,16,22,29,36,37)		6,548,235,904	5,921,459,369
39	AppropriatedRetainedEarningsAbstract APPROPRIATED RETAINED EARNINGS (Account 215)
45	AppropriatedRetainedEarnings TOTAL Appropriated Retained Earnings (Account 215)
	AppropriatedRetainedEarningsAmortizationReserveFederalAbstract APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46	AppropriatedRetainedEarningsAmortizationReserveFederal TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)		(b) 64,399,488	(e) 64,399,488
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)		64,399,488	64,399,488
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		6,612,635,392	5,985,858,857
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)		54,269,402	100,240,452
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)		11,357,123	7,996,585
51	DividendsReceived (Less) Dividends Received (Debit)
52	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
52.1	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits Transfers to/from Unappropriated Retained Earnings (Account 216)		44,005	53,967,635
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)		65,582,520	54,269,402

STATEMENT OF CASH FLOWS
Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost.
Line No.	Description (See Instructions No.1 for explanation of codes) (a)	Current Year to Date Quarter/Year (b)	Previous Year to Date Quarter/Year (c)
1	NetCashFlowFromOperatingActivitiesAbstract Net Cash Flow from Operating Activities
2	NetIncomeLoss Net Income (Line 78(c) on page 117)	640,140,656	538,923,971
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	(a) 1,274,013,514	1,072,275,371
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization:
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of software and other intangibles	10,981,704	70,801,797
5.3	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of electric plant acquisition adjustment	376,987	376,987
5.4	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of regulatory assets	4,127,458	8,556,667
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	36,059,773	2,367,289
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	1,596,074	670,026
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	147,892,332	77,794,824
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	91,672,160	295,762,588
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances and Environmental Credits Inventory	(b) 70,677,490
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	261,884,210	200,924,072
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	461,899,749	219,826,279
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	20,621,788	16,110,240
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	119,886,497	203,117,652
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies	11,313,118	45,971,050
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other Operating Activities:
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amounts Due To/From Affiliates, Net	88,013,120	153,174,068
18.3	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Derivative Collateral (Net)	64,200,000	3,800,000
18.4	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Prepayments	137,823,957	99,598,554
18.5	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other Assets	51,742,832	6,395,288
18.6	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Depreciation and depletion included in cost of fuel	2,554,157	2,557,211
18.7	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Net (gain) / loss on sale of property	11,844,453	1,516,873
18.8	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Asset under construction write-offs and plant disallowances and impairments	20,508,566	23,478,688
18.9	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Change in corporate owned life insurance cash surrender value	10,291,731	11,167,817
18.10	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of debt issuance expenses and bond discount/premium	7,217,613	7,245,225
18.11	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Net (gain) / loss on long-term incentive plan and deferred compensation securities	2,125,135	2,378,416
18.12	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other	26,988	29,323
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	1,714,579,876	1,204,199,160
24	CashFlowsFromInvestmentActivitiesAbstract Cash Flows from Investment Activities:
25	ConstructionAndAcquisitionOfPlantIncludingLandAbstract Construction and Acquisition of Plant (including land):
26	GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities Gross Additions to Utility Plant (less nuclear fuel)	3,115,147,626	3,303,219,384
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant	516,117	1,590,806
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	119,886,497	203,117,653
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	2,994,745,012	3,101,692,537
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)	(c) 13,273,269	(d) 3,866,730
39	InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Investments in and Advances to Assoc. and Subsidiary Companies
40	ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies Contributions and Advances from Assoc. and Subsidiary Companies
41	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract Disposition of Investments in (and Advances to)
42	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
44	PurchaseOfInvestmentSecurities Purchase of Investment Securities (a)
45	ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a)
46	LoansMadeOrPurchased Loans Made or Purchased
47	CollectionsOnLoans Collections on Loans
49	NetIncreaseDecreaseInReceivablesInvestingActivities Net (Increase) Decrease in Receivables
50	NetIncreaseDecreaseInInventoryInvestingActivities Net (Increase) Decrease in Inventory
51	NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities Net (Increase) Decrease in Allowances and Environmental Credits Held for Speculation
52	NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities Net Increase (Decrease) in Payables and Accrued Expenses
53	OtherAdjustmentsToCashFlowsFromInvestmentActivities Other (provide details in footnote):
53.1	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Other Investing Activities:
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Net proceeds from (purchases of) long-term incentive plan and deferred compensation securities	3,214,312	4,042,500
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Net proceeds from (purchases of) company owned life insurance policies	1,818,728	2,554,225
53.4	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Other investments / special funds	149,864	30,856
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	2,976,588,567	3,091,198,226
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	850,000,000	(e) 3,761,850,318
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)	759,671,316
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	1,609,671,316	3,761,850,318
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	301,700,000	591,450,000
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock	4,448,603
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Net repayments of affiliate borrowing from subsidiary company, Pacific Minerals, Inc.		40,600,000
76.2	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Repayment of finance lease obligations	3,721,643	1,506,702
76.3	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Other deferred financing costs	1,158,180	1,231,705
76.4	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Long-term debt issuance costs	9,054,996	(f) 0
76.5	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Other	60,327	135,325
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)		1,364,062,556
80	DividendsOnPreferredStock Dividends on Preferred Stock	40,475	161,902
81	DividendsOnCommonStock Dividends on Common Stock
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	1,289,487,092	1,762,702,128
85	NetIncreaseDecreaseInCashAndCashEquivalentsAbstract Net Increase (Decrease) in Cash and Cash Equivalents
86	NetIncreaseDecreaseInCashAndCashEquivalents Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83)	27,478,401	124,296,938
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	56,677,501	180,974,439
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	84,155,902	56,677,501

TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not attempt to include or aggregate amounts in a nonspecific category such as "general". Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Line No.	Description of the Good or Service (a)	Name of Associated/Affiliated Company (b)	Account(s) Charged or Credited (c)	Amount Charged or Credited (d)
1	Non-power Goods or Services Provided by Affiliated
2	Coal purchases	Bridger Coal Company	151, 501	110,068,574
3	Coal purchases	Trapper Mining Inc.	151, 501	22,892,705
4	(a) Administrative services under the IASA	Berkshire Hathaway Energy Company	107, 134, 165, 426.1, 426.4, 426.5, 557, 903, 909, 921, 923, 924, 925, 930.2, 935.2	93,097,050
5	Gas transportation services	Kern River Gas Transmission Company	547	3,096,121
6	Operational support services	Kern River Gas Transmission Company	567, 571	5,633,022
7	Administrative services under the IASA	MidAmerican Energy Company	107, 165, 426.1, 426.4, 426.5, 921, 923, 930.2, 935.2	14,865,389
8	Administrative services under the IASA	Nevada Power Company	107, 923	1,112,576
9	Operational support services	Nevada Power Company	561.7, 570, 571	293,756
10	Administrative services under the IASA	Northern Natural Gas	107, 923, 930.2	1,318,372
11	Rail services and right-of-way fees	BNSF Railway Company	151, 501, 507, 567, 589, 593	(b) 29,134,802
12	Rating agency fees	Moody's Investors Service, Inc.	186	488,750
13	Travel services	NetJets, Inc.	426.5	821,661
19
20	Non-power Goods or Services Provided for Affiliated
21	Administrative support services	Bridger Coal Company	426.5, 501, 557, 925, 929	2,012,966
22	Administrative services under the IASA	Berkshire Hathaway Energy Company	408, 426.5, 535, 556, 557, 560, 580, 588, 589, 590, 901, 903, 922, 923, 929, 931, 935.2	6,498,703
23	Administrative services under the IASA	BHE Renewables, LLC	535, 539, 556, 557, 580, 922, 923, 929, 935.2	827,340
24	Administrative services under the IASA	BHE GT&S, LLC	557, 580, 922, 923, 929, 935.2	2,143,295
25	Administrative services under the IASA	BHE U.S. Transmission	557, 560, 580, 922, 923, 929, 935.2	1,265,754
26	Administrative services under the IASA	Kern River Gas Transmission Company	556, 557, 580, 922, 923, 929, 935.2	301,778
27	Administrative services under the IASA	Northern Natural Gas Company	556, 557, 580, 903, 922, 923, 929, 935.2	1,693,112
28	Administrative services under the IASA	BHE Turbo Machinery, LLC	426.5, 535, 557, 560, 922, 929	470,657
29	Administrative services under the IASA	MTL Canyon Holdings, LLC	560, 580, 922, 929	1,205,149
30	Administrative services under the IASA	MidAmerican Energy Company	426.5, 539, 556, 557, 580, 901, 903, 922, 923, 929, 930.2, 935.2	8,817,982
31	Administrative services under the IASA	Northern Powergrid Holdings Company	557, 580, 922, 923, 929, 935.2	1,725,199
32	Administrative services under the IASA	NV Energy, Inc.	535, 539, 556, 557, 580, 592.3, 903, 922, 923, 929, 930.2, 935.2	3,671,418
33	Administrative services under the IASA	Nevada Power Company	557, 580, 922, 923, 929, 935.2	891,700
34	Administrative services under the IASA	Sierra Pacific Power Company	557, 580, 922, 923, 929, 935.2	555,624
35	Operational support services	Sierra Pacific Power Company	456	9,952
42

FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

Purpose

Who Must Submit

What and Where to Submit

When to Submit

Where to Send Comments on Public Reporting Burden.

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report