THIS FILING IS

Item 1:

☑ An Initial (Original) Submission

☐ Resubmission No.




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

Exact Legal Name of Respondent (Company)

NorthWestern Corporation

Year/Period of Report

End of:

2025

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

Purpose
FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q) is a quarterly regulatory requirement which supplements the annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be non-confidential public use forms.
Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities, Licensees, and Others Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).
Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:
1. one million megawatt hours of total annual sales,
2. 100 megawatt hours of annual sales for resale,
3. 500 megawatt hours of annual power exchanges delivered, or
4. 500 megawatt hours of annual wheeling for others (deliveries plus losses).

What and Where to Submit

Submit FERC Form Nos. 1 and 3-Q electronically through the eCollection portal at https://eCollection.ferc.gov, and according to the specifications in the Form 1 and 3-Q taxonomies.
The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of the Commission at:
Secretary
Federal Energy Regulatory Commission 888 First Street, NE
Washington, DC 20426

For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to the Secretary of the Commission at the address above.

The CPA Certification Statement should:

Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting releases), and

Be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18 C.F.R. §§ 41.10-41.12 for specific qualifications.)

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

The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported.
“In connection with our regular examination of the financial statements of [COMPANY NAME] for the year ended on which we have reported separately under date of [DATE], we have also reviewed schedules [NAME OF SCHEDULES] of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below) conform in all material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist.
Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. Further instructions are found on the Commission’s website at https://www.ferc.gov/ferc-online/ferc-online/frequently-asked-questions-faqs-efilingferc-online.
Federal, State, and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-Q free of charge from https://www.ferc.gov/general-information-0/electric-industry-forms.

When to Submit
FERC Forms 1 and 3-Q must be filed by the following schedule:
1. FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and
2. FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400).
Where to Send Comments on Public Reporting Burden.
The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,168 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated to average 168 hours per response.
Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information does not display a valid control number (44 U.S.C. § 3512 (a)).

GENERAL INSTRUCTIONS

Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words and phrases in accordance with the USofA.
Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the current year's year to date amounts.
Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and completely states the fact.
For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) on the List of Schedules, pages 2 and 3.
Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to be completed only for resubmissions (see VII. below).
Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.
For any resubmissions, please explain the reason for the resubmission in a footnote to the data field.
Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different figures were used.
Schedule specific instructions are found in the applicable taxonomy and on the applicable blank rendered form.

Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:

FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff. "Self" means the respondent.

FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.

LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and” firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.

OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and “firm” means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally get out of the contract.

SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations, where the duration of each period of reservation is less than one-year.

NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions.

OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentioned classifications, such as all other service regardless of the length of the contract and service FERC Form. Describe the type of service in a footnote for each entry.

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.

DEFINITIONS

Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any other Commission. Name the commission whose authorization was obtained and give date of the authorization.
Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report is made.

EXCERPTS FROM THE LAW

Federal Power Act, 16 U.S.C. § 791a-825r

Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:

’Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafter defined;
'Person' means an individual or a corporation;
'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successor in interest thereof;

'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or distributing power; ......

"project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power there from to the point of junction with the distribution system or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary or appropriate in the maintenance and operation of such unit;

"Sec. 4. The Commission is hereby authorized and empowered

'To make investigations and to collect and record data concerning the utilization of the water 'resources of any region to be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity, development costs, and relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for the purposes of this Act."

"Sec. 304.

Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the Commission may by rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the proper administration of this Act. The Commission may prescribe the manner and FERC Form in which such reports shall be made, and require from such persons specific answers to all questions upon which the Commission may need information. The Commission may require that such reports shall include, among other things, full information as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other facilities, depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless the Commission otherwise specifies*.10

"Sec. 309.

The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may prescribe the FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and the time within which they shall be field..."

GENERAL PENALTIES

The Commission may assess up to $1 million per day per violation of its rules and regulations. See FPA § 316(a) (2005), 16 U.S.C. § 825o(a).

FERC FORM NO.

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

IDENTIFICATION

01 Exact Legal Name of Respondent

NorthWestern Corporation

02 Year/ Period of Report

End of:

2025

03 Previous Name and Date of Change (If name changed during year)

04 Address of Principal Office at End of Period (Street, City, State, Zip Code)

3010 West 69th Street, Sioux Falls, SD 57108

05 Name of Contact Person

Evan VerWey

06 Title of Contact Person

Manager of Financial Reporting

07 Address of Contact Person (Street, City, State, Zip Code)

3010 West 69th Street, Sioux Falls, SD 57108

08 Telephone of Contact Person, Including Area Code

605-978-2906

09 This Report is An Original / A Resubmission

(1)

☑ An Original

(2)

☐ A Resubmission

10 Date of Report (Mo, Da, Yr)

12/31/2025

Annual Corporate Officer Certification

The undersigned officer certifies that:

I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material respects to the Uniform System of Accounts.

01 Name

Jeff Berzina

02 Title

Controller

03 Signature

Jeff Berzina

04 Date Signed (Mo, Da, Yr)

02/27/2026

Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any false, fictitious or fraudulent statements as to any matter within its jurisdiction.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

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	Not Applicable
16	ScheduleElectricPlantInServiceAbstract Electric Plant in Service	204
17	ScheduleElectricPropertyLeasedToOthersAbstract Electric Plant Leased to Others	213	Not Applicable
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	Not Applicable
25	ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract Unrecovered Plant and Regulatory Study Costs	230b	Not Applicable
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	Not Applicable
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	Not Applicable
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	Not Applicable
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	Not Applicable
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	Not Applicable
55	ScheduleDistributionOfSalariesAndWagesAbstract Distribution of Salaries and Wages	354
56	ScheduleCommonUtilityPlantAndExpensesAbstract Common Utility Plant and Expenses	356
57	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts included in ISO/RTO Settlement Statements	397	Not Applicable
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	Not Applicable
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	Not Applicable
66	ScheduleGeneratingPlantStatisticsAbstract Generating Plant Statistics Pages	410
66.1	ScheduleEnergyStorageOperationsLargePlantsAbstract Energy Storage Operations (Large Plants)	414	Not Applicable
66.2	ScheduleEnergyStorageOperationsSmallPlantsAbstract Energy Storage Operations (Small Plants)	419
67	ScheduleTransmissionLineStatisticsAbstract Transmission Line Statistics Pages	422
68	ScheduleTransmissionLinesAddedAbstract Transmission Lines Added During Year	424	Not Applicable
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

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

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. Jeff B. Berzina Contoller 3010 West 69th Street, Sioux Falls, SD 57108
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. State of Incorporation: DE Date of Incorporation: 1923-11-27 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. (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. Electric and Natural Gas Utility in Montana; Electric Utility in Wyoming (Yellowstone National Park); and Propane in Montana.
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

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the respondent at the end of the year, state name of controlling corporation or organization, manner in which control was held, and extent of control. If control was in a holding company organization, show the chain of ownership or control to the main parent company or organization. If control was held by a trustee(s), state name of trustee(s), name of beneficiary or beneficiaries for whom trust was maintained, and purpose of the trust.

Respondent is a wholly-owned, direct subsidiary of NorthWestern Energy Group, Inc. At December 31, 2025, NorthWestern Energy Group, Inc. owned 100% of the common stock of Respondent.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

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	Canadian-Montana Pipe Line Corporation	Owns natural gas pipeline	100
2	Havre Pipeline Company, LLC	Natural gas transmission and gathering system	96
3	Clarkfork and Blackfoot, LLC	Owned a former hydro facility in Montana	100
4	Lodge Creek Pipelines, LLC	Natural gas gathering system	100
5	Willow Creek Pipelines, LLC	Nautral gas gathering system	100
6	NorthWestern Great Falls Gas, LLC	Natural gas distribution system and operations	100
7	NorthWestern Cut Bank Gas, LLC	Natural gas distribution system and operations	100

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

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	President and Chief Executive Officer	Brian Bird	921,263
2	Vice President, Chief Financial Officer	Cyrstal Lail	511,813
3	Vice President, General Counsel and Federal Government Affairs	Shannon Heim	378,741
4	Vice President, Asset Management & Business Development	Bleau Lafave	289,627
5	Vice President, Customer Care, Communications, and Human Resources	Bobbi Schroeppel	358,269
6	Vice President, Distribution	Jason Merkel	298,432
7	Vice President, Technology	Jeanne Vold	286,615
8	Vice President, Supply and Montana Government Affairs	John Hines	353,151
9	Vice President, Transmission	Michael Cashell	353,151

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

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	Brian Bird (President and Chief Executive Officer)	Sioux Falls, South Dakota	false	false
2	Cyrstal Lail (Vice President, Chief Financial Officer)	Sioux Falls, South Dakota	false	false
3	Shannon Heim (Vice President, General Counsel and Federal Government Affairs)	Helena, Montana	false	false
4	Bleau Lafave (Vice President, Asset Management & Business Development)	Sioux Falls, South Dakota	false	false
5	Bobbi Schroeppel (Vice President, Customer Care, Communications, and Human Resources)	Sioux Falls, South Dakota	false	false
6	Jason Merkel (Vice President, Distribution)	Helena, Montana	false	false
7	Jeanne Vold (Vice President, Technology)	Sioux Falls, South Dakota	false	false
8	John Hines (Vice President, Supply and Montana Government Affairs)	Helena, Montana	false	false
9	Michael Cashell (Vice President, Transmission)	Butte, Montana	false	false

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

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	Montana OATT, Attachment O, Formula Rate Protocols and Template	ER26-605-000

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

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	20251125-5353	11/25/2025	ER26-605-000	Informational Filing of June 1, 2025, to May 31, 2026, Formula Rate Annual Update of NorthWestern Corporation (Montana)	Montana OATT, Attachment O, Formula Rate Protocols and Template

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

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
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

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

IMPORTANT CHANGES DURING THE QUARTER/YEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the franchise rights were acquired. If acquired without the payment of consideration, state that fact. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to Commission authorization. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were submitted to the Commission. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give reference to such authorization. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments. State the estimated annual effect and nature of any important wage scale changes during the year. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such proceedings culminated during the year. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder reported on Pages 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest. (Reserved.) If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.

1) None
2.) None
3.) Acquisition of Energy West Montana Assets In July 2024, we entered into an Asset Purchase Agreement with Hope Utilities to acquire its Energy West natural gas distribution system and operations serving approximately 33,000 customers located in Great Falls, Cut Bank, and West Yellowstone, Montana. In May 2025, the Montana Public Service Commission (MPSC) approved this acquisition and on July 1, 2025, we completed this acquisition for approximately $35.9 million in cash. Upon the completion of the acquisition, we transferred the utility operations to our two wholly-owned subsidiaries, NorthWestern Great Falls Gas LLC and NorthWestern Cut Bank Gas LLC. Colstrip - Avista Corporation Transaction In January 2023, we entered into a definitive agreement with Avista Corporation (Avista) to acquire their respective interests in Colstrip Units 3 and 4 for $0 and completed this acquisition on January 1, 2026. Accordingly, we are responsible for the associated operating costs beginning on January 1, 2026, which we will not collect through utility base rates, until requested in a future Montana rate review. Avista will remain responsible for their respective pre-closing share of environmental and pension liabilities attributed to events or conditions existing prior to the closing of the transaction and for any future decommissioning and demolition costs associated with the existing facilities that comprise their interests. The 222 megawatts of generation capacity from Colstrip Units 3 and 4 acquired from Avista (Avista Interests) on January 1, 2026, was identified as a key element in our strategy to achieve resource adequacy for customers, as outlined in our 2023 Montana Integrated Resource Plan.
4.) None
5.) None
6.) See Note 11 "Unsecured Creidt Facilities." Debt Issuance: FERC Order ES25-23-000
7.) None
8.) None
9.) See Note 19 "Commitments and Contingencies."
10.) None
12.) None
13.) None
14.) None

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

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	7,472,772,542	7,136,721,129
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	137,797,710	125,080,799
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		7,610,570,252	7,261,801,927
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	2,567,943,202	2,449,906,491
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		5,042,627,050	4,811,895,436
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)		5,042,627,050	4,811,895,437
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)		273,855,612	263,806,234
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)		38,206,206	38,192,545
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		686,805	686,805
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		71,615	68,042
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	43,849,050	16,896,016
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances and Environmental Credits	228
24	OtherInvestments Other Investments (124)		14,672,278	14,135,821
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)
29	SpecialFunds Special Funds (Non Major Only) (129)
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		59,136,518	31,650,599
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		2,827,329	888,205
36	SpecialDeposits Special Deposits (132-134)		10,786,659	13,894,365
37	WorkingFunds Working Fund (135)		16,200	17,500
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		70,662,006	66,518,761
41	OtherAccountsReceivable Other Accounts Receivable (143)		18,674,312	12,617,308
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		2,397,030	2,160,945
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		13,370,564	4,946,575
45	FuelStock Fuel Stock (151)	227	2,255,915	2,248,613
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	84,079,524	79,780,714
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
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances and Environmental Credits	228
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227
55	GasStoredCurrent Gas Stored Underground - Current (164.1)		6,320,240	6,743,589
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57	Prepayments Prepayments (165)		20,684,324	18,978,349
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)		56,198	64,160
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		73,565,824	74,104,042
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		358,632	1,025,532
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)
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)		301,260,697	279,666,769
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		11,834,207	9,376,139
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	738,810,317	676,869,364
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)
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)		193,253
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	606,384	930,479
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)		15,873,179	16,960,804
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	186,067,513	194,013,891
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)		1,204,021	253,352
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		951,794,326	898,404,029
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		6,666,880,409	6,323,615,613

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

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	1	1
3	PreferredStockIssued Preferred Stock Issued (204)	250	0	0
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	2,050,821,868	2,044,999,693
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
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	367,995,733	351,876,746
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	4,968,446	2,801,118
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)	4,912,586	5,383,393
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		2,408,936,570	2,388,691,929
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	2,338,660,000	2,074,660,000
19	ReacquiredBonds (Less) Reacquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256	362,000,000	342,000,000
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)		1,998,623
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		2,702,658,623	2,416,660,000
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		868,750	2,292,287
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		4,158,310	5,427,889
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		9,044,273	4,015,920
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)		22,098,420	30,772,444
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		32,554,134	33,987,819
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		68,723,887	68,464,519
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)
38	AccountsPayable Accounts Payable (232)		(a) 100,446,379	90,053,114
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		2,383,986	2,928,190
41	CustomerDeposits Customer Deposits (235)		17,508,366	17,640,442
42	TaxesAccrued Taxes Accrued (236)	262	(b) 85,145,815	76,961,039
43	InterestAccrued Interest Accrued (237)		29,793,801	24,578,517
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		312,293	298,173
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		(c) 62,363,707	57,584,644
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		2,319,559	3,902,892
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities
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)		300,273,906	273,947,011
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)		138,076,346	123,249,058
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	3,374,953	2,229,208
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	45,627,055	93,579,661
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	117,697,851	119,721,846
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reacquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		627,642,931	601,179,098
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		253,868,287	235,893,283
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		1,186,287,423	1,175,852,154
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		6,666,880,409	6,323,615,613

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: AccountsPayable

Montana Operations unfunded reserves for Accounts Payable (232) are $75,231 and $ 1,774,369 for 2025 and 2024, respectively.

(b) Concept: TaxesAccrued

Montana Operations unfunded reserves for Taxes Accrued (236) are $82,479,295 and $ 74,804,269 for 2025 and 2024, respectively.

Montana Operations unfunded reserve for Miscellaneous Current and Accrued Liabilities (242) are $24,488,823 and $ 27,081,196 for 2025 and 2024, respectively.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

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	1,262,716,526	1,234,008,163			1,040,981,011	1,027,480,707	220,876,051	205,531,424	859,464	996,032
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	513,184,218	601,729,005			419,044,032	498,891,273	93,408,245	102,019,130	731,941	818,602
5	MaintenanceExpense Maintenance Expenses (402)	320	75,811,794	48,036,864			64,172,294	40,796,831	11,638,465	7,221,122	1,035	18,911
6	DepreciationExpense Depreciation Expense (403)	336	166,382,756	147,931,740			141,402,974	125,039,639	24,925,609	22,846,012	54,173	46,089
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336					0
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	16,680,799	15,745,292			9,928,967	8,776,685	6,751,832	6,968,607
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336	14,747,883	14,747,883			14,747,883	14,747,883	0	0
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)		48,398,094	39,840,684			30,664,446	27,630,970	17,733,648	12,209,714
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		67,580,038	83,044,374			44,181,467	57,321,723	23,398,571	25,722,651
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	181,636,516	164,247,932			141,554,372	127,004,398	40,033,142	37,198,187	49,002	45,347
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	5,664,788	1,904,817			5,569,221	397,921	107,535	1,521,370	11,968	14,474
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	3,353,153	916,223			3,324,561	385,059	32,717	536,153	4,125	4,989
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	126,727,314	319,664,736			101,977,213	241,322,245	24,756,966	78,358,682	6,865	16,191
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	113,790,332	303,691,475			87,776,570	222,335,142	26,013,762	81,356,333
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	1,145,745	1,970,244			1,145,745	1,970,244
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)
24.1	GainsFromDispositionOfEnvironmentalCredits (Less) Gains from Disposition of Environmental Credits (411.11)
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)		954,326,809	964,357,491			783,786,108	805,740,323	169,695,322	157,684,947	845,379	932,221
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		308,389,717	269,650,672			257,194,903	221,740,384	51,180,729	47,846,477	14,085	63,811
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)		548,565	574,229
32	CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)		436,921	465,686
33	RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417)		223,443	84,271
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		37,637	167,477
35	NonoperatingRentalIncome Nonoperating Rental Income (418)
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	2,167,328	1,443,963
37	InterestAndDividendIncome Interest and Dividend Income (419)		432,482	3,540
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		8,690,963	17,537,612
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		1,882,952	637,335
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		8,689,633	16,591,319
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		577,245	732,306
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)		1,202,592	2,249,995
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		566,936	200,297
49	OtherDeductions Other Deductions (426.5)		32,996,673	761,637
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		35,343,446	555,755
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	7,992	2,856
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	7,856,610	2,938,964
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	2,820,385	810,080
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	(a) 3,410	12,137
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	2,301	18,228
57	InvestmentTaxCreditAdjustmentsNonutilityOperations Investment Tax Credit Adj.-Net (411.5)
58	InvestmentTaxCredits (Less) Investment Tax Credits (420)
59	TaxesOnOtherIncomeAndDeductions TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)		10,686,096	3,745,809
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		37,339,909	13,401,265
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		116,333,820	103,589,994
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		1,895,350	1,459,646
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		1,071,829	1,563,112
65	AmortizationOfPremiumOnDebtCredit (Less) Amort. of Premium on Debt-Credit (429)		78,377
66	AmortizationOfGainOnReacquiredDebtCredit (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67	InterestOnDebtToAssociatedCompanies Interest on Debt to Assoc. Companies (430)
68	OtherInterestExpense Other Interest Expense (431)		1,170,595	4,288,429
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		4,295,067	7,927,686
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		116,098,150	102,973,495
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		154,951,659	180,078,442
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
77	ExtraordinaryItemsAfterTaxes Extraordinary Items After Taxes (line 75 less line 76)
78	NetIncomeLoss Net Income (Total of line 71 and 77)		154,951,659	180,078,442

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions

Included in the Provision for Deferred Income Taxes, in the Statements of Income, is amortization of the excess and deficient ADIT's as follows:

Line No.	Description (a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)

	FERC Method of Amortization	RSG	SL		ARAM/RSG	RSG	SL			SL (MT) / RSG (SD)	SL
	Amortization period	Book Lives	5 Years		Book Lives	Book Lives	5 Years			5 years (MT) / Book Lives (SD)	5 Years
	Protected/Unprotected	Protected	Unprotected		Protected	Unprotected	Unprotected			F/T "as-if" normalized	F/T "as-if" normalized
	FERC Amorization Account	410.1	410.1		411.1	411.1	411.1			411.1	410.1
	TCJA Excess ADIT Account Reduced	190	190	Subtotal	282	282	283	Subtotal	Total of 182.3	282	190
	Reg Asset Acccount Impacted	182.3	182.3	182.3	254	254	254	254	and 254	254	182.3	Total
1	Montana:
2	Electric	921,622	-	921,622	(2,817,180)	-	-	(2,817,180)	(1,895,558)	-	-	(1,895,558)
3	Gas	-	1,303,764	1,303,764	(838,248)	(147,909)	(1,043,609)	(2,029,766)	(726,002)	-	18,486	(707,516)
4	Total	921,622	1,303,764	2,225,386	(3,655,428)	(147,909)	(1,043,609)	(4,846,946)	(2,621,560)	-	18,486	(2,603,074)

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

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		351,876,746	810,816,636
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
4.1	AdjustmentsToRetainedEarningsCredit
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
10.1	AdjustmentsToRetainedEarningsDebit Holding Company Reorganization			570,525,446
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)			570,525,446
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		157,118,987	181,522,404
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)
29	DividendsDeclaredPreferredStock TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30	DividendsDeclaredCommonStockAbstract Dividends Declared-Common Stock (Account 438)
30.1	DividendsDeclaredCommonStock Common Stock Dividend		141,000,000	69,936,848
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		141,000,000	69,936,848
37	TransfersFromUnappropriatedUndistributedSubsidiaryEarnings Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38	UnappropriatedRetainedEarnings Balance - End of Period (Total 1,9,15,16,22,29,36,37)		367,995,733	351,876,746
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)
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		367,995,733	351,876,746
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)		2,801,118	1,503,684
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)		2,167,328	1,443,963
51	DividendsReceived (Less) Dividends Received (Debit)
52	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
52.1	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits Other unappropriated undistributed subsidiary earnings for the year			146,529
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)		4,968,446	2,801,118

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

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)	154,951,659	180,078,442
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	166,382,756	147,931,740
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of	31,428,682	30,493,175
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other Non-cash charges to net income-net	(a) 9,607,460	7,050,426
5.3	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Regulatory disallowance of certain YCGS capital costs	30,895,449	0
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	12,938,091	15,967,170
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	1,145,745	1,970,244
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	18,388,153	9,651,518
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	3,882,763	6,710,218
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances and Environmental Credits Inventory
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	16,555,688	20,062,712
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	23,273,474	9,340,746
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	2,023,995	35,364,509
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	8,690,963	17,537,612
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies	2,167,328	1,443,963
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other	(b) 47,797,945	30,242,813
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	322,015,565	334,134,984
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)	419,003,873	489,816,600
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant	14,795,590	12,693,286
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	8,690,963	17,537,612
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	425,108,500	484,972,274
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)
39	InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Investments in and Advances to Assoc. and Subsidiary Companies	39,211,228
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 Investment in Equity Securities		253,166
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	464,319,728	485,225,440
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	502,077,000	175,000,000
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Distribution of Cash from NorthWestern Energy Group, Inc.		60,000,000
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	502,077,000	235,000,000
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	236,000,000	100,000,000
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Debt Financing Costs	3,942,719	792,994
76.2	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Line of Credit (Repayments) Borrowings, Net	20,000,000	78,000,000
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock	141,000,000	69,936,848
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	141,134,281	142,270,158
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)	1,169,882	8,820,298
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	14,800,070	23,620,368
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	(c) 13,630,188	14,800,070

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: NoncashAdjustmentsToCashFlowsFromOperatingActivities

	12/31/2025	12/31/2024
Other Noncash Charges to Income, Net:
Amortization of debt issue costs, discount, premium and deferred hedge gain	3,107,645	3,233,304
Other noncash (gains) losses	706,964	(59,779)
Stock based compensation costs	5,792,851	3,876,901
	9,607,460	7,050,426

(b) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

Other Assets and Liabilities, Net:
Net change - other current assets	(1,031,113)	(7,893,558)
Net change - accrued utility revenues	538,218	9,990,207
Net change - deferred debits	1,821,406	2,980,620
Net change - deferred credits	(34,803,050)	(22,358,643)
Net change - noncurrent liabilities	(14,323,406)	(12,961,439)
	(47,797,945)	(30,242,813)

	12/31/2025	12/31/2024	12/31/2023
Cash (131)	2,827,329	888,205	8,740,865
Working Funds (135)	16,200	17,500	22,850
Other Special Deposits (134)	10,786,659	13,894,365	14,856,653
Total	13,630,188	14,800,070	23,620,368

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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.

NOTES TO FINANCIAL STATEMENTS

(1) Nature of Operations and Basis of Consolidation

NorthWestern Corporation (NW Corp), a direct wholly-owned subsidiary of NorthWestern Energy Group, Inc., doing business as NorthWestern Energy, provides electricity and / or natural gas to approximately 690,100 customers in Montana and Yellowstone National Park. We have generated and distributed electricity and distributed natural gas in Montana since 2002.

The Financial Statements for the periods included herein have been prepared by NW Corp (NorthWestern, we or us), pursuant to the rules and regulations of the Federal Energy Regulatory Commission (FERC) as set forth in its applicable Uniform System of Accounts and published accounting releases. The preparation of financial statements in conformity with the accounting requirements of the FERC as set forth in its applicable Uniform System of Accounts and published accounting releases requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. Events occurring subsequent to December 31, 2025, have been evaluated as to their potential impact to the Consolidated Financial Statements through the date of issuance.

The following notes to the financials statements appear in NorthWestern Corporation’s annual report to the shareholders and are prepared in conformity with GAAP. This report differs from GAAP due to FERC requiring the presentation of subsidiaries on the equity method of accounting, which differs from Accounting Standards Codification (ASC) 810, Consolidation. ASC 810 requires that all majority-owned subsidiaries be consolidated. The other significant differences consist of the following:

• Removal and decommissioning costs of generation, transmission and distribution assets are reflected in the Balance Sheets as a component of accumulated depreciation of $462.2 million and $444.1 million as of December 31, 2025 and December 31, 2024, respectively, in accordance with regulatory treatment as compared to regulatory liabilities for GAAP purposes;

• Goodwill is reflected in the Balance Sheets as a utility plant adjustments of $273.9 million as of December 31, 2025 and $263.8 million as of December 31, 2024, respectively, in accordance with regulatory treatment, as compared to goodwill for GAAP purposes (see Note 8);

• The write-down of plant values associated with the 2002 acquisition of the Montana operations is reflected in the Balance Sheets as a component of accumulated depreciation of $147.6 million for December 31, 2025 and December 31, 2024, respectively, in accordance with regulatory treatment as compared to plant for GAAP purposes;

• The current portion of gas stored underground is reflected in the Balance Sheets as current and accrued assets, as compared to inventory for GAAP purposes;

• Operating lease right of use assets are reflected in the Balance Sheets as capital leases of $1.3 million and $0.7 million as of December 31, 2025 and December 31, 2024, respectfully, in accordance with regulatory treatment, as compared to non-current assets for GAAP purposes;

• Operating lease liabilities are reflected in the Balance Sheets as current and long term obligations under capital leases of $1.3 million and $0.7 million as of December 31, 2025 and December 31, 2024, respectfully, in accordance with regulatory treatment, as compared to accrued expenses and long term liabilities for GAAP purposes;

• Unamortized debt expense is classified in the Balance Sheets as deferred debits in accordance with regulatory treatment, as compared to long-term debt for GAAP purposes;

• Current and long-term debt is classified in the Balance Sheets as all long-term debt in accordance with regulatory treatment, while current and long-term debt are presented separately for GAAP reporting;

• The current portion of the provision for injuries and damages and the expected insurance proceeds receivable related to the provision for injuries and damages are reported as a current liability for GAAP purposes, as compared to a non-current liability for FERC purposes;

• Accumulated deferred tax assets and liabilities are classified in the Balance Sheets as gross non-current deferred debits and credits, respectively, while GAAP presentation reflects a net non-current deferred tax liability;

• Stranded tax effects associated with the Tax Cuts and Jobs Act are included in accumulated other comprehensive income (AOCI) in accordance with regulatory treatment, while included in retained earnings for GAAP purposes;

• Uncertain tax positions related to temporary differences are classified in the Balance Sheets within the deferred tax accounts in accordance with regulatory treatment, as compared to other noncurrent liabilities for GAAP purposes. In addition, interest related to uncertain tax positions is recognized in interest expense in accordance with regulatory treatment, as compared to income tax expense for GAAP purposes;

• Net periodic benefit costs and net periodic post retirement benefit costs are reflected in operating expense for FERC purposes, as compared to the GAAP presentation, which reflects the current service costs component of the net periodic benefit costs in operating expenses and the other components outside of income from operations. In addition, only the service cost component of net periodic benefit cost is eligible for capitalization for GAAP purposes, as compared to the total net periodic benefit costs for FERC purposes;

• Regulatory assets and liabilities are reflected in the Balance Sheets as non-current items, while current and non-current amounts are presented separately for GAAP;

• Unbilled revenue is reflected in the Balance Sheets in Accrued utility revenues in accordance with regulatory treatment, as compared to Accounts receivable, net for GAAP purposes;

• Implementation costs associated with cloud computing arrangements are reflected on the Balance Sheets as Miscellaneous Intangible Plant in accordance with regulatory treatment, as compared to Other current assets for GAAP purposes. Additionally, these cash outflows are presented within investing activities cash outflows in the Statement of Cash Flows in accordance with regulatory treatment, as compared to operating activities cash outflows for GAAP purposes; and

• GAAP revenue differs from FERC revenue primarily due to the equity method of accounting as discussed above, netting of electric purchases and sales for resale in revenue for the GAAP presentation as compared to a gross presentation for FERC purposes (with the exception of those transactions in a regional transmission organization (RTO)), the netting of RTO transmission transactions for the GAAP presentation as compared to a gross presentation for FERC purposes, and the classification of regulatory amortizations in revenue for GAAP purposes as compared to expense for FERC purposes.

Holding Company Reorganization

On January 1, 2024, we completed the second and final phase of the holding company reorganization. NW Corp contributed the assets and liabilities of its South Dakota and Nebraska regulated utilities to NorthWestern Energy Public Service Corporation (NWE Public Service), and then distributed its equity interest in NWE Public Service and certain other subsidiaries, with a total value of $570.7 million, to NorthWestern Energy Group, Inc., resulting in NW Corp owning and operating the Montana regulated utility and NWE Public Service owning and operating the Nebraska and South Dakota utilities, each as a direct subsidiary of NorthWestern Energy Group, Inc.

NorthWestern Energy Group, Inc. Pending Merger with Black Hills Corporation

On August 18, 2025, NorthWestern Energy Group, Inc. entered into a Merger Agreement with Black Hills and River Merger Sub Inc., a direct wholly owned subsidiary of Black Hills (Merger Sub). The Merger Agreement provides for an all-stock merger of equals between NorthWestern Energy Group, Inc. and Black Hills upon the terms and subject to the conditions set forth therein. The Merger Agreement provides for Merger Sub to merge with and into NorthWestern Energy Group, Inc. (Merger), with NorthWestern Energy Group, Inc. continuing as the surviving entity and a direct wholly owned subsidiary of Black Hills, which would assume the new corporate name of Bright Horizon Energy Corporation as the resulting parent company of the combined corporate group. The completion of the Merger is subject to the satisfaction or waiver of certain conditions to closing. We anticipate the transaction closing in the second half of 2026, subject to the satisfaction or waiver of certain closing conditions.

(2) Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for such items as long-lived asset values and impairment charges, long-lived asset useful lives, tax provisions, uncertain tax position reserves, AROs, regulatory assets and liabilities, allowances for uncollectible accounts, our QF liability, environmental liabilities, unbilled revenues and actuarially determined benefit costs and liabilities. We revise the recorded estimates when we receive better information or when we can determine actual amounts. Those revisions can affect operating results.

Revenue Recognition

We recognize revenue as customers obtain control of promised goods and services in an amount that reflects consideration expected in exchange for those goods or services. Generally, the delivery of electricity and natural gas results in the transfer of control to customers at the time the commodity is delivered and the amount of revenue recognized is equal to the amount billed to each customer, including estimated volumes delivered when billings have not yet occurred.

Cash Equivalents

We consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents.

Restricted Cash

Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements.

Accounts Receivable, Net

Accounts receivable are net of allowances for uncollectible accounts of $2.5 million and $2.2 million at December 31, 2025 and December 31, 2024, respectively. Receivables include unbilled revenues of $75.7 million and $74.1 million at December 31, 2025 and December 31, 2024, respectively.

Inventories

Inventories are stated at the lower of average cost or net realizable value.

Regulation of Utility Operations

Our regulated operations are subject to the provisions of ASC 980, Regulated Operations. Regulated accounting is appropriate provided that (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise's cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be charged to and collected from customers.

Our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. The economic effects of regulation can result in regulated companies recording costs that have been, or are deemed probable to be, allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities).

If we were required to terminate the application of these provisions to our regulated operations, all such deferred amounts would be recognized in the Consolidated Statements of Income at that time. This would result in a charge to earnings and accumulated other comprehensive loss (AOCL), net of applicable income taxes, which could be material. In addition, we would determine any impairment to the carrying costs of deregulated plant and inventory assets.

Derivative Financial Instruments

We account for derivative instruments in accordance with ASC 815, Derivatives and Hedging. All derivatives are recognized in the Consolidated Balance Sheets at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales (NPNS) exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). For fair-value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash-flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in AOCL and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For other derivative contracts that do not qualify or are not designated for hedge accounting, changes in the fair value of the derivatives are recognized in earnings each period. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the underlying nature of the hedged items. As of December 31, 2025, the only derivative instruments we have qualify for the NPNS exception.

Revenues and expenses on contracts that are designated as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but on an accrual basis of accounting. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric and gas operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it were determined that a transaction designated as a NPNS no longer met the exceptions, the fair value of the related contract would be reflected as an asset or liability and immediately recognized through earnings. See Note 9 - Risk Management and Hedging Activities, for further discussion of our derivative activity.

Property, Plant and Equipment

Property, plant and equipment are stated at original cost, including contracted services, direct labor and material, allowance for funds used during construction (AFUDC), and indirect charges for engineering, supervision and similar overhead items. All expenditures for maintenance and repairs of utility property, plant and equipment are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal. Also included in plant and equipment are assets under finance lease, which are stated at the present value of minimum lease payments.

AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. This rate averaged 7.2% and 7.0% for 2025 and 2024, respectively. AFUDC capitalized totaled $13.0 million and $25.5 million for the years ended December 31, 2025 and 2024, respectively.

We record provisions for depreciation at amounts substantially equivalent to calculations made on a straight-line method by applying various rates based on useful lives of the various classes of properties (ranging from 5 to 127 years) determined from engineering studies. As a percentage of the depreciable utility plant at the beginning of the year, our provision for depreciation of utility plant was approximately 2.8% for 2025 and 2024.

Depreciation rates include a provision for our share of the estimated costs to decommission our jointly owned plants at the end of the useful life. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in noncurrent regulatory liabilities.

Pension and Postretirement Benefits

We have liabilities under defined benefit retirement plans and a postretirement plan that offers certain health care and life insurance benefits to eligible employees and their dependents. The costs of these plans are dependent upon numerous factors, assumptions and estimates, including determination of discount rate, expected return on plan assets, rate of future compensation increases, age and mortality and employment periods. In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in material changes in the cost and liabilities we recognize.

Income Taxes

We follow the liability method in accounting for income taxes. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized.

Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ from these estimates. The resolution of tax matters in a particular future period could have a material impact on our Consolidated Income Statements and provision for income taxes.

Under the Inflation Reduction Act of 2022 our production tax credits may be transferred to an unrelated entity. Our policy is to account for these transferable credits within income tax expense.

Environmental Costs

We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. If an environmental cost is related to facilities we currently use, such as pollution control equipment, then we may capitalize and depreciate the costs over the remaining life of the asset, assuming the costs are recoverable in future rates or future cash flows.

Our remediation cost estimates are based on the use of an environmental consultant, our experience, our assessment of the current situation and the technology currently available for use in the remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, then we estimate and record only our share of the cost.

Supplemental Cash Flow Information

	Year Ended December 31,
	2025	2024
	(in thousands)
Cash (received) paid for:
Federal income tax	$ —	$ 57
Montana state income tax	—	(4,826)
Total Income taxes	$ —	$ (4,769)

Interest	107,073	100,853
Significant non-cash transactions:
Capital expenditures included in trade accounts payable	30,080	18,537

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts shown in the Consolidated Statements of Cash Flows (in thousands):

	December 31,
	2025	2024
Cash and cash equivalents	$ 4,201	$ 1,934
Restricted cash	10,787	13,894
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows	$ 14,988	$ 15,828

Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements.

Accounting Standards Issued

In December 2023, the Financial Accounting Standards Board issued Accounting Standards Update 2023-09, Improvements to Income Tax Disclosures, which expands income tax disclosures. The expanded disclosures require the disclosure of prescribed categories presented in the income tax rate reconciliation and additional disclosures on income tax expense and taxes paid, net of refunds received, for federal, state, and foreign jurisdictions. We early adopted this standard for the year ended December 31, 2025, and used the retrospective method of adoption, with no material impact on our Consolidated Financial Statements.

At this time, we are not expecting the adoption of recently issued accounting standards to have a material impact to our financial condition, results of operations, and cash flows.

(3) Acquisition of Energy West Operations

In July 2024, we entered into an Asset Purchase Agreement with Hope Utilities to acquire its Energy West natural gas distribution system and operations serving approximately 33,000 customers located in Great Falls, Cut Bank, and West Yellowstone, Montana. In May 2025, the Montana Public Service Commission (MPSC) approved this acquisition and on July 1, 2025, we completed this acquisition for approximately $35.9 million in cash. Upon the completion of the acquisition, we transferred the utility operations to our two wholly-owned subsidiaries, NorthWestern Great Falls Gas LLC and NorthWestern Cut Bank Gas LLC.

The assets acquired and liabilities assumed were measured at estimated fair value in accordance with the accounting guidance under the Business Combinations Topic in the Financial Accounting Standards Board Accounting Standards Codification. These assets and liabilities are subject to rate-setting provisions that provide for revenues derived from costs, including a return on investment of assets less liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values.

The excess of the purchase price over the fair value of the assets acquired and liabilities assumed has been reflected as $10.0 million of goodwill within the Gas segment. Goodwill resulting from the acquisition is largely attributable to efficiency opportunities. The goodwill recognized in connection with the acquisition will be deductible for income tax purposes.

(4) Regulatory Matters

Montana Rate Review

In July 2024, we filed a Montana electric and natural gas rate review with the MPSC requesting an annual increase to electric and natural gas utility rates. In December 2025, the MPSC issued a final order approving the natural gas settlement agreement and partial electric settlement agreement. Among other things, the approved partial electric settlement agreement provides for the deferral and annual recovery of incremental operating costs related to wildfire mitigation and insurance expenses through the Wildfire Mitigation Balancing Account.

The details of this final order are set forth below:

Returns, Capital Structure & Revenue Increase Resulting From Final Order ($ in millions)
	Electric	Natural Gas
Return on Equity (ROE)	9.65 %	9.60 %
Equity Capital Structure	47.84 %	47.84 %

Base Rates	$ 105.5	$ 18.0
Power Cost and Credit Adjustment Mechanism (PCCAM)(1)(2)	(94.5)	n/a
Property Tax (tracker base adjustment)(1)	(1.8)	0.1
Total Revenue Increase Through Final Order	$ 9.2	$ 18.1

(1) These items are flow-through costs. PCCAM reflects our fuel and purchased power costs.

(2) This PCCAM reduction of $94.5 million represents the reduction in revenue at the previously approved 2021 PCCAM base of $208.3 million using the 2023 Montana rate review test period loads.

The final order provides for an update to the PCCAM by adjusting the base costs from $208.3 million to $119.0 million. It also suspended the 90/10 cost sharing mechanism of the PCCAM on a temporary basis pending further review by the MPSC. Within this final order, the MPSC disallowed a portion of the capital costs related to the construction of Yellow Stone County Generating Station. As a result, in the fourth quarter of 2025 we recorded a $30.9 million non-cash charge for the regulatory disallowance within Operating, administrative, and general on the Consolidated Statements of Income and a corresponding reduction to Property, plant, and equipment, net on the Consolidated Balance Sheets. As of December 31, 2025, we have deferred $7.7 million of base rate revenues collected that will be refunded to customers.

In January 2026, we filed a Motion for Reconsideration (Motion) as it relates to this final order. Among other things, our Motion requests that the MPSC reconsider their prudence conclusions regarding the capital costs associated with the construction of YCGS and clarification as to the effective date of the PCCAM sharing mechanism suspension, which we have requested an effective date of July 1, 2025, to align with the PCCAM tracker year. Any subsequent modifications by the MPSC to their final order would be reflected in our 2026 results.

Colstrip Acquisitions and Requests for Cost Recovery

In January 2023, we entered into a definitive agreement with Avista Corporation (Avista) to acquire their respective interests in Colstrip Units 3 and 4 for $0 and completed this acquisition on January 1, 2026. Accordingly, we are responsible for the associated operating costs beginning on January 1, 2026, which we will not collect through utility base rates, until requested in a future Montana rate review. Avista will remain responsible for their respective pre-closing share of environmental and pension liabilities attributed to events or conditions existing prior to the closing of the transaction and for any future decommissioning and demolition costs associated with the existing facilities that comprise their interests.

The 222 megawatts of generation capacity from Colstrip Units 3 and 4 acquired from Avista (Avista Interests) on January 1, 2026, was identified as a key element in our strategy to achieve resource adequacy for customers, as outlined in our 2023 Montana Integrated Resource Plan. Noting the costs associated with operating this resource are not currently reflected in utility customer rates, in August 2025, we filed a temporary PCCAM tariff waiver request with the MPSC that would provide a near-term cost-recovery mechanism expected to largely offset approximately $18.0 million in annual incremental operating and maintenance costs associated with the Avista Interests. This waiver requested that the MPSC allow us to keep 100 percent of the net revenue associated with certain designated power sales contracts up to the amount of the operating and maintenance expenses we incur associated with our Avista Interests. Furthermore, the waiver request indicated that any net revenues from the designated contracts exceeding the operating and maintenance expenses associated with our Avista Interests would continue to flow back to retail customers. In January 2026, the MPSC approved our PCCAM tariff waiver request on an interim basis with final approval or denial subject to the ongoing PCCAM docket process.

(5) Regulatory Assets and Liabilities

We prepare our Consolidated Financial Statements in accordance with the provisions of ASC 980, as discussed in Note 2 - Significant Accounting Policies. Pursuant to this guidance, certain expenses and credits, normally reflected in income as incurred, are deferred and recognized when included in rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded based on management's assessment that it is probable that a cost will be recovered or that an obligation has been incurred. Accordingly, we have recorded the following major classifications of regulatory assets and liabilities that will be recognized in expenses and revenues in future periods when the matching revenues are collected or refunded. Of these regulatory assets and liabilities, energy supply costs are the only items earning a rate of return. The remaining regulatory items have corresponding assets and liabilities that will be paid for or refunded in future periods.

	Note Reference	Remaining Amortization Period	December 31,
			2025	2024
			(in thousands)
Flow-through income taxes	13	Plant Lives	$ 557,832	$ 522,015
Supply costs		1 Year	39,966	1,132
Excess deferred income taxes	13	Plant Lives	36,550	39,040
Wildfire Mitigation		Undetermined	29,433	17,368
Pension	15	See Note 15	21,416	56,719
State & local taxes & fees		1 Year	20,367	8,863
Employee related benefits	15	See Note 15	16,548	17,877
Deferred financing costs	12	See Note 12	15,873	16,961
Environmental clean-up	18	Undetermined	2,674	—
Other		Various	18,273	15,098
Total Regulatory Assets			$ 758,932	$ 695,073
Removal cost	7	Plant Lives	$ 462,221	$ 444,058
Excess deferred income taxes	13	Plant Lives	103,157	108,154
Rates subject to refund	4	1 Year	7,660	—
Gas storage sales		14 years	5,784	6,205
Supply costs		1 Year	1,715	5,093
Employee related benefits	15	See Note 15	798	—
State & local taxes & fees		1 Year	607	46
Other		Various	2,166	1,977
Total Regulatory Liabilities			$ 584,108	$ 565,533

Income Taxes

Flow-through income taxes primarily reflect the effects of plant related temporary differences such as flow-through of depreciation, repairs related deductions, and removal costs that we will recover or refund in future rates. We amortize these amounts as temporary differences reverse. Excess deferred income tax assets and liabilities are recorded as a result of the Tax Cuts and Jobs Act and will be recovered or refunded in future rates. See Note 13 - Income Taxes for further discussion.

Supply Costs

The MPSC has authorized the use of electric and natural gas supply cost trackers that enable us to track actual supply costs and either recover the under collection or refund the over collection to our customers. Accordingly, we have recorded a regulatory asset and liability to reflect the future recovery of under collections and refunding of over collections through the ratemaking process. We earn interest on natural gas supply costs under collected, or apply interest to an over collection, of 6.7 percent. For our electric supply tracker, the PCCAM, the interest rate we earn on supply costs under collected, or the interest rate we apply to an over collection, is based on the monthly interest rate for three month commercial paper as published by the Federal Reserve.

Enhanced Wildfire Mitigation Plan

We have developed an Enhanced Wildfire Mitigation Plan addressing five key areas: situational awareness, operational practices, system preparedness, vegetation management, and public communications outreach. Because of ever-increasing wildfire risk, our plan includes greater focus on situational awareness to monitor changing environmental conditions, operational practices that are more reactive to changing conditions, increased frequency of patrol and repairs, and more robust system hardening programs that target higher risk segments in our transmission and distribution systems. The MPSC has approved the deferral of incremental operating costs related to this Enhanced Wildfire Mitigation Plan.

Pension and Employee Related Benefits

We recognize the unfunded portion of plan benefit obligations in the Consolidated Balance Sheets, which is remeasured at each year end, with a corresponding adjustment to regulatory assets/liabilities as the costs associated with these plans are recovered in rates. The MPSC allows recovery of pension costs on a cash funding basis. The portion of the regulatory asset related to our Montana pension plan will amortize as cash funding amounts exceed accrual expense under GAAP. The MPSC allows recovery of postretirement benefit costs on an accrual basis.

State & Local Taxes & Fees (Montana Property Tax Tracker)

Under Montana law, we are allowed to track the changes in the actual level of state and local taxes and fees and recover the increase, or refund the decrease, in rates, less the amount allocated to Federal Energy Regulatory Commission jurisdictional customers and net of the related income tax benefit.

Deferred Financing Costs

Consistent with our historical regulatory treatment, a regulatory asset has been established to reflect the remaining deferred financing costs on long-term debt that has been replaced through the issuance of new debt. These amounts are amortized over the life of the new debt.

Environmental Clean-Up

Environmental clean-up costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss the specific sites and clean-up requirements further in Note 18 - Commitments and Contingencies. Environmental clean-up costs are typically recoverable in customer rates when they are actually incurred. When cost projections become known and measurable, we coordinate with the appropriate regulatory authority to determine a recovery period.

Removal Cost

The anticipated costs of removing assets upon retirement are collected from customers in advance of removal activity as a component of depreciation expense. Our depreciation method, including cost of removal, is established by the respective regulatory commissions. Therefore, consistent with this regulated treatment, we reflect this accrual of removal costs for our regulated assets by increasing our regulatory liability. See Note 7 - Asset Retirement Obligations, for further information regarding this item.

Gas Storage Sales

A regulatory liability was established in 2000 and 2001 based on gains on cushion gas sales in Montana. This gain is being flowed to customers over a period that matches the depreciable life of surface facilities that were added to maintain deliverability from the field after the withdrawal of the gas. This regulatory liability is a reduction of rate base.

(6) Property, Plant and Equipment

The following table presents the major classifications of our property, plant and equipment (in thousands):

	December 31,
	2025	2024
	(in thousands)
Electric Plant	$ 5,119,202	$ 4,888,326
Natural Gas Plant	1,490,780	1,328,386
Plant acquisition adjustment(1)	656,319	656,319
Common and Other Plant	209,030	204,663
Construction work in process	151,143	133,740
Total property, plant and equipment	7,626,474	7,211,434
Less accumulated depreciation	(1,672,982)	(1,561,647)
Less accumulated amortization	(369,964)	(344,785)
Net property, plant and equipment	$ 5,583,528	$ 5,305,002

(1) The plant acquisition adjustment balance above includes our hydro generating assets acquired in 2014 and the inclusion of our interest in Colstrip Unit 4 in rate base in 2009. The acquisition adjustment is amortized on a straight-line basis over the estimated remaining useful life of each related asset in depreciation expense.

Net plant and equipment under finance lease were $1.0 million and $3.0 million as of December 31, 2025 and 2024, respectively, which is a long-term power supply contract with the owners of a natural gas fired peaking plant, which has been accounted for as a finance lease.

Jointly Owned Electric Generating Plant

We have a 30% ownership interest in Colstrip Unit 4, a base-load electric generating plant, which is coal fired and operated by Talen Montana, LLC (Talen). Talen has a 30 percent ownership interest in Colstrip Unit 3. We have a reciprocating sharing agreement with Talen regarding the operation of Colstrip Units 3 and 4, in which each party receives 15 percent of the respective combined output and is responsible for 15 percent of the respective operating and construction costs, regardless of whether a particular cost is specified to Colstrip Unit 3 or 4. However, each party if responsible for its own fuel-related costs. Our interest in this plant is reflected in the Consolidated Balance Sheets on a pro rata basis and our share of operating expenses is reflected in the Consolidated Statements of Income. The participants each finance their own investment.

Information relating to our ownership interest in this facility is as follows (in thousands):

	Colstrip Unit 4
December 31, 2025
Ownership percentages	30.0 %
Plant in service	$ 339,677
Accumulated depreciation	147,749
December 31, 2024
Ownership percentages	30.0 %
Plant in service	$ 330,888
Accumulated depreciation	137,153

On January 1, 2026, we acquired a 15 percent ownership interest in Colstrip Units 3 & 4 from Avista. With this acquisition we will own 15 percent of Colstrip Unit 3 and 45 percent of Unit 4. See Note 4 - Regulatory Matters for further discussion regarding these acquisitions.

(7) Asset Retirement Obligations

We are obligated to dispose of certain long-lived assets upon their abandonment. We recognize a liability for the legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event. We measure the liability at fair value when incurred and capitalize a corresponding amount as part of the book value of the related assets, which increases our property, plant and equipment and other noncurrent liabilities. The increase in the capitalized cost is included in determining depreciation expense over the estimated useful life of these assets. Since the fair value of the asset retirement obligation (ARO) is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period and recorded as a regulatory asset until the settlement of the liability. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a regulatory asset or liability for the difference, which will be surcharged/refunded to customers through the rate making process. We record regulatory assets and liabilities for differences in timing of asset retirement costs recovered in rates and AROs recorded since asset retirement costs are recovered through rates charged to customers.

Our AROs relate to the reclamation and removal costs at our jointly-owned coal-fired generation facility, U.S. Department of Transportation requirements to cut, purge and cap retired natural gas pipeline segments, our obligation to plug and abandon oil and gas wells at the end of their life, and to remove all above-ground wind power facilities and restore the soil surface at the end of their life. The following table presents the change in our ARO (in thousands):

	December 31,
	2025	2024
Liability at January 1,	$ 34,212	$ 34,808
Accretion expense	1,560	1,626
Liabilities incurred	371	—
Liabilities settled	(3,578)	(1,923)
Revisions to cash flows	594	(299)
Liability at December 31,	$ 33,159	$ 34,212

During the twelve months ended December 31, 2025 our ARO liability decreased $3.6 million for partial settlement of the legal obligations at our jointly-owned coal-fired generation facility and natural gas pipeline segments. Additionally, during the twelve months ended December 31, 2025, our ARO liability increased $1.0 million related to changes in both the timing and amount of retirement cost estimates and liabilities incurred.

In addition, we have identified removal liabilities related to our electric and natural gas transmission and distribution assets that have been installed on easements over property not owned by us. The easements are generally perpetual and only require remediation action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as we intend to utilize these properties indefinitely. In the event we decide to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time. We also identified AROs associated with our hydroelectric generating facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the Consolidated Financial Statements.

We collect removal costs in rates for certain transmission and distribution assets that do not have associated AROs. Generally, the accrual of future non-ARO removal obligations is not required; however, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. The recorded amounts of costs collected from customers through depreciation rates are classified as a regulatory liability in recognition of the fact that we have collected these amounts that will be used in the future to fund asset retirement costs and do not represent legal retirement obligations. See Note 5 - Regulatory Assets and Liabilities for removal costs recorded as regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2025 and 2024.

(8) Goodwill

We completed our annual goodwill impairment test as of April 1, 2025, and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections.

For the year ended December 31, 2025, goodwill increased $10.0 million. See Note 3 - Acquisition of Energy West Operations for additional information.

Goodwill by segment is as follows (in thousands):

	December 31,
	2025	2024
Electric	$ 179,890	$ 179,890
Natural gas	93,966	83,917
Total Goodwill	$ 273,856	$ 263,807

(9) Risk Management and Hedging Activities

Nature of Our Business and Associated Risks

We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. We rely on market purchases to fulfill a portion of our electric and natural gas supply requirements. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.

Objectives and Strategies for Using Derivatives

To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide greater price stability for consumers. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes consistent with regulatory guidelines.

In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.

Accounting for Derivative Instruments

We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: NPNS; cash flow hedge; fair value hedge; and mark-to-market.

Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.

Normal Purchases and Normal Sales

We have applied the NPNS scope exception to our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no unrealized amounts recorded in the Consolidated Financial Statements at December 31, 2025 and 2024. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.

Credit Risk

Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We limit credit risk in our commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.

We are exposed to credit risk through buying and selling electricity and natural gas to serve customers. We may request collateral or other security from our counterparties based on the assessment of creditworthiness and expected credit exposure. It is possible that volatility in commodity prices could cause us to have material credit risk exposures with one or more counterparties. We enter into commodity master enabling agreements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are: (1) Western Systems Power Pool agreements – standardized power purchase and sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements – standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements – standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements – standardized power sales contracts in the electric industry.

Many of our forward purchase contracts contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our credit rating were to fall below investment grade, the counterparties could require immediate payment or demand immediate and ongoing full overnight collateralization on contracts in net liability positions.

Interest Rate Swaps Designated as Cash Flow Hedges

We have previously used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. We have no interest rate swaps outstanding. These swaps were designated as cash flow hedges with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in AOCL. We reclassify these gains from AOCL into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these interest rate swaps previously terminated on the Consolidated Financial Statements (in thousands):

Cash Flow Hedges		Location of Amount Reclassified from AOCL to Income		Amount Reclassified from AOCL into Income during the Year Ended December 31, 2025
Interest rate contracts		Interest Expense		$ 612

A pre-tax loss of approximately $11.6 million is remaining in AOCL as of December 31, 2025, and we expect to reclassify approximately $0.6 million of pre-tax losses from AOCL into interest expense during the next twelve months. These amounts relate to terminated swaps.

(10) Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs.

Applicable accounting guidance establishes a hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:

• Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities;

• Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and

• Level 3 – Significant inputs that are generally not observable from market activity.

We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. Due to the short-term nature of cash and cash equivalents, accounts receivable, net, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. NPNS transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 9 - Risk Management and Hedging Activities for further discussion.

We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented.

December 31, 2025	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)	Margin Cash Collateral Offset	Total Net Fair Value
	(in thousands)
Rabbi trust investments	14,673	—	—	—	14,673
Total	$ 14,673	$ —	$ —	$ —	$ 14,673

December 31, 2024
Rabbi trust investments	14,136	—	—	—	14,136
Total	$ 14,136	$ —	$ —	$ —	$ 14,136

Rabbi trust investments represent assets held for non-qualified deferred compensation plans, which consist of our common stock and actively traded mutual funds with quoted prices in active markets.

Financial Instruments

The estimated fair value of financial instruments is summarized as follows (in thousands):

	December 31, 2025		December 31, 2024
	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Liabilities:
Long-term debt	$ 2,690,083	$ 2,449,267	$ 2,406,206	$ 2,104,381

The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange.

We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.

(11) Unsecured Credit Facilities

On January 24, 2025, we amended our existing $400.0 million revolving credit facility (Amended Facility) to increase the capacity to $425.0 million. The Amended Facility has a maturity date of November 29, 2028 and this facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points. The Amended Facility has uncommitted features that allow us to request one-year extensions to the maturity date and increase the size of the Amended Facility by an additional $75.0 million.

Commitment fees for the unsecured revolving lines of credit were $0.3 million and $0.4 million for the years ended December 31, 2025 and 2024.

The availability under the facilities in place for the years ended December 31 is shown in the following table (in millions):

	2025	2024
Unsecured revolving line of credit, expiring November 2028	$ 425.0	$ 400.0

Amounts outstanding at December 31:
SOFR borrowings	362.0	342.0
Letters of credit	—	—
	362.0	342.0
Net availability as of December 31	$ 63.0	$ 58.0

Our credit facilities include covenants that require us to meet certain financial tests, including a maximum debt to capitalization ratio not to exceed 65 percent. The facilities also contain covenants which, among other things, limit our ability to engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, and enter into transactions with affiliates. A default on the Montana First Mortgage Bonds would trigger a cross default on the Amended Facility; however, a default on the Amended Facility would not trigger a default on the Montana First Mortgage Bonds.

(12) Long-Term Debt and Finance Leases

Long-term debt and finance leases consisted of the following (in thousands):

		December 31,
	Due	2025	2024
Unsecured Debt:
Unsecured Revolving Line of Credit	2028	$ 362,000	$ 342,000
Secured Debt:
Mortgage bonds—
Montana—5.01%	2025	—	161,000
Montana—3.11%	2025	—	75,000
Montana—3.99%	2028	35,000	35,000
Montana—5.073%	2030	500,000	—
Montana—3.21%	2030	100,000	100,000
Montana—5.57%	2031	175,000	175,000
Montana—5.57%	2033	239,000	239,000
Montana—5.71%	2039	55,000	55,000
Montana—4.15%	2042	60,000	60,000
Montana—4.85%	2043	15,000	15,000
Montana—4.176%	2044	450,000	450,000
Montana—4.11%	2045	125,000	125,000
Montana—4.03%	2047	250,000	250,000
Montana—3.98%	2049	150,000	150,000
Montana—4.30%	2052	40,000	40,000
Pollution control obligations—
Montana—3.88%	2028	144,660	144,660
Other Long Term Debt:
Discount on Notes and Bonds and Debt Issuance Costs, Net		(10,577)	(10,454)
Total Long-Term Debt		$ 2,690,083	$ 2,406,206
Less current maturities (including associated debt issuance costs)		—	(235,959)
Total Long-Term Debt, Net of Current Maturities		$ 2,690,083	$ 2,170,247

Finance Leases:
Total Finance Leases	2026	$ 1,865	$ 5,461
Less current maturities		(1,865)	(3,596)
Total Long-Term Finance Leases		$ —	$ 1,865

Secured Debt

First Mortgage Bonds and Pollution Control Obligations

The Montana First Mortgage Bonds are a series of general obligation bonds issued under our Montana indenture. These bonds are secured by our electric and natural gas assets.

On March 28, 2024, we issued and sold $175.0 million aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 5.56 percent maturing on March 28, 2031. These bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were used to redeem the $100.0 million of Montana First Mortgage Bonds due this year and for other general utility purposes. The bonds are secured by our electric and natural gas assets associated with its Montana utility operations.

On March 21, 2025, and November 7, 2025, we issued and sold $400.0 million and $100.0 million, respectively, aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 5.07 percent maturing on March 21, 2030. These bonds were issued and sold to certain initial purchasers without being registered under the Securities Act of 1933, as amended (Securities Act), in reliance upon exemptions therefrom in compliance with Rule 144A under the Securities Act, or under Regulation S under the Securities Act for sales to non-U.S. persons. The proceeds from the March 2025 issuance were utilized to redeem our $161.0 million of 5.01 percent Montana First Mortgage Bonds due May 1, 2025 and $75.0 million of 3.11 percent Montana First Mortgage Bonds due July 1, 2025, and for general utility purposes. The proceeds from the November 2025 issuance, which included $2.1 million of debt premium, were used for general utility purposes.

As of December 31, 2025, we were in compliance with our financial debt covenants.

Maturities of Long-Term Debt

The aggregate minimum principal maturities of long-term debt and finance leases, during the next five years are $1.9 million in 2026, $541.7 million in 2028, and $600.0 million in 2030.

(13) Income Taxes

Income tax expense (benefit) is comprised of the following (in thousands):

	Year Ended December 31,
	2025	2024
Federal
Current	$ 65	$ 1,667
Deferred	13,387	13,602
Investment tax credits	1,146	1,970
State
Current	(776)	61
Deferred	(649)	2,365
Income Tax Expense	$ 13,173	$ 19,665

Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable), and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.

The table below reconciles our effective income tax rate to the federal statutory rate and summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in thousands). Our income from continuing operations is primarily from domestic operations.

	Year Ended December 31,
	2025		2024
	(in dollars)	(in percent)	(in dollars)	(in percent)
Income before income taxes	$ 168,125		$ 199,744

Income tax calculated at federal statutory rate	35,306	21.0 %	41,946	21.0 %

State income tax, net of federal provision(1)	(919)	(0.5)	1,719	0.9
Tax Credits
Production tax credits	(1,650)	(1.0)	(2,288)	(1.1)
Other	(129)	(0.1)	(130)	(0.1)
Impact of utility ratemaking on income taxes
Flow-through repairs deductions	(27,128)	(16.1)	(19,274)	(9.6)
Amortization of excess deferred income taxes	(2,692)	(1.6)	(2,465)	(1.2)
AFUDC, net	(1,170)	(0.7)	(2,417)	(1.2)
Plant and depreciation of flow through items	13,071	7.8	6,690	3.3
Gas repairs safe harbor method change	—	—	(4,366)	(2.2)
Changes in Unrecognized Tax Benefits
Release of unrecognized tax benefits	(353)	(0.2)	—	—
Interest and penalties	(1,734)	(1.0)	766	0.4
Nontaxable and nondeductible items	881	0.5	232	0.1
Other	(310)	(0.3)	(748)	(0.5)
	(22,133)	(13.2)	(22,281)	(11.2)

Income Tax Expense and Effective Tax Rate	$ 13,173	7.8 %	$ 19,665	9.8 %

(1) For all years presented, the state of Montana comprises the majority of the domestic state income taxes, net of federal provisions.

We and our subsidiaries are included in NorthWestern Energy Group, Inc.'s consolidated federal and state income tax returns. In accordance with our tax sharing agreement with NorthWestern Energy Group, Inc., we compute our income taxes based upon the separate return method, where we are assumed to file a separate return with the taxing authority, thereby reporting our taxable income and paying the applicable tax to or receiving the appropriate refund from NorthWestern Energy Group, Inc.

In 2023, the Internal Revenue Service (IRS) issued a safe harbor method of accounting for the repair and maintenance of natural gas transmission and distribution property. For the year ending December 31, 2024, after completion of our impact analysis of the gas repairs safe harbor method change, we recorded an income tax benefit of approximately $4.4 million related to tax deductions for repair costs that were previously capitalized in the 2022 and prior tax years.

The components of the net deferred income tax liability recognized in our Consolidated Balance Sheets are related to the following temporary differences (in thousands):

	December 31,
	2025	2024
NOL carryforward	$ 84,771	89,816
Production tax credit	36,575	$ 35,602
Customer advances	36,406	32,455
Compensation accruals	10,126	9,857
Unbilled revenue	6,048	3,126
Interest rate hedges	3,044	3,205
Environmental liability	2,790	2,131
Reserves and accruals	1,277	2,133
Pension / postretirement benefits	—	10,369
Other	5,814	4,334
Deferred Tax Asset	186,851	193,028
Excess tax depreciation	(627,465)	(599,893)
Flow through depreciation	(129,905)	(119,674)
Goodwill amortization	(92,009)	(89,687)
Pension / postretirement benefits	(656)	—
Regulatory assets and other	(32,516)	(23,721)
Deferred Tax Liability	(882,551)	(832,975)
Deferred Tax Liability, net	$ (695,700)	$ (639,947)

As of December 31, 2025, our total federal net operation loss (NOL) carryforward was approximately $327.1 million. Our federal NOL carryforward does not expire. Our state NOL carryforward as of December 31, 2025 was approximately $301.6 million. If unused, our state NOL carryforwards will expire in 2033. We believe it is more likely than not that sufficient taxable income will be generated to utilize these NOL carryforwards.

At December 31, 2025, our total production tax credit carryforward was approximately $36.6 million. If unused, our production tax credit carryforwards will expire as follows: $0.5 million in 2035, $3.4 million in 2036, $3.5 million in 2037, $3.9 million in 2038, $4.4 million in 2039, $5.4 million in 2040, $4.4 million in 2041, $4.5 million in 2042, $2.6 million in 2043, $2.3 million in 2044, and $1.7 million in 2045. We believe it is more likely than not that sufficient taxable income will be generated to utilize these production tax credit carryforwards.

Uncertain Tax Positions

We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The change in unrecognized tax benefits is as follows (in thousands):

	2025	2024
Unrecognized Tax Benefits at January 1	$ 3,610	$ 5,179
Gross increases - tax positions in prior period	—	—
Gross increases - tax positions in current period	—	—
Gross decreases - tax positions in current period	—	(1,569)
Lapse of statute of limitations	(3,610)	—
Unrecognized Tax Benefits at December 31	$ —	$ 3,610

During the years ending December 31, 2025 and 2024, due to the expiration of the statute of limitations we decreased our unrecognized tax benefits by $3.6 million and $1.6 million, respectively.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2025, we have no accrual for the payment of interest and penalties in the Consolidated Balance Sheets. As of December 31, 2024, we had $1.7 million accrued for the payment of interest and penalties.

Tax years 2022 and forward remain subject to examination by the IRS and state taxing authorities.

(14) Comprehensive Income (Loss)

The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands):

	December 31,
	2025			2024
	Before-Tax Amount	Tax Expense (Benefit)	Net-of-Tax Amount	Before-Tax Amount	Tax Expense	Net-of-Tax Amount
Foreign currency translation adjustment	$ 18	$ —	$ 18	$ (4)	$ —	$ (4)
Reclassification of net income (loss) on derivative instruments	612	(160)	452	612	(160)	452
Postretirement medical liability adjustment	—	—	—	—	—	—
Other comprehensive income (loss)	$ 630	$ (160)	$ 470	$ 608	$ (160)	$ 448

Balances by classification included within AOCL on the Consolidated Balance Sheets are as follows, net of tax (in thousands):

	December 31,
	2025	2024
Foreign currency translation	$ 1,451	$ 1,433
Derivative instruments designated as cash flow hedges	(8,469)	(8,921)
Postretirement medical plans	(45)	(45)
Accumulated other comprehensive loss	$ (7,063)	$ (7,533)

The following table displays the changes in AOCL by component, net of tax (in thousands):

		December 31, 2025
		Year Ended
	Affected Line Item in the Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges	Postretirement Medical Plans	Foreign Currency Translation	Total
Beginning balance		$ (8,921)	$ (45)	$ 1,433	$ (7,533)
Other comprehensive income before reclassifications		—	—	18	18
Amounts reclassified from AOCL	Interest Expense	452	—	—	452
Net current-period other comprehensive income (loss)		452	—	18	470
Ending Balance		$ (8,469)	$ (45)	$ 1,451	$ (7,063)

		December 31, 2024
		Year Ended
	Affected Line Item in the Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges	Postretirement Medical Plans	Foreign Currency Translation	Total
Beginning balance		$ (9,373)	$ 280	$ 1,437	$ (7,656)
Other comprehensive loss before reclassifications		—	—	(4)	(4)
Amounts reclassified from AOCL	Interest Expense	452	—	—	452
Amounts reclassified from AOCL		—	—	—	—
Net current-period other comprehensive income (loss)		452	—	(4)	448
Distribution to Parent			$ (325)		$ (325)
Ending Balance		$ (8,921)	$ (45)	$ 1,433	$ (7,533)

(15) Employee Benefit Plans

Pension and Other Postretirement Benefit Plans

We sponsor and/or contribute to pension, postretirement health care and life insurance benefit plans for eligible employees. The pension plan for our Montana employees is referred to as the NorthWestern Energy MT Plan. We utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. The Plans' funded status is recognized as a liability in our Consolidated Financial Statements. See Note 5 - Regulatory Assets and Liabilities, for further discussion on how these costs are recovered through rates charged to our customers.

Benefit Obligation and Funded Status

Following is a reconciliation of the changes in plan benefit obligations and fair value of plan assets, and a statement of the funded status (in thousands):

	Pension Benefits		Other Postretirement Benefits
	December 31,		December 31,
	2025	2024	2025	2024
Change in benefit obligation:
Obligation at beginning of period	$ 404,803	$ 427,326	$ 8,339	$ 10,598
Service cost	4,207	5,099	210	252
Interest cost	17,716	20,725	423	456
Actuarial (gain) loss	(13,121)	(26,780)	(1,407)	(1,804)
Settlements(1)	(221,423)	(848)	—	—
Benefits paid	(18,578)	(20,719)	(407)	(1,163)
Benefit Obligation at End of Period	$ 173,604	$ 404,803	$ 7,158	$ 8,339
Change in Fair Value of Plan Assets:
Fair value of plan assets at beginning of period	$ 342,715	$ 348,134	$ 24,772	$ 22,309
Return on plan assets	34,106	8,026	3,648	3,177
Employer contributions	10,000	8,122	(121)	449
Settlements(1)	(221,423)	(848)	—	—
Benefits paid	(18,578)	(20,719)	(407)	(1,163)
Fair value of plan assets at end of period	$ 146,820	$ 342,715	$ 27,892	$ 24,772
Funded Status	$ (26,784)	$ (62,088)	$ 20,734	$ 16,433

Amounts Recognized in the Balance Sheet Consist of:
Noncurrent asset	—	—	21,216	16,943
Total Assets	—	—	21,216	16,943
Current liability	(11,500)	(10,000)	(482)	(510)
Noncurrent liability	(15,284)	(52,088)	—	—
Total Liabilities	(26,784)	(62,088)	(482)	(510)
Net amount recognized	$ (26,784)	$ (62,088)	$ 20,734	$ 16,433

Amounts Recognized in Regulatory Assets Consist of:
Prior service credit	—	—	—	—
Net actuarial gain (loss)	970	(30,843)	7,221	3,716
Total	$ 970	$ (30,843)	$ 7,221	$ 3,716

(1) In August 2025, we entered into a group annuity contract with an insurance company to provide for the payment of pension benefits to select pension plan participants. We purchased the contract with $221.4 million of plan assets, representing 92 percent of the settled benefit obligation. The insurance company took over the payments of these benefits starting November 1, 2025. As a result of this transaction, during the twelve months ended December 31, 2025, we recorded a non-cash, non-operating settlement charge of $1.2 million. This charge is recorded within other income, net on the Consolidated Statements of Income. As discussed within Note 5 – Regulatory Assets and Liabilities, the MPSC allows recovery of pension costs on a cash funding basis. As such, this charge was deferred as a regulatory asset on the Consolidated Balance Sheets, with a corresponding decrease to operating and maintenance expense on the Consolidated Statements of Income.

The actuarial gain/loss is generally due to discount rate assumptions and actual asset returns compared with expected amounts. In the case of the NorthWestern Energy MT Pension Plan the actuarial gain/loss is mainly related to demographic changes as a result of the annuitization mentioned above.

Net Periodic Cost (Credit)

The components of the net costs (credits) for our pension and other postretirement plans are as follows (in thousands):

	Pension Benefits		Other Postretirement Benefits
	December 31,		December 31,
	2025	2024	2025	2024
Components of Net Periodic Benefit Cost
Service cost	$ 4,207	$ 5,099	$ 210	$ 252
Interest cost	17,716	20,725	423	456
Expected return on plan assets	(16,581)	(22,585)	(1,418)	(1,280)
Recognized actuarial loss (gain)	—	33	(133)	—
Settlement loss recognized(1)	1,168	—	—	—
Net Periodic Benefit Cost (Credit)	$ 6,510	$ 3,272	$ (918)	$ (572)

Regulatory deferral of net periodic benefit cost(2)	3,490	4,850	—	—
Previously deferred costs recognized(2)	—	—	133	181
Net Periodic Benefit Cost (Credit) Recognized	$ 10,000	$ 8,122	$ (785)	$ (391)

(1) Settlement losses are related to partial annuitizations of the pension plan.

(2) Net periodic benefit costs for pension and postretirement benefit plans are recognized for financial reporting based on the authorization of each regulatory jurisdiction in which we operate. A portion of these costs are recorded in regulatory assets and recognized in the Consolidated Statements of Income as those costs are recovered through customer rates.

For the years ended December 31, 2025 and 2024 service costs were recorded in Operating, general, and administrative expense while non-service costs were recorded in Other income, net on the Consolidated Statements of Income.

For purposes of calculating the expected return on pension plan assets, the market-related value of assets is used, which is based upon fair value. The difference between actual plan asset returns and estimated plan asset returns are amortized equally over a period not to exceed five years.

Actuarial Assumptions

The measurement dates used to determine pension and other postretirement benefit measurements for the plans are December 31, 2025 and 2024. The actuarial assumptions used to compute net periodic pension cost and postretirement benefit cost are based upon information available as of the beginning of the year, specifically, market interest rates, past experience and management's best estimate of future economic conditions. Changes in these assumptions may impact future benefit costs and obligations. In computing future costs and obligations, we must make assumptions about such things as employee mortality and turnover, expected salary and wage increases, discount rate, expected return on plan assets, and expected future cost increases. Two of these assumptions have the most impact on the level of cost: (1) discount rate and (2) expected rate of return on plan assets. During 2022, the plan's actuary conducted an experience study to review five years of plan experience and update these assumptions.

On an annual basis, we set the discount rate using a yield curve analysis. This analysis includes constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year, projected benefit cash flow from our plans. The increase in the discount rate during 2025 decreased our projected benefit obligation by approximately $1.2 million.

In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions. Based on the target asset allocation for our pension assets and future expectations for asset returns, we decreased our long term rate of return on assets assumption for the pension plan to 6.3 percent for 2026.

The weighted-average assumptions used in calculating the preceding information are as follows:

	Pension Benefits		Other Postretirement Benefits
	December 31,		December 31,
	2025	2024	2025	2024
Discount rate	5.65	5.60	5.05	5.45
Expected rate of return on assets	6.17	6.65	5.80	5.84
Long-term rate of increase in compensation levels (non-union)	4.00	4.00	4.00	4.00
Long-term rate of increase in compensation levels (union)	4.00	4.00	4.00	4.00
Interest crediting rate	6.00	6.00	N/A	N/A

The postretirement benefit obligation is calculated assuming that health care costs increase by a 5 percent fixed rate. The company contribution toward the premium cost is capped, therefore future health care cost trend rates are expected to have a minimal impact on company costs and the accumulated postretirement benefit obligation.

Investment Strategy

Our investment goals with respect to managing the pension and other postretirement assets are to meet current and future benefit payment needs while maximizing total investment returns (income and appreciation) after inflation within the constraints of diversification, prudent risk taking, Prudent Man Rule of the Employee Retirement Income Security Act of 1974 and liability-based considerations. Each plan is diversified across asset classes to achieve optimal balance between risk and return and between income and growth through capital appreciation. Our investment philosophy is based on the following:

• Each plan should be substantially invested as long-term cash holdings reduce long-term rates of return;

• Pension Plan portfolio risk is described by volatility in the funded status of the Plans;

• It is prudent to diversify each plan across the major asset classes;

• Equity investments provide greater long-term returns than fixed income investments, although with greater short-term volatility;

• Fixed income investments of the plans should strongly correlate with the interest rate sensitivity of the plan’s aggregate liabilities in order to hedge the risk of change in interest rates negatively impacting the pension plans overall funded status, (such assets will be described as Liability Hedging Fixed Income assets);

• Allocation to foreign equities increases the portfolio diversification and thereby decreases portfolio risk while providing for the potential for enhanced long-term returns;

• Private real estate and broad global opportunistic fixed income asset classes can provide diversification to both equity and liability hedging fixed income investments and a moderate allocation to each can potentially improve the expected risk-adjusted return for the NorthWestern Energy MT Pension Plan investments over full market cycles;

• Active management can reduce portfolio risk and potentially add value through security selection strategies;

• A portion of plan assets should be allocated to passive, indexed management funds to provide for greater diversification and lower cost; and

• It is appropriate to retain more than one investment manager, provided that such managers offer asset class or style diversification.

Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense. In the optimization study, assumptions are formulated about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period. Based on this, the target asset allocation established, within an allowable range of plus or minus 3 - 8.5 percent, is as follows:

	NorthWestern Energy MT Pension		NorthWestern Energy Health and Welfare
	December 31,		December 31,
	2025	2024	2025	2024
Fixed income securities	45.0 %	45.0 %	40.0 %	40.0 %
Opportunistic fixed income	11.0	11.0	—	—
Global equities	38.5	38.5	60.0	60.0
Private real estate	5.5	5.5	—	—

The actual allocation by plan is as follows:

	NorthWestern Energy MT Pension		NorthWestern Energy Health and Welfare
	December 31,		December 31,
	2025	2024	2025	2024
Cash and cash equivalents(1)	4.7 %	— %	0.4 %	0.3 %
Fixed income securities(2)	37.9	43.7	30.8	32.2
Opportunistic fixed income	9.1	11.1	—	—
Global equities(2)	33.3	39.0	68.8	67.5
Private real estate(2)	15.0	6.2	—	—
	100.0 %	100.0 %	100.0 %	100.0 %

(1) Includes a substantial required cash allocation for the NorthWestern Energy MT Pension Plan related to a new overlay strategy designed to mitigate interest rate risk. Cash and cash equivalents, for purposes of this strategy, would be considered fixed income securities as it relates to target investment allocations.

(2) While some of the actual asset allocations above differ from established target allocations as of December 31, 2025, the plan Investment Manager has 60 days to initiate action to rebalance portfolios, when allocations fall out of acceptable ranges. While target allocations are the goal, both plan liquidity needs and investment liquidity terms (particularly as they pertain to the pension plan annuitization mentioned above) may cause temporary imbalances to occur.

Generally, the asset mix will be rebalanced to the target mix as individual portfolios approach their minimum or maximum levels. The guidelines allow for a transition to targets over time as assets are reallocated to newly-approved asset classes of opportunistic fixed income and private real estate. Debt securities consist of U.S. and international instruments including emerging markets and high yield instruments, as well as government, corporate, asset backed and mortgage backed securities. While the portfolio may invest in high yield securities, the average quality must be rated at least “investment grade" by rating agencies. Equity, real estate and fixed income portfolios may be comprised of both active and passive management strategies. Performance of fixed income investments is measured by both traditional investment benchmarks as well as relative changes in the present value of the plan's liabilities. Equity investments consist primarily of U.S. stocks including large, mid and small cap stocks. We also invest in global equities with exposure to developing and emerging markets. Equity investments may also be diversified across investment styles such as growth and value. Derivatives, options and futures are permitted for the purpose of reducing risk but may not be used for speculative purposes. Real estate investments will consist of global equity or debt interests in tangible property consisting of land, buildings, and other improvements in commercial and residential sectors.

The following tables set forth, both by level within the fair value hierarchy and by net asset value (NAV) as a practical expedient, the assets (in thousands) that were accounted for on a recurring basis:

	December 31, 2025
	Level 1	Level 2	Level 3	Total Investments Measured at Fair Value(1)	Total Investments Measured at NAV (Common Collective Trusts)	Total Investments
Pension Plan
Cash and cash equivalents	$ —	$ —	$ —	$ —	$ 6,927	$ 6,927
Fixed income securities	—	13,541	—	13,541	41,968	55,509
Opportunistic fixed income	—	—	—	—	13,383	13,383
Global equities	—	—	—	—	48,922	48,922
Private real estate	—	—	—	—	22,079	22,079
Total investments	$ —	$ 13,541	$ —	$ 13,541	$ 133,279	$ 146,820

Other Postretirement Benefits Plan
Cash and cash equivalents	$ —	$ —	$ —	$ —	$ 103	$ 103
Fixed income securities	5,940	—	—	5,940	2,653	8,593
Global equities	3,808	—	—	3,808	15,388	19,196
Total investments	$ 9,748	$ —	$ —	$ 9,748	$ 18,144	$ 27,892

	December 31, 2024
	Level 1	Level 2	Level 3	Total Investments Measured at Fair Value(1)	Total Investments Measured at NAV (Common Collective Trusts)	Total Investments
Pension Plan
Cash and cash equivalents	$ —	$ —	$ —	$ —	$ 104	$ 104
Fixed income securities	—	—	—	—	149,567	149,567
Opportunistic fixed income	—	—	—	—	38,163	38,163
Global equities	—	—	—	—	133,692	133,692
Private real estate	—	—	—	—	21,189	21,189
Total investments	$ —	$ —	$ —	$ —	$ 342,715	$ 342,715

Other Postretirement Benefits Plan
Cash and cash equivalents	$ —	$ —	$ —	$ —	$ 72	$ 72
Fixed income securities	5,504	—	—	5,504	2,475	7,979
Global equities	3,093	—	—	3,093	13,628	16,721
Total investments	$ 8,597	$ —	$ —	$ 8,597	$ 16,175	$ 24,772

(1) See Note 11 - Fair Value Measurements for further information on fair value measurement inputs and methods.

The following are descriptions of the methods and assumptions used to value investments held by pension and other postretirement trusts.

• Common/Collective Trusts: The majority of our plan assets are held by common collective trusts (CCTs). In accordance with our investment policy, these pooled investment funds must have an adequate asset base relative to their asset class, be invested in a diversified manner and have a minimum of three years of verified investment performance experience or have a portfolio manager with a minimum of three years of verified investment experience in a similar investment strategy. The fund must have management and/or oversight by an investment advisor registered with the SEC. Investments in a collective investment vehicle are valued by multiplying the investee company’s NAV per share by the number of units or shares owned at the valuation date. NAV per share is determined by the trustee. Investments held by the CCT, including collateral invested for securities on loan, are valued on the basis of valuations furnished by a pricing service approved by the CCT’s investment manager, which determines valuations using methods based on quoted closing market prices on national securities exchanges, or at fair value as determined in good faith by the CCT’s investment manager if applicable. The direct holding of NorthWestern Energy Group stock is not permitted; however, any holding in a diversified mutual fund or collective investment fund is permitted.

• Registered Investment Companies: Investments in mutual funds, categorized as global equities above, sponsored by a registered investment company are valued based on exchange listed prices. Where the value is a quoted price in an active market, the investment is classified within Level 1 of the fair value hierarchy.

• Fixed Income Securities: Certain fixed income securities are valued at the closing price reported in the active market in which the security is traded. Other fixed income securities are valued based on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar securities, the bonds are valued for the trustee by a pricing vendor on the basis of bid or mid evaluations in accordance to the region's market convention, using factors which include but are not limited to market quotes, yields, maturities and the bond's terms and conditions. Pricing vendors use proprietary methods to arrive at the evaluated price, which represents the price a dealer would pay for the security.

• Derivative Financial Instruments: Futures contracts that are publicly traded in active markets are valued at closing prices as of the last business day of the year. Fixed income futures and options are marked to market daily.

Cash Flows

In accordance with the Pension Protection Act of 2006 (PPA), and the relief provisions of the Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), we are required to meet minimum funding levels in order to avoid required contributions and benefit restrictions. We have elected to use asset smoothing provided by the WRERA, which allows the use of asset averaging, including expected returns (subject to certain limitations), for a 24-month period in the determination of funding requirements. Additional funding relief was passed in the American Rescue Plan Act of 2021, providing for longer amortization and interest rate smoothing, which we elected to use. We expect to continue to make contributions to the pension plans in 2026 and future years that reflect the minimum requirements and discretionary amounts consistent with the amounts recovered in rates. Additional legislative or regulatory measures, as well as fluctuations in financial market conditions, may impact our funding requirements.

Due to the regulatory treatment of pension costs in Montana, pension costs for 2025 and 2024 were based on actual contributions to the plan. Annual contributions to each of the pension plans are as follows (in thousands):

	2025		2024
NorthWestern Energy Pension Plan	$ 10,000		$ 8,122

We estimate the plans will make future benefit payments to participants as follows (in thousands):

	Pension Benefits	Other Postretirement Benefits
2026	11,120	992
2027	5,825	846
2028	6,743	816
2029	7,679	701
2030	8,441	707
2031-2035	54,046	2,832

Defined Contribution Plan

Our defined contribution plan permits employees to defer receipt of compensation as provided in Section 401(k) of the Internal Revenue Code. Under the plan, employees may elect to direct a percentage of their gross compensation to the plan. We also contribute various percentages of employees' gross compensation to the plan. Company contributions for the years ended December 31, 2025 and 2024 were $12.3 million and $11.6 million, respectively.

(16) Stock-Based Compensation

Our employees participate in the NorthWestern Energy Group, Inc. Amended and Restated Equity Compensation Plan (ECP), which includes restricted stock awards and performance share awards. Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. We account for our share-based compensation arrangements by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. The compensation cost is based on the fair value of the grant on the date it was awarded.

We recognized total stock-based compensation expense of $4.8 million and $2.8 million for the years ended December 31, 2025 and 2024, respectively, and related income tax benefit of $1.3 million and $0.6 million for the years ended December 31, 2025 and 2024, respectively.

(17) Common Stock

We have 250,000,000 shares authorized consisting of 200,000,000 shares of common stock with a $0.01 par value and 50,000,000 shares of preferred stock with a $0.01 par value. We have 100 shares of common stock issued and outstanding.

Dividend Restrictions

Under various state regulatory agreements, debt agreements and the Federal Power Act, we have restrictions, including minimum equity ratios, that limit the amount of dividend distributions that can be made.

Pursuant to the MPSC regulatory agreement, if our secured credit ratings are above BBB- for S&P Global Ratings and Baa3 for Moody's Investor Services, we may declare or pay dividends as long as our common equity ratio is 40 percent or above. If our secured credit ratings are BBB- for S&P Global Ratings or Baa3 for Moody's Investor Services, we may declare or pay dividends as long as our common equity ratio is 43 percent or above. If our secured credit ratings fall below BBB- with S&P Global Ratings or Baa3 with Moody's Investor Services, we may not declare or pay dividends.

Our ability to pay dividends is also limited by the terms of various debt agreements, pursuant to which, we are required to maintain a debt to capitalization ratio of no more than 0.65 to 1.00.

As of December 31, 2025, approximately $615.9 million of our net assets were available for the payment of dividends under our most restrictive dividend restriction.

(18) Commitments and Contingencies

Qualifying Facilities Liability

Our QF liability primarily consists of unrecoverable costs associated with a contract covered under the PURPA. This contract requires us to purchase minimum amounts of energy at prices ranging from $124 to $130 per MWH through 2029. As of December 31, 2025, our estimated gross contractual obligation related to this contract was approximately $168.6 million through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $152.8 million through 2029. As contractual obligations are settled, the related purchases and sales are recorded within Fuel, purchased power and direct transmission expense and Electric revenues in our Consolidated Statements of Income. The present value of the remaining liability is recorded in Other noncurrent liabilities in our Consolidated Balance Sheets. The following summarizes the change in the liability (in thousands):

	December 31,
	2025	2024
Beginning QF liability	$ 23,498	$ 28,670
Settlements	(10,206)	(7,606)
Interest expense	1,585	2,434
Ending QF liability	$ 14,877	$ 23,498

The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands):

	Gross Obligation	Recoverable Amounts	Net
2026	$ 55,393	$ 46,274	$ 9,119
2027	56,665	46,668	9,997
2028	42,400	41,664	736
2029	14,134	18,231	(4,097)
Total(1)	$ 168,592	$ 152,837	$ 15,755

(1) This net unrecoverable amount represents the undiscounted difference between the total gross obligations and recoverable amounts. The ending QF liability in the table above represents the present value of this net unrecoverable amount.

Long Term Supply and Capacity Purchase Obligations

We have entered into various commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 24 years. Costs incurred under these contracts are included in Fuel, purchased power and direct transmission expense in the Consolidated Statements of Income and were approximately $166.2 million and $189.5 million for the years ended December 31, 2025 and 2024, respectively. As of December 31, 2025, our commitments under these contracts were $347.6 million in 2026, $289.4 million in 2027, $287.0 million in 2028, $291.4 million in 2029, $287.5 million in 2030, and $2.0 billion thereafter. These commitments are not reflected in our Consolidated Financial Statements.

Hydroelectric License Commitments

With the 2014 purchase of hydroelectric generating facilities and associated assets located in Montana, we assumed two Memoranda of Understanding (MOUs) existing with state, federal and private entities. The MOUs are periodically updated and renewed and require us to implement plans to mitigate the impact of the projects on fish, wildlife and their habitats, and to increase recreational opportunities. The MOUs were created to maximize collaboration between the parties and enhance the possibility to receive matching funds from relevant federal agencies. Under these MOUs, we have a remaining commitment to spend approximately $18.1 million between 2024 and 2040. These commitments are not reflected in our Consolidated Financial Statements.

ENVIRONMENTAL LIABILITIES AND REGULATION

Environmental Matters

The operation of electric generating, transmission and distribution facilities, and gas gathering, storage, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.

Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, our environmental reserve is estimated to range between $7.8 million to $15.4 million. As of December 31, 2025, we had a reserve of approximately $10.6 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred.

The following summarizes the change in our environmental liability (in thousands):

	December 31,
	2025	2024
Liability at January 1,	$ 8,093	$ 8,438
Additions	2,638	—
Deductions	(696)	(416)
Charged to costs and expense	561	71
Liability at December 31,	$ 10,596	$ 8,093

We are permitted to recover the remediation costs related to certain environmental liabilities within rates. Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as available and applicable; therefore, although we cannot guarantee regulatory recovery for all remediation costs, we do not expect these costs to have a material effect on our consolidated financial position or results of operations.

In connection with the acquisition of the Energy West operations we recognized an additional $2.6 million reserve for remediation costs associated with a site in Great Falls, Montana that was identified during the acquisition. The MPSC has previously approved the recovery of costs related to this site, and as such, the costs associated with this reserve have been deferred as a regulatory asset on the Consolidated Balance Sheets. If approval to recover costs from retail customers is subsequently denied, our Asset Purchase Agreement with Hope Utilities includes provisions that allow us to seek recovery from them.

Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of GHG including, most significantly, carbon dioxide (CO2) and methane emissions from natural gas. These actions include legislative proposals, Executive, Congressional and EPA actions at the federal level, state level activity, investor activism and private party litigation relating to emissions. Coal-fired plants have come under particular scrutiny due to their level of emissions. We have a joint ownership interests in the Colstrip Units 3 & 4 coal-fired electric generating plant, which is operated by Talen. We are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.

EPA Rules - Congress has not passed any federal climate change legislation regarding GHG emissions from coal fired plants, and we cannot predict the timing or form of any potential legislation. Historically, Section 111(d) of the Clean Air Act (CAA) has been interpreted to confer authority on EPA in coordination with the states to regulate emissions, including GHG emissions, from existing stationary sources. On April 25, 2024, the EPA released final rules related to GHG emission standards (GHG Rules) for existing coal-fired facilities and new coal and natural gas-fired facilities as well as final rules strengthening the MATS requirements (MATS Rules). As finalized, compliance with the rules would require expensive upgrades at Colstrip Units 3 and 4 with proposed compliance dates that may not be achievable and / or require technology that is unproven, resulting in significant impacts to costs of the facilities. The final MATS and GHG Rules require compliance as early as 2027 and 2032, respectively.

On June 11, 2025, the EPA issued a Notice of Proposed Rulemaking proposing significant changes to the federal regulatory framework for both GHG emissions and hazardous air pollutants from power plants. If either the lead or alternative proposal is adopted, our additional material compliance costs would be eliminated. On February 19, 2026, the EPA rescinded the 2024 MATS Rules, restoring the rule to the 2012 MATS standards.

On February 12, 2026, the EPA released a final rule titled Rescission of the Greenhouse Gas Endangerment Finding and Motor Vehicle Greenhouse Gas Emission Standards Under the Clean Air Act. This action reflects a further shift in federal policy regarding the regulation of GHG emissions under the CAA and may have implications for the scope of the EPA's authority to regulate GHG emissions from stationary sources, including power plants. The legal and practical effects of this final rule, including the potential for judicial review or subsequent regulatory action, remain uncertain.

Notwithstanding these developments, existing and future federal, state, or regional environmental requirements - including potential revisions to GHG emissions standards, or other air quality regulations could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Technology to efficiently capture, remove and/or sequester such GHG emissions or hazardous air pollutants may not be available within a timeframe consistent with the implementation of any such requirements.

Regional Haze Rules - In January 2017, the EPA published amendments to the requirements under the CAA for state plans for protection of visibility - regional haze rules. Among other things, these amendments revised the process and requirements for the state implementation plans and extended the due date for the next periodic comprehensive regional haze state implementation plan revisions from 2018 to 2021.

The state of Montana has developed and submitted to the EPA, for its approval, a State Implementation Plans (SIP) for Regional Haze compliance. While the state of Montana did not meet the EPA’s July 31, 2021, submission deadline, it was submitted in 2022. The Montana SIP as drafted and submitted to EPA does not call for additional controls for our interest in Colstrip Unit 4. Until this SIP is finalized and approved by EPA, the potential remains that installation of additional emissions controls might be required at the Colstrip Units 3 & 4 facility.

Jointly Owned Plants - We have joint ownership in a generation plant located in Montana that is or may become subject to the various regulations discussed above that have been or may be issued or proposed.

Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.

We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:

• We may not know all sites for which we are alleged or will be found to be responsible for remediation; and

• Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.

LEGAL PROCEEDINGS

We are subject to various legal proceedings, governmental audits and claims that arise in the ordinary course of business. In our opinion, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.

(19) Revenue from Contracts with Customers

Accounting Policy

Our revenues are primarily from tariff based sales. We provide gas and/or electricity to customers under these tariffs without a defined contractual term (at-will). As the revenue from these arrangements is equivalent to the electricity or gas supplied and billed in that period (including estimated billings), there will not be a shift in the timing or pattern of revenue recognition for such sales. We have also completed the evaluation of our other revenue streams, including those tied to longer term contractual commitments. These revenue streams have performance obligations that are satisfied at a point in time, and do not have a shift in the timing or pattern of revenue recognition.

Customers are billed monthly on a cycle basis. To match revenues with associated expenses, we accrue unbilled revenues for electric and natural gas services delivered to customers, but not yet billed at month-end.

Nature of Goods and Services

We currently provide retail electric and natural gas services to three primary customer classes. Our largest customer class consists of residential customers, which include single private dwellings and individual apartments. Our commercial customers consist primarily of main street businesses, and our industrial customers consist primarily of manufacturing and processing businesses that turn raw materials into products.

Electric Segment - Our regulated electric utility business primarily provides generation, transmission, and distribution services to our customers. We recognize revenue when electricity is delivered to the customer. Payments on our tariff based sales are generally due in 20-30 days after the billing date.

Natural Gas Segment - Our regulated natural gas utility business primarily provides production, storage, transmission, and distribution services to our customers. We recognize revenue when natural gas is delivered to the customer. Payments on our tariff based sales are generally due in 20-30 days after the billing date.

Disaggregation of Revenue

The following tables disaggregate our revenue for the twelve months ended by major source and customer class (in thousands):

December 31, 2025	Electric	Natural Gas	Total
Residential	$ 406,643	$ 120,830	$ 527,473
Commercial	408,530	68,722	477,252
Industrial	43,128	2,439	45,567
Lighting, governmental, irrigation, and interdepartmental	31,031	2,223	33,254
Total Retail Revenues	889,332	194,214	1,083,546
Regulatory Amortization	59,200	5,336	64,536
Transmission	111,024	—	111,024
Transportation, wholesale and other	5,559	42,732	48,291
Total Revenues	$ 1,065,115	$ 242,282	$ 1,307,397

December 31, 2024	Electric	Natural Gas	Total
Residential	$ 398,790	$ 110,215	$ 509,005
Commercial	408,977	59,925	468,902
Industrial	46,638	1,041	47,679
Lighting, governmental, irrigation, and interdepartmental	29,537	1,352	30,889
Total Retail Revenues	883,942	172,533	1,056,475
Regulatory Amortization	21,140	14,622	35,762
Transmission	96,999	—	96,999
Transportation, wholesale and other	8,153	37,058	45,211
Total Revenues	$ 1,010,234	$ 224,213	$ 1,234,447

(20) Related Party Transactions and Shared Services

Our parent, NorthWestern Energy Group, Inc., is organized as a holding company. As part of a holding company we receive services and share costs with Northwestern Energy Group, Inc., and its other subsidiaries pursuant to an Intercompany Services Agreement (ISA) that became effective in 2023. The ISA was approved by the MPSC. We employ all or substantially all of the employees of NorthWestern Energy Group, Inc. and its subsidiaries and, in accordance with the ISA, will provide all employment related services to the parties to the ISA. Pursuant to the ISA, all rendered services are at cost. The total amount of payroll related services provided to NorthWestern Energy Public Service Corporation, a direct wholly-owned subsidiary of NorthWestern Energy Group, Inc., was $39.3 million for each of the years ended December 31, 2025 and 2024.

Additionally, pursuant to the ISA, when utility-related operating, administrative, and general costs are attributable to more than one entity within the holding company structure and are unable to be direct charged (Shared OA&G Costs), these costs will be allocated amongst the entities pursuant to a Cost Allocation Manual. The nature of these Shared OA&G Costs includes operations supervision and engineering, energy supply marketing, networking communications, information technology, human resources, accounting, legal, and other such administrative costs.

The services provided under the ISA are settled in cash amongst the parties each month.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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		273,619		1,437,159	7,223,778		5,513,000
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income		318,221			452,130		133,909
3	Preceding Quarter/Year to Date Changes in Fair Value				4,302			4,302
4	Total (lines 2 and 3)		318,221		4,302	452,130		129,607	180,078,442	180,208,048
5	Balance of Account 219 at End of Preceding Quarter/Year		44,602		1,432,857	6,771,648		5,383,393
6	Balance of Account 219 at Beginning of Current Year		44,602		1,432,857	6,771,648		5,383,393
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income					452,130		452,130
8	Current Quarter/Year to Date Changes in Fair Value				18,677			18,677
9	Total (lines 7 and 8)				18,677	452,130		470,807	154,951,659	155,422,466
10	Balance of Account 219 at End of Current Quarter/Year		44,602		1,451,534	6,319,518		4,912,586

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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)	6,768,078,889	5,193,251,750	1,360,742,838	(b) 1,730,244			212,354,057
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	41,532,618				(c) 40,209,537	(d) 1,323,081
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold	0
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	0
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified	2,882,883	2,882,883
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	6,812,494,390	5,196,134,633	1,360,742,838	1,730,244	40,209,537	1,323,081	212,354,057
9	UtilityPlantLeasedToOthers Leased to Others	0
10	UtilityPlantHeldForFutureUse Held for Future Use	3,959,559	3,929,693	29,866
11	ConstructionWorkInProgress Construction Work in Progress	137,797,710	105,205,685	11,080,777	0			21,511,248
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	656,318,593	656,318,593
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	7,610,570,252	5,961,588,604	1,371,853,481	1,730,244	40,209,537	1,323,081	233,865,305
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	2,567,943,202	1,999,872,202	461,034,802	1,217,902	39,204,279	0	66,614,017
15	UtilityPlantNet Net Utility Plant (13 less 14)	5,042,627,050	3,961,716,402	910,818,679	512,342	1,005,258	1,323,081	167,251,288
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	2,234,003,254	1,757,506,271	392,759,785	1,217,902	39,204,279		43,315,017
19	AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService Amortization and Depletion of Producing Natural Gas Land and Land Rights	59,647,662		59,647,662
20	AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService Amortization of Underground Storage Land and Land Rights	0
21	AmortizationOfOtherUtilityPlantUtilityPlantInService Amortization of Other Utility Plant	65,836,229	(a) 33,909,874	8,627,355				23,299,000
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	2,359,487,145	1,791,416,145	461,034,802	1,217,902	39,204,279	0	66,614,017
23	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract Leased to Others
24	DepreciationUtilityPlantLeasedToOthers Depreciation	0
25	AmortizationAndDepletionUtilityPlantLeasedToOthers Amortization and Depletion	0
26	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers Total Leased to Others (24 & 25)	0	0	0	0	0	0	0
27	DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract Held for Future Use
28	DepreciationUtilityPlantHeldForFutureUse Depreciation	0
29	AmortizationUtilityPlantHeldForFutureUse Amortization	0
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)	0	0	0	0	0	0	0
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)	0
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	208,456,057	208,456,057
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	2,567,943,202	1,999,872,202	461,034,802	1,217,902	39,204,279	0	66,614,017

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: AmortizationOfOtherUtilityPlantUtilityPlantInService

Amortization of other Montana electric plant was $29,808,909 for 2024.

(b) Concept: UtilityPlantInServiceClassified

This column represents regulated propane.

This column represents an electric default supply capacity and energy sales agreement classified as a capital lease.

(d) Concept: UtilityPlantInServicePropertyUnderCapitalLeases

This column represents our right of use (operating lease) assets.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	19,995	0	0	0	0	19,995
3	(302) Franchise and Consents	22,457,191	0	0	0	0	22,457,191
4	(303) Miscellaneous Intangible Plant	16,896,105	6,930	0	0	16,896,106	6,929
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	39,373,291	6,930	0	0	16,896,106	22,484,115
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	446,126	0	0	0	0	446,126
9	(311) Structures and Improvements	28,368,032	9,939	0	0	0	28,377,971
10	(312) Boiler Plant Equipment	46,434,378	3,449,158	0	0	0	49,883,536
11	(313) Engines and Engine-Driven Generators	0	0	0	0	0	0
12	(314) Turbogenerator Units	22,268,868	5,854,223	0	0	0	28,123,091
13	(315) Accessory Electric Equipment	2,734,161	181	0	0	0	2,734,342
13.1	(315.1) Computer Hardware	0				307,981	307,981
13.2	(315.2) Computer Software	0					0
13.3	(315.3) Communication Equipment	0					0
14	(316) Misc. Power Plant Equipment	22,947,674	382,100	69,724	0	0	23,260,050
15	(317) Asset Retirement Costs for Steam Production	20,705,728	4,026	0	0	0	20,709,754
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	143,904,967	9,699,627	69,724	0	307,981	153,842,851
17	B. Nuclear Production Plant
18	(320) Land and Land Rights	0					0
19	(321) Structures and Improvements	0					0
20	(322) Reactor Plant Equipment	0					0
21	(323) Turbogenerator Units	0					0
22	(324) Accessory Electric Equipment	0					0
22.1	(324.1) Computer Hardware	0					0
22.2	(324.2) Computer Software	0					0
22.3	(324.3) Communication Equipment	0					0
23	(325) Misc. Power Plant Equipment	0					0
24	(326) Asset Retirement Costs for Nuclear Production	0					0
25	TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)	0	0	0	0	0	0
26	C. Hydraulic Production Plant
27	(330) Land and Land Rights	6,339,292	12,196	0	0	0	6,351,488
28	(331) Structures and Improvements	130,635,819	1,558,828	134,896	0	291,309	132,351,060
29	(332) Reservoirs, Dams, and Waterways	206,122,833	2,198,870	216,172	0	0	208,105,531
30	(333) Water Wheels, Turbines, and Generators	201,672,413	16,456,327	1,106,223	0	0	217,022,517
31	(334) Accessory Electric Equipment	95,546,019	388,615	24,303	0	371,404	95,538,927
31.1	(334.1) Computer Hardware	0	844,842	290,139	0	697,084	1,251,787
31.2	(334.2) Computer Software	0	0	365,166	0	1,098,316	733,150
31.3	(334.3) Communication Equipment	0	0	0	0	2,185,981	2,185,981
32	(335) Misc. Power Plant Equipment	20,879,880	53,880	0	0	7,071	20,833,071
33	(336) Roads, Railroads, and Bridges	3,908,013	475,078	0	0	0	4,383,091
34	(337) Asset Retirement Costs for Hydraulic Production	0	0	0	0	0	0
35	TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)	665,104,269	21,880,876	2,136,899	0	3,908,357	688,756,603
35.1	D. Solar Production Plant
35.2	(338.1) Land and Land Rights	0	0	0	0	0	0
35.3	(338.2) Structures and Improvements	0	753,802	0		225,691	979,493
35.5	(338.4) Solar Panels	0	211,733	0	0	258,295	470,028
35.6	(338.5) Collector System	0	0	0	0	29,619	29,619
35.7	(338.6) Generator Step-up Transformers (GSU)	0	0	0	0	0	0
35.8	(338.7) Inverters	0	10,653	0	0	75,691	86,344
35.9	(338.8) Other Accessory Electrical Equipment	0	148,918	0	0	654,963	803,881
35.10	(338.9) Computer Hardware	0	0	0	0	13,645	13,645
35.11	(338.10) Computer Software	0	0	0	0	0	0
35.12	(338.11) Communication Equipment	0	44,160	0	0	3,088	47,248
35.13	(338.12) Miscellaneous Power Plant Equipment	0	532,908	0	0	0	532,908
35.14	(338.13) Asset Retirement Costs for Solar Production	0	0	0	0	0	0
35.15	TOTAL Solar Production Plant (Enter Total of lines 35.2 thru 35.14)	0	1,702,174	0	0	1,260,992	2,963,166
35.16	E. Wind Production Plant
35.17	(338.20) Land and Land Rights	0	0	0	0	111,793	111,793
35.18	(338.21) Structures and Improvements	0	0	0	0	3,566,687	3,566,687
35.20	(338.23) Wind Turbines	0	0	0	0	53,479,614	53,479,614
35.21	(338.24) Wind Towers and Fixtures	0	0	0	0	33,767,103	33,767,103
35.23	(338.26) Collector System	0	0	0	0	0	0
35.24	(338.27) Generator Step-up Transformers (GSU)	0	0	0	0	0	0
35.25	(338.28) Inverters	0	0	0	0	0	0
35.26	(338.29) Other Accessory Electrical Equipment	0	0	0	0	9,279,210	9,279,210
35.27	(338.30) Computer Hardware	0	0	0	0	0	0
35.28	(338.31) Computer Software	0	0	0	0	10,188	10,188
35.29	(338.32) Communication Equipment	0	0	0	0	33,538	33,538
35.30	(338.33) Miscellaneous Power Plant Equipment	0	0	0	0	2,582,418	2,582,418
35.31	(338.34) Asset Retirement Costs for Wind Production	0	0	0	0	3,686,816	3,686,816
35.32	TOTAL Wind Production Plant (Enter Total of lines 35.17 thru 35.31)	0	0	0	0	106,517,367	106,517,367
35.33	F. Other Renewable Production Plant
35.34	(339.1) Land and Land Rights	0					0
35.35	(339.2) Structures and Improvements	0					0
35.36	(339.3) Fuel Holders	0					0
35.37	(339.4) Boilers	0					0
35.39	(339.6) Generators	0					0
35.41	(339.8) Other Accessory Electrical Equipment	0					0
35.42	(339.9) Computer Hardware	0					0
35.43	(339.10) Computer Software	0					0
35.44	(339.11) Communication Equipment	0					0
35.45	(339.12) Miscellaneous Power Plant Equipment	0					0
35.46	(339.13) Asset Retirement Costs for Other Renewable Production	0					0
35.47	TOTAL Other Renewable Production Plant (Enter Total of lines 35.34 thru 35.46)	0	0	0	0	0	0
36	G. Other Production Plant
37	(340) Land and Land Rights	3,819,385	0	0	0	111,793	3,707,592
38	(341) Structures and Improvements	123,846,271	23,563,282	0	0	37,333,791	62,949,198
39	(342) Fuel Holders, Products, and Accessories	34,699,345	5,524,008	67,488	0	0	40,155,865
40	(343) Prime Movers	178,282,348	46,748,582	10,935,393	0	2,329,571	216,425,108
41	(344) Generators	116,365,367	5,249,797	0	0	53,479,614	68,135,550
42	(345) Accessory Electric Equipment	52,121,970	1,647,433	7,821	0	9,279,210	41,187,506
42.1	(345.1) Computer Hardware	0	0	0	0	297,376	297,376
42.2	(345.2) Computer Software	0	0	0	0	49,987	49,987
42.3	(345.3) Communication Equipment	0	386,093	0	0	42,920	429,013
43	(346) Misc. Power Plant Equipment	61,774,033	12,692,673	67,775	0	4,911,988	44,101,597
44	(347) Asset Retirement Costs for Other Production	3,686,816				3,686,816	0
45	TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)	574,595,535	20,005,092	11,078,477	0	106,083,358	477,438,792
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, 35.15, 35.32, 35.47, and 45)	1,383,604,771	53,287,769	13,285,100	0	5,911,339	1,429,518,779
47	3. Transmission Plant
48	(350) Land and Land Rights	43,467,408	251,319	6	0	0	43,718,721
48.2	(351.1) Computer Hardware	0	592,793	0	0	2,067,382	2,660,175
48.3	(351.2) Computer Software	0	47,411	604,734	0	8,767,034	8,209,711
48.4	(351.3) Communication Equipment	0	2,127,755	8,264	0	36,480,763	38,600,254
49	(352) Structures and Improvements	86,576,778	2,991,910	662,154	0	310	88,906,224
50	(353) Station Equipment	384,949,916	13,601,161	63,014	0	293,297	398,781,360
51	(354) Towers and Fixtures	30,640,142	0	3,118	0	0	30,637,024
52	(355) Poles and Fixtures	519,430,680	45,872,016	4,790,100	0	116,212	560,396,384
53	(356) Overhead Conductors and Devices	189,374,072	5,012,727	117,611	0	0	194,269,188
54	(357) Underground Conduit	137,878	0	0	0	0	137,878
55	(358) Underground Conductors and Devices	1,961,964	0	0	0	0	1,961,964
56	(359) Roads and Trails	4,056,595	0	0	0	0	4,056,595
57	(359.1) Asset Retirement Costs for Transmission Plant	0	0	0	0	0	0
58	TOTAL Transmission Plant (Enter Total of lines 48 thru 57)	1,260,595,433	70,497,092	6,249,001	0	47,491,954	1,372,335,478
59	4. Distribution Plant
60	(360) Land and Land Rights	14,732,728	46,608	0	0	232,370	15,011,706
61	(361) Structures and Improvements	52,764,767	4,401,119	11,108	0	268,563	57,423,341
62	(362) Station Equipment	276,646,321	25,916,442	1,556,375	0	629,957	300,376,431
63.1	(363.1) Computer Hardware	0	53,128	0	0	2,371,583	2,424,711
63.2	(363.2) Computer Software	0	2,911,356	366,321	0	9,603,578	12,148,613
63.3	(363.3) Communication Equipment	0	1,873,284	0	0	5,257,586	7,130,870
64	(364) Poles, Towers, and Fixtures	415,390,059	26,157,995	1,614,110	0	48,666	439,982,610
65	(365) Overhead Conductors and Devices	166,151,862	7,767,254	118,877	0	67,546	173,867,785
66	(366) Underground Conduit	195,766,544	14,035,599	120	0	0	209,802,023
67	(367) Underground Conductors and Devices	298,985,173	19,887,659	497,379	0	0	318,375,453
68	(368) Line Transformers	293,830,738	18,882,670	2,353,506	0	0	310,359,902
69	(369) Services	200,535,016	13,236,442	351,771	0	0	213,419,687
70	(370) Meters	92,679,949	6,565,823	16,215,176	0	0	83,030,596
71	(371) Installations on Customer Premises	0	0	0	0	0	0
72	(372) Leased Property on Customer Premises	0	0	0	0	0	0
73	(373) Street Lighting and Signal Systems	83,788,345	1,384,232	351,402	0	0	84,821,175
74	(374) Asset Retirement Costs for Distribution Plant	0	0	0	0	0	0
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	(a) 2,100,138,602	143,119,611	23,436,145	0	8,352,835	2,228,174,903
76	5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77	(380) Land and Land Rights	0	0	0	0	0	0
78	(381) Structures and Improvements	0	0	0	0	0	0
79	(382) Computer Hardware	0	0	0	0	0	0
80	(383) Computer Software	0	0	0	0	0	0
81	(384) Communication Equipment	0	0	0	0	0	0
82	(385) Miscellaneous Regional Transmission and Market Operation Plant	0	0	0	0	0	0
83	(386) Asset Retirement Costs for Regional Transmission and Market Oper	0	0	0	0	0	0
84	TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)	0	0	0	0	0	0
84.1	6. ENERGY STORAGE PLANT
84.2	(387.1) Land and Land Rights	0	2,878	0	0	714,650	717,528
84.3	(387.2) Structures and Improvements	0	645	0	0	160,065	160,710
84.4	(387.3) Energy Storage Equipment	0	23,893	0	0	5,933,002	5,956,895
84.6	(387.5) Collector System	0	4,502	0	0	1,117,914	1,122,416
84.7	(387.6) Generator Step-up Transformers (GSU)	0	3,196	0	0	793,510	796,706
84.8	(387.7) Inverters	0	8	0	0	1,865	1,873
84.9	(387.8) Computer Hardware	0	0	0	0	0	0
84.10	(387.9) Computer Software	0	0	0	0	0	0
84.11	(387.10) Communication Equipment	0	588	0	0	146,093	146,681
84.12	(387.11) Miscellaneous Energy Storage Equipment	0	0	0	0	0	0
84.13	(387.12) Asset Retirement Costs for Energy Storage	0	0	0	0	0	0
84.14	TOTAL Energy Storage Plant (Total lines 84.2 thru 84.13)	0	35,709	0	0	8,867,100	8,902,809
85	7. General Plant
86	(389) Land and Land Rights	689,633	0	0	0	0	689,633
87	(390) Structures and Improvements	10,602,203	12,785	2,000	0	4,648	10,608,340
88	(391) Office Furniture and Equipment	3,221,767	123,915	0	0	2,944,752	400,930
89	(392) Transportation Equipment	69,838,782	4,484,575	2,168,030	0	43,887	72,111,440
90	(393) Stores Equipment	1,179,099	0	16,025	0	0	1,163,074
91	(394) Tools, Shop and Garage Equipment	11,549,407	1,811,155	181,560	0	68,096	13,247,098
92	(395) Laboratory Equipment	1,027,426	0	562	0	0	1,026,864
93	(396) Power Operated Equipment	6,949,253	1,740,946	211,207	0	0	8,478,992
94	(397.1) Computer Hardware	0	0	0	0	440,978	440,978
94.1	(397.2) Computer Software	0	0	0	0	270,496	270,496
94.2	(397.3) Communication Equipment	63,025,160	371,563	0	0	42,512,169	20,884,554
95	(398) Miscellaneous Equipment	2,253,006	260,261	0	0	0	2,513,267
96	SUBTOTAL (Enter Total of lines 86 thru 95)	170,335,736	8,805,200	2,579,384	0	44,725,886	131,835,666
97	(399) Other Tangible Property	0	0	0	0	0	0
98	(399.1) Asset Retirement Costs for General Plant	0	0	0	0	0	0
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	170,335,736	8,805,200	2,579,383	0	44,725,886	131,835,667
100	TOTAL (Accounts 101 and 106)	4,954,047,833	275,752,311	45,549,629	0	9,001,236	5,193,251,751
101	(102) Electric Plant Purchased (See Instr. 8)	0	0	0	0	0	0
102	(Less) (102) Electric Plant Sold (See Instr. 8)	0	0	0	0	0	0
103	(103) Experimental Plant Unclassified	4,798,750	0	654,876	0	1,260,991	2,882,883
104	TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)	4,958,846,583	275,752,311	46,204,506	0	7,740,245	5,196,134,633

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: DistributionPlant

FERC Order 898 removed account 363 - Energy Storage Equipment - Distribution from Distribution plant and created new accounts under Energy Storage Plant 387. Order 898 was effective January 1, 2025 and applies prospectively, without requiring historical restatement. On December 31, 2024 we had $8,867,100 in account 363. During 2025 this balance was transferred to various accounts under Energy Storage Plant. The beginning balance for Distribution plant has not been restated on page 204 in our 2025 filing, and the subtotal presented does not tie to the individual accounts due to the removal of account 363 from Distribution Plant. Below is detail of our Distribution plant including account 363 for the year ending December 31, 2025.

204 - Schedule - Electric Plant In Service

Line No.	Account (a)	Balance Beginning of Year (b)	Additions (c)	Retirements (d)	Adjustments (e)	Transfers (f)	Balance at End of Year (g)
59	4. Distribution Plant
60	(360) Land and Land Rights	14,732,728	46,608	0	0	232,370	15,011,706
61	(361) Structures and Improvements	52,764,767	4,401,119	11,108	0	268,563	57,423,341
62	(362) Station Equipment	276,646,321	25,916,442	1,556,375	0	-629,957	300,376,431
63	(363) Energy Storage Equipment - Distribution	8,867,100	0	0	0	-8,867,100	0
63.1	(363.1) Computer Hardware	0	53,128	0	0	2,371,583	2,424,711
63.2	(363.2) Computer Software	0	2,911,356	366,321	0	9,603,578	12,148,613
63.3	(363.3) Communication Equipment	0	1,873,284	0	0	5,257,586	7,130,870
64	(364) Poles, Towers, and Fixtures	415,390,059	26,157,995	1,614,110	0	48,666	439,982,610
65	(365) Overhead Conductors and Devices	166,151,862	7,767,254	118,877	0	67,546	173,867,785
66	(366) Underground Conduit	195,766,544	14,035,599	120	0	0	209,802,023
67	(367) Underground Conductors and Devices	298,985,173	19,887,659	497,379	0	0	318,375,453
68	(368) Line Transformers	293,830,738	18,882,670	2,353,506	0	0	310,359,902
69	(369) Services	200,535,016	13,236,442	351,771	0	0	213,419,687
70	(370) Meters	92,679,949	6,565,823	16,215,176	0	0	83,030,596
71	(371) Installations on Customer Premises	0	0	0	0	0	0
72	(372) Leased Property on Customer Premises	0	0	0	0	0	0
73	(373) Street Lighting and Signal Systems	83,788,345	1,384,232	351,402	0	0	84,821,175
74	(374) Asset Retirement Costs for Distribution Plant	0	0	0	0	0	0
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	2,100,138,602	143,119,611	23,436,145	0	8,352,835	2,228,174,903

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Townsend Transmission Sub site	01/01/2011	12/31/2031	1,763,378
3	Missoula Miller Creek Sub site	01/01/2001	03/31/2026	625,904
4	Billings Metra Sub Site	07/01/2019	12/31/2036	595,346
5	Minor Projects (Less than $250,000 - 17 items)			945,065
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			3,929,693

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Black Eagle Spillway Upgrade	10,455,016
2	SSIP AUTOTRANSFORMER UPGRADE	7,099,562
3	500kV SBSE Broadview Cap Replace	5,232,890
4	ETCA MILLER STEVI A LINE	4,893,316
5	Thompson Falls U6 Turbine Upgrade	2,908,440
6	500KV LOCO MTN NTWK	2,896,818
7	Broadview Bus	2,822,110
8	Beaver Creek Wind TPIF	2,571,926
9	Holter U4 Turbine Upgrade	2,534,323
10	LOLO BANK UPGRADE	2,340,989
11	Great Falls 230 Swyd Expansion	2,301,874
12	Hauser U6 Turb-Gen Upgrade	2,158,245
13	Three Rivers 230/161 Bnk	1,931,555
14	Holter U4 Generator Rewind	1,706,733
15	BELGRADE WEST BANK 2	1,664,957
16	Thompson Falls U6 Generator Rewind	1,514,498
17	Thompson Falls Relicensing	1,473,278
18	SBSE DOC Enhancements	1,365,136
19	Mill Creek-Garrison #2	1,326,712
20	Great Falls Southside - MT Refini	1,238,683
21	TWO DOT XFMR UPGRADE	1,080,436
22	Anaconda Transformer Upgrade	1,062,405
23	Bozeman WESTSIDE 14	1,027,698
24	Minor Projects (Less than $1,000,000 - 285 items)	41,598,085
43	Total	105,205,685

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	1,673,739,727	1,673,739,727	0	0
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	137,531,550	137,531,550
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs	0
5	ExpensesOfElectricPlantLeasedToOthers (413) Exp. of Elec. Plt. Leas. to Others	0
6	TransportationExpensesClearing Transportation Expenses-Clearing	0
7	OtherClearingAccounts Other Clearing Accounts	0
8	OtherAccounts Other Accounts (Specify, details in footnote):	0
9.1		0
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	137,531,550	137,531,550	0	0
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	44,868,278	44,868,278
13	CostOfRemovalOfPlant Cost of Removal	12,959,371	12,959,371
14	SalvageValueOfRetiredPlant Salvage (Credit)	1,120,871	1,120,871
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	56,706,778	56,706,778	0	0
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):	2,941,772	2,941,772
17.1	Transfers	2,941,303	2,941,303
17.2	Other	469	469
18	BookCostOfAssetRetirementCosts Book Cost or Asset Retirement Costs Retired	0
19	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)	1,757,506,271	1,757,506,271	0	0
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	45,603,704	45,603,704
21	AccumulatedDepreciationNuclearProduction Nuclear Production	0
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional	149,090,904	149,090,904
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage	0
23.1	AccumulatedDepreciationSolarProduction Solar Production	1,459,620	1,459,620
23.2	AccumulatedDepreciationWindProduction Wind Production	50,658,409	50,658,409
23.3	AccumulatedDepreciationOtherRenewableProduction Other Renewable Production	0
24	AccumulatedDepreciationOtherProduction Other Production	38,346,755	38,346,755
25	AccumulatedDepreciationTransmission Transmission	474,053,889	474,053,889
26	AccumulatedDepreciationDistribution Distribution	912,681,713	912,681,713
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation	0
27.1	AccumulatedDepreciationEnergyStorage Energy Storage	629,799	629,799
28	AccumulatedDepreciationGeneral General	84,981,478	84,981,478
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	1,757,506,271	1,757,506,271	0	0

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Canadian Montana Pipeline Corporation - Paid in Capital	02/15/2002		1,388,429			1,388,429
2	Canadian Montana Pipeline Corporation - Equity in Undistributed Earnings	02/15/2002		2,263,042	88,024		2,175,018
3	Canadian Montana Pipeline Corporation- Translation Adjustment	02/15/2002		1,682,015			1,700,690
4				5,333,486	88,024	0	5,264,137
5	Havre Pipeline Company - Paid in Capital	12/01/2013		16,626,690			19,898,989
6	Havre Pipeline Company - Equity in Undistributed Earnings	12/01/2013		5,064,160	1,806,904		6,871,064
7				11,562,530	1,806,904	0	13,027,925
8	NorthWestern Great Falls Gas, LLC - Paid in Capital	07/01/2025					23,889,007
9	NorthWestern Great Falls Gas, LLC - Equity in Undistributed Earnings	07/01/2025			94,462		94,462
10				0	94,462		23,794,545
11	NorthWestern Cut Bank Gas, LLC - Paid in Capital	07/01/2025					1,940,381
12	NorthWestern Cut Bank Gas, LLC - Equity in Undistributed Earnings	07/01/2025			177,938		177,938
13					177,938		1,762,443
42	Total Cost of Account 123.1 $		Total	16,896,016	2,167,328		43,849,050

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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)	2,248,613	2,255,915	Electric & Gas
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)	76,163,131	80,640,678	Electric, Gas, & Common
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)
8	Transmission Plant (Estimated)	405,337	408,994	Electric & Gas
9	Distribution Plant (Estimated)	773,116	808,210	Electric, Gas, & Common
10	Regional Transmission and Market Operation Plant (Estimated)	2,439,130	2,221,642	Electric, Gas, & Common
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)	79,780,714	84,079,524
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	82,029,327	(a)(b) 86,335,439

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: MaterialsAndOperatingSupplies

Line No.	Account (a)	Balance Beginning of Year (b)	Balance End of Year (c )	Estimate of Portion Attributable to Construction	Balance End of Year w/ Assigned to Construction (c )	Department or Departments which Use Material (d)
1	Fuel Stock (Account 151)	2,248,613	2,255,915		2,255,915	Electric & Gas
2	Fuel Stock Expense Undistributed (Account 152)
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	-	-	80,640,678	80,640,678	Electric, Gas, & Common
6	Assigned to - Operatons and Maintenance
7	Production Plant (Estimated)	8,939,134	9,999,879	(9,590,884)	408,994	Electric & Gas
8	Transmission Plant (Estimated)	17,049,982	19,760,680	(18,952,471)	808,210	Electric, Gas, & Common
9	Distribution Plant (Estimated)	53,791,598	54,318,965	(52,097,323)	2,221,642	Electric, Gas, & Common
10	Regional Transmission and Market Operation Plant (Estimated)				-
11	Assigned to - Other	-	-		-
12	TOTAL Account 154 (Enter Total of lines 5 thru 10)	79,780,714	84,079,524	-	84,079,524
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)
15	Nuclear Materials Held for Sale (Account 157)
16	Store Expense Undistributed (Account 163)
17
18
19
20	TOTAL Materials and Supplies (Per Balance Sheet)	82,029,327	86,335,439	-	86,335,439

(b) Concept: MaterialsAndOperatingSupplies

Montana Operations
Line No.	Account (a)	Gas (b)	Electric Transmission (c)	Other Electric (d)	Total (e)
1	Fuel Stock (Account 151)	-	-	2,255,915	2,255,915
2	Fuel Stock Expense Undistributed (Account 152)				-
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	12,069,161.00	14,610,553.00	53,960,964.00	80,640,678
6	Assigned to - Operatons and Maintenance
7	Production Plant (Estimated)	4,823	-	404,171	408,994
8	Transmission Plant (Estimated)	185,157	623,053.00	-	808,210
9	Distribution Plant (Estimated)	324,699	-	1,896,943	2,221,642
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other
12	TOTAL Account 154 (Enter Total of lines 5 thru 10)	12,583,840	15,233,606	56,262,078	84,079,524
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)
15	Nuclear Materials Held for Sale (Account 157)
16	Store Expense Undistributed (Account 163)
17
18
19
20	TOTAL Materials and Supplies (Per Balance Sheet)	12,583,840	15,233,606	58,517,993	86,335,439

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	0	0
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	1,111,760.75	3,271,951
5	Returned by authoritative agency
6
7
8
9
10
11
12
13
14
15	Total	1,111,760.75	3,271,951
16
17	Relinquished During Year:
18	Charges to Account 509, 555.2, and 555.3	1,111,760.75	3,271,951
19	Other:
20	Allowances Used
21	Cost of Sales/Transfers:
22
23
24
25
26
27
28	Total
29	Balance-End of Year	0	0
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)
34	Gains
35	Losses
	Allowances Withheld (Acct 158.2)
36	Balance-Beginning of Year
37	Add: Withheld by authoritative agency
38	Deduct: Returned by authoritative agency
39	Cost of Sales
40	Balance-End of Year
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	FAC Studies	27,337	253	145,000	253
3	SIS Studies	307,108	253	488,787	253
4	Line Interconnection Studies	106,318	253	0	253
20	Total	440,763		633,787
21	Generation Studies
22	FAC Studies	93,480	253	20,349	253
23	FEA Studies	6,478	253	6,192	253
24	Optional Studies	20,045	253	17,596	253
25	SIS Studies	286	253	42,067	253
26	Large Load Studies	48,882	253	506,000	253
39	Total	169,171		508,070
40	Grand Total	609,934		1,141,857

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Flow-through Income Taxes (Montana)	522,015,167	35,957,368		813,355	557,159,180
2	Excess Deferred Income Taxes (Montana)	39,040,398	68,255		3,118,549	(a) 35,990,104
3	Basin Creek Capital Lease (Montana)	2,445,764	0		1,585,794	859,970
4	BPA Residential Exchange Program (Montana) - Docket 2018.8.49 Order 7630; Annual Amortization	1,143,941	525,047		941,466	727,522
5	Property Tax Tracker (Montana) - Docket 2017.11.86 - Order 7580a; Annual Amortization	6,366,553	21,854,212		9,486,780	18,733,985
6	FAS 106 (Montana) - Docket 93.6.24 and Docket 2009.9.129	2,973,383	7,274,499		10,114,796	133,086
7	FAS 112 (Montana) - Docket 93.6.24 and Docket 2009.9.129	2,927,375	547,955		0	3,475,330
8	Compensated Absences (Montana) - Docket 97.11.219	11,976,514	1,364,496		401,866	12,939,144
9	Pension Plan - MT	56,719,333	0		35,303,516	21,415,817
10	Montana Consumer Counsel Tax (Montana) - Docket 2018.10.67 - Order 7637	30,818	114,607		98,303	47,122
11	Montana Public Service Commission (Montana) - Docket 2017.9.78 - Order 7568	2,465,528	1,693,355		2,720,503	1,438,380
12	Montana Wildfire Mitigation	17,367,539	13,133,437		1,067,710	29,433,266
13	Asset Retirement Obligation (Montana)	11,397,051	1,982,003		677,632	12,701,422
14	Power Cost & Credit Adjustment Mechanism	0	67,147,626		27,250,637	39,896,989
15	Land Rents	0	3,859,000		0	3,859,000
44	TOTAL	676,869,364	155,521,860		93,580,907	738,810,317

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: OtherRegulatoryAssets

Line No.	Description (a)	(b)	(c)	(d)

	MONTANA:
		12/31/2024
		Protected	Unprotected
	TCJA Excess ADIT Account Reduced	190	190	Subtotal
	Reg Asset Acccount Impacted	182.3	182.3	182.3
1	Electric:
2	Regulatory Assets / Liabilities		-	-
3	Unbilled Revenue		-	-
4	Compensation Accruals		-	-
5	Reserves & Accruals		-	-
6	Intangible amortization		-	-
7	Pension / Postretirement Benefits		-	-
8	Environmental Liability		-	-
9	Interest Rate Hedge		-	-
10	Customer Advances		-	-
11	Excess Tax Depreciation / Other Property			-
12	Net Operating Loss	24,175,218	-	24,175,218
13	Total Electric	24,175,218	-	24,175,218
14	Gas:
15	Regulatory Assets / Liabilities		(17,949)	(17,949)
16	Unbilled Revenue		374,160	374,160
17	Compensation Accruals		409,088	409,088
18	Reserves & Accruals		81,336	81,336
19	Intangible amortization		-	-
20	Pension / Postretirement Benefits		2,683,902	2,683,902
21	Environmental Liability		143,989	143,989
22	Interest Rate Hedge		-	-
23	Customer Advances		884,843	884,843
24	Excess Tax Depreciation / Other Property			-
25	Net Operating Loss	-	-	-
26	Total Gas	-	4,559,369	4,559,369
27	Other (Specify)	-	25,499	25,499
28	Subtotal	24,175,218	4,584,868	28,760,086
29	Gross-up	8,641,448	1,638,864	10,280,312
30	Total	32,816,666	6,223,732	39,040,398
31
32	Other (Specify)
33	QF Obligations	-	-	-
34	NOL Carryforward	-	-	-
35	AMT Credit Carryforward	-	-	-
36	Production Tax Credit	-	-	-
37	Regulatory Assets / Liabilities	-	-	-
38	Other, net	-	25,499	25,499
39	Total	-	25,499	25,499
40
41
42		12/31/2025
43		Protected	Unprotected
44	TCJA Excess ADIT Account Reduced	190	190	Subtotal
45	Reg Asset Acccount Impacted	182.3	182.3	182.3
46	Electric:
47	Regulatory Assets / Liabilities		-	-
48	Unbilled Revenue		-	-
49	Compensation Accruals		-	-
50	Reserves & Accruals		-	-
51	Intangible amortization		-	-
52	Pension / Postretirement Benefits		-	-
53	Environmental Liability		-	-
54	Interest Rate Hedge		-	-
55	Customer Advances		-	-
56	Excess Tax Depreciation / Other Property			-
57	Net Operating Loss	23,253,596	-	23,253,596
58	Total Electric	23,253,596	-	23,253,596
59	Gas:
60	Regulatory Assets / Liabilities		(12,821)	(12,821)
61	Unbilled Revenue		267,257	267,257
62	Compensation Accruals		292,206	292,206
63	Reserves & Accruals		58,098	58,098
64	Intangible amortization		-	-
65	Pension / Postretirement Benefits		1,917,073	1,917,073
66	Environmental Liability		102,849	102,849
67	Interest Rate Hedge		-	-
68	Customer Advances		632,031	632,031
69	Excess Tax Depreciation / Other Property			-
70	Net Operating Loss	-	-	-
71	Total Gas	-	3,256,693	3,256,693
72	Other (Specify)	-	2,721	2,721
73	Subtotal	23,253,596	3,259,414	26,513,010
74	Gross-up	8,312,014	1,165,080	9,477,094
75	Total	31,565,610	4,424,494	35,990,104
76
77	Other (Specify)
78	QF Obligations	-	-	-
79	NOL Carryforward	-	-	-
80	AMT Credit Carryforward	-	-	-
81	Production Tax Credit	-	-	-
82	Regulatory Assets / Liabilities	-	-	-
83	Other, net	-	2,721	2,721
84	Total	-	2,721	2,721

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Energy Stored in Out of State Utilities (Montana)	44	42,808	555	29,152	13,700
2	500 kV Operations - Partner's Share (Montana)	149,231		131		149,231
3	PPLM Share of WET Tax (Montana)	1,886	41,144	131	42,237	793
4	Unamortized Debt Expense (Montana)	1,077,780		930.2	336,659	741,121
47	Miscellaneous Work in Progress
48	Deferred Regulatory Comm. Expenses (See pages 350 - 351)
49	TOTAL	930,479				606,384

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Regulatory Asset/Liability	456,122	416,043
3	Unbilled Revenue	2,210,303	4,336,421
4	Compensation Accruals	7,112,215	7,308,679
5	Reserves & Accruals	1,894,237	1,008,890
6	Pension / Postretirement Benefits	7,405,206	642,805
7	Other	(a) 90,728,182	89,076,700
8	TOTAL Electric (Enter Total of lines 2 thru 7)	109,806,265	101,503,928
9	Gas
10	Regulatory Asset/Liability	177,787	160,366
11	Unbilled Revenue	915,938	1,711,349
12	Compensation Accruals	2,744,498	2,817,163
13	Reserves & Accruals	169,263	192,062
14	Pension / Postretirement Benefits	2,963,577	13,085
15	Other	(b) 36,819,931	37,133,298
16	TOTAL Gas (Enter Total of lines 10 thru 15)	43,790,994	42,001,153
17	Other (Specify)	(c) 40,416,632	42,562,432
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	194,013,891	186,067,513

Notes

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxes

Schedule Page: 234 Line No.:7 Column: b and c
	Balance at Beginning of Year	Balance at End of Year
	(b)	( c)
Environmental Liability	1,532,474	1,506,610
Interest Rate Hedge	3,205,349	3,043,735
Customer Advances	25,596,315	29,177,777
NOL Carryforward	60,394,044	55,348,578
	90,728,182	89,076,700

(b) Concept: AccumulatedDeferredIncomeTaxes

Schedule Page: 234 Line No.: 15 Column: b and c
	Balance at Beginning of Year	Balance at End of Year
	(b)	( c)
Environmental Liability	598,740	589,173
Interest Rate Hedge	-	-
Customer Advances	6,858,243	7,181,177
NOL Carryforward	29,362,948	29,362,948
	36,819,931	37,133,298

Account 190 Other (Specify)	Balance at Beginning of Year	Balance at End of Year
NOL Carryforward	59,264	59,264
Production Tax Credit	35,601,979	36,574,998
Other, net	4,755,389	5,928,170
Total	40,416,632	42,562,432

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Common Stock	200,000,000	0.01		100	1	0
9	Total	200,000,000			100	1
10	Preferred Stock (Account 204)
11	Preferred Stock - None Issued	50,000,000	0.01		0	0
17	Total	50,000,000			0	0

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2025-12-31

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	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	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	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	2,044,999,693
15.1	IncreasesDecreasesDueToMiscellaneousPaidInCapital Stock Compensation	5,822,175
15	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital	5,822,175
16	MiscellaneousPaidInCapital Ending Balance Amount	2,050,821,868
17	OtherPaidInCapitalAbstract Other Paid in Capital
18	OtherPaidInCapitalDetail Beginning Balance Amount
19	IncreasesDecreasesInOtherPaidInCapital Increases (Decreases) in Other Paid-In Capital
20	OtherPaidInCapitalDetail Ending Balance Amount
40	OtherPaidInCapital Total	2,050,821,868

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22	TOTAL

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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 5.71% (Montana)		(a) 55,000,000		549,881			10/15/2009	10/15/2039	10/15/2009	10/15/2039	55,000,000	3,140,500
3	First Mortgage Bonds 5.010% (Montana)		161,000,000		909,702	4,730,180		05/27/2010	05/01/2025	05/27/2010	05/01/2025	0	2,240,583
4	First Mortgage Bonds 4.15% (Montana)		60,000,000		376,671			08/10/2012	08/10/2042	08/10/2012	08/10/2042	60,000,000	2,490,000
5	First Mortgage Bonds 4.30% (Montana)		40,000,000		251,114			08/10/2012	08/10/2052	08/10/2012	08/10/2052	40,000,000	1,720,000
6	First Mortgage Bonds 4.85% (Montana)		15,000,000		70,047			12/19/2013	12/19/2043	12/19/2013	12/19/2043	15,000,000	727,500
7	First Mortgage Bonds 3.99% (Montana)		35,000,000		163,444			12/19/2013	12/19/2028	12/19/2013	12/19/2028	35,000,000	1,396,500
8	First Mortgage Bonds 4.176% (Montana)		450,000,000		4,927,101			11/14/2014	11/15/2044	11/14/2014	11/15/2044	450,000,000	18,792,000
9	First Mortgage Bonds 3.11% (Montana)		75,000,000		4,137,235			06/23/2015	07/01/2025	07/01/2015	07/01/2025	0	1,166,250
10	First Mortgage Bonds 4.11% (Montana)		125,000,000		6,895,391			06/23/2015	07/01/2045	07/01/2015	07/01/2045	125,000,000	5,137,500
11	First Mortgage Bonds 4.03% (Montana)		250,000,000		17,138,156			11/06/2017	11/06/2047	11/06/2017	11/06/2047	250,000,000	10,075,000
12	First Mortgage Bonds 3.98% (Montana) A		50,000,000		322,669			06/26/2019	06/26/2049	06/26/2019	06/26/2049	50,000,000	1,990,000
13	First Mortgage Bonds 3.98% (Montana) B		100,000,000		645,339			09/17/2019	09/17/2049	09/17/2019	09/17/2049	100,000,000	3,980,000
14	First Mortgage Bonds 3.21% (Montana)		100,000,000		422,199			05/15/2020	05/15/2030	05/15/2020	05/15/2030	100,000,000	3,210,000
15	First Mortgage Bonds 5.57% (Montana)		239,000,000		1,158,989			03/30/2023	03/30/2033	03/30/2023	03/30/2033	239,000,000	13,312,300
16	First Mortgage Bonds 5.56% (Montana)		175,000,000		792,992			05/28/2024	03/28/2031	05/28/2024	03/28/2031	175,000,000	9,730,000
17	First Mortgage Bonds 5.073% (Montana) A		400,000,000		3,195,112			03/21/2025	03/21/2030	03/21/2025	03/21/2030	400,000,000	15,782,667
18	First Mortgage Bonds 5.073% (Montana) B		100,000,000		747,608	2,077,000		11/07/2025	03/21/2030	11/07/2025	03/20/2030	100,000,000	732,767
19	Pollution Control Revenue Bonds - 3.88% Series, City of Forsyth (Montana)		144,660,000		1,555,503			05/18/2022	05/18/2027	05/18/2022		144,660,000	5,605,575
20	Subtotal		2,574,660,000		44,259,153	2,653,180						2,338,660,000	101,229,142
21	Reacquired Bonds (Account 222)
22
23
24
25	Subtotal
26	Advances from Associated Companies (Account 223)
27
28
29
30	Subtotal
31	Other Long Term Debt (Account 224)
32	Senior Unsecured Revolving Line of Credit ($425m)		362,000,000					11/29/2023	11/29/2028	11/29/2023	11/29/2028	362,000,000	14,490,934
33	Interest Rate Hedge Amortizations												613,744
34	Subtotal		362,000,000									362,000,000	15,104,678
33	TOTAL		2,936,660,000									2,700,660,000	116,333,820

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: BondsPrincipalAmountIssued

As issuances are redeemed, the related expense and premium or discount, as applicable, is charged to Loss on Reacquired Debt.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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)	154,951,659
2	Reconciling Items for the Year
3
4	Taxable Income Not Reported on Books
5	Equity Earnings of Subsidiaries	2,167,328
9	Deductions Recorded on Books Not Deducted for Return
10	Meals and Entertainment	898,943
11	Non-Deductible Dues/Lobbying Expense/Penalties/Professional Fees/Non-Deductible Parking/GILTI Inclusion	2,890,228
12	Federal Income Taxes	5,064,786
13	State Tax Adjustment	10,678,103
14	Income Recorded on Books Not Included in Return
15
16
17
18
19	Deductions on Return Not Charged Against Book Income
20	Net Tax Greater Than Book Depreciation	35,026,359
21	Amortization of Intangibles	569,053
22	Plant Flow Through Items	72,158,361
23	Reserves & Accruals	87,707,241
24	Deferred Book Revenue & Gains	21,557,184
25	Contributions & Advances for Construction	21,749,196
26	NOL Carryforward	15,468,386
27	Other Miscellaneous	1,911,421
27	Federal Tax Net Income	10,939,448
28	Show Computation of Tax:
29	Federal tax Expense/(Benefit) @ 21%	2,297,284

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	FICA and Medicare	Federal Tax	Montana	2025	0		11,396,504	11,396,504		0		5,992,478			5,404,026
2	State Income Tax	State Tax	Montana	2025	45,877		532,768		(a) 81,476	568,367		3,324,561			2,791,793
3	City License Tax	State Tax	Montana	2025	0		1,200	1,200		0		1,025			175
4	Hydro Invasive Species Tax	Other Taxes	Montana	2024	184,616			184,616		0		0			0
5	Hydro Invasive Species Tax	Other Taxes	Montana	2025	0		743,240	557,430		185,810		743,240			0
6	Heavy Highway Tax	Other Taxes	Montana	2025	0		21,210	21,210		0		14,638			6,572
7	WET Tax	Other Taxes	Montana	2024	432,677			432,677		0		0			0
8	WET Tax	Other Taxes	Montana	2025	0		1,705,943	1,281,488		424,455		1,461,651			244,292
9	EELT Tax	Other Taxes	Montana	2024	231,333			231,333		0		0			0
10	EELT Tax	Other Taxes	Montana	2025	0		920,645	691,303		229,342		920,651			6
11	Consumer Counsel	Other Taxes	Montana	2024	122,035			122,035		0		0			0
12	Consumer Counsel	Other Taxes	Montana	2025	0		493,493	414,304		79,189		421,208			72,285
13	Montana Public Service Commission	Other Taxes	Montana	2024	671,987			671,987		0		0			0
14	Montana Public Service Commission	Other Taxes	Montana	2025	0		2,888,025	2,281,304		606,721		2,597,923			290,102
15	Property Tax	Property Tax	Montana	2024	74,804,269			74,804,269		0		0			0
16	Property Tax	Property Tax	Montana	2025	0		165,019,370	82,540,074		82,479,296		128,915,042			36,104,328
17	Property Tax - Crow Tribe	Property Tax	Montana	2025	0		209,784	209,784		0		74,880			134,904
18	Property Tax - Blackfoot	Property Tax	Montana	2025	0		757,600	757,600		0		0			757,600
19	Federal Unemplyment Tax	Unemployment Tax	Montana	2024	1,167			1,167		0		0			0
20	Federal Unemplyment Tax	Unemployment Tax	Montana	2025	0		63,575	62,412		1,163		18,222			45,353
21	State Unemployment Tax	Unemployment Tax	Montana	2024	20,732			20,732		0		0			0
22	State Unemployment Tax	Unemployment Tax	Montana	2025	0		510,217	485,712		24,505		156,537			353,680
23	Use Tax	Sales And Use Tax	Wyoming	2024	0			0		0		0			0
24	Use Tax	Sales And Use Tax	Wyoming	2025	0		6,221	6,221		0		0			6,221
25	Use Tax	Sales And Use Tax	South Dakota	2024	7,258			7,258		0		0			0
26	Use Tax	Sales And Use Tax	South Dakota	2025	0		225,545	156,170		69,375		0			225,545
27	Federal Income Tax	Income Tax	Montana	2024	427,271		2,191,822	0	(b) 1,042,880	1,576,213		5,569,221			7,761,043
28	Delaware Franchise Tax	Franchise Tax	Montana	2025	0		320,370	320,370		0		236,877			83,493
29	Electric Vehicle Charging Station Tax		Montana	2025	11,817		118,282	91,986		38,113		0			118,282
40	TOTAL				76,961,039		187,060,278	177,751,146	1,124,356	(c) 85,145,815		(d) 132,660,590			54,399,688

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: TaxAdjustments

Re-classification between State and Federal Income Taxes

(b) Concept: TaxAdjustments

Uncertain Tax Position write off, partly offset by reclassification between Federal and State Income Taxes.

Montana Operations unfunded reserves for Taxes Accrued (236) are $82,479,295 and $ 74,804,269 for 2025 and 2024, respectively.

(d) Concept: TaxesAccruedPrepaidAndCharged

Montana Electric - taxes accrued, exclusive of federal and state income taxes	Taxes Charged During the Year 2025
(b)	(c)
Payroll Tax - FICA	4,734,283
Payroll Tax - Medicare	1,258,195
Payroll Tax - FUT	18,222
Highway Vehicle Use Tax - MT	14,638
Payroll Tax - SUT - MT	156,537
Real & Personal Property - Transmission	34,656,864
Real & Personal Property - Production	27,269,258
Real & Personal Property - Distribution	67,063,800
City License Tax - MT	1,025
WET - Montana	1,461,651
EELT - Montana	920,651
EEL Tax 2018	743,240
Cons Council Tax - MT	421,208
MPSC - Montana	2,597,923
Delaware Franchise	236,877
	141,554,372

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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
8	TOTAL Electric (Enter Total of lines 2 thru 7)
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10	Other - 30%	2,229,208		101,129		129,482	1,174,098	3,374,953	5 Years
47	OTHER TOTAL
48	GRAND TOTAL	2,229,208		101,129		129,482	1,174,098	3,374,953

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Pension Plan Requirement (Montana)	52,088,122	Various	89,944,869	37,856,747	(a) 0
2	Projects & Studies Prepaid by Customers (Montana)	16,523,372		44,386,241	46,485,553	18,622,684
3	Deferred Compensation (Montana)	13,261,785		5,629,615	5,397,773	13,029,943
4	Permanent Uncertain Tax Positions (Montana)	1,270,377		5,013,640	3,743,263	0
5	Other Minor Items (7) - some are amortized over various periods (Montana)	10,436,005		1,395,663	4,934,086	13,974,428
47	TOTAL	93,579,661		146,370,028	98,417,422	45,627,055

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: OtherDeferredCredits

Pension Plan Requirement balance of $15,284,606 as of December 31, 2025 was reclassified to Accumulated Provision for Pensions and Benefits (228.3).

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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)

Accelerated Amortization (Account 281)

Electric

Defense Facilities

Pollution Control Facilities

Other

5.1

Other

5.2

Other

TOTAL Electric (Enter Total of lines 3 thru 7)

Gas

Defense Facilities

Pollution Control Facilities

Other

12.1

Other

12.2

Other

TOTAL Gas (Enter Total of lines 10 thru 14)

Other

16.1

Other

16.2

Other

TOTAL (Acct 281) (Total of 8, 15 and 16)

Classification of TOTAL

Federal Income Tax

State Income Tax

Local Income Tax

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	504,911,925	22,445,990								527,357,915
3	Gas	114,021,805	4,218,432								118,240,237
4	Other (Specify)	17,754,631		200,589							17,955,221
5	Total (Total of lines 2 thru 4)	601,179,098	26,664,422	200,589							627,642,931
6
7
8
9	TOTAL Account 282 (Total of Lines 5 thru 8)	601,179,098	26,664,422	200,589							627,642,931
10	Classification of TOTAL
11	Federal Income Tax	447,074,517	19,829,338	149,171							466,754,684
12	State Income Tax	154,104,581	6,835,084	51,418							160,888,247
13	Local Income Tax

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	17,584,543	10,258,687								27,843,230
4	Excess Tax Depreciation	92,739,058			8,483,068						101,222,126
9	TOTAL Electric (Total of lines 3 thru 8)	110,323,601	10,258,687		8,483,068						129,065,356
10	Gas
11	Regulatory Assets	6,067,753		2,305,752							3,762,001
12	Excess Tax Depreciation	26,576,827			1,931,083						28,507,910
17	TOTAL Gas (Total of lines 11 thru 16)	32,644,580		2,305,752	1,931,083						32,269,911
18	TOTAL Other	92,925,102			149,846	541,928					(a) 92,533,020
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	235,893,283	10,258,687	2,305,752	10,563,997	541,928					253,868,287
20	Classification of TOTAL
21	Federal Income Tax	175,425,053	7,629,004	1,714,702	7,856,051	403,011					188,792,395
22	State Income Tax	60,468,230	2,629,683	591,050	2,707,946	138,917					65,075,892
23	Local Income Tax
NOTES

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOther

CHANGES DURING YEAR						ADJUSTMENTS
Account	Balance at Beginning of Year	Amounts Debited to Account 410.1	Amounts Credited to Account 411.1	Amounts Debited to Account 410.2	Amounts Credited to Account 411.2	Account Credited	Amount	Account Debited	Amount	Balance at End of Year
	(b)	(c )	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)
Line 249 Detail - Other

Other, Net	1,065,736	-	-	-	541,928		-		-	523,808
Intangible Amortization	91,859,366	-	-	149,846	-		-		-	92,009,212

Total	92,925,102	-	-	149,846	541,928		-		-	92,533,020

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Excess Deferred Income Taxes (Montana)	108,153,744		6,665,955	57,019	(a) 101,544,808
2	Deferred Gas Storage Sales (Montana) - Docket D2001.1.1; Amortization 2001 - 2039	6,204,912		420,516	0	5,784,396
3	Montana Public Service Commission Consumer Counsel Taxes (Montana) - Dockets 2017.9.78 and 2018.10.67	0		1,684,664	1,684,664	0
4	CTC QF Over/Under Collections (Montana) - Docket 97.9.90 and Docket 2001.1.15; Annual Amortization	1,102,462		613,612	815,345	1,304,195
5	Property Tax Tracker (Montana) - Docket 2017.11.86 - Order 7580a; Annual Amortization	0		6,951,354	6,951,354	0
6	Natural Gas Regulatory Deferrals (Montana)	46,463		247,891	808,367	606,939
7	Power Cost & Credit Mechanism (Montana)	4,214,265		4,214,265	0	0
8	Environmental Credit Liability	0		1,653,720	1,653,720	0
9	FAS 106 (Montana) - Docket 93.6.24 and Docket 2009.9.129	0		0	797,344	797,344
10	Deferred Electric Revenues	0		0	7,660,169	7,660,169
41	TOTAL	119,721,846		22,451,977	20,427,982	117,697,851

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: OtherRegulatoryLiabilities

Line No.	Description (a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)

	MONTANA:
		12/31/2024
		Protected	Unprotected	Unprotected			Normalizing EDIT
	TCJA Excess ADIT Account Reduced	282	282	283	Subtotal	Total of 182.3	Subtotal	282
	Reg Asset Acccount Impacted	254	254	254	254	and 254	182.3	254
1	Electric:
2	Regulatory Assets / Liabilities			-	-	-	-	-
3	Unbilled Revenue			-	-	-	-	-
4	Compensation Accruals			-	-	-	-	-
5	Reserves & Accruals			-	-	-	-	-
6	Intangible amortization			-	-	-	-	-
7	Pension / Postretirement Benefits			-	-	-	-	-
8	Environmental Liability			-	-	-	-	-
9	Interest Rate Hedge			-	-	-	-	-
10	Customer Advances			-	-	-	-	-
11	Excess Tax Depreciation / Other Property	(62,371,363)	-	-	(62,371,363)	(62,371,363)	-	(62,371,363)
12	Net Operating Loss				-	24,175,218	-	24,175,218
13	Total Electric	(62,371,363)	-	-	(62,371,363)	(38,196,145)	-	(38,196,145)
14	Gas:
15	Regulatory Assets / Liabilities			(1,479,087)	(1,479,087)	(1,497,036)	-	(1,497,036)
16	Unbilled Revenue			-	-	374,160	-	374,160
17	Compensation Accruals			-	-	409,088	-	409,088
18	Reserves & Accruals			-	-	81,336	-	81,336
19	Intangible amortization			(2,173,541)	(2,173,541)	(2,173,541)	-	(2,173,541)
20	Pension / Postretirement Benefits			-	-	2,683,902	-	2,683,902
21	Environmental Liability			-	-	143,989	-	143,989
22	Interest Rate Hedge			-	-	-	-	-
23	Customer Advances			-	-	884,843	-	884,843
24	Excess Tax Depreciation / Other Property	(9,357,104)	(3,993,562)	-	(13,350,666)	(13,350,666)	-	(13,350,666)
25	Net Operating Loss				-	-	-	-
26	Total Gas	(9,357,104)	(3,993,562)	(3,652,628)	(17,003,294)	(12,443,925)	-	(12,443,925)
27	Other (Specify)	(277,812)	-	(21,690)	(299,502)	(274,003)	64,702	(209,301)
28	Subtotal	(72,006,279)	(3,993,562)	(3,674,318)	(79,674,159)	(50,914,073)	64,702	(50,849,371)
29	Gross-up	(25,738,695)	(1,427,502)	(1,313,388)	(28,479,585)	(18,199,272)	23,127	(18,176,145)
30	Total	(97,744,974)	(5,421,064)	(4,987,706)	(108,153,744)	(69,113,345)	87,829	(69,025,516)
31
32	Other (Specify)
33	QF Obligations	-		-	-	-	-	-
34	NOL Carryforward	-		-	-	-	-	-
35	AMT Credit Carryforward	-		-	-	-	-	-
36	Production Tax Credit	-		-	-	-	-	-
37	Regulatory Assets / Liabilities	-		-	-	-	-	-
38	Other, net	(277,812)		(21,690)	(299,502)	(274,003)	64,702	(209,301)
39	Total	(277,812)	-	(21,690)	(299,502)	(274,003)	64,702	(209,301)
40
41
42		12/31/2025
43		Protected	Unprotected	Unprotected			Normalizing EDIT
44	TCJA Excess ADIT Account Reduced	282	282	283	Subtotal	Total of 182.3	Subtotal	282
45	Reg Asset Acccount Impacted	254	254	254	254	and 254	182.3	254
46	Electric:
47	Regulatory Assets / Liabilities			-	-	-	-	-
48	Unbilled Revenue			-	-	-	-	-
49	Compensation Accruals			-	-	-	-	-
50	Reserves & Accruals			-	-	-	-	-
51	Intangible amortization			-	-	-	-	-
52	Pension / Postretirement Benefits			-	-	-	-	-
53	Environmental Liability			-	-	-	-	-
54	Interest Rate Hedge			-	-	-	-	-
55	Customer Advances			-	-	-	-	-
56	Excess Tax Depreciation / Other Property	(59,502,259)	-	-	(59,502,259)	(59,502,259)	-	(59,502,259)
57	Net Operating Loss				-	23,253,596	-	23,253,596
58	Total Electric	(59,502,259)	-	-	(59,502,259)	(36,248,663)	-	(36,248,663)
59	Gas:
60	Regulatory Assets / Liabilities			(1,056,490)	(1,056,490)	(1,069,311)	-	(1,069,311)
61	Unbilled Revenue			-	-	267,257	-	267,257
62	Compensation Accruals			-	-	292,206	-	292,206
63	Reserves & Accruals			-	-	58,098	-	58,098
64	Intangible amortization			(1,552,529)	(1,552,529)	(1,552,529)	-	(1,552,529)
65	Pension / Postretirement Benefits			-	-	1,917,073	-	1,917,073
66	Environmental Liability			-	-	102,849	-	102,849
67	Interest Rate Hedge			-	-	-	-	-
68	Customer Advances			-	-	632,031	-	632,031
69	Excess Tax Depreciation / Other Property	(8,518,856)	(3,845,653)	-	(12,364,509)	(12,364,509)	-	(12,364,509)
70	Net Operating Loss				-	-	-	-
71	Total Gas	(8,518,856)	(3,845,653)	(2,609,019)	(14,973,528)	(11,716,835)	-	(11,716,835)
72	Other (Specify)	(329,736)	-	-	(329,736)	(327,015)	46,215	(280,800)
73	Subtotal	(68,350,851)	(3,845,653)	(2,609,019)	(74,805,523)	(48,292,513)	46,215	(48,246,298)
74	Gross-up	(24,432,060)	(1,374,630)	(932,595)	(26,739,285)	(17,262,191)	16,520	(17,245,671)
75	Total	(92,782,911)	(5,220,283)	(3,541,614)	(101,544,808)	(65,554,704)	62,735	(65,491,969)
76
77	Other (Specify)
78	QF Obligations	-	-	-	-	-	-	-
79	NOL Carryforward	-	-	-	-	-	-	-
80	AMT Credit Carryforward	-	-	-	-	-	-	-
81	Production Tax Credit	-	-	-	-	-	-	-
82	Regulatory Assets / Liabilities	-	-	-	-	-	-	-
83	Other, net	(329,736)	-	-	(329,736)	(327,015)	46,215	(280,800)
84	Total	(329,736)		-	(329,736)	(327,015)	46,215	(280,800)

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	410,579,617	398,789,874	2,833,866	2,803,096	334,010	328,419
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	425,785,644	422,770,099	3,225,871	3,182,280	79,670	78,071
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	43,376,433	46,637,461	307,580	322,200	80	80
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	16,027,222	14,857,439	25,155	25,479	25,434	3,584
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales	914,785	886,039	6,735	6,653	347	347
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	896,683,700	883,940,912	6,399,207	6,339,707	439,541	410,501
11	SalesForResaleAbstract (447) Sales for Resale	29,691,269	36,084,608	854,892	1,016,891
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	926,374,969	920,025,520	7,254,099	7,356,598	439,541	410,501
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds	7,351,853
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	919,023,116	920,025,520	7,254,099	7,356,598	439,541	410,501
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	88,411	93,984
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	3,768,142	4,255,667
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(a) 12,400,403	12,080,582
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	105,700,939	91,024,954
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	121,957,895	107,455,187
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	1,040,981,011	1,027,480,707
Line12, column (b) includes $ of unbilled revenues.
Line12, column (d) includes MWH relating to unbilled revenues

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: OtherElectricRevenue

YTD Dec	YTD Dec	YTD Dec
Total Electric Revenue	2025	2024
Ancillary Services:
Scheduling, System Control and Dispatch	1,925,781	1,915,646
Regulation and Frequency Response	1,107,982	1,208,931
Energy Imbalance	6,174,611	6,189,023
Other Transmission Revenue	72,886	(150,019)
Low Income Housing	2,504,848	2,826,777
Steam Sales	-	-
Sale of Materials	7,505	15,859
Miscellaneous	606,790	74,365
	12,400,403	12,080,582

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Residential	2,649,699	383,941,751	334,010	8,484	0.1449
41	TOTAL Billed Residential Sales	2,649,699	383,941,751	334,010	8,484	0.1449
42	TOTAL Unbilled Rev. (See Instr. 6)	184,167	26,637,866
43	TOTAL	2,833,866	410,579,617	334,010	8,484	0.1449

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	General Service - 1	2,930,410	389,341,477	77,305	40,426	0.1317
2	Irrigation	100,697	14,059,950	2,364	42,588	0.1396
41	TOTAL Billed Small or Commercial	3,031,107	403,401,427	79,670	40,491	0.132
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)	194,764	22,384,217
43	TOTAL Small or Commercial	3,225,871	425,785,644	79,670	40,491	0.132

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	General Service - 2	279,113	40,295,965	80	3,824,827	0.141
41	TOTAL Billed Large (or Ind.) Sales	279,113	40,295,965	80	3,824,827	0.141
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)	28,467	3,080,468
43	TOTAL Large (or Ind.)	307,580	43,376,433	80	3,824,827	0.141

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Lighting	25,155	16,027,222	25,434	989	0.6371
41	TOTAL Billed Public Street and Highway Lighting	25,155	16,027,222	25,434	989	0.6371
42	TOTAL Unbilled Rev. (See Instr. 6)	0	0
43	TOTAL	25,155	16,027,222	25,434	989	0.6371

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Interdepartmental	6,735	914,785	347	19,419	0.1358
41	TOTAL Billed Interdepartmental Sales	6,735	914,785	347	19,419	0.1358
42	TOTAL Unbilled Rev. (See Instr. 6)	0	0
43	TOTAL	6,735	914,785	347	19,419	0.1358

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Provision for Rate Refunds		7,351,853
41	TOTAL Billed Provision For Rate Refunds		7,351,853
42	TOTAL Unbilled Rev. (See Instr. 6)		0
43	TOTAL		7,351,853

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	5,991,809	844,581,149	439,541	14,559	0.1401
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts	407,398	52,102,551
43	TOTAL - All Accounts	6,399,207	896,683,700	439,541	14,559	0.1401

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	AVISTA CORPORATION	LF	Reserve Energy Services	0	0	0	14	0	604	0	604
2	BC HYDRO DISTRIBUTION	LF	Reserve Energy Services	0	0	0	13	0	514	0	514
3	BONNEVILLE POWER ADMINISTRATION	LF	Reserve Energy Services	0	0	0	22	0	1,014	0	1,014
4	GRID FORCE ENERGY MANAGEMENT, LLC	LF	Reserve Energy Services	0	0	0	211	0	9,435	0	9,435
5	GRANT COUNTY PUD	LF	Reserve Energy Services	0	0	0	3	0	120	0	120
6	PACIFICORP	LF	Reserve Energy Services	0	0	0	172	0	7,431	0	7,431
7	PORTLAND GENERAL ELECTRIC COMPANY	LF	Reserve Energy Services	0	0	0	42	0	2,044	0	2,044
8	BHE GLACIER WIND	LF	Reserve Energy Services	0	0	0	5	0	287	0	287
9	BHE WIND WATCH	LF	Reserve Energy Services	0	0	0	4	0	149	0	149
10	TALEN MONTANA, LLC	LF	Reserve Energy Services	0	0	0	62	0	1,704	0	1,704
11	IDAHO POWER COMPANY	LF	Reserve Energy Services	0	0	0	30	0	1,062	0	1,062
12	PUGET SOUND ENERGY, INC	LF	Reserve Energy Services	0	0	0	7	0	270	0	270
13	SACRAMENTO MUNICIPAL UTILITY DISTRICT	LF	Reserve Energy Services	0	0	0	5	0	269	0	269
14	CHELAN COUNTY PUD	LF	Reserve Energy Services	0	0	0	3	0	64	0	64
15	SEATTLE CITY LIGHT	LF	Reserve Energy Services	0	0	0	8	0	288	0	288
16	AVANGRID	LF	Reserve Energy Services	0	0	0	9	0	343	0	343
17	Avista Corporation	SF	Market-Based Rate Tariff				23,861	0	587,297	0	587,297
18	AlbertaEx L.P.	SF	Market-Based Rate Tariff				2,156	0	76,115	0	76,115
19	Altop Energy Trading LLC	SF	Market-Based Rate Tariff				16,869	0	668,611	0	668,611
20	Basin Electric Power Cooperative	SF	Market-Based Rate Tariff				1,257	0	56,870	0	56,870
21	Black Hills Power Inc	SF	Market-Based Rate Tariff				2,903	0	122,088	0	122,088
22	Bonneville Power Administration	SF	Market-Based Rate Tariff				141,991	0	4,505,866	0	4,505,866
23	Big Horn County Electric Cooperative Inc	SF	Market-Based Rate Tariff				22,943	0	1,466,117	0	1,466,117
24	Clatskanie Peoples Utility District - Electric	SF	Market-Based Rate Tariff				3,535	0	140,912	0	140,912
25	ConocoPhillips Company	SF	Market-Based Rate Tariff				5,225	0	216,431	0	216,431
26	Shell Energy North America (US), L.P.	SF	Market-Based Rate Tariff				58,295	0	1,799,162	0	1,799,162
27	Dynasty Power Inc.	SF	Market-Based Rate Tariff				16,068	0	668,635	0	668,635
28	EDF Trading North America, LLC	SF	Market-Based Rate Tariff				37,012	0	1,494,233	0	1,494,233
29	Energy Keepers Inc.	SF	Market-Based Rate Tariff				53,654	0	1,599,140	0	1,599,140
30	Eugene Water & Electric Board	SF	Market-Based Rate Tariff				15,968	0	655,949	0	655,949
31	Constellation Energy Generation, LLC	SF	Market-Based Rate Tariff				147	0	6,062	0	6,062
32	Guzman Energy, LLC	SF	Market-Based Rate Tariff				10,084	0	361,697	0	361,697
33	Heartland Generation LTD	SF	Market-Based Rate Tariff				1,450	0	52,465	0	52,465
34	MAG Energy Solution, Inc	SF	Market-Based Rate Tariff				167	0	4,008	0	4,008
35	Macquarie Energy LLC	SF	Market-Based Rate Tariff				262,666	0	9,534,620	0	9,534,620
36	Mercuria Energy America, LLC	SF	Market-Based Rate Tariff				1,170	0	51,120	0	51,120
37	Morgan Stanley Capital Group, Inc.	SF	Market-Based Rate Tariff				1,639	0	62,735	0	62,735
38	Portland General Electric	SF	Market-Based Rate Tariff				9,102	0	267,105	0	267,105
39	Avangrid Power LLC	SF	Market-Based Rate Tariff				28,293	0	1,086,249	0	1,086,249
40	PacifiCorp	SF	Market-Based Rate Tariff				715	0	33,325	0	33,325
41	Phillips 66 Energy Trading LLC	SF	Market-Based Rate Tariff				805	0	32,127	0	32,127
42	PUD No. 1 of Snohomish County	SF	Market-Based Rate Tariff				1,567	0	60,950	0	60,950
43	Puget Sound Energy	SF	Market-Based Rate Tariff				3,634	0	157,837	0	157,837
44	Powerex Corp.	SF	Market-Based Rate Tariff				55,710	0	1,282,269	0	1,282,269
45	Rainbow Energy Marketing Corporation	SF	Market-Based Rate Tariff				6,428	0	190,805	0	190,805
46	Seattle City Light	SF	Market-Based Rate Tariff				5,611	0	197,452	0	197,452
47	The Energy Authority, Inc.	SF	Market-Based Rate Tariff				28,296	0	957,367	0	957,367
48	TransAlta Energy Marketing (US) Inc.	SF	Market-Based Rate Tariff				33,938	0	1,222,307	0	1,222,307
49	Tenaska Power Services	SF	Market-Based Rate Tariff				438	0	20,720	0	20,720
50	Tacoma Power	SF	Market-Based Rate Tariff				340	0	11,000	0	11,000
51	Western Area Power Administration	SF	Market-Based Rate Tariff				195	0	8,775	0	8,775
52	Vitol Inc-Electric	SF	Market-Based Rate Tariff				150	0	7,250	0	7,250
15	Subtotal - RQ
16	Subtotal-Non-RQ						854,892	0	29,691,269	0	29,691,269
17	Total						854,892	0	29,691,269	0	29,691,269

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	66,006	53,571
5	FuelSteamPowerGeneration (501) Fuel	34,170,982	32,828,350
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	1,468,607	1,447,837
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	235,606	274,631
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	3,092,829	2,718,070
11	RentsSteamPowerGeneration (507) Rents
12	Allowances (509) Allowances
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	39,034,030	37,322,459
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	456,678	409,168
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	903,306	841,135
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	8,128,205	7,173,388
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	1,379,518	1,387,575
18.1	MaintenanceOfComputerHardwareSteamPowerGeneration (513.1) Maintenance of Computer Hardware
18.2	MaintenanceOfComputerSoftwareSteamPowerGeneration (513.2) Maintenance of Computer Software	494,655
18.3	MaintenanceOfCommunicationEquipmentSteamPowerGeneration (513.3) Maintenance of Communication Equipment	1,511
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	470,844	493,370
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	11,834,717	10,304,636
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	50,868,747	47,627,095
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	1,009,907	1,064,069
45	WaterForPower (536) Water for Power	1,121,963	1,004,649
46	HydraulicExpenses (537) Hydraulic Expenses	4,213,848	4,131,752
47	ElectricExpensesHydraulicPowerGeneration (538) Electric Expenses	3,401,890	3,528,125
48	MiscellaneousHydraulicPowerGenerationExpenses (539) Miscellaneous Hydraulic Power Generation Expenses	2,851,104	2,361,963
49	RentsHydraulicPowerGeneration (540) Rents	864,494	842,469
50	HydraulicPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 44 thru 49)	13,463,206	12,933,027
51	HydraulicPowerGenerationContinuedAbstract C. Hydraulic Power Generation (Continued)
52	HydraulicPowerGenerationMaintenanceAbstract Maintenance
53	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration (541) Maintenance Supervision and Engineering	843,886	921,622
54	MaintenanceOfStructuresHydraulicPowerGeneration (542) Maintenance of Structures	375,886	342,314
55	MaintenanceOfReservoirsDamsAndWaterways (543) Maintenance of Reservoirs, Dams, and Waterways	204,985	148,326
56	MaintenanceOfElectricPlantHydraulicPowerGeneration (544) Maintenance of Electric Plant	995,041	821,098
56.1	MaintenanceOfComputerHardwareHydraulicPowerGeneration (544.1) Maintenance of Computer Hardware
56.2	MaintenanceOfComputerSoftwareHydraulicPowerGeneration (544.2) Maintenance of Computer Software	33,852
56.3	MaintenanceOfCommunicationEquipmentHydraulicPowerGeneration (544.3) Maintenance of Communication Equipment	89,026
57	MaintenanceOfMiscellaneousHydraulicPlant (545) Maintenance of Miscellaneous Hydraulic Plant	230,103	88,700
58	HydraulicPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 53 thru 57)	2,772,779	2,322,060
59	PowerProductionExpensesHydraulicPower TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)	16,235,985	15,255,087
60	OtherPowerGenerationAbstract D. Other Power Generation
61	OtherPowerGenerationOperationAbstract Operation
62	OperationSupervisionAndEngineeringOtherPowerGeneration (546) Operation Supervision and Engineering	529,801	512,655
63	Fuel (547) Fuel	29,943,470	16,452,550
64	GenerationExpenses (548) Generation Expenses	6,914,088	4,395,712
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses	827,085	857,099
66	RentsOtherPowerGeneration (550) Rents
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	38,214,444	22,218,016
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering
70	MaintenanceOfStructures (552) Maintenance of Structures
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant	2,010,787	1,719,640
71.1	MaintenanceOfComputerHardwareOtherPowerGeneration (553.1) Maintenance of Computer Hardware	873
71.2	MaintenanceOfComputerSoftwareOtherPowerGeneration (553.2) Maintenance of Computer Software	89,547
71.3	MaintenanceOfCommunicationEquipmentOtherPowerGeneration (553.3) Maintenance of Communication Equipment	647
72	MaintenanceOfMiscellaneousOtherPowerGenerationPlant (554) Maintenance of Miscellaneous Other Power Generation Plant	14,861	34,147
73	OtherPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 69 thru 72)	2,116,715	1,753,787
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	40,331,159	23,971,803
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	210,396,480	256,772,116
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations
76.2	BundledEnvironmentalCredits (555.2) Bundled Environmental Credits	3,271,951
76.3	UnbundledEnvironmentalCredits (555.3) Unbundled Environmental Credits
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	(a) 38,516,775	15,042,672
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	175,151,656	271,814,788
79.1	SolarGenerationAbstract F. Solar Generation
79.2	SolarGenerationOperationAbstract Operation
79.3	OperationSupervisionAndEngineeringSolarGeneration (558.1) Operation Supervision and Engineering	12,185
79.4	SolarPanelGenerationAndOtherPlantOperatingExpensesSolarGeneration (558.2) Solar Panel Generation and Other Plant Operating Expenses
79.6	RentsSolarGeneration (558.4) Rents
79.7	SolarGenerationOperationsExpense TOTAL Operation (Enter Total of lines 79.3 thru 79.6)	12,185
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	645
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	2,100
79.15	SolarGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 79.9 thru 79.14)	2,745
79.16	PowerProductionExpensesSolar TOTAL Power Production Expenses-Solar (total of lines 79.7 & 79.15)	14,930
79.17	WindGenerationAbstract G. Wind Generation
79.18	WindGenerationOperationAbstract Operation
79.19	OperationSupervisionAndEngineeringWindGeneration (558.13) Operation Supervision and Engineering	87,602
79.20	WindTurbineGenerationAndOtherPlantOperatingExpensesWindGeneration (558.14) Wind Turbine Generation and Other Plant Operating Expenses	2,327,767
79.21	RentsWindGeneration (558.16) Rents	78,237
79.22	WindGenerationOperationsExpense TOTAL Operation (Enter Total of lines 79.19 thru 79.21)	2,493,606
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	37,145
79.26	MaintenanceOfComputerHardwareWindGeneration (558.20) Maintenance of Computer Hardware
79.27	MaintenanceOfComputerSoftwareWindGeneration (558.21) Maintenance of Computer Software
79.28	MaintenanceOfCommunicationEquipmentWindGeneration (558.22) Maintenance of Communication Equipment	1,092
79.29	MaintenanceOfMiscellaneousWindGenerationPlant (558.23) Maintenance of Miscellaneous Wind Generation Plant	154,512
79.30	WindGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 79.24 thru 79.29)	192,749
79.31	PowerProductionExpensesWind TOTAL Power Production Expenses-Wind (total of lines 79.22 & 79.30)	2,686,355
79.32	OtherRenewableGenerationAbstract H. Other Renewable Generation
79.33	OtherRenewableGenerationOperationAbstract Operation
79.34	OperationSupervisionAndEngineeringOtherRenewableGeneration (559.1) Operation Supervision and Engineering
79.35	OtherMiscellaneousGenerationAndOtherPlantOperatingExpensesOtherRenewableGeneration (559.2) Other Miscellaneous Generation and Other Plant Operating Expenses
79.36	FuelOtherRenewableGeneration (559.3) Fuel
79.37	RentsOtherRenewableGeneration (559.4) Rents
79.38	OtherRenewableGenerationOperationsExpense TOTAL Operation (Enter Total of lines 79.34 thru 79.37)
79.39	OtherRenewableGenerationMaintenanceAbstract Maintenance
79.40	MaintenanceSupervisionAndEngineeringOtherRenewableGeneration (559.6) Maintenance Supervision and Engineering
79.41	MaintenanceOfStructuresOtherRenewableGeneration (559.7) Maintenance of Structures
79.42	MaintenanceOfBoilersOtherRenewableGeneration (559.9) Maintenance of Boilers
79.43	MaintenanceOfGeneratingAndElectricEquipmentOtherRenewableGeneration (559.10) Maintenance of Generating and Electric Equipment
79.44	MaintenanceOfComputerHardwareOtherRenewableGeneration (559.12) Maintenance of Computer Hardware
79.45	MaintenanceOfComputerSoftwareOtherRenewableGeneration (559.13) Maintenance of Computer Software
79.46	MaintenanceOfCommunicationEquipmentOtherRenewableGeneration (559.14) Maintenance of Communication Equipment
79.47	MaintenanceOfMiscellaneousRenewableProductionPlantOtherRenewableGeneration (559.15) Maintenance of Miscellaneous Renewable Production Plant
79.48	OtherRenewableGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 79.40 thru 79.47)
79.49	PowerProductionExpensesOtherRenewable TOTAL Power Production Expenses-Other Renewable (total of lines 79.38 & 79.48)
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74, 79, 79.16, 79.31, & 79.49)	285,288,833	358,668,773
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	3,698,144	3,082,102
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability	878,697	953,566
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	810,565	883,165
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	1,126,014	1,088,750
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development
90	TransmissionServiceStudies (561.6) Transmission Service Studies
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services
93	StationExpensesTransmissionExpense (562) Station Expenses	1,196,642	1,694,747
94	OverheadLineExpense (563) Overhead Lines Expenses	2,594,501	1,113,452
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	6,261,346	6,395,363
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	104,747	117,177
98	RentsTransmissionElectricExpense (567) Rents	1,080,320	1,285,765
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	17,750,976	16,614,087
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	535,695	594,405
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	25,226	22,308
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	1,659,385	1,381,160
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	843,579	3,125
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	298,451
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	386,926	677,570
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	5,030,823	2,096,311
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	8,780,085	4,774,879
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	26,531,061	21,388,966
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	2,222
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)	2,222
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	19,894
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)	19,894
131.16	EnergyStorageExpenses TOTAL Energy Storage Expenses (Total of 131.7 and 131.15)	22,116
132	DistributionExpensesAbstract 5. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	3,467,514	3,449,092
135	LoadDispatching (581) Load Dispatching
136	StationExpensesDistribution (582) Station Expenses	1,510,488	1,614,284
137	OverheadLineExpenses (583) Overhead Line Expenses	3,245,924	2,017,558
138	UndergroundLineExpenses (584) Underground Line Expenses	2,892,263	2,687,440
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	115,123	87,712
140	MeterExpenses (586) Meter Expenses	1,381,583	1,369,015
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	1,703,704	1,691,467
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	2,820,906	2,719,335
143	RentsDistributionExpense (589) Rents	101,502	104,715
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	17,239,007	15,740,618
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	1,576,682	1,388,562
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	83,162	23,996
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	776,748	507,786
148.1	MaintenanceOfComputerHardwareDistribution (592.2) Maintenance of Computer Hardware
148.2	MaintenanceOfComputerSoftwareDistribution (592.3) Maintenance of Computer Software	428,902
148.3	MaintenanceOfCommunicationEquipmentDistribution (592.4) Maintenance of Communication Equipment	235,932
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	17,562,094	12,441,889
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	1,274,603	1,262,015
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	38,600	63,818
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	515,198	434,662
153	MaintenanceOfMeters (597) Maintenance of Meters	1,053,773	1,113,031
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	23,545,694	17,235,759
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	40,784,701	32,976,377
157	CustomerAccountsExpensesAbstract 6. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision
160	MeterReadingExpenses (902) Meter Reading Expenses	912,200	1,008,194
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	9,217,593	8,412,790
162	UncollectibleAccounts (904) Uncollectible Accounts	1,918,136	1,383,537
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	12,047,929	10,804,521
165	CustomerServiceAndInformationalExpensesAbstract 7. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	969,510	1,348,887
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses	1,672,552	1,691,380
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	2,642,062	3,040,267
172	SalesExpenseAbstract 8. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses
176	AdvertisingExpenses (913) Advertising Expenses	609,692	543,461
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	609,692	543,461
179	AdministrativeAndGeneralExpensesAbstract 9. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	30,886,509	31,454,597
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	4,942,290	15,002,954
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	8,535,277	7,599,517
184	OutsideServicesEmployed (923) Outside Services Employed	5,673,037	6,796,380
185	PropertyInsurance (924) Property Insurance	4,371,503	4,835,181
186	InjuriesAndDamages (925) Injuries and Damages	18,703,723	15,507,192
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	(b) 24,946,927	22,844,846
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	4,465,275	3,875,995
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	280,717	273,666
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	(c)(d) 14,171,177	14,373,724
193	RentsAdministrativeAndGeneralExpense (931) Rents	477,136	495,011
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	100,383,017	107,860,029
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	2,208,744	4,405,710
196.1	MaintenanceOfComputerHardwareAdministrativeAndGeneralExpenses (935.1) Maintenance of Computer Hardware	25,820
196.2	MaintenanceOfComputerSoftwareAdministrativeAndGeneralExpenses (935.2) Maintenance of Computer Software	10,265,172
196.3	MaintenanceOfCommunicationEquipmentAdministrativeAndGeneralExpenses (935.3) Maintenance of Communication Equipment	2,407,180
196.4	AdministrativeAndGeneralMaintenanceExpenses TOTAL Maintenance (Enter Total of lines 196 thru 196.3)	14,906,916	4,405,710
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196.4)	(e) 115,289,933	112,265,739
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 131.16, 156, 164, 171, 178, and 197)	483,216,326	539,688,104

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: OtherExpensesOtherPowerSupplyExpenses

Account 557 Other Expenses	Amount
Account 557 Total Expense	(38,516,775)
Less Variable Supply Costs	(38,665,333)
Amount to disclose in FERC Template page WP_FCR	148,558

Account 557 Fixed Costs:
Wind Procurement Costs	127,983
Mktg Supply - Other Power Supp	20,575
Subtotal	148,558

(b) Concept: EmployeePensionsAndBenefits

Plan Name	MT Medical
	(Regulatory)
Country	US
Fiscal year ending on	Dec 31, 2025
A. Net Periodic Benefit Cost
1. Service cost	209,646
2. Interest cost	423,034
3. Expected return on plan assets	(1,417,543)
4. Amortization of initial net obligation (asset)	—
5. Amortization of prior service cost	—
6. Amortization of net (gain) loss	—
7. Curtailment (gain)/loss recognized	—
8. Settlement (gain)/loss recognized	—
9. Special termination benefit recognized	—
10. Net periodic benefit cost	(784,863)

Electric Only	409,112

	12/31/2025
Universal System Benefits Charge	10,238,483
Our Portion of Shared Ownership Gen	1,905,851
Uncollectible Accounts
Subtotal	12,144,334


Board of Directors Fees	1,458,013
Amortization of upfront fees	217,835
Industry & Association Dues	271,307
Human Resources general expenses (non-labor and not provided for elsewhere)	13,257
Miscellaneous	-76,700
Shareholder Expenses	143,131
Subtotal	2,026,843

Total Account 930.2	14,171,177

(d) Concept: MiscellaneousGeneralExpenses

Montana Operations Miscellaneous General Expenses account 930.2 includes $106,778 of Electric non-allowed Industry and Association Dues, which is removed for rate making purposes.

(e) Concept: AdministrativeAndGeneralExpenses

Merger transaction-related costs associated with the pending merger with Black Hills Corporation totaled $696,339 for 2025.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	QUALIFYING FACILITIES
2	TIER II QF CONTRACTS
3	Billings Generation Inc (TIER II QF)	LU					458,357		0	0	0	55,660,372	(a) 9,705	55,650,667
4	Replacement Purchases CELP/MACQ (TIER II QF)	LU					152,005		0	0	0	7,600,250	0	7,600,250
5	Ross Creek Hydro (TIER II QF)	LU					1,615		0	0	0	104,426	(b) 2,840	101,586
6	NON TIER II QF-1 CONTRACTS						0		0	0	0	0	0	0
7	71 Ranch (NON TIER II QF)	LU					10,746		0	0	0	599,276	0	599,276
8	Big Timber Wind (Greycliff) (NON TIER II QF)	LU					73,308		0	0	0	3,324,517	0	3,324,517
9	Boulder Hydro (NON TIER II QF)	LU					1,257		0	0	0	47,007	0	47,007
10	Broadview East/Two Dot (NON TIER II QF)	LU					4,188		0	0	0	211,685	0	211,685
11	Cycle Horseshoe Bend (NON TIER II QF)	LU					4,072		0	0	0	191,620	0	191,620
12	DA Wind (NON TIER II QF)	LU					8,547		0	0	0	483,727	0	483,727
13	Fairfield Wind (NON TIER II QF)	LU					27,688		0	0	0	1,971,622	(c) 41,804	1,929,818
14	Flint Creek Hydro (NON TIER II QF)	LU					8,987		0	0	0	641,486	0	641,486
15	Gordon Butte Wind (NON TIER II QF)	LU					37,141		0	0	0	2,570,540	0	2,570,540
16	Greenfield Wind (NON TIER II QF)	LU					79,678		0	0	0	3,944,668	0	3,944,668
17	Hanover Hydro (NON TIER II QF)	LU					148		0	0	0	9,281	0	9,281
18	KEC Fighting Creek (NON TIER II QF)	LU					5,519		0	0	0	239,872	0	239,872
19	Lower South Fork (NON TIER II QF)	LU					696		0	0	0	48,684	0	48,684
20	Musselshell Wind 1 (NON TIER II QF)	LU					23,648		0	0	0	1,636,665	0	1,636,665
21	Musselshell Wind 2 (NON TIER II QF)	LU					27,497		0	0	0	1,903,056	0	1,903,056
22	Oversight Resources (NON TIER II QF)	LU					10,028		0	0	0	557,783	0	557,783
23	Pony Hydro (NON TIER II QF)	LU					754		0	0	0	29,187	0	29,187
24	South Dry Creek (NON TIER II QF)	LU					3,968		0	0	0	145,732	0	145,732
25	South Peak Wind (NON TIER II QF)	LU					243,061		0	0	0	5,496,535	0	5,496,535
26	Stillwater Wind LLC (NON TIER II QF)	LU					252,725		0	0	0	9,499,768	0	9,499,768
27	Strawberry Creek (NON TIER II QF)	LU					68		0	0	0	3,212	0	3,212
28	Wisconsin Creek (NON TIER II QF)	LU					802		0	0	0	34,351	0	34,351
29	Pine Creek (NON TIER II QF)	LU					1,254		0	0	0	50,171	0	50,171
30	Colstrip Energy Ltd/Montana One (NON TIER II QF)	LU					277,535		0	0	0	17,055,345	0	17,055,345
31	State of Montana-DNRC / Broadwater Dam (NON TIER II QF)	LU					28,832		0	0	0	1,219,726	(d) 5,088	1,214,638
32	NON TIER II SOLAR QF CONTRACTS						0		0	0	0	0	0	0
33	River Bend Solar (NON TIER II SOLAR QF )	LU					3,069		0	0	0	194,687	0	194,687
34	Green Meadow Solar (NON TIER II SOLAR QF )	LU					5,451		0	0	0	349,503	0	349,503
35	South Mills Solar 1 (NON TIER II SOLAR QF )	LU					4,906		0	0	0	313,046	0	313,046
36	Black Eagle Solar (NON TIER II SOLAR QF )	LU					4,823		0	0	0	307,170	0	307,170
37	Great Divide Solar LLC (NON TIER II SOLAR QF )	LU					5,781		0	0	0	372,415	0	372,415
38	Magpie Solar LLC (NON TIER II SOLAR QF )	LU					4,631		0	0	0	266,389	0	266,389
39	Montana Sun, LLC (NON TIER II SOLAR QF )	LU					143,108		0	0	0	6,076,190	0	6,076,190
40	Apex Solar LLC (NON TIER II SOLAR QF )	LU					166,420		0	0	0	6,699,428	0	6,699,428
41	RESERVE SHARING TRANSACTIONS						0		0	0	0	0	0	0
42	AVISTA CORPORATION (RESERVE SHARING)	LF	Reserve Energy Services				75		0	0	0	1,556	0	1,556
43	AVANGRID RENEWABLES, LLC (RESERVE SHARING)	LF	Reserve Energy Services				4		0	0	0	164	0	164
44	BONNEVILLE POWER ADMINISTRATION (RESERVE SHARING)	LF	Reserve Energy Services				100		0	0	0	3,953	0	3,953
45	CHELAN COUNTY PUD (RESERVE SHARING)	LF	Reserve Energy Services				9		0	0	0	299	0	299
46	GRIDFORCE ENERGY MANAGEMENT (RESERVE SHARING)	LF	Reserve Energy Services				10		0	0	0	385	0	385
47	DOUGLAS COUNTY PUD (RESERVE SHARING)	LF	Reserve Energy Services				3		0	0	0	94	0	94
48	GRANT COUNTY PUD (RESERVE SHARING)	LF	Reserve Energy Services				11		0	0	0	356	0	356
49	PACIFICORP (RESERVE SHARING)	LF	Reserve Energy Services				33		0	0	0	1,035	0	1,035
50	PORTLAND GENERAL ELECTRIC COMPANY (RESERVE SHARING)	LF	Reserve Energy Services				19		0	0	0	767	0	767
51	PUGET SOUND ENERGY (RESERVE SHARING)	LF	Reserve Energy Services				5		0	0	0	265	0	265
52	SEATTLE CITY LIGHT (RESERVE SHARING)	LF	Reserve Energy Services				19		0	0	0	618	0	618
53	TACOMA POWER (RESERVE SHARING)	LF	Reserve Energy Services				10		0	0	0	319	0	319
54	EXCHANGES						0		0	0	0	0	0	0
55	Pacificorp - Costrip Loss/Startup (EXCHANGES)	EX	RS 190				0		3,279	3,333	0	2,265	0	2,265
56	Talen Energy Marketing, LLC - Startup (EXCHANGES)	EX	RS 190				0		4,962	5,001	0	1,683	0	1,683
57	Portland General Electric - Colstrip Loss/Startup (EXCHANGES)	EX	RS 190				0		6,523	6,667	0	6,204	0	6,204
58	Puget Sound Energy - Colstrip Units 3&4 Startup (EXCHANGES)	EX	RS 190				0		8,195	8,334	0	5,773	0	5,773
59	Northwestern Energy Colstrip Unit 4 - Startup (EXCHANGES)	EX	RS 190				0		4,921	5,001	0	3,417	0	3,417
60	AVISTA Corporation - Colstrip Loss/Startup (EXCHANGES)	EX	RS 190				0		4,919	5,001	0	3,508	0	3,508
61	Purchased Power Supply						0		0	0	0	0	0	0
62	Avista Corporation (Purchased Power Supply)	SF	Market-Based Rate Tariff				19,870		0	0	0	1,230,792	0	1,230,792
63	AlbertaEx L.P. (Purchased Power Supply)	SF	Market-Based Rate Tariff				3,621		0	0	0	142,395	0	142,395
64	Altop Energy Trading LLC (Purchased Power Supply)	SF	Market-Based Rate Tariff				1,901		0	0	0	100,410	0	100,410
65	Basin Creek-Electric Power Plant (Purchased Power Supply)	SF	Market-Based Rate Tariff				0		0	0	0	7,583,584	0	7,583,584
66	Black Hills Power Inc (Purchased Power Supply)	SF	Market-Based Rate Tariff				60		0	0	0	1,800	0	1,800
67	Bonneville Power Administration (Purchased Power Supply)	SF	Market-Based Rate Tariff				12,005		0	0	0	646,973	0	646,973
68	Clatskanie Peoples Utility District - Electric (Purchased Power Supply)	SF	Market-Based Rate Tariff				3,530		0	0	0	128,369	0	128,369
69	ConocoPhillips Company (Purchased Power Supply)	SF	Market-Based Rate Tariff				2,715		0	0	0	79,831	0	79,831
70	Shell Energy North America (US), L.P. (Purchased Power Supply)	SF	Market-Based Rate Tariff				1,949		0	0	0	50,141	0	50,141
71	Dynasty Power Inc. (Purchased Power Supply)	SF	Market-Based Rate Tariff				4,344		0	0	0	129,572	0	129,572
72	Constellation Energy Generation, LLC (Purchased Power Supply)	SF	Market-Based Rate Tariff				276		0	0	0	10,200	0	10,200
73	EDF Trading North America, LLC (Purchased Power Supply)	SF	Market-Based Rate Tariff				214,608		0	0	0	12,308,113	0	12,308,113
74	Energy Keepers, Inc. (Purchased Power Supply)	SF	Market-Based Rate Tariff				45,844		0	0	0	2,639,601	0	2,639,601
75	Eugene Water & Electric Board (Purchased Power Supply)	SF	Market-Based Rate Tariff				6,420		0	0	0	193,324	0	193,324
76	Guzman Energy, LLC (Purchased Power Supply)	SF	Market-Based Rate Tariff				3,545		0	0	0	225,370	0	225,370
77	Avangrid Power LLC (Purchased Power Supply)	SF	Market-Based Rate Tariff				9,290		0	0	0	297,983	0	297,983
78	Heartland Generation LTD (Purchased Power Supply)	SF	Market-Based Rate Tariff				10,877		0	0	0	9,436,802	0	9,436,802
79	Idaho Power Company (Purchased Power Supply)	SF	Market-Based Rate Tariff				3,951		0	0	0	112,504	0	112,504
80	Invenergy Energy Marketing LLC-Electric (Purchased Power Supply)	SF	Market-Based Rate Tariff				410,163		0	0	0	14,339,260	0	14,339,260
81	Macquarie Energy LLC (Purchased Power Supply)	SF	Market-Based Rate Tariff				5,978		0	0	0	300,505	0	300,505
82	MAG Energy Solution, Inc (Purchased Power Supply)	SF	Market-Based Rate Tariff				75		0	0	0	4,125	0	4,125
83	Mercuria Energy America, Inc. (Purchased Power Supply)	SF	Market-Based Rate Tariff				120		0	0	0	4,200	0	4,200
84	Morgan Stanley Capital Group, Inc. (Purchased Power Supply)	SF	Market-Based Rate Tariff				5,074		0	0	0	111,611	0	111,611
85	PacifiCorp (Purchased Power Supply)	SF	Market-Based Rate Tariff				355		0	0	0	18,700	0	18,700
86	Phillips 66 Energy Trading LLC (Purchased Power Supply)	SF	Market-Based Rate Tariff				1,036		0	0	0	39,028	0	39,028
87	Portland General Electric (Purchased Power Supply)	SF	Market-Based Rate Tariff				23,861		0	0	0	1,145,070	0	1,145,070
88	Powerex Corp. (Purchased Power Supply)	SF	Market-Based Rate Tariff				280,562		0	0	0	35,924,272	0	35,924,272
89	PUD No. 1 of Snohomish County (Purchased Power Supply)	SF	Market-Based Rate Tariff				3,790		0	0	0	229,150	0	229,150
90	Puget Sound Energy (Purchased Power Supply)	SF	Market-Based Rate Tariff				33,095		0	0	0	1,610,245	0	1,610,245
91	Rainbow Energy Marketing Corporation (Purchased Power Supply)	SF	Market-Based Rate Tariff				1,600		0	0	0	89,600	0	89,600
92	Seattle City Light (Purchased Power Supply)	SF	Market-Based Rate Tariff				4,634		0	0	0	226,610	0	226,610
93	Tacoma Power (Purchased Power Supply)	LU	Market-Based Rate Tariff				2,441		0	0	0	102,970	0	102,970
94	The Energy Authority, Inc. (Purchased Power Supply)	SF	Market-Based Rate Tariff				9,987		0	0	0	366,129	0	366,129
95	TransAlta Energy Marketing (US), Inc. (Purchased Power Supply)	LU	Market-Based Rate Tariff				9,727		0	0	0	401,547	0	401,547
96	Turnbull Hydro, LLC (Purchased Power Supply)	SF	Market-Based Rate Tariff				18,047		0	0	0	1,321,969	0	1,321,969
97	Tenaska Power Services (Purchased Power Supply)	SF	Market-Based Rate Tariff				6,496		0	0	0	441,559	0	441,559
98	Western Area Power Administation (Purchased Power Supply)	SF	Market-Based Rate Tariff				30		0	0	0	450	0	450
99	Vitol Inc- Electric (Purchased Power Supply)	SF	Market-Based Rate Tariff				840		0	0	0	49,400	0	49,400
100	California Independent System Operator - EIM Transmission (Purchased Power Supply)	SF	CAISO				0		0	0	0	144,567	0	144,567
101	California Independent System Operator - EIM Supply (Purchased Power Supply)	SF	CAISO				0		0	0	0	11,222,275	0	11,222,275
102	Estimate Energy (Purchased Power Supply)	OS					0		0	0	0	2,915,059	0	2,915,059
103	Rounding	OS					1
15	TOTAL						3,245,327		32,799	33,337	0	213,727,868	59,437	213,668,431

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: OtherChargesOfPurchasedPower

Annual interconnect fee.

(b) Concept: OtherChargesOfPurchasedPower

Annual interconnect fee.

Credits to Qualifying Facilities Developer for delay penalties for projects not completed on time.

(d) Concept: OtherChargesOfPurchasedPower

Annual interconnect fee.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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.	PaymentByCompanyOrPublicAuthority Payment By (Company of Public Authority) (Footnote Affiliation) (a)	TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName Energy Received From (Company of Public Authority) (Footnote Affiliation) (b)	TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c)	StatisticalClassificationCode Statistical Classification (d)	RateScheduleTariffNumber Ferc Rate Schedule of Tariff Number (e)	TransmissionPointOfReceipt Point of Receipt (Substation or Other Designation) (f)	TransmissionPointOfDelivery Point of Delivery (Substation or Other Designation) (g)	BillingDemand Billing Demand (MW) (h)	TransmissionOfElectricityForOthersEnergyReceived Megawatt Hours Received (i)	TransmissionOfElectricityForOthersEnergyDelivered Megawatt Hours Delivered (j)	Demand Charges ($) (k)	Energy Charges ($) (l)	Other Charges ($) (m)	RevenuesFromTransmissionOfElectricityForOthers Total Revenues ($) (k+l+m) (n)
1	Montana Choice Transmission
2	Ash Grove Cement	Talen Energy	Ash Grove Cement	FNO	Montana OATT	As Available	Clancy, MT	7	40,145	40,145	243,531	0	0	243,531
3	Aspen Air U.S., LLC	Talen Energy	Aspen Air Corporation	FNO	Montana OATT	Colstrip	Billings, MT	11	55,072	55,072	296,420	0	0	296,420
4	Beartooth Electric Cooperative, Inc.	WAPA & Energy Keepers Inc.	Beartooth Electric Cooperative, Inc.	FNO	Montana OATT	Fort Peck & Kerr	Various in Montana	18	89,633	89,633	764,575	0	0	764,575
5	Benefis Health Systems	Guzman Energy	Benefis Health Systems	FNO	Montana OATT	Hardin	Various in Montana	7	33,930	33,930	242,863	0	0	242,863
6	Big Horn County Electric Coop. Inc.	Northwestern Energy/WAPA	Big Horn County Electric Coop. Inc.	FNO	Montana OATT	Various & Great Falls	Various in Montana	18	70,338	70,338	607,113	0	0	607,113
7	Bonneville Power Administration	BPA	Bonneville Power Administration	FNO	Montana OATT	BPAT.NWMT	Various in Montana	202	897,126	897,126	7,277,658	0	0	7,277,658
8	Basin Electric Power Cooperative	Morgan Stanley, WAPA	Basin Electric Power Cooperative	FNO	Montana OATT	BPAT.NWMT & Great Falls	Various NWMT & WAUW	164	874,865	874,865	6,958,724	0	0	6,958,724
9	Basin Electric Power Cooperative	Basin Electric, WAPA, Morgan Stanley	Basin Electric Power Cooperative	FNO	Montana OATT	BPAT.NWMT & Great Falls	Various NWMT & WAUW	15	77,271	77,271	597,732	0	0	597,732
10	CHS, Inc.	Mercuria	CHS, Inc.	FNO	Montana OATT	BPAT.NWMT & MATL.NWMT	Various in Montana	58	363,301	363,301	2,266,544	0	0	2,266,544
11	City of Great Falls	Guzman Energy	City of Great Falls	FNO	Montana OATT	Hardin	Various in Montana	6	19,962	19,962	133,110	0	0	133,110
12	Talen Montana, LLC	Avista Energy	Colstrip Steam Electric Station	FNO	Montana OATT	Colstrip	Nichols Pump Sub	10	27,959	27,959	140,054	0	0	140,054
13	Atlas Power, LLC	Portland General Electric	Atlas Power, LLC	FNO	Montana OATT	Colstrip	Butte, MT	75	558,708	558,708	3,338,796	0	0	3,338,796
14	Phillips 66 Company	Phillips 66 Trading and Maketing	Phillips 66 Company	FNO	Montana OATT	BPAT.NWMT	Various in Montana	70	492,052	492,052	2,973,366	0	0	2,973,366
15	Par Montana, LLC	Phillips 66 Trading and Maketing	Par Montana, LLC	FNO	Montana OATT	AVAT.NWMT	Billings, MT	35	227,973	227,973	1,515,845	0	0	1,515,845
16	General Mills Operations, LLC	Talen Energy	General Mills Operations, LLC	FNO	Montana OATT	Colstrip	Great Falls, MT	4	21,240	21,240	133,585	0	0	133,585
17	Great Falls Public Schools	Energy Keepers Inc.	Great Falls Public Schools	FNO	Montana OATT	Kerr	Great Falls, MT	3	9,812	9,812	74,857	0	0	74,857
18	GCC Three Forks, LLC	Various	GCC Three Forks, LLC	FNO	Montana OATT	As Available	Three Forks, MT	8	26,623	26,623	192,249	0	0	192,249
19	Magris Talc USA, Inc.	Energy Keepers Inc.	Magris Talc USA, Inc.	FNO	Montana OATT	Kerr	Three Forks, MT	6	25,297	25,297	174,789	0	0	174,789
20	DFA Dairy Brands Fluid, LLC	Talen Energy	DFA Dairy Brands Fluid, LLC	FNO	Montana OATT	Colstrip	Various in Montana	1	6,005	6,005	39,769	0	0	39,769
21	Calumet Refining, LLC	Talen Energy	Calumet Montana Refining Company, Inc.	FNO	Montana OATT	Colstrip	Great Falls, MT	25	168,473	168,473	970,308	0	0	970,308
22	Montana Resources	Energy Keepers, Inc.	Montana Resources	FNO	Montana OATT	BPAT.NWMT & Kerr	Butte, MT	50	359,831	359,831	2,246,525	0	0	2,246,525
23	REC Silicon Company	Shell Energy	REC Silicon Company	FNO	Montana OATT	BPAT.NWMT	Butte, MT	75	122,599	122,599	1,195,679	0	0	1,195,679
24	Roseburg Forest Products Company	Shell Energy	Roseburg Forest Products Company	FNO	Montana OATT	BPAT.NWMT	Missoula, MT	8	275	275	29,841	0	0	29,841
25	Sibanye-Stillwater	Various	Stillwater Mining Company	FNO	Montana OATT	As Available	Various in Montana	46	174,801	174,801	1,323,743	0	0	1,323,743
26	Western Area Power Administration	WAPA	Western Area Power Administration	FNO	Montana OATT	Crossover	Various NWMT & WAUW	4	8	8	34,967	0	0	34,967
27	Montana State University - Bozeman	WAPA	Montana State University - Bozeman	FNO	Montana OATT	Fort Peck West	Great Falls, MT	4	16,138	16,138	107,865	0	0	107,865
28	Western Area Power Administration	WAPA	Malmstrom Air Force Base	FNO	Montana OATT	Fort Peck West	Great Falls, MT	4	28,156	28,156	193,376	0	0	193,376
29	Montana Point to Point
30	AlbertaEx, L.P.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT	0	1,837	1,837	0	11,216	0	11,216
31	AlbertaEx, L.P.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	NWMT.SYSTEM	0	66	66	0	399	0	399
32	AlbertaEx, L.P.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	GTFALLSNWMT	0	14	14	0	85	0	85
33	AlbertaEx, L.P.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	8,899	8,899	0	53,753	0	53,753
34	AlbertaEx, L.P.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	1,083	1,083	0	6,541	0	6,541
35	AlbertaEx, L.P.	BPAT	NWMT	SFP	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	768	768	0	4,640	0	4,640
36	AlbertaEx, L.P.	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT	0	980	980	0	5,950	0	5,950
37	AlbertaEx, L.P.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	1,315	1,315	0	7,943	0	7,943
38	AlbertaEx, L.P.	NWMT	GWA	NF	MONTANA OATT	MATL.NWMT	GLWND1	0	3	3	0	19	0	19
39	AlbertaEx, L.P.	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	MATL.NWMT	0	170	170	0	1,052	0	1,052
40	AlbertaEx, L.P.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	160	160	0	966	0	966
41	AlbertaEx, L.P.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	JEFF	0	30	30	0	181	0	181
42	Altop Energy Trading LLC	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY	0	120	120	0	725	0	725
43	Altop Energy Trading LLC	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	75	75	0	453	0	453
44	Altop Energy Trading LLC	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	1,947	1,947	0	12,025	0	12,025
45	Altop Energy Trading LLC	BPAT	WAPA	SFP	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	1,200	1,200	0	7,450	0	7,450
46	Altop Energy Trading LLC	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT	0	45	45	0	279	0	279
47	Altop Energy Trading LLC	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT	0	1,177	1,177	0	7,284	0	7,284
48	Altop Energy Trading LLC	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	2,074	2,074	0	12,876	0	12,876
49	Avista Corporation	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	31,408	31,408	0	191,468	0	191,468
50	Avista Corporation	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	45,401	45,401	0	278,179	0	278,179
51	Avista Corporation	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	COLSTRIP	0	1,062	1,062	0	6,481	0	6,481
52	Avista Corporation	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	NWMT.SYSTEM	0	1,262	1,262	0	7,704	0	7,704
53	Avista Corporation	AVA	NWMT	SFP	MONTANA OATT	AVAT.NWMT	NWMT.SYSTEM	0	192	192	0	1,160	0	1,160
54	Avista Corporation	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	COLSTRIP	0	452	452	0	2,730	0	2,730
55	Avista Corporation	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	206	206	0	1,244	0	1,244
56	Avista Corporation	NWMT	AVA	LFP	MONTANA OATT	CLEARWATER	AVAT.NWMT	100	876,000	876,000	5,340,817	0	0	5,340,817
57	Avista Corporation	NWMT	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	51	51	0	317	0	317
58	Avista Corporation	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY	0	597	597	0	3,707	0	3,707
59	Basin Electric Power Cooperative	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	31	31	0	193	0	193
60	Basin Electric Power Cooperative	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	YTP	0	1,200	1,200	0	7,250	0	7,250
61	Basin Electric Power Cooperative	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	GREATFALLS	0	514	514	0	3,110	0	3,110
62	Basin Electric Power Cooperative	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	COLSTRIP	0	1	1	0	6	0	6
63	Basin Electric Power Cooperative	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	NWMT.SYSTEM	0	160	160	0	966	0	966
64	Basin Electric Power Cooperative	NWMT	PACE	NF	MONTANA OATT	KERR	YTP	0	1,262	1,262	0	7,622	0	7,622
65	Basin Electric Power Cooperative	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP	0	2,704	2,704	0	16,332	0	16,332
66	Basin Electric Power Cooperative	NWMT	WAUW	NF	MONTANA OATT	COLSTRIP	GREATFALLS	0	327	327	0	1,995	0	1,995
67	Basin Electric Power Cooperative	NWMT	WAUW	NF	MONTANA OATT	JUDITHGAP	GREATFALLS	0	110	110	0	664	0	664
68	Basin Electric Power Cooperative	PPW	NWMT	NF	MONTANA OATT	YTP	NWMT.SYSTEM	0	20	20	0	121	0	121
69	Basin Electric Power Cooperative	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	54	54	0	326	0	326
70	Basin Electric Power Cooperative	PPW	WAPA	NF	MONTANA OATT	YTP	GREATFALLS	0	1,049	1,049	0	6,336	0	6,336
71	Basin Electric Power Cooperative	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	50	50	0	311	0	311
72	Basin Electric Power Cooperative	WAPA	WAPA	LFP	MONTANA OATT	CROSSOVER	GREATFALLS	23	203,081	203,081	1,246,926	0	0	1,246,926
73	Basin Electric Power Cooperative	WAPA	WAPA	NF	MONTANA OATT	CROSSOVER	GREATFALLS	0	90	90	0	544	0	544
74	Black Hills Power Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	240	240	0	1,450	0	1,450
75	Black Hills Power Inc.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP	0	1,143	1,143	0	6,936	0	6,936
76	Black Hills Power Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	25	25	0	155	0	155
77	Bonneville Power Administration	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	1,422	1,422	0	8,776	0	8,776
78	Bonneville Power Administration	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	ANTE	0	192	192	0	1,160	0	1,160
79	Bonneville Power Administration	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY	0	179	179	0	1,101	0	1,101
80	Bonneville Power Administration	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	91	91	0	558	0	558
81	Bonneville Power Administration	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	GREATFALLS	0	6,222	6,222	0	37,581	0	37,581
82	Brookfield Renewable Trading and Marketing LP	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	56	56	0	347	0	347
83	CP Energy Marketing (US) Inc.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT	0	234	234	0	1,413	0	1,413
84	CP Energy Marketing (US) Inc.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	NWMT.SYSTEM	0	17	17	0	103	0	103
85	CP Energy Marketing (US) Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	39,797	39,797	0	242,827	0	242,827
86	CP Energy Marketing (US) Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	1,472	1,472	0	8,966	0	8,966
87	CP Energy Marketing (US) Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	1,457	1,457	0	8,837	0	8,837
88	CP Energy Marketing (US) Inc.	NWMT	NWMT	NF	MONTANA OATT	MATL.NWMT	NWMT.SYSTEM	0	33	33	0	205	0	205
89	CP Energy Marketing (US) Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	YTP	0	320	320	0	1,933	0	1,933
90	CP Energy Marketing (US) Inc.	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	CROSSOVER	0	165	165	0	1,001	0	1,001
91	CP Energy Marketing (US) Inc.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	24	24	0	145	0	145
92	Cycle Power Partners, LLC	NWMT	PACE	NF	MONTANA OATT	HORSESHOE	BRDY	0	1,129	1,129	0	6,934	0	6,934
93	Cycle Power Partners, LLC	NWMT	PACE	NF	MONTANA OATT	HORSESHOE	JEFF	0	16,957	16,957	0	103,845	0	103,845
94	Dynasty Power Inc.	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	92	92	0	556	0	556
95	Dynasty Power Inc.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT	0	12,216	12,216	0	75,841	0	75,841
96	Dynasty Power Inc.	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER	0	25	25	0	155	0	155
97	Dynasty Power Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	19,384	19,384	0	119,965	0	119,965
98	Dynasty Power Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY	0	129	129	0	779	0	779
99	Dynasty Power Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	79	79	0	483	0	483
100	Dynasty Power Inc.	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	21,520	21,520	0	131,548	0	131,548
101	Dynasty Power Inc.	BPAT	WAPA	SFP	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	34,272	34,272	0	212,410	0	212,410
102	Dynasty Power Inc.	NWMT	AVA	NF	MONTANA OATT	KERR	AVAT.NWMT	0	25	25	0	151	0	151
103	Dynasty Power Inc.	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT	0	200	200	0	1,208	0	1,208
104	Dynasty Power Inc.	NWMT	BPAT	NF	MONTANA OATT	KERR	BPAT.NWMT	0	293	293	0	1,770	0	1,770
105	Dynasty Power Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	2,927	2,927	0	17,738	0	17,738
106	Dynasty Power Inc.	NWMT	PACE	NF	MONTANA OATT	KERR	YTP	0	25	25	0	151	0	151
107	Dynasty Power Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	2,319	2,319	0	14,007	0	14,007
108	Dynasty Power Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	YTP	0	44	44	0	266	0	266
109	Dynasty Power Inc.	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	CROSSOVER	0	250	250	0	1,510	0	1,510
110	Dynasty Power Inc.	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT	0	2,280	2,280	0	14,155	0	14,155
111	Dynasty Power Inc.	PACE	NWMT	NF	MONTANA OATT	YTP	MATL.NWMT	0	462	462	0	2,837	0	2,837
112	Dynasty Power Inc.	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT	0	35	35	0	217	0	217
113	Dynasty Power Inc.	PPW	WAPA	NF	MONTANA OATT	BRDY	CROSSOVER	0	1,870	1,870	0	11,612	0	11,612
114	Dynasty Power Inc.	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	7,068	7,068	0	43,329	0	43,329
115	Dynasty Power Inc.	PPW	WAPA	SFP	MONTANA OATT	YTP	CROSSOVER	0	4,296	4,296	0	26,531	0	26,531
116	Dynasty Power Inc.	WAPA	AVA	NF	MONTANA OATT	CROSSOVER	AVAT.NWMT	0	205	205	0	1,264	0	1,264
117	Dynasty Power Inc.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	5,367	5,367	0	32,595	0	32,595
118	Dynasty Power Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	JEFF	0	24	24	0	149	0	149
119	Dynasty Power Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	11,002	11,002	0	66,688	0	66,688
120	Dynasty Power Inc.	WAUW	NWMT	NF	MONTANA OATT	CROSSOVER	MATL.NWMT	0	363	363	0	2,195	0	2,195
121	EDF Trading North America, LLC	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	569	569	0	3,520	0	3,520
122	EDF Trading North America, LLC	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	1,200	1,200	0	7,450	0	7,450
123	EDF Trading North America, LLC	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	COLSTRIP	0	130	130	0	807	0	807
124	EDF Trading North America, LLC	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	GTFALLSNWMT	0	4	4	0	25	0	25
125	EDF Trading North America, LLC	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	NWMT.SYSTEM	0	507	507	0	3,121	0	3,121
126	EDF Trading North America, LLC	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	JEFF	0	20	20	0	124	0	124
127	EDF Trading North America, LLC	BPAT	BPAT	NF	MONTANA OATT	BPAT.NWMT	BPAT.NWMT	0	1	1	0	6	0	6
128	EDF Trading North America, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	COLSTRIP	0	1,352	1,352	0	8,208	0	8,208
129	EDF Trading North America, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	GTFALLSNWMT	0	700	700	0	4,229	0	4,229
130	EDF Trading North America, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	8,484	8,484	0	51,537	0	51,537
131	EDF Trading North America, LLC	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	JEFF	0	50	50	0	311	0	311
132	EDF Trading North America, LLC	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	GREATFALLS	0	426	426	0	2,573	0	2,573
133	EDF Trading North America, LLC	NWMT	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	1,042	1,042	0	6,379	0	6,379
134	EDF Trading North America, LLC	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT	0	35,939	35,939	0	219,130	0	219,130
135	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	COLSTRIP	0	5,989	5,989	0	36,629	0	36,629
136	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	GTFALLSNWMT	0	38	38	0	234	0	234
137	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	MATL.NWMT	0	126	126	0	770	0	770
138	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	NWMT.SYSTEM	0	401	401	0	2,438	0	2,438
139	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	DAVEGATES	NWMT.SYSTEM	0	69	69	0	417	0	417
140	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	MATL.NWMT	NWMT.SYSTEM	0	86	86	0	534	0	534
141	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	NWMTIMBALANC	NWMT.SYSTEM	0	507	507	0	3,073	0	3,073
142	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	TFALLS	COLSTRIP	0	248	248	0	1,537	0	1,537
143	EDF Trading North America, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	ANTE	0	51	51	0	308	0	308
144	EDF Trading North America, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY	0	25,124	25,124	0	153,830	0	153,830
145	EDF Trading North America, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	JEFF	0	571	571	0	3,546	0	3,546
146	EDF Trading North America, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP	0	4,257	4,257	0	26,074	0	26,074
147	EDF Trading North America, LLC	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	BRDY	0	1,800	1,800	0	11,175	0	11,175
148	EDF Trading North America, LLC	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	YTP	0	2,160	2,160	0	13,050	0	13,050
149	EDF Trading North America, LLC	NWMT	WAPA	NF	MONTANA OATT	COLSTRIP	CROSSOVER	0	852	852	0	5,205	0	5,205
150	EDF Trading North America, LLC	PACE	NWMT	NF	MONTANA OATT	BRDY	COLSTRIP	0	57	57	0	346	0	346
151	EDF Trading North America, LLC	PACE	NWMT	NF	MONTANA OATT	YTP	COLSTRIP	0	368	368	0	2,225	0	2,225
152	EDF Trading North America, LLC	PPW	NWMT	NF	MONTANA OATT	BRDY	GTFALLSNWMT	0	33	33	0	199	0	199
153	EDF Trading North America, LLC	PPW	NWMT	NF	MONTANA OATT	BRDY	NWMT.SYSTEM	0	200	200	0	1,208	0	1,208
154	EDF Trading North America, LLC	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	JEFF	0	5	5	0	30	0	30
155	Energy Keepers Inc.	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	1,676	1,676	0	10,124	0	10,124
156	Energy Keepers Inc.	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	1,536	1,536	0	9,280	0	9,280
157	Energy Keepers Inc.	NWMT	AVA	NF	MONTANA OATT	KERR	AVAT.NWMT	0	2,761	2,761	0	17,085	0	17,085
158	Energy Keepers Inc.	NWMT	AVA	SFP	MONTANA OATT	KERR	AVAT.NWMT	0	7,920	7,920	0	49,050	0	49,050
159	Energy Keepers Inc.	NWMT	BPAT	LFP	MONTANA OATT	KERR	BPAT.NWMT	40	350,400	350,400	2,136,327	0	0	2,136,327
160	Energy Keepers Inc.	NWMT	BPAT	NF	MONTANA OATT	KERR	BPAT.NWMT	0	2,514	2,514	0	15,488	0	15,488
161	Energy Keepers Inc.	NWMT	BPAT	SFP	MONTANA OATT	KERR	KERR.MVP	0	20,544	20,544	0	124,132	0	124,132
162	Energy Keepers Inc.	NWMT	PACE	LFP	MONTANA OATT	KERR	ANTE	10	90,600	90,600	566,094	0	0	566,094
163	Energy Keepers Inc.	NWMT	PACE	LFP	MONTANA OATT	KERR	BRDY	38	330,000	330,000	1,991,096	0	0	1,991,096
164	Energy Keepers Inc.	NWMT	PACE	NF	MONTANA OATT	KERR	BRDY	0	1,640	1,640	0	10,027	0	10,027
165	Energy Keepers Inc.	NWMT	PACE	NF	MONTANA OATT	KERR	JEFF	0	1,468	1,468	0	8,867	0	8,867
166	Energy Keepers Inc.	NWMT	PACE	NF	MONTANA OATT	KERR	YTP	0	51	51	0	308	0	308
167	Energy Keepers Inc.	NWMT	PACE	SFP	MONTANA OATT	KERR	JEFF	0	5,376	5,376	0	32,448	0	32,448
168	Energy Keepers Inc.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	ANTE	0	1,245	1,245	0	7,522	0	7,522
169	Energy Keepers Inc.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY	0	13,722	13,722	0	82,901	0	82,901
170	Energy Keepers Inc.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	JEFF	0	99	99	0	598	0	598
171	Energy Keepers Inc.	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	JEFF	0	3,840	3,840	0	23,184	0	23,184
172	Energy Keepers Inc.	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	YTP	0	120	120	0	725	0	725
173	Guzman Energy, LLC	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	BRDY	0	64	64	0	387	0	387
174	Guzman Energy, LLC	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP	0	1,998	1,998	0	12,150	0	12,150
175	Guzman Energy, LLC	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY	0	150	150	0	932	0	932
176	Guzman Energy, LLC	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	4,347	4,347	0	26,571	0	26,571
177	Guzman Energy, LLC	NWMT	BPAT	NF	MONTANA OATT	HARDIN	BPAT.NWMT	0	576	576	0	3,480	0	3,480
178	Guzman Energy, LLC	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	COLSTRIP	0	59	59	0	356	0	356
179	Guzman Energy, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP	0	905	905	0	5,522	0	5,522
180	Guzman Energy, LLC	NWMT	WAUW	NF	MONTANA OATT	NWMTIMBALANC	CROSSOVER	0	15	15	0	91	0	91
181	Guzman Energy, LLC	PPW	AVA	LFP	MONTANA OATT	YTP	AVAT.NWMT	7	58,744	58,744	354,805	0	0	354,805
182	Guzman Energy, LLC	PPW	AVA	NF	MONTANA OATT	BRDY	AVAT.NWMT	0	3	3	0	18	0	18
183	Guzman Energy, LLC	PPW	AVA	NF	MONTANA OATT	YTP	AVAT.NWMT	0	767	767	0	4,664	0	4,664
184	Guzman Energy, LLC	PPW	BPAT	NF	MONTANA OATT	JEFF	BPAT.NWMT	0	95	95	0	590	0	590
185	Guzman Energy, LLC	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT	0	2,997	2,997	0	18,102	0	18,102
186	Guzman Energy, LLC	PPW	PPW	NF	MONTANA OATT	YTP	ANTE	0	78	78	0	471	0	471
187	Guzman Energy, LLC	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	1,456	1,456	0	8,829	0	8,829
188	Guzman Energy, LLC	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	2,507	2,507	0	15,187	0	15,187
189	Heartland Generation Ltd	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	GTFALLSNWMT	0	60	60	0	373	0	373
190	Heartland Generation Ltd	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	NWMT.SYSTEM	0	240	240	0	1,490	0	1,490
191	Heartland Generation Ltd	BPAT	BPAT	NF	MONTANA OATT	BPAT.NWMT	BPAT.NWMT	0	120	120	0	745	0	745
192	Heartland Generation Ltd	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	GTFALLSNWMT	0	504	504	0	3,130	0	3,130
193	Heartland Generation Ltd	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	2,560	2,560	0	15,898	0	15,898
194	Heartland Generation Ltd	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	250	250	0	1,553	0	1,553
195	Heartland Generation Ltd	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	GREATFALLS	0	55	55	0	342	0	342
196	Iberdrola Renewables Inc.	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	34	34	0	205	0	205
197	Idaho Power Co	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT	0	101	101	0	610	0	610
198	Idaho Power Company	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	MLCK	0	240	240	0	1,490	0	1,490
199	Idaho Power Company	PACE	NWMT	NF	MONTANA OATT	JEFF	MLCK	0	4,079	4,079	0	24,657	0	24,657
200	Idaho Power Company	PACE	NWMT	SFP	MONTANA OATT	JEFF	MLCK	0	5,064	5,064	0	30,955	0	30,955
201	Idaho Power Company	PPW	AVA	NF	MONTANA OATT	YTP	AVAT.NWMT	0	1	1	0	6	0	6
202	Idaho Power Company	PPW	IPCO	SFP	MONTANA OATT	JEFF	TNDY	0	528	528	0	3,238	0	3,238
203	Macquarie Energy, LLC	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	400	400	0	2,416	0	2,416
204	Macquarie Energy, LLC	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	1,200	1,200	0	7,250	0	7,250
205	Macquarie Energy, LLC	AVA	BPAT	NF	MONTANA OATT	AVAT.NWMT	BPAT.NWMT	0	96	96	0	580	0	580
206	Macquarie Energy, LLC	AVA	PPW	SFP	MONTANA OATT	AVAT.NWMT	JEFF	0	768	768	0	4,640	0	4,640
207	Macquarie Energy, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	2,440	2,440	0	14,738	0	14,738
208	Macquarie Energy, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	48	48	0	290	0	290
209	Macquarie Energy, LLC	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY	0	216	216	0	1,305	0	1,305
210	Macquarie Energy, LLC	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	BRDY	0	384	384	0	2,320	0	2,320
211	Macquarie Energy, LLC	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	9,554	9,554	0	59,423	0	59,423
212	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	BGI	AVAT.NWMT	0	10,318	10,318	0	63,266	0	63,266
213	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	HAUSER	AVAT.NWMT	0	40	40	0	242	0	242
214	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	JUDITHGAP	AVAT.NWMT	0	1,600	1,600	0	9,664	0	9,664
215	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT	0	400	400	0	2,484	0	2,484
216	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	MT1	AVAT.NWMT	0	166	166	0	1,003	0	1,003
217	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	NWMTIMBALANC	AVAT.NWMT	0	29	29	0	175	0	175
218	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	STILLWIND	AVAT.NWMT	0	800	800	0	4,832	0	4,832
219	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	TFALLS	AVAT.NWMT	0	2,531	2,531	0	15,317	0	15,317
220	Macquarie Energy, LLC	NWMT	AVA	SFP	MONTANA OATT	BGI	AVAT.NWMT	0	5,903	5,903	0	35,580	0	35,580
221	Macquarie Energy, LLC	NWMT	AVA	SFP	MONTANA OATT	TFALLS	AVAT.NWMT	0	600	600	0	3,725	0	3,725
222	Macquarie Energy, LLC	NWMT	BPA	NF	MONTANA OATT	BGI	BPAT.NWMT	0	4,222	4,222	0	26,194	0	26,194
223	Macquarie Energy, LLC	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	801	801	0	4,939	0	4,939
224	Macquarie Energy, LLC	NWMT	BPAT	NF	MONTANA OATT	NWMTIMBALANC	BPAT.NWMT	0	4	4	0	24	0	24
225	Macquarie Energy, LLC	NWMT	BPAT	NF	MONTANA OATT	TFALLS	BPAT.NWMT	0	3,861	3,861	0	23,737	0	23,737
226	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	BGI	BRDY	0	4,262	4,262	0	26,314	0	26,314
227	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	BGI	YTP	0	400	400	0	2,416	0	2,416
228	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	JUDITHGAP	BRDY	0	402	402	0	2,428	0	2,428
229	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	116	116	0	720	0	720
230	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	YTP	0	75	75	0	453	0	453
231	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	MT1	YTP	0	34	34	0	205	0	205
232	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	STILLWIND	JEFF	0	240	240	0	1,450	0	1,450
233	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	STILLWIND	YTP	0	240	240	0	1,450	0	1,450
234	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	TFALLS	BRDY	0	1,000	1,000	0	6,040	0	6,040
235	Macquarie Energy, LLC	NWMT	PACE	NF	MONTANA OATT	TFALLS	JEFF	0	147	147	0	888	0	888
236	Macquarie Energy, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY	0	1,040	1,040	0	6,283	0	6,283
237	Macquarie Energy, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	JEFF	0	2,688	2,688	0	16,224	0	16,224
238	Macquarie Energy, LLC	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	JEFF	0	1,920	1,920	0	11,600	0	11,600
239	Macquarie Energy, LLC	NWMT	WAPA	SFP	MONTANA OATT	COLSTRIP	CROSSOVER	0	8,208	8,208	0	49,544	0	49,544
240	Macquarie Energy, LLC	PACE	NWMT	NF	MONTANA OATT	YTP	MATL.NWMT	0	55	55	0	332	0	332
241	Macquarie Energy, LLC	PPW	AVA	NF	MONTANA OATT	BRDY	AVAT.NWMT	0	8,736	8,736	0	54,340	0	54,340
242	Macquarie Energy, LLC	PPW	AVA	NF	MONTANA OATT	YTP	AVAT.NWMT	0	11,328	11,328	0	72,464	0	72,464
243	Macquarie Energy, LLC	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT	0	384	384	0	2,384	0	2,384
244	Macquarie Energy, LLC	PPW	NWMT	NF	MONTANA OATT	YTP	NWMT.SYSTEM	0	42	42	0	254	0	254
245	Macquarie Energy, LLC	WAUW	NWMT	NF	MONTANA OATT	CROSSOVER	MATL.NWMT	0	96	96	0	580	0	580
246	MAG Energy Solutions	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT	0	3,905	3,905	0	23,586	0	23,586
247	MAG Energy Solutions	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT	0	47	47	0	284	0	284
248	MAG Energy Solutions	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	28,648	28,648	0	173,657	0	173,657
249	MAG Energy Solutions	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	287	287	0	1,733	0	1,733
250	MAG Energy Solutions	BPAT	NWMT	SFP	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	1,536	1,536	0	9,280	0	9,280
251	MAG Energy Solutions	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	1	1	0	6	0	6
252	MAG Energy Solutions	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	YTP	0	920	920	0	5,800	0	5,800
253	MAG Energy Solutions	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	1,256	1,256	0	7,620	0	7,620
254	MAG Energy Solutions	BPAT	WAPA	SFP	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	18,913	18,913	0	117,474	0	117,474
255	MAG Energy Solutions	NWMT	AVA	NF	MONTANA OATT	KERR	AVAT.NWMT	0	28	28	0	174	0	174
256	MAG Energy Solutions	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	1,286	1,286	0	7,767	0	7,767
257	MAG Energy Solutions	NWMT	NWMT	NF	MONTANA OATT	KERR	MLCK	0	2	2	0	12	0	12
258	MAG Energy Solutions	NWMT	NWMT	NF	MONTANA OATT	MATL.NWMT	NWMT.SYSTEM	0	14	14	0	85	0	85
259	MAG Energy Solutions	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	14	14	0	87	0	87
260	MAG Energy Solutions	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	YTP	0	68	68	0	413	0	413
261	MAG Energy Solutions	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	CROSSOVER	0	2,532	2,532	0	15,647	0	15,647
262	MAG Energy Solutions	NWMT	WAUW	SFP	MONTANA OATT	MATL.NWMT	CROSSOVER	0	3,360	3,360	0	20,900	0	20,900
263	MAG Energy Solutions	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT	0	1	1	0	6	0	6
264	MAG Energy Solutions	PACE	NWMT	NF	MONTANA OATT	JEFF	MATL.NWMT	0	308	308	0	1,860	0	1,860
265	MAG Energy Solutions	PACE	NWMT	NF	MONTANA OATT	YTP	MATL.NWMT	0	204	204	0	1,232	0	1,232
266	MAG Energy Solutions	PPW	NWMT	NF	MONTANA OATT	YTP	NWMT.SYSTEM	0	8	8	0	48	0	48
267	MAG Energy Solutions	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	2,679	2,679	0	16,633	0	16,633
268	MAG Energy Solutions	PPW	WAPA	SFP	MONTANA OATT	YTP	CROSSOVER	0	1,104	1,104	0	6,854	0	6,854
269	MAG Energy Solutions	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	593	593	0	3,582	0	3,582
270	MAG Energy Solutions	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY	0	30	30	0	181	0	181
271	MAG Energy Solutions	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	441	441	0	2,664	0	2,664
272	MAG Energy Solutions	WAUW	NWMT	NF	MONTANA OATT	CROSSOVER	MATL.NWMT	0	515	515	0	3,111	0	3,111
273	MAG Energy Solutions	WAUW	NWMT	NF	MONTANA OATT	GREATFALLS	MATL.NWMT	0	124	124	0	749	0	749
274	Mercuria Energy America, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	16	16	0	97	0	97
275	Mercuria Energy America, LLC	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT	0	20	20	0	121	0	121
276	Mercuria Energy America, LLC	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT	0	448	448	0	2,782	0	2,782
277	Mercuria Energy America, LLC	PPW	NWMT	NF	MONTANA OATT	MLCK	NWMT.SYSTEM	0	26	26	0	157	0	157
278	MFT Energy US Power LLC	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT	0	166	166	0	1,003	0	1,003
279	MFT Energy US Power LLC	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT	0	82	82	0	495	0	495
280	MFT Energy US Power LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	17,249	17,249	0	105,077	0	105,077
281	MFT Energy US Power LLC	BPAT	NWMT	SFP	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	1,248	1,248	0	7,632	0	7,632
282	MFT Energy US Power LLC	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY	0	1	1	0	6	0	6
283	MFT Energy US Power LLC	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	5,270	5,270	0	32,281	0	32,281
284	MFT Energy US Power LLC	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	CROSSOVER	0	572	572	0	3,455	0	3,455
285	MFT Energy US Power LLC	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT	0	320	320	0	1,935	0	1,935
286	MFT Energy US Power LLC	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT	0	24	24	0	145	0	145
287	MFT Energy US Power LLC	PPW	WAPA	NF	MONTANA OATT	BRDY	CROSSOVER	0	6,341	6,341	0	38,305	0	38,305
288	MFT Energy US Power LLC	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	40	40	0	248	0	248
289	MFT Energy US Power LLC	WAUW	NWMT	NF	MONTANA OATT	CROSSOVER	MATL.NWMT	0	220	220	0	1,329	0	1,329
290	Morgan Stanley Capital Group, Inc.	AVA	BPAT	NF	MONTANA OATT	AVAT.NWMT	BPAT.NWMT	0	500	500	0	3,021	0	3,021
291	Morgan Stanley Capital Group, Inc.	AVA	GWA	NF	MONTANA OATT	AVAT.NWMT	GLWND1	0	99	99	0	608	0	608
292	Morgan Stanley Capital Group, Inc.	AVA	GWA	NF	MONTANA OATT	AVAT.NWMT	GLWND2	0	3	3	0	18	0	18
293	Morgan Stanley Capital Group, Inc.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT	0	29,756	29,756	0	181,616	0	181,616
294	Morgan Stanley Capital Group, Inc.	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	ANTE	0	481	481	0	2,905	0	2,905
295	Morgan Stanley Capital Group, Inc.	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	BRDY	0	77	77	0	465	0	465
296	Morgan Stanley Capital Group, Inc.	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP	0	100	100	0	604	0	604
297	Morgan Stanley Capital Group, Inc.	BPAT	GWA	NF	MONTANA OATT	BPAT.NWMT	GLWND1	0	6,863	6,863	0	42,025	0	42,025
298	Morgan Stanley Capital Group, Inc.	BPAT	GWA	NF	MONTANA OATT	BPAT.NWMT	GLWND2	0	2,916	2,916	0	17,978	0	17,978
299	Morgan Stanley Capital Group, Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	171,301	171,301	0	1,059,975	0	1,059,975
300	Morgan Stanley Capital Group, Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	6	6	0	37	0	37
301	Morgan Stanley Capital Group, Inc.	BPAT	NWMT	SFP	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	16,920	16,920	0	103,189	0	103,189
302	Morgan Stanley Capital Group, Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	ANTE	0	155	155	0	936	0	936
303	Morgan Stanley Capital Group, Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY	0	46	46	0	278	0	278
304	Morgan Stanley Capital Group, Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	JEFF	0	110	110	0	664	0	664
305	Morgan Stanley Capital Group, Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	59	59	0	356	0	356
306	Morgan Stanley Capital Group, Inc.	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	20	20	0	124	0	124
307	Morgan Stanley Capital Group, Inc.	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	GREATFALLS	0	24	24	0	145	0	145
308	Morgan Stanley Capital Group, Inc.	GWA	AVA	NF	MONTANA OATT	GLWND1	AVAT.NWMT	0	67,711	67,711	0	414,853	0	414,853
309	Morgan Stanley Capital Group, Inc.	GWA	AVA	NF	MONTANA OATT	GLWND2	AVAT.NWMT	0	43,478	43,478	0	264,973	0	264,973
310	Morgan Stanley Capital Group, Inc.	GWA	AVA	SFP	MONTANA OATT	GLWND1	AVAT.NWMT	0	408	408	0	2,525	0	2,525
311	Morgan Stanley Capital Group, Inc.	GWA	AVA	SFP	MONTANA OATT	GLWND2	AVAT.NWMT	0	720	720	0	4,390	0	4,390
312	Morgan Stanley Capital Group, Inc.	GWA	BPAT	NF	MONTANA OATT	GLWND1	BPAT.NWMT	0	235,548	235,548	0	1,440,496	0	1,440,496
313	Morgan Stanley Capital Group, Inc.	GWA	BPAT	NF	MONTANA OATT	GLWND2	BPAT.NWMT	0	149,434	149,434	0	913,990	0	913,990
314	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND1	MATL.NWMT	0	13,578	13,578	0	83,656	0	83,656
315	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND2	MATL.NWMT	0	3,584	3,584	0	22,080	0	22,080
316	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND2	NWMT.SYSTEM	0	48,102	48,102	0	294,090	0	294,090
317	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND1	ANTE	0	4	4	0	24	0	24
318	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND1	BRDY	0	63,246	63,246	0	387,635	0	387,635
319	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND1	JEFF	0	16,204	16,204	0	97,648	0	97,648
320	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND1	YTP	0	3,619	3,619	0	21,864	0	21,864
321	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND2	BRDY	0	11,634	11,634	0	70,539	0	70,539
322	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND2	JEFF	0	4,568	4,568	0	27,748	0	27,748
323	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND2	YTP	0	1,003	1,003	0	6,059	0	6,059
324	Morgan Stanley Capital Group, Inc.	GWA	PPW	SFP	MONTANA OATT	GLWND1	BRDY	0	7,728	7,728	0	46,698	0	46,698
325	Morgan Stanley Capital Group, Inc.	GWA	PPW	SFP	MONTANA OATT	GLWND1	JEFF	0	1,272	1,272	0	7,685	0	7,685
326	Morgan Stanley Capital Group, Inc.	GWA	PPW	SFP	MONTANA OATT	GLWND2	JEFF	0	768	768	0	4,640	0	4,640
327	Morgan Stanley Capital Group, Inc.	GWA	PPW	SFP	MONTANA OATT	GLWND2	YTP	0	1,056	1,056	0	6,380	0	6,380
328	Morgan Stanley Capital Group, Inc.	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT	0	164,429	164,429	0	1,005,628	0	1,005,628
329	Morgan Stanley Capital Group, Inc.	NWMT	AVA	SFP	MONTANA OATT	MATL.NWMT	AVAT.NWMT	0	2,160	2,160	0	13,050	0	13,050
330	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT	0	1	1	0	6	0	6
331	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	415,354	415,354	0	2,513,154	0	2,513,154
332	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	(blank)	(blank)	0	2,229	2,229	0	13,185	0	13,185
333	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	MATL.NWMT	GLWND1	0	8,857	8,857	0	54,463	0	54,463
334	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	MATL.NWMT	GLWND2	0	2,855	2,855	0	17,534	0	17,534
335	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	MATL.NWMT	0	2,920	2,920	0	18,112	0	18,112
336	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	SFP	MONTANA OATT	COLSTRIP	MATL.NWMT	0	480	480	0	2,980	0	2,980
337	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	SFP	MONTANA OATT	KERR	MATL.NWMT	0	600	600	0	3,625	0	3,625
338	Morgan Stanley Capital Group, Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	ANTE	0	266	266	0	1,607	0	1,607
339	Morgan Stanley Capital Group, Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	30,393	30,393	0	184,848	0	184,848
340	Morgan Stanley Capital Group, Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	JEFF	0	16,593	16,593	0	100,407	0	100,407
341	Morgan Stanley Capital Group, Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	YTP	0	9,994	9,994	0	60,378	0	60,378
342	Morgan Stanley Capital Group, Inc.	NWMT	PACE	SFP	MONTANA OATT	MATL.NWMT	JEFF	0	1,872	1,872	0	11,310	0	11,310
343	Morgan Stanley Capital Group, Inc.	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	CROSSOVER	0	250	250	0	1,510	0	1,510
344	Morgan Stanley Capital Group, Inc.	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT	0	2,725	2,725	0	16,750	0	16,750
345	Morgan Stanley Capital Group, Inc.	PPW	AVA	NF	MONTANA OATT	BRDY	AVAT.NWMT	0	200	200	0	1,242	0	1,242
346	Morgan Stanley Capital Group, Inc.	PPW	AVA	NF	MONTANA OATT	YTP	AVAT.NWMT	0	192	192	0	1,160	0	1,160
347	Morgan Stanley Capital Group, Inc.	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT	0	600	600	0	3,725	0	3,725
348	Morgan Stanley Capital Group, Inc.	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT	0	20	20	0	121	0	121
349	Morgan Stanley Capital Group, Inc.	PPW	PPW	NF	MONTANA OATT	JEFF	ANTE	0	105	105	0	634	0	634
350	Morgan Stanley Capital Group, Inc.	PPW	PPW	NF	MONTANA OATT	JEFF	BRDY	0	480	480	0	2,900	0	2,900
351	Morgan Stanley Capital Group, Inc.	PPW	PPW	NF	MONTANA OATT	YTP	BRDY	0	62	62	0	374	0	374
352	Morgan Stanley Capital Group, Inc.	PPW	PPW	NF	MONTANA OATT	YTP	JEFF	0	114	114	0	689	0	689
353	Morgan Stanley Capital Group, Inc.	WAPA	AVA	NF	MONTANA OATT	GREATFALLS	AVAT.NWMT	0	7,900	7,900	0	48,445	0	48,445
354	Morgan Stanley Capital Group, Inc.	WAPA	BPAT	NF	MONTANA OATT	GREATFALLS	BPAT.NWMT	0	11,203	11,203	0	68,043	0	68,043
355	Morgan Stanley Capital Group, Inc.	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	ANTE	0	6	6	0	36	0	36
356	Morgan Stanley Capital Group, Inc.	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	BRDY	0	5,751	5,751	0	34,988	0	34,988
357	Morgan Stanley Capital Group, Inc.	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	JEFF	0	1,057	1,057	0	6,504	0	6,504
358	Morgan Stanley Capital Group, Inc.	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	YTP	0	308	308	0	1,860	0	1,860
359	Morgan Stanley Capital Group, Inc.	WAUW	NWMT	NF	MONTANA OATT	GREATFALLS	MATL.NWMT	0	18,901	18,901	0	116,858	0	116,858
360	Naturener Power Watch, LLC	GWA	GWA	SFP	MONTANA OATT	GLWND1	GLWND2	0	43,800	43,800	0	267,050	0	267,050
361	PacifiCorp	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	COLSTRIP	0	478	478	0	2,902	0	2,902
362	PacifiCorp	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	JEFF	0	104	104	0	646	0	646
363	PacifiCorp	NWMT	BPAT	NF	MONTANA OATT	NWMTIMBALANC	BPAT.NWMT	0	30	30	0	181	0	181
364	PacifiCorp	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP	0	5,432	5,432	0	32,818	0	32,818
365	PacifiCorp	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	YTP	0	8,856	8,856	0	53,505	0	53,505
366	PacifiCorp	PACE	NWMT	NF	MONTANA OATT	YTP	COLSTRIP	0	46	46	0	286	0	286
367	PacifiCorp	PPW	NWMT	NF	MONTANA OATT	MLCK	JEFF	0	5,070	5,070	0	31,477	0	31,477
368	PacifiCorp	PPW	NWMT	SFP	MONTANA OATT	MLCK	JEFF	0	1,248	1,248	0	7,748	0	7,748
369	Phillips 66 Energy Trading, LLC	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	277	277	0	1,674	0	1,674
370	Phillips 66 Energy Trading, LLC	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	JEFF	0	80	80	0	483	0	483
371	Phillips 66 Energy Trading, LLC	AVA	PPW	SFP	MONTANA OATT	AVAT.NWMT	JEFF	0	528	528	0	3,190	0	3,190
372	Phillips 66 Energy Trading, LLC	NWMT	AVA	SFP	MONTANA OATT	MATL.NWMT	AVAT.NWMT	0	202,974	202,974	0	1,232,530	0	1,232,530
373	Phillips 66 Energy Trading, LLC	NWMT	NWMT	SFP	MONTANA OATT	COLSTRIP	NWMT.SYSTEM	0	384	384	0	2,360	0	2,360
374	Phillips 66 Energy Trading, LLC	NWMT	NWMT	SFP	MONTANA OATT	MATL.NWMT	GTFALLSNWMT	0	24	24	0	145	0	145
375	Phillips 66 Energy Trading, LLC	NWMT	PACE	SFP	MONTANA OATT	MATL.NWMT	JEFF	0	66,000	66,000	0	398,230	0	398,230
376	Phillips 66 Energy Trading, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	JEFF	0	1	1	0	6	0	6
377	Phillips 66 Energy Trading, LLC	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	JEFF	0	48	48	0	290	0	290
378	Phillips 66 Energy Trading, LLC	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	YTP	0	24	24	0	145	0	145
379	Phillips 66 Energy Trading, LLC	PPW	AVA	LFP	MONTANA OATT	BRDY	AVAT.NWMT	26	224,400	224,400	1,353,945	0	0	1,353,945
380	Phillips 66 Energy Trading, LLC	PPW	AVA	NF	MONTANA OATT	BRDY	AVAT.NWMT	0	155	155	0	963	0	963
381	Phillips 66 Energy Trading, LLC	PPW	AVA	SFP	MONTANA OATT	BRDY	AVAT.NWMT	0	127,440	127,440	0	801,633	0	801,633
382	Phillips 66 Energy Trading, LLC	PPW	AVA	SFP	MONTANA OATT	JEFF	AVAT.NWMT	0	3,696	3,696	0	22,990	0	22,990
383	Portland General Electric Company	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	3,277	3,277	0	19,966	0	19,966
384	Portland General Electric Company	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	COLSTRIP	0	1,560	1,560	0	9,514	0	9,514
385	Portland General Electric Company	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	1,759	1,759	0	10,647	0	10,647
386	Portland General Electric Company	NWMT	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	3,803	3,803	0	23,436	0	23,436
387	Portland General Electric Company	NWMT	BPAT	LFP	MONTANA OATT	CLEARWATER	BPAT.NWMT	297	2,603,924	2,603,924	15,881,813	0	0	15,881,813
388	Portland General Electric Company	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT	0	8,797	8,797	0	54,019	0	54,019
389	Portland General Electric Company	NWMT	NWMT	LFP	MONTANA OATT	COLSTRIP	TOWNSEND	3	23,776	23,776	140,637	0	0	140,637
390	Portland General Electric Company	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	MATL.NWMT	0	1,325	1,325	0	8,224	0	8,224
391	Portland General Electric Company	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	TOWNSEND	0	404	404	0	2,440	0	2,440
392	Portland General Electric Company	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY	0	2,290	2,290	0	13,991	0	13,991
393	Portland General Electric Company	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	JEFF	0	645	645	0	4,001	0	4,001
394	Powerex Corporation	AVA	BPAT	NF	MONTANA OATT	AVAT.NWMT	BPAT.NWMT	0	5	5	0	31	0	31
395	Powerex Corporation	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT	0	410	410	0	2,476	0	2,476
396	Powerex Corporation	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP	0	3,787	3,787	0	22,873	0	22,873
397	Powerex Corporation	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER	0	181	181	0	1,093	0	1,093
398	Powerex Corporation	BPAT	GWA	NF	MONTANA OATT	BPAT.NWMT	GLWND1	0	377	377	0	2,277	0	2,277
399	Powerex Corporation	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	7,212	7,212	0	43,693	0	43,693
400	Powerex Corporation	BPAT	PPW	LFP	MONTANA OATT	BPAT.NWMT	BRDY	78	683,160	683,160	4,172,239	0	0	4,172,239
401	Powerex Corporation	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY	0	300	300	0	1,812	0	1,812
402	Powerex Corporation	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	33,011	33,011	0	199,974	0	199,974
403	Powerex Corporation	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	5,388	5,388	0	32,589	0	32,589
404	Powerex Corporation	GWA	NWMT	NF	MONTANA OATT	GLWND1	MATL.NWMT	0	1	1	0	6	0	6
405	Powerex Corporation	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT	0	42	42	0	254	0	254
406	Powerex Corporation	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	3,858	3,858	0	23,302	0	23,302
407	Powerex Corporation	NWMT	NWMT	NF	MONTANA OATT	MATL.NWMT	MLCK	0	52	52	0	314	0	314
408	Powerex Corporation	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	ANTE	0	1	1	0	6	0	6
409	Powerex Corporation	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT	0	146	146	0	882	0	882
410	Powerex Corporation	PACE	NWMT	NF	MONTANA OATT	JEFF	MATL.NWMT	0	219	219	0	1,323	0	1,323
411	Powerex Corporation	PPW	AVA	NF	MONTANA OATT	JEFF	AVAT.NWMT	0	368	368	0	2,274	0	2,274
412	Powerex Corporation	PPW	AVA	NF	MONTANA OATT	MLCK	AVAT.NWMT	0	445	445	0	2,763	0	2,763
413	Powerex Corporation	PPW	AVA	NF	MONTANA OATT	YTP	AVAT.NWMT	0	144	144	0	870	0	870
414	Powerex Corporation	PPW	BPAT	NF	MONTANA OATT	JEFF	BPAT.NWMT	0	2	2	0	12	0	12
415	Powerex Corporation	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT	0	450	450	0	2,791	0	2,791
416	Powerex Corporation	PPW	WAPA	NF	MONTANA OATT	BRDY	CROSSOVER	0	52	52	0	323	0	323
417	Powerex Corporation	WAPA	AVA	NF	MONTANA OATT	CROSSOVER	AVAT.NWMT	0	255	255	0	1,540	0	1,540
418	Powerex Corporation	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	2,050	2,050	0	12,383	0	12,383
419	Powerex Corporation	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	1,007	1,007	0	6,191	0	6,191
420	Powerex Corporation	WAUW	NWMT	NF	MONTANA OATT	GREATFALLS	MATL.NWMT	0	128	128	0	773	0	773
421	Public Service Company of Colorado	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	682	682	0	4,182	0	4,182
422	Puget Sound Energy Marketing	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	1,300	1,300	0	7,865	0	7,865
423	Puget Sound Energy Marketing	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	1,200	1,200	0	7,450	0	7,450
424	Puget Sound Energy Marketing	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	COLSTRIP	0	63	63	0	391	0	391
425	Puget Sound Energy Marketing	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	COLSTRIP	0	1,503	1,503	0	9,166	0	9,166
426	Puget Sound Energy Marketing	NWMT	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	3,168	3,168	0	19,436	0	19,436
427	Puget Sound Energy Marketing	NWMT	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	6,168	6,168	0	37,813	0	37,813
428	Puget Sound Energy Marketing	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT	0	191,017	191,017	0	1,155,740	0	1,155,740
429	Puget Sound Energy Marketing	NWMT	NWMT	LFP	MONTANA OATT	BEAVERCREEK	COLSTRIP	0	0	0	1,123,130	1,123,192	0	62
430	Puget Sound Energy Marketing	NWMT	NWMT	NF	MONTANA OATT	KERR	COLSTRIP	0	112	112	0	696	0	696
431	Puget Sound Energy Marketing	NWMT	NWMT	SFP	MONTANA OATT	BEAVERCREEK	COLSTRIP	0	1,636,800	1,636,800	0	9,876,166	0	9,876,166
432	Puget Sound Energy Marketing	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY	0	121	121	0	731	0	731
433	Puget Sound Energy Marketing	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT	0	57	57	0	344	0	344
434	Rainbow Electric Marketing Corp.	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP	0	100	100	0	621	0	621
435	Rainbow Electric Marketing Corp.	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER	0	418	418	0	2,525	0	2,525
436	Rainbow Electric Marketing Corp.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	1,418	1,418	0	8,574	0	8,574
437	Rainbow Electric Marketing Corp.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	309	309	0	1,919	0	1,919
438	Rainbow Electric Marketing Corp.	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	JEFF	0	600	600	0	3,725	0	3,725
439	Rainbow Electric Marketing Corp.	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	26,098	26,098	0	159,171	0	159,171
440	Rainbow Electric Marketing Corp.	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT	0	203	203	0	1,240	0	1,240
441	Rainbow Electric Marketing Corp.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY	0	517	517	0	3,123	0	3,123
442	Rainbow Electric Marketing Corp.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	JEFF	0	336	336	0	2,070	0	2,070
443	Rainbow Electric Marketing Corp.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP	0	50	50	0	311	0	311
444	Rainbow Electric Marketing Corp.	NWMT	WAPA	NF	MONTANA OATT	COLSTRIP	CROSSOVER	0	18	18	0	112	0	112
445	Rainbow Electric Marketing Corp.	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	CROSSOVER	0	232	232	0	1,401	0	1,401
446	Rainbow Electric Marketing Corp.	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT	0	320	320	0	1,933	0	1,933
447	Rainbow Electric Marketing Corp.	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT	0	266	266	0	1,652	0	1,652
448	Rainbow Electric Marketing Corp.	PPW	NWMT	SFP	MONTANA OATT	JEFF	NWMT.SYSTEM	0	2,112	2,112	0	13,112	0	13,112
449	Rainbow Electric Marketing Corp.	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	23,521	23,521	0	145,283	0	145,283
450	Rainbow Electric Marketing Corp.	PPW	WAPA	SFP	MONTANA OATT	YTP	CROSSOVER	0	3,240	3,240	0	20,115	0	20,115
451	Rainbow Electric Marketing Corp.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	336	336	0	2,029	0	2,029
452	Rainbow Electric Marketing Corp.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	1,519	1,519	0	9,280	0	9,280
453	Rainbow Electric Marketing Corp.	WAUW	NWMT	NF	MONTANA OATT	CROSSOVER	MATL.NWMT	0	332	332	0	2,005	0	2,005
454	Second Foundation US Trading, LLC	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	CROSSOVER	0	63	63	0	391	0	391
455	Shell Energy North America	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	56	56	0	338	0	338
456	Shell Energy North America	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	2,589	2,589	0	15,687	0	15,687
457	Shell Energy North America	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	54	54	0	335	0	335
458	Shell Energy North America	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	2,964	2,964	0	18,058	0	18,058
459	Shell Energy North America	NWMT	AVA	NF	MONTANA OATT	HOLTER	AVAT.NWMT	0	415	415	0	2,577	0	2,577
460	Shell Energy North America	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT	0	1,626	1,626	0	9,957	0	9,957
461	Shell Energy North America	NWMT	BPAT	NF	MONTANA OATT	HOLTER	BPAT.NWMT	0	1,867	1,867	0	11,503	0	11,503
462	Shell Energy North America	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	534	534	0	3,246	0	3,246
463	Shell Energy North America	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	MATL.NWMT	0	78	78	0	484	0	484
464	Shell Energy North America	NWMT	PACE	NF	MONTANA OATT	HOLTER	BRDY	0	390	390	0	2,422	0	2,422
465	Shell Energy North America	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY	0	133	133	0	826	0	826
466	Shell Energy North America	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	532	532	0	3,304	0	3,304
467	Shell Energy North America	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	28	28	0	169	0	169
468	Shell Energy North America	WAPA	NWMT	NF	MONTANA OATT	CROSSOVER	NWMT.SYSTEM	0	54	54	0	328	0	328
469	SociVolta, Inc.	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	CROSSOVER	0	2	2	0	12	0	12
470	TEC Energy Inc.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT	0	854	854	0	5,158	0	5,158
471	TEC Energy Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	21	21	0	130	0	130
472	TEC Energy Inc.	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	CROSSOVER	0	14	14	0	85	0	85
473	TEC Energy Inc.	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT	0	832	832	0	5,144	0	5,144
474	TEC Energy Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY	0	45	45	0	272	0	272
475	Tenaska Power Services Co.	NWMT	AVA	NF	MONTANA OATT	HARDIN	AVAT.NWMT	0	135	135	0	815	0	815
476	Tenaska Power Services Co.	NWMT	AVA	SFP	MONTANA OATT	HARDIN	AVAT.NWMT	0	4,992	4,992	0	30,160	0	30,160
477	Tenaska Power Services Co.	NWMT	BPAT	NF	MONTANA OATT	HARDIN	BPAT.NWMT	0	207	207	0	1,250	0	1,250
478	Tenaska Power Services Co.	NWMT	NWMT	NF	MONTANA OATT	HARDIN	NWMT.SYSTEM	0	146	146	0	886	0	886
479	Tenaska Power Services Co.	NWMT	NWMT	SFP	MONTANA OATT	HARDIN	COLSTRIP	0	5	5	0	0	0	0
480	Tenaska Power Services Co.	NWMT	NWMT	SFP	MONTANA OATT	HARDIN	NWMT.SYSTEM	0	3,504	3,504	0	22,010	0	22,010
481	Tenaska Power Services Co.	NWMT	PACE	NF	MONTANA OATT	HARDIN	JEFF	0	68	68	0	415	0	415
482	Tenaska Power Services Co.	NWMT	PPW	NF	MONTANA OATT	HARDIN	BRDY	0	16,095	16,095	0	98,767	0	98,767
483	Tenaska Power Services Co.	NWMT	PPW	SFP	MONTANA OATT	HARDIN	BRDY	0	1,464	1,464	0	9,089	0	9,089
484	The Energy Authority	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	165	165	0	997	0	997
485	The Energy Authority	AVA	BPAT	NF	MONTANA OATT	AVAT.NWMT	BPAT.NWMT	0	37	37	0	230	0	230
486	The Energy Authority	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	GTFALLSNWMT	0	10	10	0	62	0	62
487	The Energy Authority	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	NWMT.SYSTEM	0	40	40	0	248	0	248
488	The Energy Authority	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER	0	156	156	0	969	0	969
489	The Energy Authority	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT	0	1,404	1,404	0	8,511	0	8,511
490	The Energy Authority	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	GTFALLSNWMT	0	75	75	0	466	0	466
491	The Energy Authority	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	400	400	0	2,482	0	2,482
492	The Energy Authority	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY	0	392	392	0	2,423	0	2,423
493	The Energy Authority	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	JEFF	0	277	277	0	1,691	0	1,691
494	The Energy Authority	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	420	420	0	2,584	0	2,584
495	The Energy Authority	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	9,157	9,157	0	56,021	0	56,021
496	The Energy Authority	NWMT	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT	0	275	275	0	1,661	0	1,661
497	The Energy Authority	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT	0	458	458	0	2,766	0	2,766
498	The Energy Authority	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	2,287	2,287	0	14,202	0	14,202
499	The Energy Authority	NWMT	BPAT	NF	MONTANA OATT	NWMTIMBALANC	BPAT.NWMT	0	13	13	0	79	0	79
500	The Energy Authority	NWMT	NWMT	NF	MONTANA OATT	DAVEGATES	NWMT.SYSTEM	0	27	27	0	163	0	163
501	The Energy Authority	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	190	190	0	1,180	0	1,180
502	The Energy Authority	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	JEFF	0	94	94	0	584	0	584
503	The Energy Authority	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	ANTE	0	72	72	0	435	0	435
504	The Energy Authority	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY	0	80	80	0	483	0	483
505	The Energy Authority	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP	0	40	40	0	242	0	242
506	The Energy Authority	NWMT	WAPA	NF	MONTANA OATT	COLSTRIP	CROSSOVER	0	104	104	0	628	0	628
507	The Energy Authority	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT	0	422	422	0	2,587	0	2,587
508	The Energy Authority	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT	0	372	372	0	2,272	0	2,272
509	The Energy Authority	PPW	NWMT	NF	MONTANA OATT	MLCK	NWMT.SYSTEM	0	27	27	0	163	0	163
510	The Energy Authority	PPW	PPW	NF	MONTANA OATT	YTP	JEFF	0	145	145	0	884	0	884
511	The Energy Authority	PPW	WAPA	NF	MONTANA OATT	BRDY	CROSSOVER	0	1,253	1,253	0	7,778	0	7,778
512	The Energy Authority	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	2,955	2,955	0	18,170	0	18,170
513	The Energy Authority	WAPA	AVA	NF	MONTANA OATT	CROSSOVER	AVAT.NWMT	0	384	384	0	2,385	0	2,385
514	The Energy Authority	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	7,425	7,425	0	45,143	0	45,143
515	The Energy Authority	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	ANTE	0	90	90	0	544	0	544
516	The Energy Authority	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	JEFF	0	2,099	2,099	0	12,922	0	12,922
517	The Energy Authority	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	12,659	12,659	0	77,210	0	77,210
518	Transalta Energy Marketing (US) Inc.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	NWMT.SYSTEM	0	150	150	0	906	0	906
519	Transalta Energy Marketing (US) Inc.	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER	0	52	52	0	314	0	314
520	Transalta Energy Marketing (US) Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	GTFALLSNWMT	0	160	160	0	994	0	994
521	Transalta Energy Marketing (US) Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT	0	338	338	0	2,090	0	2,090
522	Transalta Energy Marketing (US) Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM	0	1,858	1,858	0	11,371	0	11,371
523	Transalta Energy Marketing (US) Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP	0	1,543	1,543	0	9,449	0	9,449
524	Transalta Energy Marketing (US) Inc.	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	13,958	13,958	0	85,296	0	85,296
525	Transalta Energy Marketing (US) Inc.	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	GREATFALLS	0	20	20	0	124	0	124
526	Transalta Energy Marketing (US) Inc.	BPAT	WAPA	SFP	MONTANA OATT	BPAT.NWMT	CROSSOVER	0	10,512	10,512	0	64,290	0	64,290
527	Transalta Energy Marketing (US) Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT	0	69,453	69,453	0	419,631	0	419,631
528	Transalta Energy Marketing (US) Inc.	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	MATL.NWMT	0	160	160	0	994	0	994
529	Transalta Energy Marketing (US) Inc.	NWMT	NWMT	NF	MONTANA OATT	MATL.NWMT	GTFALLSNWMT	0	20	20	0	124	0	124
530	Transalta Energy Marketing (US) Inc.	NWMT	NWMT	NF	MONTANA OATT	MATL.NWMT	MLCK	0	1	1	0	6	0	6
531	Transalta Energy Marketing (US) Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY	0	565	565	0	3,496	0	3,496
532	Transalta Energy Marketing (US) Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	JEFF	0	240	240	0	1,490	0	1,490
533	Transalta Energy Marketing (US) Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	YTP	0	1,890	1,890	0	11,416	0	11,416
534	Transalta Energy Marketing (US) Inc.	NWMT	WAUW	NF	MONTANA OATT	MATL.NWMT	CROSSOVER	0	3,997	3,997	0	24,142	0	24,142
535	Transalta Energy Marketing (US) Inc.	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT	0	36,078	36,078	0	230,553	0	230,553
536	Transalta Energy Marketing (US) Inc.	PPW	NWMT	NF	MONTANA OATT	YTP	NWMT.SYSTEM	0	11	11	0	66	0	66
537	Transalta Energy Marketing (US) Inc.	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	321	321	0	1,993	0	1,993
538	Transalta Energy Marketing (US) Inc.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT	0	2,215	2,215	0	13,420	0	13,420
539	Transalta Energy Marketing (US) Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY	0	34	34	0	205	0	205
540	Transalta Energy Marketing (US) Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	3,716	3,716	0	23,071	0	23,071
541	Western Area Power Administration	NWMT	NWMT	NF	MONTANA OATT	CANYONFERRY	NWMT.SYSTEM	0	16	16	0	99	0	99
542	Western Area Power Administration	NWMT	NWMT	SFP	MONTANA OATT	CANYONFERRY	NWMT.SYSTEM	0	9,312	9,312	0	55,944	0	55,944
543	Western Area Power Administration	NWMT	WAPA	NF	MONTANA OATT	CANYONFERRY	CROSSOVER	0	845	845	0	5,247	0	5,247
544	Western Area Power Administration	NWMT	WAPA	NF	MONTANA OATT	CANYONFERRY	GREATFALLS	0	2,332	2,332	0	14,098	0	14,098
545	Western Area Power Administration	NWMT	WAPA	NF	MONTANA OATT	COLSTRIP	CROSSOVER	0	160	160	0	966	0	966
546	Western Area Power Administration	NWMT	WAPA	SFP	MONTANA OATT	CANYONFERRY	CROSSOVER	0	328,322	328,322	0	2,003,836	0	2,003,836
547	Western Area Power Administration	NWMT	WAPA	SFP	MONTANA OATT	CANYONFERRY	GREATFALLS	0	8,664	8,664	0	52,345	0	52,345
548	Western Area Power Administration	NWMT	WAUW	SFP	MONTANA OATT	COLSTRIP	GREATFALLS	0	2,784	2,784	0	17,084	0	17,084
549	Western Area Power Administration	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER	0	538	538	0	3,339	0	3,339
550	Western Area Power Administration	PPW	WAPA	SFP	MONTANA OATT	YTP	CROSSOVER	0	373,411	373,411	0	2,278,343	0	2,278,343
551	Western Area Power Administration	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP	0	16,452	16,452	0	100,461	0	100,461
552	Western Area Power Administration	WAPA	PPW	SFP	MONTANA OATT	CROSSOVER	YTP	0	314,275	314,275	0	1,911,960	0	1,911,960
553	Western Area Power Administration	WAPA	WAPA	LFP	MONTANA OATT	CROSSOVER	GREATFALLS	10	87,600	87,600	534,082	0	0	534,082
554	Western Area Power Administration	WAPA	WAPA	LFP	MONTANA OATT	GREATFALLS	CROSSOVER	20	175,200	175,200	1,068,163	0	0	1,068,163
555	Western Area Power Administration	WAUW	NWMT	SFP	MONTANA OATT	GREATFALLS	GTFALLSNWMT	0	17,520	17,520	0	106,820	0	106,820
556	Rounding							0			1	4	0	3
557	Total							1,586	16,546,779	16,546,779	69,983,959	35,716,980	0	105,700,939
35	TOTAL

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Vigilante Elec Coop	OLF	24,823	24,823	50,400	0	0	50,400
2	Bonneville Power Administration	OLF	0	0	0	0	(a) 3,552,023	3,552,023
3	Sun River Elect Coop	FNS	3,929	3,929	21,608	0	0	21,608
4	Southwest Power Pool	FNS	111,072	111,072	1,262,954	0	0	1,262,954
5	Talen Montana	OLF	0	0	0	45,445	0	45,445
6	Supply							0
7	Avista	NF	3,358	3,358	0	29,225	0	29,225
8	Bonneville Power Administration	NF	435,768	435,768	0	1,260,574	0	1,260,574
9	Shell Energy North America	NF	400	400	0	700	0	700
10	Idaho Power Company	NF	4,733	4,733	0	28,288	0	28,288
11	Snohomish County PUD	NF	1,857	1,857	0	3,125	0	3,125
12	Seattle City Light	NF	4,002	4,002	0	7,004	0	7,004
	TOTAL		589,942	589,942	1,334,962	1,374,361	3,552,023	6,261,346

FOOTNOTE DATA

(a) Concept: OtherChargesTransmissionOfElectricityByOthers

Monthly system usage fee

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	271,307
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	143,131
5	OtherMiscellaneousGeneralExpenses Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
6	Universal Systems Benefits Charge	10,238,483
7	Board of Directors	1,458,013
8	Amortization of Upfront Fees	217,835
9	Our Portion of Shared Generation	1,905,851
10	Human Resources General Expenses (non-labor and not provided elsewhere)	13,257
11	Miscellaneous	76,700
46	MiscellaneousGeneralExpenses TOTAL	(a)(b) 14,171,177

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: MiscellaneousGeneralExpenses

	12/31/2025
Universal System Benefits Charge	10,238,483
Our Portion of Shared Ownership Gen	1,905,851
Uncollectible Accounts
Subtotal	12,144,334


Board of Directors Fees	1,458,013
Amortization of upfront fees	217,835
Industry & Association Dues	271,307
Human Resources general expenses (non-labor and not provided for elsewhere)	13,257
Miscellaneous	-76,700
Shareholder Expenses	143,131
Subtotal	2,026,843

Total Account 930.2	14,171,177

(b) Concept: MiscellaneousGeneralExpenses

Montana Operations Miscellaneous General Expenses account 930.2 includes $106,778 of Electric non-allowed Industry and Association Dues, which is removed for rate making purposes.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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			375,612		375,612
2	Steam Production Plant	4,729,352				4,729,352
3	Nuclear Production Plant					0
4	Hydraulic Production Plant-Conventional	12,380,270		219,663		12,599,933
5	Hydraulic Production Plant-Pumped Storage					0
5.1	Solar Production Plant	249,469				249,469
5.2	Wind Production Plant	4,797,590		2,038		4,799,628
5.3	Other Renewable Production Plant					0
6	Other Production Plant	14,360,927		10,318		14,371,245
7	Transmission Plant	32,208,046		2,337,155		34,545,201
8	Distribution Plant	63,666,009		1,354,011		65,020,020
9	Regional Transmission and Market Operation					0
9.1	Energy Storage Plant	611,830				611,830
10	General Plant	4,528,056		54,099		4,582,155
11	Common Plant-Electric	3,871,425		5,576,071		9,447,496
12	TOTAL	141,402,974	0	(a) 9,928,967	0	151,331,941

B. Basis for Amortization Charges
The basis used to compute the charges is the ending plant balance. The basis is different from the preceding year due to net plant additions throughout the year and the addition of new software accounts pursuant to FERC Order 898. For our Montana operations, the rates used to compute amortization charges for 'Intangible Plant - Electric' (Account 404) are as follows: 302 Intangible Plant: Franchises and Consents 2.00%; 303 Intangible Plant: Five Year Software 20%; 334.2 Hydro 5 Year Software 20%; 338.31 Wind Production 5 Year Software 20%; 340.2 Intangible Plant: Other Production Land Rights 3.34%; 345.2 Other Production Software 20%; 350.2 Intangible Plant: Transmission Land Rights 1.61%; 354.21 Transmission 10 Year Software 10%; 354.25 Transmission 5 Year Software 20%; 360.2 Intangible Plant: Distribution Land Rights (0.79%); 363.21 Distribution 10 Year Software 10%; 363.25 Distribution 5 Year Software 20%; 397.21 General Plant 10 Year Software 10%; 397.25 General Plant 5 Year Software 20%; 4303.5 Intangible Plant: Five Year Common Software 20%; and 4303.1 Intangible Plant: Ten Year Common Software 10%. Common amortization expense is allocated to 72% to electric and 28% to gas based on allocation studies.

	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
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

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: AmortizationOfLimitedTermPlantOrProperty

The following represents transmission and distribution land rights and computer software amortization applicable to or allocated to the electric department. These costs are amortized over the expected life of the transmission or distribution plant or computer software

Plant	Costs Being	Amortization Period	Annual	Allocated to
Account	Amortized	(Years)	Amortization	Electric

302	22,457,191	50	375,612	375,612
334.2	1,098,316	5	219,663	219,663
338.1	-	5	-	-
338.31	10,188	5	2,038	2,038
340.2	9,604	30	321	321
345.2	49,987	5	9,997	9,997
350.2	36,259,576	62	583,779	583,779
351.21	-	10	-	-
351.25	8,766,879	5	1,753,376	1,753,376
360.2	4,346,460	127	34,342	34,342
363.21	5,687,532	10	568,753	568,753
363.25	3,754,580	5	750,916	750,916
397.21	-	10	-	-
397.25	270,496	5	54,099	54,099
4303	50,008,186	5,10	7,744,543	5,576,071

	132,718,995		12,097,439	9,928,967

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	FERC Order No. 472	1,981,752		1,981,752		Electric	928	1,981,752
2	Montana PSC Electric & Gas Rate Filings		307,073	307,073		Electric	928	307,073
3	Montana PSC Electric & Gas Rate Filings		46,338	46,338		Gas	928	46,338
4	Generating Stations Under Project License	2,176,450		2,176,450		Electric	928	2,176,450
46	TOTAL	4,158,201	353,411	(a) 4,511,613	0			4,511,613

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: RegulatoryCommissionExpensesAmount

Montana electric regulatory commission expense totaled $4,465,275 for 2025. This includes $1,981,751 in expenses that are transmission specific.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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
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

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	8,929,588
4	SalariesAndWagesElectricOperationTransmission Transmission	7,690,507
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
5.1	SalariesAndWagesElectricOperationEnergyStorage Energy Storage	1,539
6	SalariesAndWagesElectricOperationDistribution Distribution	11,284,899
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	5,877,965
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	969,841
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	29,734,568
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	64,488,907
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	2,083,448
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	2,057,118
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
15.1	SalariesAndWagesElectricMaintenanceEnergyStorage Energy Storage	1,059
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	11,333,668
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	3,370,132
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	18,845,425
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	11,013,036
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	9,747,625
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)	2,598
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	22,618,567
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	5,877,965
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	969,841
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	33,104,700
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	83,334,332		83,334,332
29	SalariesAndWagesGasAbstract Gas
30	SalariesAndWagesGasOperationAbstract Operation
31	SalariesAndWagesGasOperationProductionManufacturedGas Production - Manufactured Gas
32	SalariesAndWagesGasOperationProductionNaturalGas Production-Nat. Gas (Including Expl. And Dev.)	1,492,895
33	SalariesAndWagesGasOperationOtherGasSupply Other Gas Supply	69,275
34	SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing Storage, LNG Terminaling and Processing	531,992
35	SalariesAndWagesGasOperationTransmission Transmission	4,947,936
36	SalariesAndWagesGasOperationDistribution Distribution	5,298,063
37	SalariesAndWagesGasCustomerAccounts Customer Accounts	2,093,183
38	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational	320,902
39	SalariesAndWagesGasSales Sales
40	SalariesAndWagesGasOperationAdministrativeAndGeneral Administrative and General	10,041,758
41	SalariesAndWagesGasOperation TOTAL Operation (Enter Total of lines 31 thru 40)	24,796,004
42	SalariesAndWagesGasMaintenanceAbstract Maintenance
43	SalariesAndWagesGasMaintenanceProductionManufacturedGas Production - Manufactured Gas
44	SalariesAndWagesGasMaintenanceProductionNaturalGas Production-Natural Gas (Including Exploration and Development)	138,091
45	SalariesAndWagesGasMaintenanceOtherGasSupply Other Gas Supply
46	SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing	181,630
47	SalariesAndWagesGasMaintenanceTransmission Transmission	1,008,619
48	SalariesAndWagesGasMaintenanceDistribution Distribution	2,272,626
49	SalariesAndWagesGasMaintenanceAdministrativeAndGeneral Administrative and General	1,542,765
50	SalariesAndWagesGasMaintenance TOTAL Maint. (Enter Total of lines 43 thru 49)	5,143,731
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,	1,630,986
54	SalariesAndWagesGasOtherGasSupply Other Gas Supply (Enter Total of lines 33 and 45)	69,275
55	SalariesAndWagesGasStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing (Total of lines 31 thru	713,622
56	SalariesAndWagesGasTransmission Transmission (Lines 35 and 47)	5,956,555
57	SalariesAndWagesGasDistribution Distribution (Lines 36 and 48)	7,570,689
58	SalariesAndWagesGasCustomerAccounts Customer Accounts (Line 37)	2,093,183
59	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational (Line 38)	320,902
60	SalariesAndWagesGasSales Sales (Line 39)
61	SalariesAndWagesGasAdministrativeAndGeneral Administrative and General (Lines 40 and 49)	11,584,523
62	SalariesAndWagesGasOperationAndMaintenance TOTAL Operation and Maint. (Total of lines 52 thru 61)	29,939,735		29,939,735
63	SalariesAndWagesOtherUtilityDepartmentsAbstract Other Utility Departments
64	SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance Operation and Maintenance	52,579		52,579
65	SalariesAndWagesOperationsAndMaintenance TOTAL All Utility Dept. (Total of lines 28, 62, and 64)	113,326,646		113,326,646
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	24,627,423		24,627,423
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant	9,926,623		9,926,623
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):	8,504,768		8,504,768
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	43,058,814		43,058,814
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription A/R ASSOCIATED COMPANIES (ACCT 146)	10,590,282
79	SalariesAndWagesOtherAccountsDescription EXPENSES OF NON-UTILITY OP (ACCT 417)	1,123,670
80	SalariesAndWagesOtherAccountsDescription
81	SalariesAndWagesOtherAccountsDescription
82	SalariesAndWagesOtherAccountsDescription
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	11,713,952		11,713,952
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	168,099,412		168,099,412

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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.

Item # 1
Common Utility Plant At December 31, 2025

PLANT
ACCOUNT	Description	Total	Electric	Natural Gas


C303	Misc. Intangible Plant	52,518,455.00	38,338,472.00	14,179,983.00

C389	Land & Land Rights	5,024,807.00	3,488,315.00	1,536,492.00

C390	Structures & Improvements	91,607,843.00	65,448,412.00	26,159,432.00

C391	Office Furniture & Equipment	17,223,648.00	12,592,953.00	4,630,694.00

C392	Transportation Equipment	6,723,590.00	4,908,221.00	1,815,369.00

C393	Stores Equipment	-	-	-

C394	Tools/Shop/Garage Equipment	208,374.00	153,392.00	54,982.00

C395	Laboratory Equipment	-	-	-

C396	Power Operated Equipment	-	-	-

C397	Communication Equipment	36,239,377.00	20,328,653.00	15,910,724.00

C398	Miscellaneous	2,807,963.00	1,992,917.00	815,046.00

Sub -Total		212,354,057.00	147,251,335.00	65,102,722.00


Construction Work In Progress		21,511,248.00


	Total	233,865,305.00



Item # 2
Common Utility Accumulated Depreciation Reserve At December 31, 2025

PLANT
ACCOUNT	Description	Total	Electric	Natural Gas


303	Misc. Intangible Plant	23,299,002.00	17,008,272.00	6,290,730.00
389	Land & Land Rights	(167,415.00)	(118,613.00)	(48,802.00)
390	Structures & Improvements	13,351,483.00	9,381,750.00	3,969,733.00
391	Office Furniture & Equipment	5,614,319.00	4,109,387.00	1,504,932.00
392	Transportation Equipment	2,431,077.00	1,774,686.00	656,391.00
393	Stores Equipment	-	-	-
394	Tools/Shop/Garage Equipment	18,892.00	13,980.00	4,912.00
395	Laboratory Equipment	-	-	-
396	Power Operated Equipment	-	-	-
397	Communication Equipment	21,898,444.00	12,038,383.00	9,860,061.00
398	Miscellaneous	168,215.00	119,433.00	48,782.00

Total		66,614,017.00	44,327,278.00	22,286,739.00



	NORTHWESTERN ENERGY - COMMON UTILITY PLANT EXPENSES FOR THE YEAR ENDING DECEMBER 31, 2025
	ITEM #3

			Real Estate	Depreciation
		General	& Personal	&
	Common Expenses	Building	Property Tax	Amortization	Total

	Electric:

	Depreciation			3,871,425	3,871,425
	Amortization			5,576,071	5,576,071
	Taxes Other than Income		5,895,804		5,895,804
	Administrative & General	2,208,744			2,208,744

	Subtotal	2,208,744	5,895,804	9,447,496	17,552,044

	Natural Gas				6,978,315

	Total Common Expense				24,530,359

(1)General building expense is allocated to departmental expense accounts based on estimated facility utilization.
(2)Real Estate & Personal Property Taxes are allocated to departmental expense accounts based on the estimated facility utilization.
(3)Depreciation & Amortization expense is allocated to utility departmental expense accounts based on the estimated individual facility utilization applicable to the depreciable common plant.

ITEM #4

FERC staff recommendation dated january 19, 1967 gave approval for the use of common plant classification.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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)
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)
4	Transmission Rights
5	Ancillary Services
6	Other Items (list separately)
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:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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				(a) 16,546,778,637	KWh	1,925,781
2	Reactive Supply and Voltage
3	Regulation and Frequency Response				(b) 5,223,997,444	KWh	1,107,982
4	Energy Imbalance	(c) 28,765,059,298		5,555,497
5	Operating Reserve - Spinning				189,055	KW	1,260,604
6	Operating Reserve - Supplement				189,055	kW	1,205,409
7	Other				(d) 397,352,527	KWh	9,264,095
8	Total (Lines 1 thru 7)	28,765,059,298		5,555,497	22,168,506,718		14,763,871

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: AncillaryServicesSoldNumberOfUnits

Transmission Customers are billed under the formula rate as approved in FERC docket ER19-1756. For more information see the NorthWestern Energy OATT see OASIS at https://oasis.oati.com/NWMT

	Number of Units (e)	Units of Measure	Dollars (g)
Scheduling, System Control and Dispatch Network	4,787,592,637	kWh	$ 621,716
Scheduling, System Control and Dispatch Point-to-Point	11,759,186,000	kWh	$ 1,304,065
Total	16,546,778,637	kWh	$ 1,925,781

(b) Concept: AncillaryServicesSoldNumberOfUnits

Transmission Customers are billed under the formula rate as approved in FERC docket ER19-1756. For more information see the NorthWestern Energy OATT see OASIS at https://oasis.oati.com/NWMT

	Number of Units (e)	Units of Measure	Dollars (g)
Regulation and Frequency Response on Load	3,890,466,444	kWh	$ 917,633
Regulation and Frequency Response NON VER Network SCH 3	2,035,000	kW	$ 47,153
Regulation and Frequency Response VER Network SCH 3	20,000	kW	$ 14,728
Regulation and Frequency Response Oasis SCH 3A VER	18,086,000	kWh	$ 11,394
Regulation and Frequency Response Oasis SCH 3A NON VER	1,313,390,000	kWh	$ 117,074
Total	5,223,997,444	kWh	$ 1,107,982

Line No 4 Column e: Energy Imbalance is calculated and charged based on Schedules 4, 4a, 9, 9a, and Attachment P of the NorthWestern OATT. For more information see the NorthWestern Energy OATT Schedule 4, 4a and Attachment P see OASIS at https://oasis.oati.com/NWMT

(d) Concept: AncillaryServicesSoldNumberOfUnits

Other Ancillary Services

		Number of Units (e)	Units of Measure	Dollars (g)
Losses on Load Network Customers		136,838,448	kWh	$ 4,350,939
Losses on Load Point to Point Customers		242,428,079	kWh	$ 4,894,889
Other Flex Reserves Sch 11	Schedule 11	18,086,000	kWh	$ 18,267
Total		397,352,527	kWh	$ 9,264,095

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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: Montana Operations
1	January	1,956	20	19	1,018	699	634	0	1,516	0
2	February	2,046	12	9	1,031	731	634	0	1,204	0
3	March	1,602	3	19	1,044	569	642	0	1,332	0
4	Total for Quarter 1				3,093	1,999	1,910	0	4,052	0
5	April	1,532	4	9	1,047	597	676	0	795	0
6	May	1,623	31	19	1,035	589	676	0	794	0
7	June	1,801	30	19	1,042	630	676	0	688	0
8	Total for Quarter 2				3,124	1,816	2,028	0	2,277	0
9	July	1,984	8	19	1,036	663	676	0	1,731	0
10	August	2,002	19	19	1,030	674	676	0	850	0
11	September	1,782	1	18	1,025	606	676	0	712	0
12	Total for Quarter 3				3,091	1,943	2,028	0	3,293	0
13	October	1,518	29	9	1,022	562	645	0	981	0
14	November	1,759	30	18	1,024	626	645	0	1,277	0
15	December	1,753	28	18	1,025	634	645	0	1,091	0
16	Total for Quarter 4				3,071	1,822	1,935	0	3,349	0
17	Total				12,379	7,580	7,901	0	12,971	0

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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: Enter System
1	January
2	February
3	March
4	Total for Quarter 1
5	April
6	May
7	June
8	Total for Quarter 2
9	July
10	August
11	September
12	Total for Quarter 3
13	October
14	November
15	December
16	Total for Quarter 4
17	Total Year to Date/Year

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2025-12-31

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)	6,399,207
3	Steam	1,434,437	23	Requirements Sales for Resale (See instruction 4, page 311.)
4	Nuclear		24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	854,892
5	Hydro-Conventional	2,160,046	25	Energy Furnished Without Charge
6	Hydro-Pumped Storage		26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)
6.1	Solar		27	Total Energy Losses	594,468
6.2	Wind	125,892	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	7,848,567
7	Other	883,403
8	Less Energy for Pumping
9	Net Generation (Enter Total of lines 3 through 8)	4,603,778
10	Purchases (other than for Energy Storage)	3,245,327
10.1	Purchases for Energy Storage
11	Power Exchanges:
12	Received	32,799
13	Delivered	33,337
14	Net Exchanges (Line 12 minus line 13)	538
15	Transmission For Other (Wheeling)
16	Received	16,546,779
17	Delivered	16,546,779
18	Net Transmission for Other (Line 16 minus line 17)
19	Transmission By Others Losses
20	TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)	7,848,567

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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: Montana Operations
29	January	763,926	97,458	2,590	20	19
30	February	683,130	66,944	2,680	12	9
31	March	751,993	48,148	2,244	3	19
32	April	627,225	73,024	2,208	4	9
33	May	642,562	83,079	2,299	31	19
34	June	606,979	118,782	2,477	30	19
35	July	662,498	95,979	2,660	8	19
36	August	642,985	58,781	2,678	19	19
37	September	578,789	39,612	2,458	1	18
38	October	629,748	45,601	2,163	29	9
39	November	645,337	59,756	2,404	30	18
40	December	613,395	67,728	2,398	28	18
41	Total	7,848,567	854,892

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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: (a) Colstrip 4	Plant Name: DGGS	Plant Name:	Plant Name: Yellowstone Generating Station
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)	(b) Steam	(c) Gas Turbine		(d) Gas Turbine
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)	Boiler	Conventional		Conventional
3	YearPlantOriginallyConstructed Year Originally Constructed	1984	2010		2024
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	1986	2010		2024
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)	241.5	(e) 203.25		175
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)	222	150		175
7	PlantHoursConnectedToLoad Plant Hours Connected to Load	7,015	8,761		8,742
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)	0	150		175
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water	222	150		175
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water	(f) 0	150		175
11	PlantAverageNumberOfEmployees Average Number of Employees	(g) 0	11		(h) 0
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh	1,434,437,000	498,765,000		384,085,000
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights	446,126	1,893,984		1,813,608
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements	28,377,971	22,122,874		40,807,093
15	CostOfEquipmentSteamProduction Equipment Costs	104,308,999	171,513,573		236,201,103
16	AssetRetirementCostsSteamProduction Asset Retirement Costs	20,709,754	0
17	CostOfPlant Total Cost (10-23)	153,842,850	195,530,431		278,821,804
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including	637.03	962.02		1,593.27
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr	66,005	438,742		91,057
20	FuelSteamPowerGeneration Fuel	34,170,982	10,170,396		17,142,093
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)	0	0		0
22	SteamExpensesSteamPowerGeneration Steam Expenses	1,468,608	0		0
23	SteamFromOtherSources Steam From Other Sources	0	0		0
24	SteamTransferredCredit Steam Transferred (Cr)	0	0		0
25	ElectricExpensesSteamPowerGeneration Electric Expenses	235,606	1,309,968		6,388,521
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses	3,092,829	0		0
27	RentsSteamPowerGeneration Rents	0	0		0
28	Allowances Allowances	0	0		0
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering	456,679	0		0
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures	903,306	0		0
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant	8,128,205	0		0
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant	1,875,683	1,788,569		231,158
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant	470,844	0		0
34	PowerProductionExpensesSteamPower Total Production Expenses	50,868,747	13,707,675		23,852,829
35	ExpensesPerNetKilowattHour Expenses per Net kWh	0.035	0.027		0.062

35	FuelKindAxis Plant Name	Colstrip 4	Colstrip 4	DGGS	DGGS
36	FuelKind Fuel Kind	Coal	Oil	Gas	Oil	Gas
37	FuelUnit Fuel Unit	T	bbl	MMBTU	bbl	MMBTU
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned	899,147	3,154	5,820,441	21	3,500,583
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)	8,660	140,000	1,000	140,000	1,000
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year	38	884.38	1.65	127.75	4.44
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned	38	884.38	1.65	127.75	4.44
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	2.02	150.41	1.64	20.66	4.9
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen	(i) 0.024	0.024	0.02	(j) 0.02	0.045
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation	(k) 10,869.615	10,869.615	11,669.959	(l) 11,669.959	9,114.084

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: PlantName

We have included this footnote due to rendering issues on page 404 to ensure information is submitted for our Renewable Generating Plant Statistics.

404 - Schedule - Renewable Generating Plant Statistics (Large Plants)

Line No.	Item (a)	-	Value (b)
0	Plant Name	Renewable Plant Name [Axis]
0.5	Two Dot	Two Dot
1	Kind of Plant (Solar, Wind, Biomass, etc.)		Wind Turbine
2	Type of Constr (PV Tracking, Offshore, Boiler, etc)		Wind Turbine
3	Year Originally Constructed		2014
4	Year Last Unit was Installed		2014
5	Total Installed Cap (Max Gen Name Plate Ratings-MW)		11.28
6	Net Peak Demand on Plant - MW (60 minutes)		11.00
7	Plant Hours Connected to Load		8,760
8	Net Continuous Plant Capability (Megawatts)		11.28
9	Net Generation, Exclusive of Plant Use - KWh		28,547,000.00
10	Cost of Plant: Land and Land Rights		0
11	Structures and Improvements		8,119,540
12	Solar Panels, Wind Turbines and Generators		8,677,867
13	Fuel Holders
14	Boilers
15	Collector System
16	Generator Step-up Transformers (GSU)
17	Inverters
18	Other Accessory Electrical Equipment		2,762,826
19	Computer Hardware
20	Computer Software		10,188
21	Communication Equipment		33,538
22	Miscellaneous Power Plant Equipment
23	Asset Retirement Costs		772,822
24	Total Cost (10-23)		20,376,781
25	Cost per KW of Installed Capacity (line 24/5) Including		1,806.45
26	Production Expenses: Oper, Supv, & Engr		18,158
27	Generation and Other Plant Operating Expenses		439,635
28	Fuel		0
29	Steam Expenses		0
30	Electric Expenses		0
31	Misc Steam Power Expenses		0
32	Rents		59,236
33	Environmental Credits		0
34	Maintenance Supervision and Engineering		0
35	Maintenance of Structures and Equipment		18,118
36	Maintenance of Boiler Plant		0
37	Maintenance of Electric Plant		0
38	Maintenance of Computer Hardware		0
39	Maintenance of Computer Software
40	Maintenance of Communication Equipment		0
41	Maintenance of Misc Plant		0
42	Total Production Expenses		535,147
43	Expenses per Net KWh		0.01870
0	Plant Name	Renewable Plant Name [Axis]
0.5	Two Dot	Spion Kop
1	Kind of Plant (Solar, Wind, Biomass, etc.)		Wind Turbine
2	Type of Constr (PV Tracking, Offshore, Boiler, etc)		Wind Turbine
3	Year Originally Constructed		2012
4	Year Last Unit was Installed		2012
5	Total Installed Cap (Max Gen Name Plate Ratings-MW)		40.00
6	Net Peak Demand on Plant - MW (60 minutes)		40.00
7	Plant Hours Connected to Load		8,759
8	Net Continuous Plant Capability (Megawatts)		40.00
9	Net Generation, Exclusive of Plant Use - KWh		97,345,000.00
10	Cost of Plant: Land and Land Rights		111,793
11	Structures and Improvements		29,214,250
12	Solar Panels, Wind Turbines and Generators		44,801,747
13	Fuel Holders
14	Boilers
15	Collector System
16	Generator Step-up Transformers (GSU)
17	Inverters
18	Other Accessory Electrical Equipment		6,516,384
19	Computer Hardware
20	Computer Software
21	Communication Equipment
22	Miscellaneous Power Plant Equipment		2,582,418
23	Asset Retirement Costs		2,913,994
24	Total Cost (10-23)		86,140,586
25	Cost per KW of Installed Capacity (line 24/5) Including		2,153.51
26	Production Expenses: Oper, Supv, & Engr		69,444
27	Generation and Other Plant Operating Expenses		1,888,132
28	Fuel		0
29	Steam Expenses		0
30	Electric Expenses		0
31	Misc Steam Power Expenses		0
32	Rents		19,001
33	Environmental Credits		0
34	Maintenance Supervision and Engineering		0
35	Maintenance of Structures and Equipment		19,026
36	Maintenance of Boiler Plant		0
37	Maintenance of Electric Plant		154,513
38	Maintenance of Computer Hardware		0
39	Maintenance of Computer Software
40	Maintenance of Communication Equipment		1,092
41	Maintenance of Misc Plant		0
42	Total Production Expenses		2,151,208
43	Expenses per Net KWh		0.02210

(b) Concept: PlantKind

As of 12/31/2025, We owned 30% of Colstrip Unit 4 and have a reciprical sharing agreement with the 30% owner of Colstrip Unit 3 in which we share equally in the ownership benefits and liabilities of each. This page is representative of that agreement.

Designed for regulation service.

(d) Concept: PlantKind

Designed for peak load service.

(e) Concept: InstalledCapacityOfPlant

Total Installed Capacity (Maximum Generation Name Plate Ratings-MW) is 203.25 MW as reported, however because of limitations on the combustion turbines, the maximum installed capacity is 150 MW.

(f) Concept: NetContinuousPlantCapabilityLimitedByCondenserWater

When Limited by Condensor Water with "No Limitation."

(g) Concept: PlantAverageNumberOfEmployees

All plant employees are employed by the plant operator, Talen Montana, LLC.

(h) Concept: PlantAverageNumberOfEmployees

All plant employees are employed by the plant operator, CAT.

(i) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Average cost of all fuels burned per net KWh generated.

(j) Concept: AverageCostOfFuelBurnedPerKilowattHourNetGeneration

Average cost of all fuels burned per net KWh generated.

(k) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Average BTU per net KWh generated for all fuels.

(l) Concept: AverageBritishThermalUnitPerKilowattHourNetGeneration

Average BTU per net KWh generated for all fuels.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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. 0 Plant Name: Common Hydro Plant	FERC Licensed Project No. 1869 Plant Name: Thompson Falls	FERC Licensed Project No. 2188 Plant Name: Black Eagle	FERC Licensed Project No. 2188 Plant Name: Cochrane	FERC Licensed Project No. 2188 Plant Name: Hauser	FERC Licensed Project No. 2188 Plant Name: Holter	FERC Licensed Project No. 2188 Plant Name: Madison	FERC Licensed Project No. 2188 Plant Name: Morony	FERC Licensed Project No. 2188 Plant Name: Rainbow	FERC Licensed Project No. 2188 Plant Name: Ryan	FERC Licensed Project No. 2301 Plant Name: Mystic Lake
1	PlantKind Kind of Plant (Run-of-River or Storage)		Storage	Run-of-River	Run-of-River	Run-of-River	Run-of-River	Run-of-River	Run-of-River	Run-of-River	Run-of-River	Storage
2	PlantConstructionType Plant Construction type (Conventional or Outdoor)		Conventional	Conventional	Semi-Outdoor	Conventional	Conventional	Conventional	Semi-Outdoor	Conventional	Conventional	Conventional
3	YearPlantOriginallyConstructed Year Originally Constructed		1915	1927	1958	1907	1918	1903	1930	1915	1915	1925
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed		1995	2023	2025	2022	2023	2022	1930	2014	2020	2007
5	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)		92.37	23.90	48.90	20.28	53.6	12.68	46.5	58.95	55.20	12
6	NetPeakDemandOnPlant Net Peak Demand on Plant-Megawatts (60 minutes)		94	25	64.2	22.2	55.8	11	48	64	72	12
7	PlantHoursConnectedToLoad Plant Hours Connect to Load		8,760	8,760	8,760	8,760	8,760	8,760	8,760	8,760	8,760	8,760
8	NetPlantCapabilityAbstract Net Plant Capability (in megawatts)
9	NetPlantCapabilityUnderMostFavorableOperatingConditions (a) Under Most Favorable Oper Conditions		95	25	64.2	22.2	55.8	12.68	49	64	72	12
10	NetPlantCapabilityUnderMostAdverseOperatingConditions (b) Under the Most Adverse Oper Conditions		20	2	11	10	19	3	10	18	23	1
11	PlantAverageNumberOfEmployees Average Number of Employees		5	5	5	3	3	4	4	5	4	3
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh		439,753,000	110,292,000	215,322,000	128,407,000	247,542,000	75,588,000	214,712,000	298,642,000	377,332,000	52,456,000
13	CostOfPlantAbstract Cost of Plant
14	CostOfLandAndLandRightsHydroelectricProduction Land and Land Rights	28,934	2,193,866	391,699	63,376	251,349	220,552	827,064	183,300	708,787	1,196,421	66,216
15	CostOfStructuresAndImprovementsHydroelectricProduction Structures and Improvements	10,002,764	29,860,548	1,104,249	2,567,119	1,273,107	2,678,381	1,699,854	1,003,805	77,445,399	2,649,321	1,739,046
16	CostOfReservoirsDamsAndWaterwaysHydroelectricProduction Reservoirs, Dams, and Waterways	10,532,515	23,811,409	4,802,680	11,882,456	10,007,029	12,597,816	19,498,059	35,163,310	24,790,717	10,577,119	11,915,409
17	EquipmentCostsHydroelectricProduction Equipment Costs	19,877,405	39,749,843	20,020,118	36,546,818	31,515,922	35,773,183	23,553,216	32,320,613	45,293,352	41,360,235	11,160,237
18	CostOfRoadsRailroadsAndBridgesHydroelectricProduction Roads, Railroads, and Bridges	0	102,408	131,446	93,874	39,494	458,810	628,052	3,930	3,792	30,735	2,756,989
19	AssetRetirementCostsHydroelectricProduction Asset Retirement Costs	0	0	0	0	0	0	0	0	0	0	0
20	CostOfPlant Total Cost (10-23)	40,441,618	95,718,074	26,450,192	51,153,644	43,086,901	51,728,742	46,206,245	68,674,958	148,242,047	55,813,831	27,637,897
21	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 20 / 5)		1,036	1,107	1,046	2,125	965	3,644	1,477	2,515	1,011	2,303
22	ProductionExpensesAbstract Production Expenses
23	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering	853,196	0	2,463	0	0	0	0	60,500	0	93,748	0
24	WaterForPower Water for Power	0	338,961	61,959	119,936	56,077	141,644	9,713	141,643	104,287	104,287	43,456
25	HydraulicExpenses Hydraulic Expenses	369,752	381,520	204,290	553,665	161,613	406,579	530,294	385,240	530,132	519,414	171,349
26	ElectricExpensesHydraulicPowerGeneration Electric Expenses	473,168	343,409	381,993	115,774	424,606	333,811	396,135	123,388	254,462	266,759	288,385
27	MiscellaneousHydraulicPowerGenerationExpenses Misc Hydraulic Power Generation Expenses	849,973	42,234	109,089	98,131	83,355	65,608	53,872	40,444	667,493	783,739	37,079
28	RentsHydraulicPowerGeneration Rents	0	2,280	0	0	43,627	49,264	24,086	0	0	0	20,079
29	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration Maintenance Supervision and Engineering	843,886	0	0	0	0	0	0	0	0	0	0
30	MaintenanceOfStructuresHydraulicPowerGeneration Maintenance of Structures	99,315	19,308	9,816	5,420	4,447	0	95,667	2,461	2,315	41,634	95,503
31	MaintenanceOfReservoirsDamsAndWaterways Maintenance of Reservoirs, Dams, and Waterways	128,044	52,209	33,790	6,129	44,530	18,626	17,596	5,882	67,608	28,862	57,066
32	MaintenanceOfElectricPlantHydraulicPowerGeneration Maintenance of Electric Plant	141,701	219,279	97,539	7,368	124,664	140,646	121,274	25,995	75,157	124,265	40,031
33	MaintenanceOfMiscellaneousHydraulicPlant Maintenance of Misc Hydraulic Plant	111,489	29,028	2,010	2,167	5,500	0	0	8,145	2,613	37,579	31,572
34	PowerProductionExpensesHydraulicPower Total Production Expenses (total 23 thru 33)	3,614,436	1,428,228	902,949	908,590	948,419	1,156,178	1,248,637	793,698	1,704,067	2,000,287	784,520
35	ExpensesPerNetKilowattHour Expenses per net kWh	0	0.003248	0.008187	0.00422	0.007386	0.004671	0.016519	0.003697	0.005706	0.005301	0.014956

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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. Plant Name:	FERC Licensed Project No. Plant Name:	FERC Licensed Project No. Plant Name:	FERC Licensed Project No. Plant Name:
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)
6	PlantHoursConnectedToLoad Plant Hours Connect to Load While Generating
7	NetContinuousPlantCapability Net Plant Capability (in megawatts)
8	PlantAverageNumberOfEmployees Average Number of Employees
9	NetGenerationExcludingPlantUse Generation, Exclusive of Plant Use - kWh
10	EnergyUsedForPumping Energy Used for Pumping
11	NetOutputForLoad Net Output for Load (line 9 - line 10) - Kwh
12	CostOfPlantAbstract Cost of Plant
13	CostOfLandAndLandRightsPumpedStoragePlant Land and Land Rights
14	CostOfStructuresAndImprovementsPumpedStoragePlant Structures and Improvements
15	CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant Reservoirs, Dams, and Waterways
16	CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant Water Wheels, Turbines, and Generators
17	CostOfAccessoryElectricEquipmentPumpedStoragePlant Accessory Electric Equipment
18	CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant Miscellaneous Powerplant Equipment
19	CostOfRoadsRailroadsAndBridgesPumpedStoragePlant Roads, Railroads, and Bridges
20	AssetRetirementCostsPumpedStoragePlant Asset Retirement Costs
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
25	WaterForPower Water for Power	1,121,963	1,121,963	1,121,963	1,121,963
26	PumpedStorageExpenses Pumped Storage Expenses
27	ElectricExpensesPumpedStoragePlant Electric Expenses
28	MiscellaneousPumpedStoragePowerGenerationExpenses Misc Pumped Storage Power generation Expenses
29	RentsPumpedStoragePlant Rents
30	MaintenanceSupervisionAndEngineeringPumpedStoragePlant Maintenance Supervision and Engineering
31	MaintenanceOfStructuresPumpedStoragePlant Maintenance of Structures
32	MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant Maintenance of Reservoirs, Dams, and Waterways
33	MaintenanceOfElectricPlantPumpedStoragePlant Maintenance of Electric Plant
34	MaintenanceOfMiscellaneousPumpedStoragePlant Maintenance of Misc Pumped Storage Plant
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))

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Internal Combustion
2	Yellowstone Park
3	Lake	1967	2.8		95,803	451,240	161,157	7,396	24,314	16,806	Oil		Internal Combustion
4	Old Faithful	1979	2		242,283	657,680	328,840	18,706	61,489	42,501	Oil		Internal Combustion
5	Roosevelt (Tower Falls)	1986	1		0	71,127	71,127	0	0	0	Oil		Internal Combustion
6	Grant Village	1993	3.35		214,807	1,906,510	569,108	16,584	54,516	37,681	Oil		Internal Combustion
7	(a) Yellowstone Park Solar	2020	0.1		0	2,963,166	29,631,661	10,040	0	2,745			Solar
8	Total Yellowstone Park					6,049,723		54,871	140,319	99,733
9	Other
10	Hebgen	(b) 1915				33,498,136		745,245	0	731			Hydro
11	Grand Total					(c) 36,584,693		800,116	140,319	100,464

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: PlantName

Row includes 3 Solar sites in Yellowstone National Park

	Name of Plant	Year Originally Constructed	Installed Capacity Name Plate Rating (MW)
	(a)	(b)	(c)
1	West Thumb (Yellowstone Park)	2020	0.01
2	Bechler (Yellowstone Park)	2021	0.05
3	Lamar Buffalo Ranch (Yellowstone Park)	2025	0.04

(b) Concept: YearPlantOriginallyConstructed

FERC licensed project number 2188.

Net Generation:
Page 402-403	2,317,287
Page 404	125,892
Page 410-411	553
Hydro Page 406-407	2,160,046
Ties to Page 401, line 9	4,603,778

Production Expenses:
Colstrip 4 (Page 402) agrees total Steam Power Production expense - page 320 line 21	50,868,747
Hydraulic Power (Page 406)	15,490,009
Hydraulic Power (Page 410)	745,976
Total Hydraulic Power Production expense page 320 line 59	16,235,985
DGGS and Yellowstone Generating Station (Page 402)	37,560,504
Other power generation (Page 410)	2,770,655
Total Other Power Production expense page 320 line 74	40,331,159
Two Dot and Spion Kop (Page 404) agrees total Wind Power Production expense page 320 line 79.31	2,686,355
Solar (Page 410) agrees page 320 line 79.16	14,930
Total Power Production Expense	110,137,176

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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)

TOTAL

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Geraldine Resiliancy Center	Geraldine, Montana	8902808	2,222	19,894
36	TOTAL		8,902,808	2,222	19,894

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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) Colstrip 4	Switchyard	500	500	St. Tower	2		1	795 KCM ACSR	0	71,386	71,386	0	0	0	0
2	(b) Colstrip	Broadview A	500	500	St. Tower	112		1	795 KCM ACSR	472,230	12,225,349	12,697,579	0	0	0	0
3	(c) Colstrip	Broadview B	500	500	St. Tower	116		1	795 KCM ACSR	593,662	15,825,994	16,419,656	0	0	0	0
4	(d) Broadview	Townsend A	500	500	St. Tower	133		1	795 KCM ACSR	906,294	13,915,494	14,821,788	0	0	0	0
5	(e) Broadview	Townsend B	500	500	St. Tower	133		1	795 KCM ACSR	943,009	13,718,392	14,661,401	82,559	437	168,159	250,281
6	Billings	Great Falls	230	230	Wood H Frame	188		1	1272 KCM ACSR	372,897	15,273,737	15,646,634	0	0	0	0
7	Broadview	Alkali Creek Sub	230	230	Wood H Frame	18		1	1272 KCM ACSR	106,916	2,143,745	2,250,661	0	0	0	0
8	Alkali Creek Sub	Laurel Baseline	230	230	Steel, Sgle Pole	5		1	1272 MCM ACSR	578,771	1,359,128	1,937,899	18,412	54,360	38,577	111,349
9	Colstrip	Billings	230	230	Wood H Frame	97		1	1272 KCM ACSR	334,459	11,406,000	11,740,459	81,042	20,773	0	101,815
10	Billings	Yellowtail	230	230	Wood H Frame	41		1	1272 KCM ACSR	2,868,064	4,490,617	7,358,681	71,999	0	0	71,999
11	Hot Springs	Idaho Border	230	230	Wood H Frame	307		1	1272 KCM ACSR	5,950,417	17,021,299	22,971,716	17,083	129,925	718,992	866,000
12	Ovando	Great Falls	230	230	Wood H Frame	106		1	1272 KCM ACSR	295,828	10,302,871	10,598,699	21,574	174,210	0	195,784
13	Anaconda	Billings	230	230	Wood H Frame	226		1	1272 KCM ACSR	514,337	18,121,292	18,635,629	234,378	47,135	0	281,513
14	Kerr	Anaconda A	161	161	Wood H Frame	148		1	350 MCM Cu	212,537	18,635,247	18,847,784	17,408	40,235	0	57,643
15	Anaconda	Monida	161	161	Wood H Frame	126		1	250 MCM Cu	130,004	7,696,279	7,826,283	2,076	295,487	41,007	338,570
16	Anaconda	Billings	161	161	Wood H Frame	236		1	556.5 MCM ACSR	213,709	28,801,475	29,015,184	0	0	0	0
17	Anaconda	Butte	161	161	Wood H Frame	26		1	556.5 MCM ACSR	10,667	770,840	781,507	0	0	0	0
18	Clyde Park	Bozeman	161	161	Wood H Frame	55		1	556.5 MCM ACSR	448,934	5,245,211	5,694,145	0	0	0	0
19	Missoula	Hamilton A	161	161	Wood H Frame	40		1	556.5 MCM ACSR	652,145	3,725,476	4,377,621	0	0	0	0
20	Clyde Park	Emigrant	161	161	Wood H Frame	40		1	556.5 MCM ACSR	725,426	5,027,154	5,752,580	0	0	0	0
21	Bozeman	Ennis	161	161	Wood H Frame	53		1	556.5 MCM ACSR	1,483,156	6,773,109	8,256,265	0	0	0	0
22	Kerr	Anaconda B	161	161	Wood H Frame	150		1	556.5 MCM ACSR	965,935	7,899,987	8,865,922	223,053	536,233	0	759,286
23	Rattlesnake	Missoula #4	161	161	Wood H Frame	68		1	556.5 MCM ACSR	2,685,921	11,025,840	13,711,761	0	0	0	0
24	Dillon	Salmon-Ennis	161	161	Wood H Frame	82		1	556.5 MCM ACSR	1,368,771	10,069,026	11,437,797	28,651	841,235	0	869,886
25	Rainbow	Havre	161	161	Wood H Frame	94		1	636 MCM ACSR	930,091	4,322,859	5,252,950	0	0	0	0
26	Three Rivers	Jackrabbit	161	161	SAHP Single Pole	29		1	556 KCMIL ACSR	1,643,626	9,487,264	11,130,890	0	0	0	0
27	Jackrabbit	Big Sky	161	161	Wood H Frame	37		1	556 KCMIL ACSR	0	33,675,622	33,675,622	53,692	93,205	0	146,897
28	All 115 kV	0	115	115	Various	338				688,639	39,520,458	40,209,097	219,628	326,870	0	546,498
29	All 100 kV	0	100	100	Various	1,772				10,458,362	270,644,961	281,103,323	801,151	1,550,075	63,201	2,414,427
30	All 69 kV	0	69	69	Various	1,189				2,899,169	127,561,507	130,460,676	509,333	499,313	25,028	1,033,674
31	All 50 kV	0	50	50	Various	627				3,632,033	73,971,892	77,603,925	300,200	422,205	25,355	747,760
32	Rounding					1					2	2	1	1	1	1
36	TOTAL					6,595				43,086,009	800,729,513	843,815,522	2,682,238	5,030,823	1,080,320	8,793,381

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: TransmissionLineStartPoint

KV500 kV facilities are jointly owned by Avista, Puget Sound, PacifiCorp and Portland General Electric. Plant costs and expenses are respondent's share only.

(b) Concept: TransmissionLineStartPoint

KV500 kV facilities are jointly owned by Avista, Puget Sound, PacifiCorp and Portland General Electric. Plant costs and expenses are respondent's share only.

(d) Concept: TransmissionLineStartPoint

KV500 kV facilities are jointly owned by Avista, Puget Sound, PacifiCorp and Portland General Electric. Plant costs and expenses are respondent's share only.

(e) Concept: TransmissionLineStartPoint

KV500 kV facilities are jointly owned by Avista, Puget Sound, PacifiCorp and Portland General Electric. Plant costs and expenses are respondent's share only.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	LengthOfTransmissionLineAdded Line Length in Miles	SupportingStructureOfTransmissionLineType Type	AverageNumberOfSupportingStructuresOfTransmissionLinePerMiles Average Number per Miles	NumberOfTransmissionCircuitsPerStructurePresent Present	NumberOfTransmissionCircuitsPerStructureUltimate Ultimate	ConductorSize Size	ConductorSpecification Specification	ConductorConfigurationAndSpacing Configuration and Spacing	OperatingVoltageOfTransmissionLine Voltage KV (Operating)	CostOfLandAndLandRightsTransmissionLinesAdded Land and Land Rights	CostOfPolesTowersAndFixturesTransmissionLinesAdded Poles, Towers and Fixtures	CostOfConductorsAndDevicesTransmissionLinesAdded Conductors and Devices	Asset Retire. Costs	CostOfTransmissionLinesAdded Total	SupportingStructureConstructionType Construction
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)	(q)
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	TOTAL

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

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	Alkali Creek (BILLINGS)	Transmission	Unattended	230	161	13.8	400	2		FOA
2	Baseline (BILLINGS)	Transmission	Unattended	230	100	13.8	200	1		FOA
3	Billings Eighth Street (BILLINGS)	Transmission	Unattended	100	50	2.4	30	3	1	FA
4	Billings Steam Plant Switchyard B (BILLINGS)	Transmission	Unattended	230	100	13.8	400	2		FOA
5	Billings Steam Plant Switchyard C (BILLINGS)	Transmission	Unattended	100	50		75	1	0	OA/FA/FA
6	Bridger Auto (BILLINGS)	Transmission	Unattended	100	50	13.8	51	2		FA & FOA
7	Broadview Switchyard A (BILLINGS)	Transmission	Unattended	230	100		200	2		FOA
8	Broadview Switchyard B (BILLINGS)	Transmission	Unattended	500	230	34.5	1200	2		FOA
9	Chrome Junction (BILLINGS)	Transmission	Unattended	100	50	13.8	25	1		FA
10	Colstrip 500 (BILLINGS)	Transmission	Unattended	500	230	34.5	1000	2	1	FOA
11	Colstrip 230 (BILLINGS)	Transmission	Unattended	230	115	13.8	200	2		FA & FOA
12	Colstrip City (BILLINGS)	Transmission	Unattended	115	69	13.8	24	3	1	OA
13	Columbus Auto (BILLINGS)	Transmission	Unattended	100	50	13.8	25	1		FA
14	Columbus-Rajelje Auto (BILLINGS)	Transmission	Unattended	230	100	13.8	200	2		OA/FA/FA
15	Glengarry (BILLINGS)	Transmission	Unattended	100	50	13.8	75	2		FOA
16	Gordon Butte (BILLINGS)	Transmission	Unattended	100	100
17	Hardin Auto A (BILLINGS)	Transmission	Unattended	230	100	13.8	200	1		FOA
18	Hardin Auto B (BILLINGS)	Transmission	Unattended	115	69	14.4	50	1		OA/FA/FA
19	Harlowtown A (BILLINGS)	Transmission	Unattended	50	4.16		3	1		FA
20	Harlowtown B (BILLINGS)	Transmission	Unattended	100	50	13.8	20	1		OA/FA/FA
21	Judith Gap Auto (BILLINGS)	Transmission	Unattended	230	100	13.8	100	1		FOA
22	Judith Gap South (BILLINGS)	Transmission	Unattended	230	230			1		FOA
23	Laurel Auto (BILLINGS)	Transmission	Unattended	100	50	13.8	25	1	0	OA/FA/FA
24	Montana One (BILLINGS)	Transmission	Unattended	115	115
25	Musselshell Wind (BILLINGS)	Transmission	Unattended	100
26	Nye (BILLINGS)	Transmission	Unattended	100
27	Painted Robe (BILLINGS)	Transmission	Unattended	100	50	13.8	25	1		FA
28	Billings Rimrock Auto A (BILLINGS)	Transmission	Unattended	230	100	14.4	600	2		OA/FA/FA
29	Billings Rimrock Auto B (BILLINGS)	Transmission	Unattended	100	50	14.4	75	1		OA/FA/FA
30	Billings Rimrock Auto C (BILLINGS)	Transmission	Unattended	100	69	13.8	50	1		OA/FA/FA
31	Roundup Auto (BILLINGS)	Transmission	Unattended	100	50	13.8	25	1		FA
32	Shorey Road Switchyard (BILLINGS)	Transmission	Unattended	230
33	South Huntley (BILLINGS)	Transmission	Unattended	230	69	13.8	83	1		FFA
34	Stanford Auto A (BILLINGS)	Transmission	Unattended	100	69	13.8	26	1		FA
35	Stanford Auto B (BILLINGS)	Transmission	Unattended	100	50	13.8	20	1		FA
36	Billings Central (BILLINGS)	Transmission	Unattended	100
37	Stillwater Wind (BILLINGS)	Transmission	Unattended	230
38	Five Mile (BILLINGS)	Transmission	Unattended	230
39	Two Dot Wind Swyd (BILLINGS)	Transmission	Unattended	100
40	Belgrade West (BOZEMAN)	Transmission	Unattended	161	50	14.4	50	1		OA/FA/FA
41	Big Sky Meadow Village (BOZEMAN)	Transmission	Unattended	161	69	14.4	50	1		OA/FA/FA
42	Big Timber Auto (BOZEMAN)	Transmission	Unattended	161	50	14.4	50	1		OA/FA/FA
43	Big Timber Wind (BOZEMAN)	Transmission	Unattended	161
44	Bozeman East Gallatin Auto (BOZEMAN)	Transmission	Unattended	161	50	14.4	300	2		OA/FA/FA
45	Bradley Creek (BOZEMAN)	Transmission	Unattended	161	100	13.8	50	1		FOA
46	Clyde Park (BOZEMAN)	Transmission	Unattended	161	50	13.8	66	3	1	FA
47	Emigrant (BOZEMAN)	Transmission	Unattended	161	69	13.8	50	1		FOA
48	Ennis Auto (BOZEMAN)	Transmission	Unattended	161	69	13.8	50	2		FA
49	Bozeman Jackrabbit Auto (BOZEMAN)	Transmission	Unattended	161	50	13.8	100	1		FOA
50	Livingston Westside A (BOZEMAN)	Transmission	Unattended	69	50	4.16	22	3	1	FA
51	Three Rivers A (BOZEMAN)	Transmission	Unattended	161	100	13.8	200	1	1	FA
52	Three Rivers B (BOZEMAN)	Transmission	Unattended	230	161	13.8	200	1		FOA
53	Trident Auto (BOZEMAN)	Transmission	Unattended	100	50	13.8	50	1		OA/FA/FA
54	Wilsall (BOZEMAN)	Transmission	Unattended	230	161	13.8	300	2		FOA & CAP	2	44
55	Mill Creek A (BUTTE)	Transmission	Unattended	230	161	13.8	1000	2		OA/FA/FA
56	Mill Creek Generating (BUTTE)	Transmission	Unattended	230	13.8		240	4		FOA
57	(a) ASIMI (BUTTE)	Transmission	Unattended	161	12.47		200	4
58	Mill Creek B (BUTTE)	Transmission	Unattended	161	100	14	250	2		OA/FA/FA
59	Sheridan City (BUTTE)	Transmission	Unattended	69	50	14	15	1
60	Dillon-Salmon (BUTTE)	Transmission	Unattended	161	69	14.4	100	2	1	FA
61	Drummond City (BUTTE)	Transmission	Unattended	100	24.94		6	1		FA
62	Peterson Flats (BUTTE)	Transmission	Unattended	230	230
63	Renova Auto (BUTTE)	Transmission	Unattended	100	50	13.8	54	2		FOA
64	Sheridan Auto (BUTTE)	Transmission	Unattended	161	69	13.8	25	1		FA
65	South Butte A (BUTTE)	Transmission	Unattended	230	161	14.4	400	1		OA/FA/FA
66	South Butte B (BUTTE)	Transmission	Unattended	161	100	2.4	250	2		OA/FA/FA
67	Conrad Auto (GREAT FALLS)	Transmission	Unattended	115	69	13.8	17	3	1	FA
68	Crooked Falls A (GREAT FALLS)	Transmission	Unattended	100	69		100	2		FOA
69	Crooked Falls B (GREAT FALLS)	Transmission	Unattended	161	100	14.4	75	1
70	Fairfield Wind (GREAT FALLS)	Transmission	Unattended	69
71	Glacier Wind Switchyard (GREAT FALLS)	Transmission	Unattended	115
72	Great Falls 230 Switchyard A (GREAT FALLS)	Transmission	Unattended	230	100		400	3		FOA
73	Great Falls 230 Switchyard B (GREAT FALLS)	Transmission	Unattended	115	100	13.8	150	1		FOA
74	Highwood Switchyard (GREAT FALLS)	Transmission	Unattended	230
75	Kershaw Switchyard (GREAT FALLS)	Transmission	Unattended	69
76	Montana Refinery (GREAT FALLS)	Transmission	Unattended	100
77	South Cut Bank (GREAT FALLS)	Transmission	Unattended	115
78	Spion Kop Collector (GREAT FALLS)	Transmission	Unattended	100	34.5		42	1
79	Spion Kop Switchyard (GREAT FALLS)	Transmission	Unattended	100
80	Spion Kop 230kV Switchyard (GREAT FALLS)	Transmission	Unattended	230
81	Holter (HELENA)	Transmission	Unattended	100
82	Boulder Auto (HELENA)	Transmission	Unattended	100	69	2.4	56	3	1	OA/FA
83	Broadwater (HELENA)	Transmission	Unattended	100
84	Custer Auto (HELENA)	Transmission	Unattended	100	69	14.4	100	1		OA/FA/FA
85	East Helena Switchyard B (HELENA)	Transmission	Unattended	100	69	13.8	150	2	1	OA/FA/FA
86	East Helena Switchyard C (HELENA)	Transmission	Unattended	100	12.47		20	1
87	Holter Wolf Creek (HELENA)	Transmission	Unattended	100	13		2.8	1
88	Lake Helena (HELENA)	Transmission	Unattended	100
89	Loweth Auto (HELENA)	Transmission	Unattended	100	69	14	15	1		OA/FA
90	Crow Creek Junction (MISSOULA)	Transmission	Unattended	115
91	Hamilton Heights (MISSOULA)	Transmission	Unattended	161	69	13.8	100	2		FOA
92	Kerr Switchyard (MISSOULA)	Transmission	Unattended	161	115	14.4	400	2		OA/FA/FA
93	Missoula Miller Creek A (MISSOULA)	Transmission	Unattended	161	100	14.4	200	1		OA/FA/FA
94	Missoula Miller Creek B (MISSOULA)	Transmission	Unattended	161	69	14.4	200	2		OA/FA/FA
95	Missoula Reserve Street (MISSOULA)	Transmission	Unattended	161	100		75	3	1	FOA & CAP	4	38
96	Ovando Switchyard (MISSOULA)	Transmission	Unattended	230
97	Placid Lake Switchyard (MISSOULA)	Transmission	Unattended	230
98	Rattlesnake Switchyard A (MISSOULA)	Transmission	Unattended	161	100	13.8	300	6		FOA & CAP	2	23
99	Rattlesnake Switchyard B (MISSOULA)	Transmission	Unattended	230	161	13.8	391	1		FOA
100	Taft Auto (MISSOULA)	Transmission	Unattended	115	100	13.1	50	1		FOA
101	Thompson Falls Generation (MISSOULA)	Transmission	Unattended	115
102	Assiniboine-Havre (HAVRE)	Transmission	Unattended	161	69		53	6	1	FA
103	Harlem (HAVRE)	Transmission	Unattended	161	69		25	3		FA
104	Malta Auto (HAVRE)	Transmission	Unattended	161	69	7.2	25	3	1	FA
105	Richardson Coulee (HAVRE)	Transmission	Unattended	161	69		20	3
106	Whatley (HAVRE)	Transmission	Unattended	69
107	Others Under 10,000 KVA (MT)	Transmission	Unattended				40.5	16	2
108	Bellrock (BILLINGS)	Distribution	Unattended	100	12.5		83	2		FFA
109	Billings Eighth Street (BILLINGS)	Distribution	Unattended	100	12.5		126	3		FFA
110	Billings City (BILLINGS)	Distribution	Unattended	100	12.5		83	2		FFA
111	Billings Conoco (BILLINGS)	Distribution	Unattended	100	12.5		120	2		FOA
112	Billings Eastside (BILLINGS)	Distribution	Unattended	100	12.5		104	3		FOA
113	Billings Shiloh Road (BILLINGS)	Distribution	Unattended	100	12.5		83	2		FFA
114	Billings Steam Plant Switchyard A (BILLINGS)	Distribution	Unattended	100	12.5		40	2		FFA
115	Bridger City (BILLINGS)	Distribution	Unattended	50	12.5		7	1		OA/FA
116	CHS (BILLINGS)	Distribution	Unattended	100	125		168	4		OA/FA/FA
117	Colstrip City (BILLINGS)	Distribution	Unattended	115	12.5		40	2		FOA
118	Columbus East (BILLINGS)	Distribution	Unattended	50	12.4		8	3		FOA
119	Billings Exxon (BILLINGS)	Distribution	Unattended	50	12.5		90	3		FA & FOA
120	Garnell Pipeline (BILLINGS)	Distribution	Unattended	100	4.16		20	1		OA/FA
121	Hardin City (BILLINGS)	Distribution	Unattended	69	12.5		20	1
122	Johnson Lane (BILLINGS)	Distribution	Unattended	69	12.5		14	1		OA/FA/FA
123	Billings King Avenue (BILLINGS)	Distribution	Unattended	100	12.5		40	2		FFA
124	Laurel City (BILLINGS)	Distribution	Unattended	100	12.5		40	2		FOA
125	Meridian (BILLINGS)	Distribution	Unattended	100	12.5		40	2		FOA
126	Red Lodge Northside (BILLINGS)	Distribution	Unattended	50	12.5		12	1		FA
127	Billings Rimrock Auto D (BILLINGS)	Distribution	Unattended	100	12.5		42	1		OA/FA/FA
128	Sarpy Creek Auto (BILLINGS)	Distribution	Unattended	115	69	13.8	24	3	1	OA
129	Western Energy Armells Creek (BILLINGS)	Distribution	Unattended	115	12.5		40	2		FOA
130	Billings Wicks Lane (BILLINGS)	Distribution	Unattended	230	12.5		50	2		FFA
131	Amsterdam Churchill (BOZEMAN)	Distribution	Unattended	50	12.5		14	1		OA/FA
132	Belgrade (BOZEMAN)	Distribution	Unattended	50	12.5		40	2		FFA
133	Belgrade West (BOZEMAN)	Distribution	Unattended	161	12.5		25	1		OA/FA/FA
134	Big Sky Meadow Village (BOZEMAN)	Distribution	Unattended	161	12.5		25	1		OA/FA/FA
135	Big Sky Midway A (BOZEMAN)	Distribution	Unattended	69	12.5		25	1		OA/FA/FA
136	Big Sky Midway B (BOZEMAN)	Distribution	Unattended	69	25		25	1		OA/FA/FA
137	Bozeman East Gallatin Auto (BOZEMAN)	Distribution	Unattended	50	12.5		62	2	0	OA/FA/FA
138	Bozeman Sourdough (BOZEMAN)	Distribution	Unattended	50	12.47		62	2		OA/FA/FA
139	Bozeman Southside (BOZEMAN)	Distribution	Unattended	50	12.5		40	2		FA & FOA
140	Bozeman Westside (BOZEMAN)	Distribution	Unattended	161	12.5		84	2		FOA
141	Ennis City (BOZEMAN)	Distribution	Unattended	69	12.5		25	1
142	Bozeman Jackrabbit Auto (BOZEMAN)	Distribution	Unattended	161	12.5		50	2		OA/FA/FA
143	Livingston Westside B (BOZEMAN)	Distribution	Unattended	50	12.5		12	1		OA/FA
144	Livingston Westside C (BOZEMAN)	Distribution	Unattended	50	12.5		20	1		OA/FA/FA
145	Livingston Northside (BOZEMAN)	Distribution	Unattended	50	4.16		14			OA/FA
146	Lone Mountain Big Sky A (BOZEMAN)	Distribution	Unattended	161	69	14.4	50	1		OA/FA/FA
147	Lone Mountain Big Sky B (BOZEMAN)	Distribution	Unattended	161	25		84	2		OA/FA/FA
148	Manhattan (BOZEMAN)	Distribution	Unattended	0	0		0	0		FA
149	Manhattan West (BOZEMAN)	Distribution	Unattended	50	12.5		20	1		OA/FA/FA
150	Bozeman Patterson (BOZEMAN)	Distribution	Unattended	50	12.5		12	1		FA
151	Bozeman Riverside (BOZEMAN)	Distribution	Unattended	50	12.5		25	1
152	Three Forks South (BOZEMAN)	Distribution	Unattended	100	12.5		20	1		FA
153	Willow Creek (BOZEMAN)	Distribution	Unattended	100	12.5		12	1		OA/FA
154	Anaconda City (BUTTE)	Distribution	Unattended	100	25		20	2
155	Barrett's Minerals (BUTTE)	Distribution	Unattended	69	25		12	1		FA
156	Butte Concentrator (BUTTE)	Distribution	Unattended	100	4.16		78	22
157	Butte Continental Drive (BUTTE)	Distribution	Unattended	100	12.5		20	1		FOA
158	Butte Industrial Park (BUTTE)	Distribution	Unattended	100	12.5		13	3	1	FA
159	Butte Montana St A (BUTTE)	Distribution	Unattended	100	69	6.9	30	3		FA
160	Butte Montana St B (BUTTE)	Distribution	Unattended	100	12.47		50	2		OA/FA/FA
161	Butte Cora (BUTTE)	Distribution	Unattended	100	12.5		22	1		FOA
162	Deer Lodge City (BUTTE)	Distribution	Unattended	100	25		16	1		FOA
163	Dillon City (BUTTE)	Distribution	Unattended	69	25		14	1		FA
164	Golden Sunlight (BUTTE)	Distribution	Unattended	230	24.94		90	2
165	MHD (BUTTE)	Distribution	Unattended	161
166	Philipsburg South (BUTTE)	Distribution	Unattended	100	25		14	1		OA/FA
167	Precipitator (BUTTE)	Distribution	Unattended	100	2.4		14	1
168	Ramsay Pump (BUTTE)	Distribution	Unattended	100	12.47		12	1		FA
169	Great Falls City (GREAT FALLS)	Distribution	Unattended	100	12.5		40	2		FOA
170	Great Falls Eastside (GREAT FALLS)	Distribution	Unattended	100	12.5		50	2		FA
171	Great Falls Northeast (GREAT FALLS)	Distribution	Unattended	100	12.5		20	1		FOA
172	Great Falls Northwest (GREAT FALLS)	Distribution	Unattended	100	12.5		40	2		FOA
173	Great Falls Riverview (GREAT FALLS)	Distribution	Unattended	100	12.5		45	2		FOA
174	Great Falls Southeast (GREAT FALLS)	Distribution	Unattended	100	12.5		42	1		FOA
175	Great Falls Southside (GREAT FALLS)	Distribution	Unattended	100	12.5		40	2		FOA
176	Great Falls Southwest (GREAT FALLS)	Distribution	Unattended	100	12.5		62	2		OA/FA/FA
177	Turnbull (GREAT FALLS)	Distribution	Unattended	69
178	Ulm (GREAT FALLS)	Distribution	Unattended	100	25		12	1
179	Valier-Williams (GREAT FALLS)	Distribution	Unattended	115	25		14	1		FA
180	Ash Grove (HELENA)	Distribution	Unattended	69	4.16		20	2		OA/FA
181	Canyon Creek (HELENA)	Distribution	Unattended	100	25		10	1
182	East Helena Switchyard A (HELENA)	Distribution	Unattended	100	12.5		25	1		OA/FA/FA
183	Helena Eastside (HELENA)	Distribution	Unattended	69	12.5		5	4	1	OA/FA
184	Helena Golf Course Bank #1 (HELENA)	Distribution	Unattended	69	12.5		20	1		OA/FA/FA
185	Helena Golf Course Bank #2 (HELENA)	Distribution	Unattended	69	12.5		20	1		OA/FA/FA
186	Helena Southside (HELENA)	Distribution	Unattended	100	12.5		40	2		OA/FA/FA
187	Helena Valley (HELENA)	Distribution	Unattended	100	12.5		32	2		OA/FA/FA
188	Helena Westside A (HELENA)	Distribution	Unattended	69	12.5		25	1		OA/FA
189	Helena Westside B (HELENA)	Distribution	Unattended	69	12.5		25	1		OA/FA/FA
190	Landers Fork (HELENA)	Distribution	Unattended	230	25		12	1		OA/FA
191	Loweth	Distribution	Unattended	100	25		14	1		OA/FA
192	White Sulphur Springs Southside	Distribution	Unattended	100	25		14	1		OA/FA
193	Spokane Bench	Distribution	Unattended	100	12.5		14	1		OA/FA
194	Montana Tunnels (HELENA)	Distribution	Unattended	100	4.16		22	6
195	Townsend (HELENA)	Distribution	Unattended	100	12.5		20	1		OA/FA/FA
196	Bonner (MISSOULA)	Distribution	Unattended	161	12.5		40	3	1	FOA
197	Darby (MISSOULA)	Distribution	Unattended	69	12.5		14	1		OA/FA/FA
198	Hamilton South Side (MISSOULA)	Distribution	Unattended	69	12.5		40	2		FOA
199	Hamilton Northside (MISSOULA)	Distribution	Unattended	69	12.5		25	1		OA/FA/FA
200	Lolo (MISSOULA)	Distribution	Unattended	69	12.5		12	1		FA
201	Missoula Butler Creek (MISSOULA)	Distribution	Unattended	100	12.5		20	1
202	Missoula City Sub #1 (MISSOULA)	Distribution	Unattended	100	12.5		84	2		OA/FA/FA
203	Missoula Hillview Heights (MISSOULA)	Distribution	Unattended	100	12.5		45	2		FOA
204	Missoula Industrial Sub (MISSOULA)	Distribution	Unattended	100	12.5		60	3		FOA
205	Missoula Reserve Street (MISSOULA)	Distribution	Unattended	100	12.5		67	2		OA/FA/FA
206	Missoula Russell Street (MISSOULA)	Distribution	Unattended	100	12.5		82	3		OA/FA/FA
207	Missoula Target Range (MISSOULA)	Distribution	Unattended	161	12.5		40	2		FOA
208	Plains (MISSOULA)	Distribution	Unattended	115	12.5		17	1		OA
209	Stevensville Sub (MISSOULA)	Distribution	Unattended	69	12.5		25			OA/FA/FA
210	Thompson Falls City (MISSOULA)	Distribution	Unattended	100	12.5		12	3	1	FOA
211	Waldorf (MISSOULA)	Distribution	Unattended	100	12.47		20	2
212	Glasgow Westside (HAVRE)	Distribution	Unattended	69	12.5		12	2		FA
213	Havre City (HAVRE)	Distribution	Unattended	69	12.4		27	2		FA
214	Havre Eastside (HAVRE)	Distribution	Unattended	69	12.5		10	1		FA
215	207 Others Under 10,000 KVA (MT)	Distribution	Unattended				677.16	369	6
217	Total			26,554	8,519.16	903.76	16,949.46	719	26		8	105

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

FOOTNOTE DATA

(a) Concept: SubstationNameAndLocation

This substation is owned by Butte Silver Bow County and currently provides service only to REC Silicon. Northwestern, through an agreement with REC, operates and maintains this substation.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2025

Year/Period of Report

End of:

2025

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	Board of Director Fees	NorthWestern Energy Group, Inc	930.2	887,982
19
20	Non-power Goods or Services Provided for Affiliated
21	Labor and Benefits	NorthWestern Energy Public Service Corporation	146	39,286,974
22	Labor and Benefits	Havre Pipeline Company, LLC	146	1,262,655
23	Labor and Benefits	Canadian-Montana Pipe Line Corporation	146	10,512
24	Labor and Benefits	NorthWestern Great Falls Gas, LLC	146	3,245,870
25	Labor and Benefits	NorthWestern Cut Bank Gas LLC	146	430,301
26	Administation Fee	NorthWestern Energy Group, Inc	922	49,947
27	Administation Fee	Havre Pipeline Company, LLC	752	505,046
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