FERC Form

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:

2022

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:

2022

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

Elaine A. Rich

06 Title of Contact Person

Assistant Controller

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

11 East Park Street, Butte, MT 59701

08 Telephone of Contact Person, Including Area Code

(406) 497-2759

09 This Report is An Original / A Resubmission

(1)

☑ An Original

(2)

☐ A Resubmission

10 Date of Report (Mo, Da, Yr)

12/31/2022

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)

03/06/2023

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:

12/31/2022

Year/Period of Report

End of:

2022

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	Not Applicable
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	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
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
61	ScheduleElectricEnergyAccountAbstract Electric Energy Account	401a
62	ScheduleMonthlyPeakAndOutputAbstract Monthly Peaks and Output	401b
63	ScheduleSteamElectricGeneratingPlantStatisticsAbstract Steam Electric Generating Plant Statistics	402
64	ScheduleHydroelectricGeneratingPlantStatisticsAbstract Hydroelectric Generating Plant Statistics	406
65	SchedulePumpedStorageGeneratingPlantStatisticsAbstract Pumped Storage Generating Plant Statistics	408	Not Applicable
66	ScheduleGeneratingPlantStatisticsAbstract Generating Plant Statistics Pages	410
0	ScheduleEnergyStorageOperationsLargePlantsAbstract Energy Storage Operations (Large Plants)	414	Not Applicable
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:

12/31/2022

Year/Period of Report

End of:

2022

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 Controller 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, South Dakota, and Wyoming (Yellowstone National Park), Gas Utility in Nebraska, 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:

12/31/2022

Year/Period of Report

End of:

2022

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.

Not Applicable

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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	Direct Subsidiaries:
2	Canadian-Montana Pipe Line Corporation	Owns natural gas pipeline	100
3	Clarkfork and Blackfoot, LLC	Owned a former hydro facility in Montana	100
4	NorthWestern Services, LLC	Non-regulated natural gas marketing in SD/NE	100
5	Risk Partners Assurance, Ltd.	Captive insurance company	100
6	Lodge Creek Pipelines, LLC	Natural gas gathering system	100
7	Willow Creek Gathering, LLC	Natural gas gathering system	100
8	Havre Pipeline Company, LLC	Natural gas transmission and gathering system	96
9	NorthWestern Energy Solutions, Inc.	Non-regulated customer services	100

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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	Chief Executive Officer	Robert Rowe	691,669
2	President, Chief Operating Officer	Brian Bird	511,019
3	Vice President, Chief Financial Officer	Crystal Lail	402,548
4	Vice President, General Counsel and Regulatory and Federal Affairs	Heather Grahame	451,204
5	Vice President, Distribution	Jason Merkel	227,963	2022-09-01
6	Vice President, Distribution	Curtis Pohl	323,334		2022-09-01
7	Vice President, Asset Management & Business Development	Curtis Pohl	323,334	2022-09-01
8	Vice President, Transmission	Michael Cashell	310,073
9	Vice President, Customer Care, Communications, and Human Resources	Bobbi Schroeppel	311,428
10	Vice, President, Supply and Montana Government Affairs	John Hines	313,515
11	Vice President, Technology	Jeanne Vold	255,510

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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	Dana J. Dykhouse	Sioux Falls, South Dakota	false	false
2	Anthony T. Clark	Ashburn, Virginia	false	false
3	Jan R. Horsfall	Colorado Springs, Colorado	false	false
4	Britt E. Ide	Bozeman, Montana	false	false
5	Robert C. Rowe, Chief Exececutive Officer	Helena, Montana	false	false
6	Linda G. Sullivan	Moneta, Virginia	false	false
7	Mahvash Yazdi	Rancho Palos Verdes, California	false	false
8	Jeffrey W. Yingling	Kneilworth, Illinois	false	false
9	Kent T. Larson	Shoreview, Minnesota	false	false

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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	Addendum 27 to Attachment H of Southwest Power Pool Open Access Transmission Tariff	ER20-1090-000 and ER20-1961-001 (not consolidated)
2	Addendum 27 to Attachment H of Southwest Power Pool Open Access Transmission Tariff	ER22-333-000
3	Montana OATT, Attachment O, Formula Rate Protocols and Template	ER19-1756-001
4	Montana OATT, Attachment O, Formula Rate Protocols and Template	ER21-779-000

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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	20221213-5197	12/31/2022	ER23-719-000	Annual Informational Attachment H Filing of NorthWestern Corporation (South Dakota) (Rate Year 2022)	Addendum 27 to Attachment H of Southwest Power Pool Open Access Transmission Tariff
2	20221205-5139	12/05/2022	ER23-564-000	Informational Filing of June 1, 2022, to May 31, 2023, 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:

12/31/2022

Year/Period of Report

End of:

2022

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
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39
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41
42
43
44

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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. On November 1, 2022, NorthWestern acquired the intrastate natural gas operating system serving approximately 140 customers in and around the community of Winifred, MT. The acquisition received approval from the Montana Public Service Commission through Order 7830d. The acquisition price of $1 fell below the threshold requiring approval from FERC. On January 16, 2023, we entered into a definitive agreement (the Avista Agreement) with Avista Corporation (Avista) to acquire Avista's 15 percent interest in each of Units 3 and 4 at the Colstrip Generating Station, a coal-fired, base-load electric generation facility located in Colstrip, Montana. The Avista Agreement provides that the purchase price will be $0 and that we will acquire Avista's interest effective December 31, 2025, subject to the satisfaction of the closing conditions contained within the Avista Agreement. Under the terms of this Avista Agreement, we will be responsible for operating costs starting on January 1, 2026; while Avista will retain responsibility for its 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 decommission and demolition costs associated with the existing facilities that comprise Avista's interest. The Avista Agreement contains customary representations and warranties, covenants, and indemnification obligations, and the Avista Agreement is subject to customary conditions and approvals, including approval from the FERC.
4) None
5) None
6. See Note 11 "Unsecured Credit Facilities" Amendment to Credit Facility and Additional Credit Facility and Note 18, "Common Stock" Equity issuance: FERC Order ES21-53-000 and MPSC Order Number 7804 Docket Number D2021.08.107
7) None
8) We negotiated seven union contracts in 2022 with effective dates between May 2022 and September 2022. The four year compounded annual growth rate on annual wage adjustments within these contracts was 3.81%.
9) See Note 19, "Commitments and Contingencies".
10) None
12) None
13. On July 27, 2022, Bob Rowe, the current Chief Executive Officer of the company and member of the board of directors, announced his retirement at the end of 2022. On this same day, the board of directors appointed Brian Bird, currently the company's President and Chief Operating Officer, to serve as President and Chief Executive Officer effective January 1, 2023. On July 28, 2022, the board of directors elected Kent Larson as a director to the board of directors to a term commencing immediately and expiring at the Company's next Annual Meeting of Stockholders, at which time Mr. Larson is expected to be nominated for approval by the Company's stockholders. On August 31, 2022, Heather Grahame, the current General Counsel and Vice President - Regulatory and Federal Government Affairs, informed the company that she will retire from her position as of January 1, 2023. Effective January 1, 2023 Cyndee Fang will serve as Vice President - Regulatory, and Shannon Heim will serve as Vice President - General Counsel and Federal Government Affairs. On August 31, 2022 the company also announced that Curtis Pohl will serve in a newly created role as Vice President - Asset Management and Business Development, effective September 1, 2022. On the same date, Jason Merkel succeeded Mr. Pohl and began serving as Vice President - Distribution.
14) NA

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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	7,591,279,874	7,084,086,086
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	300,649,215	284,729,122
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		7,891,929,089	7,368,815,208
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	2,786,711,964	2,648,396,212
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		5,105,217,125	4,720,418,996
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)		5,105,217,125	4,720,418,996
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)		357,585,527	357,585,527
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)		36,209,611	36,190,017
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)		65,534	29,270
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	25,343,937	24,377,535
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228
24	OtherInvestments Other Investments (124)		21,035,719	18,262,019
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)		47,000,927	43,297,089
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		8,029,111	2,300,750
36	SpecialDeposits Special Deposits (132-134)		12,761,965	14,658,170
37	WorkingFunds Working Fund (135)		23,450	23,250
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		106,890,491	86,846,850
41	OtherAccountsReceivable Other Accounts Receivable (143)		26,793,907	8,867,792
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		2,451,237	2,319,115
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		3,143,188	2,818,214
45	FuelStock Fuel Stock (151)	227	7,724,941	7,509,623
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	71,154,248	53,538,725
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 (158.1 and 158.2)	228
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227
55	GasStoredCurrent Gas Stored Underground - Current (164.1)		27,722,831	18,828,613
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57	Prepayments Prepayments (165)		(a) 23,739,745	22,690,392
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)		213,473	54,488
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		117,418,484	98,149,252
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		2,372,750	258,105
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)		405,537,347	314,225,109
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		9,254,937	11,120,970
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	729,084,376	685,148,784
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)		37,192	4,169
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	9,543,157	8,602,501
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)		(b) 22,619,741	25,635,857
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	163,943,624	160,914,104
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)		100,874,939	94,663,379
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		1,035,357,966	986,089,764
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		6,986,908,503	6,457,806,502

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: Prepayments

South Dakota Operations Prepayments (165) are $11,517,440 and $14,201,612 for 2022 and 2021, respectively.

Montana Operations Prepayments (165) are $12,222,305 and $8,488,780 for 2022 and 2021, respectively.

(b) Concept: UnamortizedLossOnReacquiredDebt

Montana Operations Unamortized Loss on Reacquired Debt (189) is $20,416,114 and $22,530,850 for 2022 and 2021, respectively.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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	632,782	576,063
3	PreferredStockIssued Preferred Stock Issued (204)	250
4	CapitalStockSubscribed Capital Stock Subscribed (202, 205)
5	StockLiabilityForConversion Stock Liability for Conversion (203, 206)
6	PremiumOnCapitalStock Premium on Capital Stock (207)
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	1,999,375,991	1,716,226,995
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	769,493,168	725,880,305
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	222,330	446,074
13	ReacquiredCapitalStock (Less) Reaquired Capital Stock (217)	250	98,392,040	98,248,245
14	NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218)
15	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	122(a)(b)	5,705,664	5,167,596
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		2,665,181,907	2,339,713,596
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	2,179,660,000	2,179,660,000
19	ReacquiredBonds (Less) Reaquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256	450,000,000	373,000,000
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		33,056	61,389
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		2,629,626,944	2,552,598,611
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		9,389,857	12,829,411
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		(a) 4,365,711	7,061,829
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		(b) 10,546,632	6,434,213
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)		72,588,961	88,530,057
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)		40,893,877	40,747,410
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		137,785,038	155,602,920
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)		92,402
38	AccountsPayable Accounts Payable (232)		(c) 214,538,891	120,452,816
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		4,356,816	3,931,236
41	CustomerDeposits Customer Deposits (235)		10,853,645	8,573,478
42	TaxesAccrued Taxes Accrued (236)	262	(d) 92,522,773	79,488,912
43	InterestAccrued Interest Accrued (237)		18,349,945	18,567,598
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		2,441,695	2,178,547
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		(e) 72,402,424	63,691,637
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		3,802,179	4,012,828
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)		419,360,770	300,897,052
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)		(f) 95,393,208	80,779,904
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	388,447	517,968
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	158,152,503	173,125,630
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	171,400,902	185,656,769
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		455,220,141	431,345,154
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		254,398,643	237,568,898
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		1,134,953,844	1,108,994,323
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		6,986,908,503	6,457,806,502

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: AccumulatedProvisionForInjuriesAndDamages

South Dakota Operations Provision for Injuries and Damages (228.2) are $480,925 and $570,311 for 2022 and 2021, respectively.

Montana Operations Provision for Injuries and Damages (228.2) are $3,884,786 and $6,491,517 for 2022 and 2021, respectively.

(b) Concept: AccumulatedProvisionForPensionsAndBenefits

Montana Operations Accumulated Provision for Pensions and Benefits (228.3) are $7,048,754 and $3,478,599 for 2022 and 2021, respectively.

Montana Operations unfunded reserves for Accounts Payable (232) are $2,019,947 and $2,432,071 for 2022 and 2021, respectively

(d) Concept: TaxesAccrued

Montana Operations unfunded reserves for Taxes Accrued (236) are $88,508,843 and $79,266,640 for 2022 and 2021, respectively.

(e) Concept: MiscellaneousCurrentAndAccruedLiabilities

Montana Operations Miscellaneous Current and Accrued Liabilities (242) are $60,534,114 and $46,613,454 for 2022 and 2021, respectively.

Montana Operations unfunded reserve for Miscellaneous Current and Accrued Liabilities (242) are $23,181,621 and $19,780,351 for 2022 and 2021, respectively.

(f) Concept: CustomerAdvancesForConstruction

Montana Operations Customer Advances for Construction (252) are $95,393,208 and $80,779,904 for 2022 and 2021, respectively.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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 effected 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	1,524,197,364	1,368,686,794			1,127,210,087	1,062,759,806	396,009,572	305,267,815	977,705	659,173
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	809,878,523	673,030,656			544,662,719	484,092,963	264,442,231	188,421,735	773,573	515,958
5	MaintenanceExpense Maintenance Expenses (402)	320	59,014,835	55,652,718			50,136,264	48,389,356	8,825,579	7,196,383	52,992	66,979
6	DepreciationExpense Depreciation Expense (403)	336	167,041,787	159,377,975			139,754,512	132,150,598	27,246,571	27,186,673	40,704	40,704
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	13,044,982	12,550,043			7,316,584	6,526,947	5,728,398	6,023,096
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336	15,101,772	15,101,772			(b) 15,948,277	15,948,277	846,505	846,505
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)		33,744,634	16,821,377			16,669,247	13,407,216	17,075,387	3,414,161
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		45,594,098	21,124,815			28,249,541	15,887,779	17,344,557	5,237,036
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	200,534,577	181,946,099			155,802,375	141,143,613	44,668,842	40,742,717	63,360	59,769
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	9,971,297	2,899,330			3,139,051	2,200,309	6,821,766	5,101,152	10,480	1,513
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	2,754,621	6,222,309			448,741	3,660,431	2,302,267	2,562,400	3,613	522
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	127,918,489	99,750,629			93,412,247	71,864,710	34,505,957	27,889,965	285	4,046
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	141,345,530	104,183,789			99,409,405	71,119,354	41,936,125	33,064,435
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	129,521	239,294			129,521	278,029		38,735
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)		3	2,678			3	2,678
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		1,251,936,365	1,098,286,276			899,501,547	828,257,376	351,489,811	269,351,571	945,007	677,329
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		272,260,999	270,400,518			227,708,540	234,502,430	44,519,761	35,916,244	32,698	18,156
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)		507,851	984,271
32	CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)		486,559	112,834
33	RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417)		255,417	6,199
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		535,233	825,423
35	NonoperatingRentalIncome Nonoperating Rental Income (418)
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	668,404	849,309
37	InterestAndDividendIncome Interest and Dividend Income (419)		2,150,974	2,397,370
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		14,189,693	11,082,078
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		414,852	1,474,307
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		14,998,887	14,156,659
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		987,589	940,748
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)		2,543,918	91,744
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		333,624	230,698
49	OtherDeductions Other Deductions (426.5)		253,101	4,325,600
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		4,118,232	5,405,302
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	2,160	34,252
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	6,388,081	2,639,222
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	1,203,627	3,962,420
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	(a) 18,080,883	33,401,380
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	13,616,535	28,687,003
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)		717,946	1,853,013
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		11,598,601	10,604,370
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		100,558,580	87,711,820
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		1,878,506	1,834,400
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		2,828,333	2,809,928
65	AmortizationOfPremiumOnDebtCredit (Less) Amort. of Premium on Debt-Credit (429)
66	AmortizationOfGainOnReacquiredDebtCredit (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67	InterestOnDebtToAssociatedCompanies Interest on Debt to Assoc. Companies (430)
68	OtherInterestExpense Other Interest Expense (431)		1,579,131	6,641,921
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		5,991,570	4,832,933
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		100,852,980	94,165,136
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		183,006,620	186,839,752
72	ExtraordinaryItemsAbstract Extraordinary Items
73	ExtraordinaryIncome Extraordinary Income (434)
74	ExtraordinaryDeductions (Less) Extraordinary Deductions (435)
75	NetExtraordinaryItems Net Extraordinary Items (Total of line 73 less line 74)
76	IncomeTaxesExtraordinaryItems Income Taxes-Federal and Other (409.3)	262	0
77	ExtraordinaryItemsAfterTaxes Extraordinary Items After Taxes (line 75 less line 76)
78	NetIncomeLoss Net Income (Total of line 71 and 77)		183,006,620	186,839,752

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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)

	FERC Method of Amortization	RSG	SL		ARAM/RSG	SL
	Amortization period	Book Lives	5 Years		Book Lives	5 Years
	Protected/Unprotected	Protected	Unprotected		Protected	Unprotected
	FERC Amorization Account	410.1	410.1		411.1	411.1
	TCJA Excess ADIT Account Reduced	190	190	Subtotal	282	283	Subtotal
	Reg Asset Acccount Impacted	182.3	182.3	182.3	254	254	254
1	Montana:
2	Electric	921,620	3,823,846	4,745,466	(2,113,095)	(2,447,003)	(4,560,098)
3	Gas	(118,700)	—	(118,700)	(1,304,863)	(1)	(1,304,864)
4	Subtotal	802,920	3,823,846	4,626,766	(3,417,958)	(2,447,004)	(5,864,962)
5	South Dakota:
6	Electric	138,138	—	138,138	(619,566)	—	(619,566)
7	Gas	(5,513)	1	(5,512)	(246,803)	—	(246,803)
8	Subtotal	132,625	1	132,626	(866,369)	—	(866,369)
9	Total	935,545	3,823,847	4,759,392	(4,284,327)	(2,447,004)	(6,731,331)


Line No.	Description (a)	(h)	(i)	(j)	(k)

	FERC Method of Amortization		SL (MT) / RSG (SD)	SL
	Amortization period		5 years (MT) / Book Lives (SD)	5 Years
	Protected/Unprotected		F/T "as-if" normalized	F/T "as-if" normalized
	FERC Amorization Account		411.1	410.1
	TCJA Excess ADIT Account Reduced	Total of 182.3	282	190
	Reg Asset Acccount Impacted	and 254	254	182.3	Total
1	Montana:
2	Electric	185,368	(9,824,624)	47,535	(9,591,721)
3	Gas	(1,423,564)	(2,831,409)	—	(4,254,973)
4	Subtotal	(1,238,196)	(12,656,033)	47,535	(13,846,694)
5	South Dakota:
6	Electric	(481,428)	(464,844)	—	(946,272)
7	Gas	(252,315)	(75,063)	—	(327,378)
8	Subtotal	(733,743)	(539,907)	—	(1,273,650)
9	Total	(1,971,939)	(13,195,940)	47,535	(15,120,344)

(b) Concept: AmortizationOfElectricPlantAcquisitionAdjustments

Amort. of Utility Plant Acq. Adj. of $15,948,277 consists of $14,747,883 for Montana Operations and $1,200,394 for South Dakota Operations.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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		725,880,305	666,673,846
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		183,675,024	187,689,061
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		140,062,161	128,482,602
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		140,062,161	128,482,602
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)		769,493,168	725,880,305
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)		769,493,168	725,880,305
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)		446,074	1,295,383
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)		668,404	849,309
51	DividendsReceived (Less) Dividends Received (Debit)
52	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)		222,330	446,074

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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)	183,006,620	186,839,752
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	167,041,787	159,377,975
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of	28,146,754	27,651,815
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other Noncash Charges to Income, Net	(a) 11,984,177	13,589,932
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	8,962,693	281,217
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	129,521	239,294
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	38,162,608	12,236,033
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	26,725,059	19,613,582
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	82,813,419	4,225,784
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	3,473,736	10,802,572
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	14,255,867	2,175,662
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	14,189,693	11,082,078
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies	668,404	849,309
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other	(b) 65,963,298	129,078,465
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	308,746,158	221,220,262
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)	490,436,990	403,215,894
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant	40,252,894	43,517,394
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	14,189,693	11,082,078
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	516,500,191	435,651,210
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
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 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	1,731,829	1,505,221
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	518,232,020	437,156,431
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)		99,915,000
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock	276,971,002	196,246,244
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
64.1	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Treasury Stock Activity	603,028	706,750
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other	92,403
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Line of Credit (Repayments) Borrowings, Net
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	277,666,433	296,867,994
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)		955,280
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Debt Financing Costs	1,286,054	909,219
76.2	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Line of Credit (Repayments) Borrowings, Net	77,000,000	151,000,000
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)		100,000,000
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock	140,062,161	128,482,602
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	213,318,218	217,520,893
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)	3,832,356	1,584,724
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	16,982,170	15,397,446
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	(c) 20,814,526	16,982,170

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: NoncashAdjustmentsToCashFlowsFromOperatingActivities


	12/31/2022	12/31/2021

Other Noncash Charges to Income, Net:
Amortization of debt issue costs, discount, and deferred hedge gain	6,810,280	5,257,572
Gain on disposition of assets	6,379	9,412
Other noncash gains	(320,373)	2,972,632
Stock based compensation costs	5,487,891	5,350,316
	11,984,177	13,589,932

Other Assets and Liabilities, Net:
Net change - other current assets	(3,322,983)	(7,384,241)
Net change - accrued utility revenues	(19,269,232)	(17,657,124)
Net change - deferred debits	(8,634,800)	(87,230,851)
Net change - deferred credits	(10,708,434)	22,435,310
Net change - noncurrent liabilities	(24,027,849)	(39,241,559)
	(65,963,298)	(129,078,465)

(b) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

Refer to footnote at column (b) line 6 for details.

The following table provides a reconciliation of cash, cash equivalents, other special funds, and other special deposits reported within the Balance Sheets that sum to the total cash and cash equivalents amounts reflected in the Statement of Cash Flows:


	12/31/2022		12/31/2021		12/31/2020


Cash (131)	$	8,029,111	$	2,300,750	$	5,454,203
Working Funds (135)	23,450		23,250		22,950
Special Funds (125-128)	—		—		250,000
Other Special Deposits (134)	12,761,965		14,658,170		9,670,293

Total	$	20,814,526	$	16,982,170	$	15,397,446

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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 Cormmission 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 were 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.


(1)Nature of Operations and Basis of Consolidation

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and / or natural gas to approximately 764,200 customers in Montana, South Dakota, Nebraska and Yellowstone National Park. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and 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 NorthWestern Corporation (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.

Management has evaluated the impact of events occurring after December 31, 2022 up to February 17, 2023, the date that NorthWestern's financial statements prepared in accordance with the accounting principles generally accepted in the United States of America (GAAP) were issued, and has updated such evaluation for disclosure purposes through March 6, 2023. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.


(2)Significant Accounting Policies

Financial Statement Presentation

The financial statements are presented on the basis of the accounting requirements of the FERC as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than 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 (see Note 4). The other significant differences consist of the following:

•Earnings per share and footnotes for revenue from contracts with customers, segment and related information, and quarterly financial data (unaudited) are not presented;

•Removal and decommissioning costs of generation, transmission and distribution assets are reflected in the Balance Sheets as a component of accumulated depreciation of $502.2 million and $479.3 million as of December 31, 2022 and December 31, 2021, 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 $357.6 million as of December 31, 2022 and December 31, 2021, 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, 2022 and December 31, 2021, 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 $2.1 million as of December 31, 2022 and December 31, 2021, 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 $2.1 million as of December 31, 2022 and December 31, 2021, 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.

The following table reconciles GAAP revenues to FERC revenues by segment for the twelve months ended December 31, 2022 and 2021 (in millions):


	Twelve Months Ended December 31, 2022
	Total		Electric		Natural Gas		Other

GAAP Revenues	$	1,477.8	$	1,106.5	$	371.3	$	—
Revenue from equity investments	(3.0)		—		(3.0)		—
Grossing revenues / power purchases	57.8		57.8		—		—
Regulatory amortizations	(14.4)		(44.0)		29.6		—
Other	6.0		6.9		(1.9)		1.0
FERC Revenues	$	1,524.2	$	1,127.2	$	396.0	$	1.0


	Twelve Months Ended December 31, 2021
	Total		Electric		Natural Gas		Other

GAAP Revenues	$	1,372.3	$	1,052.2	$	320.1	$	—
Revenue from equity investments	(3.0)		—		(3.0)		—
Grossing revenues / power purchases	38.1		38.1		—		—
Regulatory amortizations	(42.7)		(32.1)		(10.6)		—
Other	4.0		4.6		(1.3)		0.7
FERC Revenues	$	1,368.7	$	1,062.8	$	305.2	$	0.7

Use of Estimates

The preparation of financial statements in conformity with the regulatory basis of accounting 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 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, asset retirement obligations, regulatory assets and liabilities, allowances for uncollectible accounts, our Qualifying Facilities 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

The Company recognizes 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.

Accounts Receivable, Net

Accounts receivable are net of allowances for uncollectible accounts of $2.5 million and $2.3 million at December 31, 2022 and December 31, 2021, respectively. Unbilled revenues were $117.4 million and $98.1 million at December 31, 2022 and December 31, 2021, respectively.

Inventories

Inventories are stated at average cost. Inventory consisted of the following (in thousands):


	December 31,
	2022		2021
Fuel stock	$	7,725	$	7,510
Plant materials and operating supplies	71,154		53,539
Gas stored underground (including the non-current portion reflected in utility plant)	63,933		55,019
Total Inventories	$	142,812	$	116,068

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 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 (Accumulated Provision for Rate Refunds).

If we were required to terminate the application of these provisions to our regulated operations, all such deferred amounts would be recognized in the Statements of Income at that time. This would result in a charge to earnings and AOCI, 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 Balance Sheets at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales 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 AOCI 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 Statements of Cash Flows, depending on the underlying nature of the hedged items. As of December 31, 2022, the only derivative instruments we have qualify for the normal purchases and normal sales exception.

Revenues and expenses on contracts that are designated as normal purchases and normal sales 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. Normal purchases and normal sales 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 normal purchase or a normal sale 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.

Utility Plant

Utility Plant 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 plant 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 net interest charges, while the equity component is included in other income. This rate averaged 6.4% and 6.6% for Montana for 2022 and 2021, respectively. This rate averaged 6.4% for South Dakota for 2022 and 2021. AFUDC capitalized totaled $20.2 million and $15.9 million for the years ended December 31, 2022, 2021 respectively, for Montana and South Dakota combined.

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 2 to 96 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 2022 and 2021

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 accumulated depreciation.

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. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. 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 Statement of Income and provision for income taxes.

Environmental Costs

We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset if there is precedent for recovering similar costs from customers in rates.

Otherwise, we expense the costs. 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


	Twelve Months Ended December 31,
	2022		2021
	(in thousands)
Cash paid for:
Income taxes	$	4,707	$	4,330
Interest	95,400		87,221
Significant non-cash transactions:
Capital expenditures included in trade accounts payable	64,758		29,034
NMTC debt extinguishment included in other noncurrent assets(1)	—		18,169
NMTC debt extinguishment included in utility plant(1)	—		6,594
NMTC debt extinguishment included in long-term debt(1)	—		1,259

(1) See Note 12 - Long-Term Debt for further information regarding this non-cash transaction.

The following table provides a reconciliation of cash, working funds, other special funds, and special deposits reported within the Balance Sheets that sum to the total of the same such amounts shown in the Statements of Cash Flows (in thousands):


	December 31,
	2022		2021
Cash	$	8,029	$	2,301
Working funds	23		23
Special deposits	12,762		14,658
Total shown in the Statement of Cash Flows	$	20,814	$	16,982

Special deposits consist primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements.

Accounting Standards Issued

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)Regulatory Matters

Montana Rate Review

On August 8, 2022, we filed a Montana electric and natural gas rate review with the MPSC requesting an annual increase to electric and natural gas utility rates of $171.0 million and $23.0 million, respectively, detailed as follows:


Requested Revenue Increase (in millions)
	Electric	Natural Gas
Base Rates	$91.8	$20.2
Power Cost & Credit Mechanism (PCCAM)(1)	$68.1	n/a
Property Tax (tracker true-up)(1)	$11.1	$2.8
Total	$171.0	$23.0

(1) These items are flow-through costs, which represent approximately 42% of the requested electric and natural gas revenue increase.

Our electric request is based on a return on equity of 10.60% with a forecasted 2022 rate base of $2.8 billion and a capital structure of 51.98% debt and 48.02% equity. Our natural gas request is based on a return on equity of 10.60% with a forecasted 2022 rate base of $575.3 million and a capital structure of 51.98% debt and 48.02% equity.

Within this rate review filing we requested an increase to the Power Cost and Credit Mechanism (PCCAM) base rate (PCCAM Base rate) of $68.1 million, as well as structural revisions to the PCCAM mechanism to provide customers with prices that better reflect the cost of services received. We also proposed to implement a revised electric only pilot for the Fixed Cost Recovery Mechanism (FCRM) beginning July 1, 2023, or alternatively to terminate the FCRM. Our rate review filing also includes proposals for more timely cost recovery beyond the test period, including critical reliability resources, such as the Yellowstone County Generating Station, our Enhanced Wildfire Mitigation plan, and business technology maintenance costs.

On September 28, 2022, the MPSC approved the recommendations of the MPSC Staff for interim rates, subject to refund, which increased base electric rates $29.4 million, PCCAM Base rates $61.1 million, and base natural gas rates $1.7 million, effective October 1, 2022.

A hearing is scheduled to commence on April 11, 2023. Interim rates will remain in effect on a refundable basis until the MPSC issues a final order.

Montana Community Renewable Energy Projects (CREPs)

We were required to acquire, as of December 31, 2020, approximately 65 MW of CREPs. While we made progress towards meeting this obligation by acquiring approximately 50 MW of CREPs, we were unable to acquire the remaining MWs required for various reasons, including the fact that proposed projects fail to qualify as CREPs or do not meet the statutory cost cap. The MPSC granted us waivers for 2012 through 2016. The validity of the MPSC’s action as it related to waivers granted for 2015 and 2016 has been challenged legally and was fully briefed before the Montana Supreme Court.

On May 14, 2021, the Montana Governor signed a bill that eliminated the state's Renewable Portfolio Standard, including repeal of the CREP requirement. We notified the Montana Supreme Court of the repeal. We also dismissed our pending application filed with the MPSC for a waiver from full compliance for years 2017 through 2020.

On September 7, 2021, the Montana Supreme Court remanded the case challenging the 2015 and 2016 waivers to the District Court to determine whether the repeal of the CREP requirement made the petition moot. On May 9, 2022, the District Court imposed a $2.5 million penalty against us, payable to the Universal Low Income Assistance Fund in Montana, in connection with a petition filed by the MEIC challenging the MPSC's decision granting our waiver requests from CREP

compliance in 2015 and 2016. The expense associated with this penalty was accrued for within our 2022 results. We filed an appeal with the Montana Supreme Court and that appeal is now fully briefed.


(4)Equity Investments

The following table presents our equity investments reflected in the investments in subsidiary companies on the Balance Sheets (in thousands):


	December 31,
	2022		2021
Havre Pipeline Company, LLC	$	11,399	$	12,130
Canadian Montana Pipeline Corporation	4,984		4,867
NorthWestern Services, LLC	2,091		2,065
NorthWestern Energy Solutions, Inc.	5,738		4,126
Risk Partners Assurance, Ltd.	1,132		1,190
Total Investments in Subsidiary Companies	$	25,344	$	24,378


(5)Regulatory Assets and Liabilities

We prepare our 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, excluding the Montana PCCAM, 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,
			2022		2021
			(in thousands)
Flow-through income taxes	14	Plant Lives	$	509,038	$	464,664
Pension	16	See Note 16	87,965		98,336
Excess deferred income taxes	14	Plant Lives	54,364		60,813
Employee related benefits	16	See Note 16	27,920		21,648
State & local taxes & fees		1 Year	15,643		6,514
Environmental clean-up	19	Undetermined	10,963		11,262
Other		Various	23,191		21,912
Total Regulatory Assets			$	729,084	$	685,149
Excess deferred income taxes	14	Plant Lives	148,989		158,047
Unbilled revenue		1 Year	11,536		16,430
Gas storage sales		17 years	7,046		7,466
State & local taxes & fees		1 Year	2,327		3,021
Environmental clean-up and other		1 Year	1,503		693
Total Regulatory Liabilities			$	171,401	$	185,657

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 14 - Income Taxes for further discussion.

Pension and Employee Related Benefits

We recognize the unfunded portion of plan benefit obligations in the 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 SDPUC allows recovery of pension costs on an accrual basis. 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 in rates, less the amount allocated to FERC jurisdictional customers and net of the related income tax benefit.

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 19 - 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.

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.

Unbilled Revenue

In accordance with regulatory guidance in South Dakota, we recognize revenue when it is billed. Accordingly, we record a regulatory liability to offset unbilled revenue.


(6)Utility Plant

The following table presents the major classifications of our net utility plant (in thousands):


	December 31,
	2022		2021 (1)
	(in thousands)
Electric Plant	$	5,286,650	$	4,929,211
Natural Gas Plant	1,311,436		1,192,066
Plant acquisition adjustment	686,328		686,328
Common and Other Plant	306,866		276,481
Construction work in process	300,649		284,729
Total utility plant	7,891,929		7,368,815
Less accumulated depreciation	(2,786,712)		(2,648,396)
Net utility plant	$	5,105,217	$	4,720,419

(1) The December 31, 2021 balances reported above have been reclassified to conform with the December 31, 2022 presentation of major classifications of property, plant and equipment. The reclassification has no impact on the presentation of total property, plant and equipment. These reclassifications were done in an effort to better convey the nature of these balances.

Net utility plant under capital (finance) lease were $7.2 million and $9.2 million as of December 31, 2022 and 2021, respectively, which included $7.0 million and $9.0 million as of December 31, 2022 and 2021, respectively, related to 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 an ownership interest in four base-load electric generating plants, all of which are coal fired and operated by other companies. We have an undivided interest in these facilities and are responsible for our proportionate share of the

capital and operating costs while being entitled to our proportionate share of the power generated. Our interest in each plant is reflected in the Balance Sheets on a pro rata basis and our share of operating expenses is reflected in the Statements of Income. The participants each finance their own investment.

On January 16, 2023, we entered into a definitive agreement (Agreement) with Avista Corporation (Avista) to acquire Avista's 15 percent interest in each of Units 3 and 4 at the Colstrip Generating Station, a coal-fired, base-load electric generation facility located in Colstrip, Montana. As noted in the table below, we currently have a 30 percent interest in Unit 4. The Agreement provides that the purchase price will be $0 and that we will acquire Avista's interest effective December 31, 2025, subject to the satisfaction of the closing conditions contained within the agreement. Under the terms of this Agreement, we will be responsible for operating costs starting on January 1, 2026; while Avista will retain responsibility for its 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 decommission and demolition costs associated with the existing facilities that comprise Avista's interest.

The Agreement contains customary representations and warranties, covenants, and indemnification obligations, and the Agreement is subject to customary conditions and approvals, including approval from the FERC. Closing also is conditioned on our ability to enter into a new coal supply agreement for Colstrip by December 31, 2024. Such coal supply agreement must provide a sufficient amount of coal to Colstrip to permit the generation of electric power by the maximum permitted capacity of the interest in Colstrip then held by us during the period from January 1, 2026 through, December 31, 2030.

Either party may terminate the Agreement if any requested regulatory approval is denied or if the closing has not occurred by December 31, 2025 or if any law or order would delay or impair closing. The Agreement may be subject to the exercise by other Colstrip owners of a right of first refusal set forth in the O&O Agreement. Should any other owners exercise such rights, we intend to exercise our right of first refusal under the O&O Agreement to the fullest extent permitted, and Avista has agreed that it will not exercise its right of first refusal.

Information relating to our ownership interest in these facilities is as follows (in thousands):


	Big Stone (SD)			Neal #4 (IA)			Coyote (ND)			Colstrip Unit 4 (MT)
December 31, 2022
Ownership percentages	23.4		%	8.7		%	10.0		%	30.0		%
Plant in service	$	155,567		$	63,032		$	51,796		$	326,584
Accumulated depreciation	46,748			39,077			42,465			122,938
December 31, 2021
Ownership percentages	23.4		%	8.7		%	10.0		%	30.0		%
Plant in service	$	154,375		$	62,865		$	51,652		$	324,433
Accumulated depreciation	45,895			37,749			41,918			114,830


(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 utility plant and asset retirement obligations (ARO). 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 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 facilities, 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,
	2022		2021
Liability at January 1,	$	40,631	$	45,355
Accretion expense	1,853		2,233
Liabilities incurred	—		—
Liabilities settled	(4,004)		(2,906)
Revisions to cash flows	2,414		(3,935)
Liability at December 31,	$	40,894	$	40,747

During the twelve months ended December 31, 2022 our ARO liability decreased $4.0 million for partial settlement of the legal obligations at our jointly-owned coal-fired generation facilities and natural gas pipeline segments. Additionally, during the twelve months ended December 31, 2022, our ARO liability increased $2.4 million related to changes in both the timing and amount of retirement cost estimates.

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 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.


(8)Utility Plant Adjustments

We completed our annual utility plant adjustments impairment test as of April 1, 2022 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.


(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: normal purchase normal sale (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 Financial Statements at December 31, 2022 and 2021. 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 AOCI. We reclassify these gains from AOCI into interest on long term debt 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 Financial Statements (in thousands):

Cash Flow Hedges

Location of Amount Reclassified from AOCI to Income

Amount Reclassified from AOCI into Income during the Year Ended December 31, 2021

Interest rate contracts

Interest on long-term debt

612

A pre-tax loss of approximately $13.4 million is remaining in AOCI as of December 31, 2022, and we expect to reclassify approximately $0.6 million of pre-tax losses from AOCI 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, and accounts payable, 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, 2022	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)
Special deposits	$	12,762	$	—	$	—	$	—	$	12,762
Rabbi trust investments	20,895		—		—		—		20,895
Total	$	33,657	$	—	$	—	$	—	$	33,657

December 31, 2021
Special deposits	$	14,658	$	—	$	—	$	—	$	14,658
Rabbi trust investments	18,234		—		—		—		18,234
Total	$	32,892	$	—	$	—	$	—	$	32,892

Special deposits represent amounts held in money market mutual funds. 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, 2022				December 31, 2021
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	2,629,660	$	2,327,478	$	2,552,660	$	2,838,518

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

Credit Facility

On May 18, 2022, we amended our existing $425 million credit facility to, among other things, change the Eurodollar rate to the secured overnight financing rate as administered by the Federal Reserve Bank of New York (SOFR) and extend the maturity date of the facility from September 2, 2023 to May 18, 2027. The amended and restated credit facility (the Primary Credit Facility) maintains the same capacity at $425 million and uncommitted features that allow us to request up to two one-year extensions to the maturity date and increase the size of the facility by up to an additional $75 million. The Primary Credit 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.

On October 28, 2022, we entered into a $100 million Credit Agreement (the Additional Credit Facility) to supplement our existing $425 million revolving credit facility. The Additional Credit Facility has a maturity date of April 28, 2024. The Additional Credit 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.

On March 25, 2022, we amended our existing $25 million swingline credit facility (the Swingline Facility) to, among other things, change the Eurodollar rate to the secured overnight financing rate as administered by the Federal Reserve Bank of New York (SOFR) and extend the maturity date of the facility from March 27, 2023 to March 27, 2024. The Swingline Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a margin of 90.0 basis points, or (b) a base rate, plus a margin of 12.5 basis points.

Commitment fees for the unsecured revolving lines of credit were $0.1 million and $0.4 million for the years ended December 31, 2022 and 2021.

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


	2022		2021
Unsecured revolving line of credit, expiring May 2027	$	425.0	$	425.0
Unsecured revolving line of credit, expiring April 2024	100.0		—
Unsecured revolving line of credit, expiring March 2024	25.0		25.0
	550.0		450.0

Amounts outstanding at December 31:
SOFR borrowings	450.0		—
Eurodollar borrowings	—		373.0
Letters of credit	—		—
	450.0		373.0

Net availability as of December 31	$	100.0	$	77.0

The Credit Facility includes covenants that require us to meet certain financial tests, including a maximum debt to capitalization ratio not to exceed 65 percent. The facility also contains 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 South Dakota or Montana First Mortgage Bonds would trigger a cross default on the Credit Facility; however, a default on the Credit Facility would not trigger a default on the South Dakota or Montana First Mortgage Bonds.


(12)Long-Term Debt

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


		December 31,
	Due	2022		2021
Unsecured Debt:
Unsecured Revolving Line of Credit	2027	$	425,000	$	—
Unsecured Revolving Line of Credit	2024	25,000		—
Unsecured Revolving Line of Credit	2023	—		373,000
Secured Debt:
Mortgage bonds—
South Dakota—5.01%	2025	64,000		64,000
South Dakota—4.15%	2042	30,000		30,000
South Dakota—4.30%	2052	20,000		20,000
South Dakota—4.85%	2043	50,000		50,000
South Dakota—4.22%	2044	30,000		30,000
South Dakota—4.26%	2040	70,000		70,000
South Dakota—3.21%	2030	50,000		50,000
South Dakota—2.80%	2026	60,000		60,000
South Dakota—2.66%	2026	45,000		45,000
Montana—5.71%	2039	55,000		55,000
Montana—5.01%	2025	161,000		161,000
Montana—4.15%	2042	60,000		60,000
Montana—4.30%	2052	40,000		40,000
Montana—4.85%	2043	15,000		15,000
Montana—3.99%	2028	35,000		35,000
Montana—4.176%	2044	450,000		450,000
Montana—3.11%	2025	75,000		75,000
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—3.21%	2030	100,000		100,000
Montana—1.00%	2024	100,000		100,000
Pollution control obligations—
Montana—2.00%	2023	144,660		144,660
Total Long-Term Debt		$	2,629,660	$	2,552,660

Secured Debt

First Mortgage Bonds and Pollution Control Obligations

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

The Montana First Mortgage Bonds and Montana Pollution Control Obligations are secured by substantially all of our Montana electric and natural gas assets.

In March 2021, we issued and sold $100.0 million aggregate principal amount of Montana First Mortgage Bonds (the bonds) at a fixed interest rate of 1.00 percent maturing on March 26, 2024. The net proceeds were used to repay in full our outstanding $100.0 million term loan that was due April 2, 2021. We may redeem some or all of the bonds at any time in whole, or from time to time in part, at our option, on or after March 26, 2022, at a redemption price equal to 100% of the principal amount of the bonds to be redeemed, plus accrued and unpaid interest on the principal amount of the bonds being redeemed to, but excluding, the redemption date. The bonds are secured by our electric and natural gas assets in Montana and Wyoming.

As of December 31, 2022, we were in compliance with our financial debt covenants.

Other Long-Term Debt

In July 2021, our two loans totaling $27.0 million associated with the New Market Tax Credit (NMTC) financing agreement were extinguished. These loans were satisfied with our $18.2 million investment in the entities created in relation to the NMTC transaction, investor forgiveness of $7.9 million for substantially all of the benefits derived from the tax credits, and cash payment of $0.9 million. In accordance with our last rate case filing in the state of Montana, the portion of the loan forgiven, less unamortized debt issuance costs of $1.3 million, was recorded as a reduction to the cost of the office building associated with the NMTC financing agreement. This cash payment is reflected within the financing activities section of our Statement of Cash Flows for the year ended December 31, 2021; however, the remaining reduction to Long-term debt, Other investments, and Utility plant are non-cash financing activities that are not reflected within our Statement of Cash Flows for the year ended December 31, 2021.

Maturities of Long-Term Debt

The aggregate minimum principal maturities of long-term debt during the next five years are $144.7 million in 2023, $125.0 million in 2024, $300.0 million in 2025, $105.0 million in 2026 and $425.0 million in 2027.


(13)Related Party Transactions

Accounts receivable from and payables to associated companies primarily include intercompany billings for direct charges, overhead, and income tax obligations. The following table reflects our accounts receivable from and accounts payable to associated companies (in thousands):


	December 31,
	2022		2021
Accounts Receivable from Associated Companies:
Havre Pipeline Company, LLC	$	3,201	$	2,729
NorthWestern Energy Solutions, Inc.	16		71
Risk Partners Assurance, Ltd.	(74)		18
	$	3,143	$	2,818

Accounts Payable to Associated Companies:
Canadian Montana Pipeline Corporation	$	2,312	$	2,094
NorthWestern Services, LLC	2,045		1,837
	$	4,357	$	3,931


(14)Income Taxes

Our effective tax rate typically differs from the federal statutory tax rate primarily due to production tax credits and the regulatory impact of flowing through the federal and state tax benefit of repairs deductions and state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable). 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 components of the net deferred income tax assets and liabilities recognized in our Balance Sheets are related to the following temporary differences (in thousands):


	December 31,
	2022		2021
Production tax credit	$	80,097	$	75,092
Pension / postretirement benefits	19,291		21,435
Customer advances	25,119		21,271
Unbilled revenue	9,440		10,704
Compensation accruals	10,306		10,612
Environmental liability	6,009		5,704
Reserves and accruals	4,015		5,105
Interest rate hedges	3,372		3,158
Other, net	6,295		7,833
Deferred Tax Asset	163,944		160,914
Excess tax depreciation	(455,220)		(431,345)
Flow through depreciation	(104,976)		(92,502)
Goodwill amortization	(91,746)		(91,689)
Regulatory assets and other	(58,065)		(53,896)
Deferred Tax Liability	(710,007)		(669,432)
Deferred Tax Liability, net	$	(546,063)	$	(508,518)

At December 31, 2022, our total production tax credit carryforward was approximately $80.1 million. If unused, our production tax credit carryforwards will expire as follows: $8.9 million in 2036, $11.0 million in 2037, $10.9 million in 2038, $11.5 million in 2039, $13.1 million in 2040, $11.5 million in 2041, and $13.2 million in 2042. 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):


	2022		2021
Unrecognized Tax Benefits at January 1	$	32,049	$	33,491
Gross increases - tax positions in prior period	—		293
Gross increases - tax positions in current period	—		—
Gross decreases - tax positions in current period	(1,719)		(1,735)
Lapse of statute of limitations	—		—
Unrecognized Tax Benefits at December 31	$	30,330	$	32,049

Our unrecognized tax benefits include approximately $27.9 million and $28.1 million related to tax positions as of December 31, 2022 and 2021, that if recognized, would impact our annual effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

Our policy is to recognize interest related to uncertain tax positions in interest expense. As of December 31, 2022, we have accrued $1.4 million for the payment of interest in the Balance Sheets. As of December 31, 2021, we had $0.5 million accrued for the payment of interest.

Tax years 2019 and forward remain subject to examination by the Internal Revenue Service (IRS) and state taxing authorities. During the first quarter of 2023 the IRS commenced a limited scope examination of the Company's 2019 amended federal income tax return.


(15)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,
	2022						2021
	Before- Tax Amount		Tax Expense (Benefit)		Net-of- Tax Amount		Before- Tax Amount		Tax Expense (Benefit)		Net-of- Tax Amount
Foreign currency translation adjustment	$	(8)	$	—	$	(8)	$	(58)	$	—	$	(58)
Reclassification of net income (loss) on derivative instruments	612		(160)		452		614		(162)		452
Postretirement medical liability adjustment	(1,359)		377		(982)		(585)		149		(436)
Other comprehensive income (loss)	$	(755)	$	217	$	(538)	$	(29)	$	(13)	$	(42)

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


	December 31,
	2022		2021
Foreign currency translation	$	1,435	$	1,443
Derivative instruments designated as cash flow hedges	(7,675)		(8,127)
Postretirement medical plans	534		1,516
Accumulated other comprehensive loss	$	(5,706)	$	(5,168)

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


	December 31, 2022
	Year Ended
	Affected Line Item in the Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges		Postretirement Medical Plans		Foreign Currency Translation		Total
Beginning balance		$	(8,127)	$	1,516	$	1,443	$	(5,168)
Other comprehensive income before reclassifications						(8)		(8)
Amounts reclassified from AOCI	Interest on long-term debt	452						452
Amounts reclassified from AOCI				(982)				(982)
Net current-period other comprehensive income		452		(982)		(8)		(538)
Ending Balance		$	(7,675)	$	534	$	1,435	$	(5,706)


	December 31, 2021
	Year Ended
	Affected Line Item in the Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges		Postretirement Medical Plans		Foreign Currency Translation		Total
Beginning balance		$	(8,579)	$	1,952	$	1,501	$	(5,126)
Other comprehensive income before reclassifications						(58)		(58)
Amounts reclassified from AOCI	Interest on long-term debt	452						452
Amounts reclassified from AOCI				(436)				(436)
Net current-period other comprehensive income		452		(436)		(58)		(42)
Ending Balance		$	(8,127)	$	1,516	$	1,443	$	(5,168)


(16)Employee Benefit Plans

Pension and Other Postretirement Benefit Plans

We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for eligible employees. The pension plan for our South Dakota and Nebraska employees is referred to as the NorthWestern Corporation plan, and the pension plan for our Montana employees is referred to as the NorthWestern Energy plan, and collectively they are referred to as the Plans. 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 an asset or liability in our 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,
	2022		2021		2022		2021
Change in benefit obligation:
Obligation at beginning of period	$	696,802	$	820,979	$	19,146	$	19,146
Service cost	10,223		12,994		407		407
Interest cost	18,787		18,759		317		317
Actuarial loss	(176,389)		(28,905)		415		415
Settlements(1)	—		(93,488)		—		—
Benefits paid	(27,625)		(33,537)		(2,977)		(2,977)
Benefit Obligation at End of Period	$	521,798	$	696,802	$	17,308	$	17,308
Change in Fair Value of Plan Assets:
Fair value of plan assets at beginning of period	$	605,499	$	688,456	$	23,096	$	23,096
Return on plan assets	(144,535)		33,868		3,349		3,349
Employer contributions	8,200		10,200		1,821		1,821
Settlements(1)	—		(93,488)		—		—
Benefits paid	(27,625)		(33,537)		(2,977)		(2,977)
Fair value of plan assets at end of period	$	441,539	$	605,499	$	25,289	$	25,289
Funded Status	$	(80,259)	$	(91,303)	$	7,981	$	7,981

Amounts Recognized in the Balance Sheet Consist of:
Noncurrent asset	7,195		8,297		11,914		11,914
Total Assets	7,195		8,297		11,914		11,914
Current liability	(11,200)		(11,200)		(1,575)		(1,575)
Noncurrent liability	(76,254)		(88,400)		(2,358)		(2,358)
Total Liabilities	(87,454)		(99,600)		(3,933)		(3,933)
Net amount recognized	$	(80,259)	$	(91,303)	$	7,981	$	7,981

Amounts Recognized in Regulatory Assets Consist of:
Prior service credit	—		—		(116)		1,870
Net actuarial loss	(54,383)		(62,448)		(3,123)		1,366
Amounts recognized in AOCI consist of:
Prior service cost	—		—		—		(95)
Net actuarial gain	—		—		1,046		2,500
Total	$	(54,383)	$	(62,448)	$	(2,193)	$	5,641

(1) In December 2021, we entered into a group annuity contract from an insurance company to provide for the payment of pension benefits to 1,062 NorthWestern Energy Pension Plan participants. We purchased the contract with $93.5 million of plan assets. The insurance company took over the payments of these benefits starting January 1, 2022. This transaction settled $93.5 million of our NorthWestern Energy Pension Plan obligation. As a result of this transaction, during the twelve months ended December 31, 2021, we recorded a non-cash, non-operating settlement charge of $11.3 million. This charge is recorded within operating expenses, net on the Statements of Income. As discussed within Note 5 – Regulatory Assets and Liabilities, this charge was deferred as a regulatory asset on the Balance Sheets, with a corresponding decrease to operating expense on the Statements of Income.

The actuarial gain/loss is primarily due to the change in discount rate assumption and actual asset returns compared with expected amounts. The total projected benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were as follows (in millions):


	NorthWestern Energy Pension Plan
	December 31,
	2022		2021
Projected benefit obligation	$	474.9	$	636.3
Accumulated benefit obligation	474.9		636.3
Fair value of plan assets	388.7		537.9

_____________________

As of December 31, 2022, the fair value of the NorthWestern Corporation pension plan assets exceed the total projected and accumulated benefit obligation and are therefore excluded from this table.

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,
	2022		2021		2022		2021
Components of Net Periodic Benefit Cost
Service cost	$	10,223	$	12,994	$	351	$	407
Interest cost	18,787		18,759		359		327
Expected return on plan assets	(24,173)		(27,061)		(1,047)		(919)
Amortization of prior service cost (credit)	—		—		(1,891)		(1,835)
Recognized actuarial loss (gain)	383		6,536		(897)		(898)
Settlement loss recognized(1)	—		11,291		—		—
Net Periodic Benefit Cost (Credit)	$	5,220	$	22,519	$	(3,125)	$	(2,918)

Regulatory deferral of net periodic benefit cost(2)	2,307		(13,308)		—		—
Previously deferred costs recognized(2)	—		—		292		709
Amount Recognized in Income	$	7,527	$	9,211	$	(2,833)	$	(2,209)

_________________________

(1) Settlement loss is related to partial annuitization of NorthWestern Energy Pension Plan effective December 1, 2021.

(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 Statements of Income as those costs are recovered through customer rates.

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, 2022 and 2021. 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 2022 decreased our projected benefit obligation by approximately $179.2 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 increased our long term rate of return on assets assumption for NorthWestern Energy Pension Plan to 6.44 percent and increased our assumption on the NorthWestern Corporation Pension Plan to 4.83 percent for 2023.

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


	Pension Benefits				Other Postretirement Benefits
	December 31,				December 31,
	2022		2021		2022		2021
Discount rate	5.20	%	2.65-2.75	%	5.15-5.20	%	2.35-2.40	%
Expected rate of return on assets	2.66-4.26		3.01-4.17		4.23		4.08
Long-term rate of increase in compensation levels (non-union)	4.00		2.84		4.00		2.84
Long-term rate of increase in compensation levels (union)	4.00		2.00		4.00		2.00
Interest crediting rate	3.30-6.00		3.30-6.00		N/A		N/A

The postretirement benefit obligation is calculated assuming that health care costs increase by a 5.00 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 that a moderate allocation to each can potentially improve the expected risk-adjusted return for the NorthWestern Energy 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 5 percent, is as follows:


	NorthWestern Energy Pension				NorthWestern Corporation Pension				NorthWestern Energy Health and Welfare
	December 31,				December 31,				December 31,
	2022		2021		2022		2021		2022		2021
Fixed income securities	45.0	%	55.0	%	90.0	%	90.0	%	40.0	%	40.0	%
Non-U.S. fixed income securities	—		4.0		1.0		1.0		—		—
Opportunistic fixed income	5.5		—		—		—		—		—
Global equities	44.0		41.0		9.0		9.0		60.0		60.0
Private real estate	5.5		—		—		—		—		—

The actual allocation by plan is as follows:


	NorthWestern Energy Pension				NorthWestern Corporation Pension				NorthWestern Energy Health and Welfare
	December 31,				December 31,				December 31,
	2022		2021		2022		2021		2022		2021
Cash and cash equivalents	—	%	0.1	%	1.1	%	0.4	%	0.6	%	0.1	%
Fixed income securities	44.5		53.8		88.6		89.5		36.7		33.7
Non-U.S. fixed income securities	—		3.9		0.9		0.9		—		—
Opportunistic fixed income	5.5		—		—		—		—		—
Global equities	43.4		42.2		9.4		9.2		62.7		66.2
Private real estate	6.6		—		—		—
	100.0	%	100.0	%	100.0	%	100.0	%	100.0	%	100.0	%

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.

Our plan assets are primarily invested in common collective trusts (CCTs), which are invested in equity and fixed income securities. In accordance with our investment policy, these pooled investment funds must have an adequate asset base relative to their asset class and be invested in a diversified manner and have a minimum of three years of verified investment performance experience or verified portfolio manager investment experience in a particular investment strategy and have management and oversight by an investment advisor registered with the Securities and Exchange Commission (SEC). Investments in a collective investment vehicle are valued by multiplying the investee company’s net asset value per share with the number of units or shares owned at the valuation date. Net asset value 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 funds do not contain any redemption restrictions. The direct holding of NorthWestern Corporation stock is not permitted; however, any holding in a diversified mutual fund or collective investment fund is permitted.

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 2023 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 2022 and 2021 were based on actual contributions to the plan. Annual contributions to each of the pension plans are as follows (in thousands):


	2022		2021
NorthWestern Energy Pension Plan (MT)	$	7,000	$	9,000
NorthWestern Corporation Pension Plan (SD and NE)	1,200		1,200
	$	8,200	$	10,200

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


	Pension Benefits		Other Postretirement Benefits
2023	$	31,014	$	2,520
2024	32,448		2,079
2025	33,904		1,584
2026	34,908		1,511
2027	35,490		1,372
2028-2032	185,939		6,060

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 be contributed to the plan. We contribute various percentage amounts of the employee's gross compensation contributed to the plan. Matching contributions for the years ended December 31, 2022 and 2021 were $12.3 million and $11.8 million, respectively.


(17)Stock-Based Compensation

We grant stock-based awards through our Amended and Restated Equity Compensation Plan (ECP), which includes restricted stock awards and performance share awards. As of December 31, 2022, there were 655,565 shares of common stock remaining available for grants. The remaining vesting period for awards previously granted ranges from one to five years if the service and/or performance requirements are met. Nonvested shares do not receive dividend distributions. The long-term incentive plan provides for accelerated vesting in the event of a change in control.

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.

Performance Unit Awards

Performance unit awards are granted annually under the ECP. These awards vest at the end of the three-year performance period if we have achieved certain performance goals and the individual remains employed by us. The exact number of shares issued will vary from 0 percent to 200 percent of the target award, depending on actual company performance relative to the performance goals. These awards contain both market- and performance-based components. The performance goals are

independent of each other and equally weighted, and are based on two metrics: (i) EPS growth level and average return on equity; and (ii) total shareholder return (TSR) relative to a peer group.

Fair value is determined for each component of the performance unit awards. The fair value of the earnings per share component is estimated based upon the closing market price of our common stock as of the date of grant less the present value of expected dividends, multiplied by an estimated performance multiple determined on the basis of historical experience, which is subsequently trued up at vesting based on actual performance. The fair value of the TSR portion is estimated using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. The following summarizes the significant assumptions used to determine the fair value of performance shares and related compensation expense as well as the resulting estimated fair value of performance shares granted:


	2022		2021
Risk-free interest rate	1.82	%	0.19	%
Expected life, in years	3		3
Expected volatility	28.2% to 38.8%		28.2% to 38.5%
Dividend yield	4.5	%	4.3	%

The risk-free interest rate was based on the U.S. Treasury yield of a three-year bond at the time of grant. The expected term of the performance shares is three years based on the performance cycle. Expected volatility was based on the historical volatility for the peer group. Both performance goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest.

A summary of nonvested shares as of and changes during the year ended December 31, 2022, are as follows:


	Performance Unit Awards
	Shares	Weighted-Average Grant-Date Fair Value
Beginning nonvested grants	162,523	$	58.76
Granted	92,970	51.61
Vested	(58,889)	73.13
Forfeited	(2,197)	54.25
Remaining nonvested grants	194,407	$	51.04

We recognized compensation expense of $4.2 million and $3.9 million for the years ended December 31, 2022 and 2021 respectively, and related income tax benefit of $(1.3) million and $(0.2) million for the years ended December 31, 2022 and 2021 respectively. As of December 31, 2022, we had $6.4 million of unrecognized compensation cost related to the nonvested portion of outstanding awards, which is reflected as nonvested stock as a portion of additional paid in capital in our Statements of Common Shareholders' Equity. The cost is expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested was $4.3 million and $4.2 million for the years ended December 31, 2022 and 2021 respectively.

Retirement/Retention Restricted Share Awards

In December 2011, an executive retirement / retention program was established that provides for the annual grant of restricted share units. Awards granted before 2022 are subject to a five-year performance and vesting period. The performance measure for these awards requires net income for the calendar year of at least three of the five full calendar years during the performance period to exceed net income for the calendar year the awards are granted. Awards granted in 2022 and retirement/retention restricted share awards granted in the future no longer contain this performance measure,

instead these awards will vest after five full calendar years if the employee remains employed during that service period. Once vested, the awards will be paid out in shares of common stock in five equal annual installments after a recipient has separated from service. The fair value of these awards is measured based upon the closing market price of our common stock as of the date of grant less the present value of expected dividends.

A summary of nonvested shares as of and changes during the year ended December 31, 2022, are as follows:


	Shares	Weighted-Average Grant-Date Fair Value
Beginning nonvested grants	87,319	$	49.63
Granted	25,360	47.04
Vested	(13,394)	52.20
Forfeited	—	—
Remaining nonvested grants	99,285	$	48.62

Director's Deferred Compensation

Nonemployee directors may elect to defer up to 100 percent of any qualified compensation that would be otherwise payable to him or her, subject to compliance with our 2005 Deferred Compensation Plan for Nonemployee Directors and Section 409A of the Internal Revenue Code. The deferred compensation may be invested in NorthWestern stock or in designated investment funds. Compensation deferred in a particular month is recorded as a deferred stock unit (DSU) on the first of the following month based on the closing price of NorthWestern stock or the designated investment fund. The DSUs are marked-to-market on a quarterly basis with an adjustment to director’s compensation expense. Based on the election of the nonemployee director, following separation from service on the Board, other than on account of death, he or she shall be paid a distribution either in a lump sum or in approximately equal installments over a designated number of years (not to exceed 10 years).

Following is a summary of the components of DSUs issued and compensation expense attributable to the DSUs (in millions, except DSU amounts):


	December 31,
	2022		2021
DSUs Issued	12,109		18,741

Compensation expense	0.7		1.1
Change in value of shares	0.1		1.3
Total compensation (benefit) expense	$	0.8	$	2.4

DSUs withdrawn	4,022		186,137
Value of DSUs withdrawn	$	0.2	$	12.1


(18)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. Of these shares, 2,865,957 shares of common stock are reserved for the incentive plan awards. For further detail of grants under this plan see Note 17 - Stock-Based Compensation.

Repurchase of Common Stock

Shares tendered by employees to us to satisfy the employees' tax withholding obligations in connection with the vesting of restricted stock awards totaled 16,120 and 16,880 during the years ended December 31, 2022 and 2021, respectively, and are reflected in reacquired capital. These shares were credited to reacquired capital based on their fair market value on the vesting date.

Issuance of Common Stock

In April 2021, we entered into an Equity Distribution Agreement with BofA Securities, Inc., CIBC World Markets Corp, Credit Suisse Securities (USA) LLC, and J.P. Morgan Securities LLC, collectively the sales agents, pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $200.0 million, through an At-the-Market (ATM) offering program, including an equity forward sales component. This is a three-year agreement, expiring on February 11, 2024. During the twelve months ended December 31, 2021, we issued 1,966,117 shares of our common stock under the ATM program at an average price of $63.81, for net proceeds of $124.0 million, which is net of sales commissions and other fees paid of approximately $1.3 million. We did not issue equity through the ATM program during 2022.

On November 17, 2021, we announced a registered public offering of 6,074,767 shares of our common stock at a public offering price of $53.50 per share, for an issuance amount of $325.0 million. In conjunction with this offering, we granted the underwriters an option to purchase up to 911,215 additional shares, which was subsequently exercised in full, for an additional issuance amount of $48.8 million. Of the total 6,985,982 shares of common stock offered, we initially sold 1,401,869 shares, $75.0 million in gross proceeds, directly to the underwriters in the offering, with cash proceeds received at closing. The remaining 5,584,113 shares were sold under forward sales agreements which provide for settlement on a settlement date or dates to be specified at our discretion, but which is expected to occur on or prior to February 28, 2023. The cumulative shares issued under the forward sales agreement is limited to one and one-half times the base number of shares within the agreement, or 8,376,170 shares.

The forward sales agreements were physically settled with common shares issued by us. On settlement dates, we issued shares of common stock to the forward purchaser at the then-applicable forward sale price and received issuance proceeds at that time. The forward sale price was initially $51.8950 per share, which was subject to adjustment based on a floating interest rate factor equal to the overnight bank funding rate less a spread of 75 basis points, and was subject to decrease on certain dates specified in the forward sale agreement by amounts related to expected dividends on shares of common stock during the term of the forward sale agreement.

On June 24, 2022, we partially settled the forward sale agreement by physically delivering 2,004,483 shares of common stock in exchange for cash proceeds of $99.9 million, net of issuance costs. On September 21, 2022, we partially settled the forward sale agreement by physically delivering 1,618,932 shares of common stock in exchange for cash proceeds of approximately $80.0 million, net of issuance costs. On November 28, 2022, we partially settled the forward sale agreement by physically delivering 1,409,702 shares of common stock in exchange for cash proceeds of approximately $70.0 million, net of issuance costs. On December 21, 2022, we settled the remaining portion of the forward sale agreement by physically delivering 550,996 shares of common stock in exchange for cash proceeds of approximately $27.1 million, net of issuance costs. The proceeds were used to pay down borrowings under our revolving credit facility and for other general corporate purposes.

The forward sale agreement was classified as an equity transaction because it was indexed to our common stock, physical settlement was within our control, and the other requirements necessary for equity classification were met. As a result of the equity classification, no gain or loss was recognized within earnings due to subsequent changes in the fair value of the forward sales agreement.


(19)Commitments and Contingencies

Qualifying Facilities Liability

Our QF liability primarily consists of unrecoverable costs associated with three contracts covered under the Public Utility Regulatory Practices Act (PURPA). These contracts require us to purchase minimum amounts of energy at prices ranging from $64 to $136 per MWH through 2029. As of December 31, 2022, our estimated gross contractual obligation related to these contracts was approximately $386.1 million through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $327.8 million through 2029. As contractual obligations are settled, the related purchases and sales are recorded within Operating expense and Operating revenues in our Statements of Income. The present value of the remaining liability is recorded in Accumulated miscellaneous operating provisions in our Balance Sheets. The following summarizes the change in the liability (in thousands):


	December 31,
	2022		2021
Beginning QF liability	$	64,943	$	81,379
Settlements(1)	(20,076)		(22,497)
Interest on long-term debt	4,861		6,061
Ending QF liability	$	49,728	$	64,943

______________________

(1) The primary components of the change in settlement amounts includes (i) a lower periodic adjustment of $5.4 million due to actual price escalation, which was less than previously modeled; (ii) higher costs of approximately $0.8 million, due to a $1.8 million reduction in costs for the adjustment to actual output and pricing for the current contract year as compared with a $2.6 million reduction in costs in the prior period; and (iii) a prior year favorable adjustment of approximately $7.0 million decreasing the QF liability associated with a one-time clarification in contract term.

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


	Gross Obligation		Recoverable Amounts		Net
2023	$	80,750	$	61,280	$	19,470
2024	76,393		60,706		15,687
2025	60,360		52,950		7,410
2026	55,393		46,274		9,119
2027	56,665		46,668		9,997
Thereafter	56,534		59,895		(3,361)
Total(1)	$	386,095	$	327,773	$	58,322

_____________________

(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 Operating expenses in the Statements of Income and were approximately $328.0 million and $286.7 million for the years ended December 31, 2022 and 2021, respectively. As of December 31, 2022, our commitments under these

contracts were $413.4 million in 2023, $247.5 million in 2024, $235.8 million in 2025, $247.0 million in 2026, $230.3 million in 2027, and $1.5 billion thereafter. These commitments are not reflected in our 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 $24.5 million between 2023 and 2040. These commitments are not reflected in our 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, which relates primarily to the remediation of former manufactured gas plant sites owned by us or for which we are responsible, is estimated to range between $21.6 million to $32.7 million. As of December 31, 2022, we had a reserve of approximately $26.4 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,
	2022		2021
Liability at January 1,	$	26,866	$	28,895
Deductions	(2,033)		(2,799)
Charged to costs and expense	1,534		770
Liability at December 31,	$	26,367	$	26,866

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, we do not expect these costs to have a material effect on our financial position or results of operations.

Manufactured Gas Plants - Approximately $20.5 million of our environmental reserve accrual is related to the following manufactured gas plants.

South Dakota - A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies, implementing remedial actions pursuant to work plans approved by the South Dakota Department of Agriculture and Natural Resources, and conducting ongoing monitoring and operation and maintenance activities. As of December 31, 2022, the reserve for remediation costs at this site was approximately $7.8 million, and we estimate that approximately $2.8 million of this amount will be incurred through 2025.

Nebraska - We own sites in North Platte, Kearney, and Grand Island, Nebraska on which former manufactured gas facilities were located. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations.

Montana - We own or have responsibility for sites in Butte, Missoula, and Helena, Montana on which former manufactured gas plants were located. The Butte and Helena sites, both listed as high priority sites on Montana’s state superfund list, were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with the MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remedial actions and/or investigations, if any, at the Butte site.

In August 2016, the MDEQ sent us a Notice of Potential Liability and Request for Remedial Action regarding the Helena site. In October 2019, we submitted a third revised Remedial Investigation Work Plan (RIWP) for the Helena site addressing MDEQ comments. The MDEQ approved the RIWP in March 2020 and field work was completed in 2022. We submitted a Remedial Investigation Report (RI Report) summarizing the work completed to MDEQ and are awaiting its review and comments as to any additional field work. We expect the MDEQ review of the RI Report to be concluded in 2023, and any additional field work to commence following that.

MDEQ has indicated it expects to proceed in listing the Missoula site as a Montana superfund site. After researching historical ownership, we have identified another potentially responsible party with whom we have entered into an agreement allocating third-party costs to be incurred in addressing the site. The other party has assumed the lead role at the site and has expressed its intention to submit a voluntary remediation plan for the Missoula site to MDEQ. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula site.

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 GHG emissions. Coal-fired plants have come under particular scrutiny. We have joint ownership interests in four coal-fired electric generating plants, all of which other companies operate. Despite efforts over the years, Congress has not passed any federal climate change legislation regarding GHG emissions from coal-fired plants. While, Section 111(d) of the Clean Air Act (CAA) confers authority on EPA and the states to regulate emissions, including GHGs, from existing stationary sources, no regulation has survived judicial review. In 2022 EPA opened a docket to collect public input to guide the EPA’s next effort to reduce GHG emissions from new and existing coal fired plants and natural gas operations. EPA indicated that it intends to use this non-rulemaking docket to gather perspectives from a broad group of stakeholders in advance of an expected proposed rulemaking. Ultimately, we cannot predict whether or how future GHG emission legislation, regulations, investor activism or litigation will impact our plants. As GHG regulations are implemented, it could result in additional compliance costs impacting our future results of operations and financial position, if such costs are not recovered through regulated rates. These 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 may not be available within a timeframe consistent with the implementation of any such requirements. Physical impacts of climate change also may present potential risks for severe weather, such as droughts, fires, floods, wind, ice storms and tornadoes, in the locations where we operate or have interests. These potential risks may impact costs for electric and natural gas supply and maintenance of generation, distribution, and

transmission facilities. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from any GHG regulations that, in our view, disproportionately impact our customers.

Clean Air Act Rules and Associated Emission Control Equipment Expenditures - The EPA has proposed or issued a number of rules under different provisions of the Clean Air Act (CAA) that could require the installation of emission control equipment at the generation plants in which we have joint ownership. Air emissions at our thermal generating plants are managed by the use of emissions and combustion controls and monitoring, and sulfur dioxide allowances. These measures are anticipated to be sufficient to permit the facilities to continue to meet current air emissions compliance 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 states of Montana, North Dakota and South Dakota have developed and submitted to the EPA, for its approval, their respective State Implementation Plans (SIP) for Regional Haze compliance. While these states, among others, did not meet the EPA’s July 31, 2021 submission deadline, they were all 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. The draft North Dakota SIP does not require any additional controls at the Coyote generating facility. Similarly, the draft South Dakota SIP does not require any additional controls at the Big Stone generating facility. Until these SIPs are finalized and approved by EPA, the potential remains that installation of additional emissions controls might be required at these facilities.

Jointly Owned Plants - We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa, and Montana that are 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

Pacific Northwest Solar Litigation

Pacific Northwest Solar, LLC (PNWS) is a solar QF developer seeking to construct small solar facilities in Montana. We began negotiating with PNWS in early 2016 to purchase the output from 21 of its proposed facilities pursuant to our standard QF-1 Tariff, which is applicable to projects no larger than 3 MWs.

On June 16, 2016, however, the MPSC suspended the availability of the QF-1 Tariff standard rates for that category of solar projects, which included the projects proposed by PNWS. The MPSC exempted from the suspension any projects for which a QF had both submitted a signed power purchase agreement and had executed an interconnection agreement with us by June 16, 2016. Although we had signed four power purchase agreements with PNWS as of that date, we had not entered into interconnection agreements with PNWS for any of those projects. As a result, none of the PNWS projects in Montana qualified for the exemption.

In November 2016, PNWS sued us in state court seeking unspecified damages for breach of contract and a judicial declaration that some or all of the 21 proposed power purchase agreements it had proposed to us were in effect despite the MPSC's Order. We removed the state lawsuit to the United States District Court for the District of Montana.

On August 31, 2021, the District Court ruled that the four agreements were valid and enforceable contracts and that we breached the agreements on June 16, 2016 by refusing to go forward with the projects in spite of the MPSC's Orders. On December 15, 2021, after a three-day trial, the jury determined that PNWS had sustained $0.5 million in damages and the judge subsequently entered judgment against us in that amount.

The appeal is fully briefed at the Ninth Circuit. Oral arguments were held on February 8, 2023.

Talen Montana Bankruptcy

On May 9, 2022 Talen Energy Supply, LLC (Talen Energy) along with 71 affiliated entities, filed bankruptcy in Houston, Texas, seeking reorganization under Chapter 11 (the Talen Bankruptcy). Talen Montana, LLC (Talen) was one of the affiliated entities that filed bankruptcy and is included as a part of the Talen Bankruptcy. Talen is one of the co-owners of Colstrip Units 1, 2 and 3, and the operator of Units 3 and 4. The Talen Bankruptcy filing, along with the automatic stay under §362 of the Bankruptcy Code, has affected pending legal proceedings in which both NorthWestern and Talen are involved, including the State of Montana-Riverbed Rents Litigation, the Colstrip Arbitration and Litigation, and the Colstrip Coal Dust Litigation, as described in the individual matters below. On December 15, 2022 the bankruptcy court confirmed Talen’s Chapter 11 Plan. Apart from the delays of legal proceedings due to the automatic stay, we have not noted any detrimental effect on the operation or Colstrip Units 3 and 4 caused by Talen’s bankruptcy.

State of Montana - Riverbed Rents

On April 1, 2016, the State of Montana (State) filed a complaint on remand (the State’s Complaint) with the Montana First Judicial District Court (State District Court), naming us, along with Talen as defendants. The State claimed it owns the riverbeds underlying 10 of our, and formerly Talen’s, hydroelectric facilities (dams, along with reservoirs and tailraces) on the Missouri, Madison and Clark Fork Rivers, and seeks rents for Talen’s and our use and occupancy of such lands. The facilities at issue include the Hebgen, Madison, Hauser, Holter, Black Eagle, Rainbow, Cochrane, Ryan, and Morony facilities on the Missouri and Madison Rivers and the Thompson Falls facility on the Clark Fork River. We acquired these facilities from Talen in November 2014.

The litigation has a long prior history. In 2012, the United States Supreme Court issued a decision holding that the Montana Supreme Court erred in not considering a segment-by-segment approach to determine navigability and relying on present day recreational use of the rivers. It also held that what it referred to as the Great Falls Reach “at least from the head of the first waterfall to the foot of the last” was not navigable for title purposes, and thus the State did not own the riverbeds in that segment. The United States Supreme Court remanded the case to the Montana Supreme Court for further proceedings not inconsistent with its opinion. Following the 2012 remand, the case laid dormant for four years until the State’s Complaint was filed with the State District Court. On April 20, 2016, we removed the case from State District Court to the United States District Court for the District of Montana (Federal District Court). On August 1, 2018, the Federal District Court granted our and Talen’s motions to dismiss the State’s Complaint as it pertains to the Great Falls Reach. A bench trial before the Federal District Court commenced January 4, 2022 and concluded on January 18, 2022, which addressed the issue of navigability. Damages were bifurcated by agreement and will be tried separately, should the Federal District Court find any segments navigable.

The Talen Bankruptcy filing in May 2022, and resulting automatic stay, resulted in a hold on this case, including a hold on any decision regarding navigability. In September 2022, the parties stipulated and the Bankruptcy Court issued its Order modifying the stay to permit the Federal District Court to issue its decision on the navigability phase of the case. We are awaiting the Federal District Court decision on navigability. The damages phase of the case remains stayed.

We dispute the State’s claims and intend to continue to vigorously defend the lawsuit. At this time, we cannot predict an outcome. If the Federal District Court determines the riverbeds are navigable under the remaining six facilities that were not dismissed and if it calculates damages as the State District Court did in 2008, we estimate the annual rents could be approximately $3.8 million commencing when we acquired the facilities in November 2014. We anticipate that any obligation to pay the State rent for use and occupancy of the riverbeds would be recoverable in rates from customers, although there can be no assurances that the MPSC would approve any such recovery.

Colstrip Arbitration and Litigation

The six owners of Units 3 and 4 currently share the operating costs pursuant to the terms of an operating agreement among them, the Ownership and Operation Agreement (O&O Agreement). Costs of common facilities were historically shared among the owners of all four units. With the closure of Units 1 and 2, we have incurred additional operating costs with respect to our interest in Unit 4 and may experience a negative impact on our transmission revenue due to reduced amounts of energy transmitted across our transmission lines.

The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. Recovery of costs associated with the closure of the facility is subject to MPSC approval. Three of the joint owners of Units 3 and 4 are subject to regulation in Washington and in May 2019, the Washington state legislature enacted a statute mandating Washington electric utilities to “eliminate coal-fired resources from [their] allocation of electricity” on or before December 31, 2025, after which date they may no longer include their share of coal-fired resources in their regulated electric supply portfolio.

While we believe closure requires each owner’s consent, there are differences among the owners as to this issue under the O&O Agreement. On March 12, 2021, we initiated an arbitration under the O&O Agreement (the “Arbitration”), which seeks to resolve the primary issue of whether closure of Units 3 and 4 can be accomplished without each joint owner's consent and to clarify the obligations of the joint owners to continue to fund operations until all joint owners agree on closure.

While the pendency of the lawsuits involving Montana legislation that would have impacted the arbitration process and Talen's Bankruptcy delayed commencement of the Arbitration proceedings, and thus delayed resolution of the issues we raised when we commenced arbitration, since resolution of the lawsuits, the owners have initiated efforts to identify arbitrators pursuant to their stipulation entered in the Talen bankruptcy proceeding. Despite the litigation, we have worked and continue to work with the other joint owners to arrive at an agreed upon process for the Arbitration and a commercial resolution to the owners disagreements.

Colstrip Coal Dust Litigation

On December 14, 2020, a claim was filed against Talen, the operator of the Colstrip Units 1, 2, 3 and 4 (Colstrip), in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. The plaintiffs allege they have suffered adverse effects from coal dust generated during operations associated with Colstrip. On August 26, 2021, the claim was amended to add in excess of 100 plaintiffs. It also added NorthWestern, as well as the other owners of Colstrip, and Westmoreland Rosebud Mining LLC, as defendants. Plaintiffs are seeking economic damages, costs and disbursements, punitive damages, attorneys’ fees, and an injunction prohibiting defendants from allowing coal dust to blow onto plaintiffs’ properties. Talen’s bankruptcy and resulting automatic stay prevents the plaintiffs from pursuing their claims against Talen, but does not automatically prevent the plaintiffs from pursuing their claims against the other defendants. Based on a stipulation and Bankruptcy Court order, Talen's bankruptcy stay, as it concerns this matter, was lifted on February 13, 2023.

Since this lawsuit remains in its early stages, we are unable to predict outcomes or estimate a range of reasonably possible losses.

BNSF Demands for Indemnity and Remediation Costs

NorthWestern has received a demand for indemnity from BNSF Railway Company (BNSF) for past and future environmental investigation and remediation costs incurred by BNSF at one of the three operable units at the Anaconda Copper Mining (ACM) Smelter and Refinery Superfund Site, located near Great Falls, Montana. Smelter and refining operations at the site commenced in 1893 and continued until 1980.

According to U.S. EPA, the smelter and refining operations have contaminated soil, groundwater and surface water resources around the site with lead, arsenic and other metal wastes. ARCO (Atlantic Richfield Company) initiated reclamation and maintenance activities in the 1980s and 1990s. Between 2002 and 2008, the EPA conducted several site investigations. In March 2011, the EPA placed the ACM Smelter and Refinery Site on the Superfund program’s National Priority List. The Superfund Site is 427 acres and contains three operable units: Operable Unit 1 (consisting of five subsections including the Railroad Corridor and four other “areas of interest”), Operable Unit 2 (the former smelter and refinery site), and Operable Unit 3 (the Missouri River that flows along the south sides of Operable Units 1 and 2).

NorthWestern owns property in the Railroad Corridor sub-section of Operable Unit 1. BNSF claims it is entitled to indemnity and contribution from NorthWestern for the costs it has and will incur to investigate and remediate contamination in Operable Unit 1. BNSF reports it has incurred in excess of $4.4 million, pending final resolution of response and oversight costs incurred by government agencies (EPA and Montana DEQ), in investigative and other response costs associated with Operable Unit 1, and that in the future it will incur additional costs to implement the final remedy for Operable Unit 1. In the Record of Decision (ROD) for Operable Unit 1 issued on August 21, 2021, the EPA estimated the costs to implement the selected remedies for the Railroad Corridor will be approximately $4.1 million. In the ROD, the EPA also estimated the costs to implement the selected remedy (including institutional controls) for the four “areas of interest” in Operable Unit 1 would be approximately $1.8 million, with annual operating costs of ten thousand dollars. We are evaluating BNSF’s claim and are unable at this time to predict outcomes or estimate a range of reasonably possible losses.

Other Legal Proceedings

We are also subject to various other 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.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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		1,954,756		1,499,267	8,580,168		5,126,145
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income		(a) 436,295			(e) 452,130		15,835
3	Preceding Quarter/Year to Date Changes in Fair Value				(c) 57,286			57,286
4	Total (lines 2 and 3)		436,295		57,286	452,130		41,451	186,839,752	186,798,301
5	Balance of Account 219 at End of Preceding Quarter/Year		1,518,461		1,441,981	8,128,038		5,167,596
6	Balance of Account 219 at Beginning of Current Year		1,518,461		1,441,981	8,128,038		5,167,596
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income		(b) 982,991			(f) 452,130		530,861
8	Current Quarter/Year to Date Changes in Fair Value				(d) 7,207			7,207
9	Total (lines 7 and 8)		982,991		7,207	452,130		538,068	183,006,620	182,468,552
10	Balance of Account 219 at End of Current Quarter/Year		535,470		1,434,774	7,675,908		5,705,664

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: AccumulatedOtherComprehensiveIncomeLossMinimumPensionLiabilityAdjustmentReclassificationsToNetIncomeLoss

Postretirement medical liability adjustment.

(b) Concept: AccumulatedOtherComprehensiveIncomeLossMinimumPensionLiabilityAdjustmentReclassificationsToNetIncomeLoss

Postretirement medical liability adjustment.

Foreign currency translation adjustment.

(d) Concept: AccumulatedOtherComprehensiveIncomeLossOtherAdjustmentsToComprehensiveIncomeLossChangesInFairValue

Foreign currency translation adjustment.

(e) Concept: AccumulatedOtherComprehensiveIncomeLossOtherCashFlowHedgesInterestRateSwapsReclassificationsToNetIncomeLoss

Reclassification of net losses on derivative instruments.

(f) Concept: AccumulatedOtherComprehensiveIncomeLossOtherCashFlowHedgesInterestRateSwapsReclassificationsToNetIncomeLoss

Reclassification of net losses on derivative instruments.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

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)	6,854,874,964	5,278,108,429	1,311,406,372	(d) 1,528,964			263,831,199
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	41,504,922				(e) 40,209,537	(f) 1,295,385
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified	4,244,173	4,244,173
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	6,900,624,059	5,282,352,602	1,311,406,372	1,528,964	40,209,537	1,295,385	263,831,199
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	4,327,380	4,297,515	29,865
11	ConstructionWorkInProgress Construction Work in Progress	300,649,215	256,812,052	26,659,721				17,177,442
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	686,328,435	(a) 686,328,435
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	7,891,929,089	6,229,790,604	1,338,095,958	1,528,964	40,209,537	1,295,385	281,008,641
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	2,786,711,964	2,147,837,398	531,948,773	1,087,519	33,172,848		72,665,426
15	UtilityPlantNet Net Utility Plant (13 less 14)	5,105,217,125	4,081,953,206	806,147,185	441,445	7,036,689	1,295,385	208,343,215
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	2,513,271,574	1,950,712,066	476,620,725	1,087,519	33,172,848		51,678,416
19	AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService Amortization and Depletion of Producing Natural Gas Land and Land Rights	48,504,666		48,504,666
20	AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService Amortization of Underground Storage Land and Land Rights
21	AmortizationOfOtherUtilityPlantUtilityPlantInService Amortization of Other Utility Plant	52,020,462	(b) 24,210,070	6,823,382				20,987,010
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	2,613,796,702	1,974,922,136	531,948,773	1,087,519	33,172,848		72,665,426
23	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract Leased to Others
24	DepreciationUtilityPlantLeasedToOthers Depreciation
25	AmortizationAndDepletionUtilityPlantLeasedToOthers Amortization and Depletion
26	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers Total Leased to Others (24 & 25)
27	DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract Held for Future Use
28	DepreciationUtilityPlantHeldForFutureUse Depreciation
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	172,915,262	(c) 172,915,262
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	2,786,711,964	2,147,837,398	531,948,773	1,087,519	33,172,848		72,665,426

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: UtilityPlantAcquisitionAdjustment

Acquisition Adjustments of $686,328,435 consists of $656,318,593 for Montana Operations and $30,009,842 for South Dakota Operations.

(b) Concept: AmortizationOfOtherUtilityPlantUtilityPlantInService

Amortization of Other South Dakota Electric Plant was $2,387 and $0 for 2022 and 2021, respectively.

Amortization of Other Montana Electric Plant was $24,207,683 and $22,153,646 for 2022 and 2021, respectively

Amortization of Plant Acquisition Adjustments of $172,915,262 consist of $164,212,408 for Montana Operations and $8,702,854 for South Dakota Operations.

(d) Concept: UtilityPlantInServiceClassified

This column represents regulated propane

(e) Concept: UtilityPlantInServicePropertyUnderCapitalLeases

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

(f) 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:

12/31/2022

Year/Period of Report

End of:

2022

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:

12/31/2022

Year/Period of Report

End of:

2022

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	(a) 19,995					19,995
3	(302) Franchise and Consents	(b) 19,288,558	959,050				20,247,608
4	(303) Miscellaneous Intangible Plant	7,274,966	5,250,785	248,808		25,232	12,251,711
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	26,583,519	6,209,835	248,808		25,232	32,519,314
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	812,637					812,637
9	(311) Structures and Improvements	55,183,001	375,725	35,863			55,522,863
10	(312) Boiler Plant Equipment	236,040,765	10,752,158	1,911,462		6,256	244,887,717
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	47,550,879	1,325,909	9,755			48,867,033
13	(315) Accessory Electric Equipment	15,319,421	444,082	106,139			15,657,364
14	(316) Misc. Power Plant Equipment	25,928,303	241,975	122,231			26,048,047
15	(317) Asset Retirement Costs for Steam Production	22,463,670					22,463,670
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	403,298,676	13,139,849	2,185,450		6,256	414,259,331
17	B. Nuclear Production Plant
18	(320) Land and Land Rights
19	(321) Structures and Improvements
20	(322) Reactor Plant Equipment
21	(323) Turbogenerator Units
22	(324) Accessory Electric Equipment
23	(325) Misc. Power Plant Equipment
24	(326) Asset Retirement Costs for Nuclear Production
25	TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26	C. Hydraulic Production Plant
27	(330) Land and Land Rights
28	(331) Structures and Improvements	5,900,898	40,780				5,941,678
29	(332) Reservoirs, Dams, and Waterways	125,423,708	1,530,923	266,668			126,687,963
30	(333) Water Wheels, Turbines, and Generators	177,907,561	18,172,843	454,449			195,625,955
31	(334) Accessory Electric Equipment	151,379,698	29,192,061	3,786,313			176,785,446
32	(335) Misc. Power Plant Equipment	88,750,061	6,027,293	399,790			94,377,564
33	(336) Roads, Railroads, and Bridges	20,419,217	306,547				20,725,764
34	(337) Asset Retirement Costs for Hydraulic Production	2,493,836	458,810	5,550			2,947,096
35	TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)	572,274,979	55,729,257	4,912,770			623,091,466
36	D. Other Production Plant
37	(340) Land and Land Rights	3,901,868					3,901,868
38	(341) Structures and Improvements	86,227,692	22,947				86,250,639
39	(342) Fuel Holders, Products, and Accessories	26,525,671	8,707				26,534,378
40	(343) Prime Movers	147,196,133	85,611,878	1,957,034			230,850,977
41	(344) Generators	143,520,064					143,520,064
42	(345) Accessory Electric Equipment	27,116,751	4,079	40,824			27,080,006
43	(346) Misc. Power Plant Equipment	50,684,196	1,110,712				51,794,908
44	(347) Asset Retirement Costs for Other Production	5,038,356					5,038,356
44.1	(348) Energy Storage Equipment - Production
45	TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)	490,210,731	86,758,323	1,997,858			574,971,196
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	1,465,784,386	155,627,429	9,096,078		6,256	1,612,321,993
47	3. Transmission Plant
48	(350) Land and Land Rights	41,959,408	347,229		305,787	63,313	41,854,653
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	50,881,687	7,965,346	16,159	1,260,743	1,241,202	61,332,819
50	(353) Station Equipment	411,210,108	24,478,079	1,373,583	2,399,114	3,692,781	440,406,499
51	(354) Towers and Fixtures	30,317,776	230,191	41,421	339,700		30,385,864
52	(355) Poles and Fixtures	484,534,670	45,008,102	3,305,354	1,221,670	8,348,679	519,110,409
53	(356) Overhead Conductors and Devices	206,913,694	6,750,145	529,018	1,448,089	1,645,387	212,937,523
54	(357) Underground Conduit	778,680					778,680
55	(358) Underground Conductors and Devices	6,631,465	9,510				6,640,975
56	(359) Roads and Trails	2,519,647	521,299		1,002,426		4,043,372
57	(359.1) Asset Retirement Costs for Transmission Plant
58	TOTAL Transmission Plant (Enter Total of lines 48 thru 57)	1,235,747,135	84,155,061	5,265,535	7,977,529	5,123,396	1,317,490,794
59	4. Distribution Plant
60	(360) Land and Land Rights	15,111,729	20,183	209,051		489,007	15,371,502
61	(361) Structures and Improvements	37,600,362	3,567,267	1		1,191,998	39,975,630
62	(362) Station Equipment	298,100,260	490,474	1,316,129		3,717,345	293,557,260
63	(363) Energy Storage Equipment – Distribution
64	(364) Poles, Towers, and Fixtures	396,874,167	28,036,862	1,979,052		8,402,605	431,334,582
65	(365) Overhead Conductors and Devices	160,449,708	11,336,187	1,168,959		1,645,387	172,262,323
66	(366) Underground Conduit	166,295,854	12,941,537	258			179,237,133
67	(367) Underground Conductors and Devices	309,294,194	20,074,918	748,294		5,844	328,626,662
68	(368) Line Transformers	288,709,034	15,373,462	2,278,588		90,665	301,713,243
69	(369) Services	183,542,795	13,119,095	350,751			196,311,139
70	(370) Meters	78,725,104	17,783,111	5,514,819			90,993,396
71	(371) Installations on Customer Premises	94,490	683,485	31,888			746,087
72	(372) Leased Property on Customer Premises
73	(373) Street Lighting and Signal Systems	85,946,211	7,155,927	1,909,902			91,192,236
74	(374) Asset Retirement Costs for Distribution Plant
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	2,020,743,908	130,542,142	15,507,692		5,542,835	2,141,321,193
76	5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77	(380) Land and Land Rights
78	(381) Structures and Improvements
79	(382) Computer Hardware
80	(383) Computer Software
81	(384) Communication Equipment
82	(385) Miscellaneous Regional Transmission and Market Operation Plant
83	(386) Asset Retirement Costs for Regional Transmission and Market Oper
84	TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85	6. General Plant
86	(389) Land and Land Rights	796,461					796,461
87	(390) Structures and Improvements	12,589,466	56,190	103,214			12,542,442
88	(391) Office Furniture and Equipment	1,597,950	84,728	466,240			1,216,438
89	(392) Transportation Equipment	79,526,197	3,768,222	474,406		1	82,820,012
90	(393) Stores Equipment	955,765	187,393				1,143,158
91	(394) Tools, Shop and Garage Equipment	12,367,082	653,745	437,213			12,583,614
92	(395) Laboratory Equipment	1,046,044		12,866			1,033,178
93	(396) Power Operated Equipment	6,774,037	701,087	83,252		1	7,391,873
94	(397) Communication Equipment	53,032,703	115,501	506,531	163,575		52,805,248
95	(398) Miscellaneous Equipment	2,110,622	36,911	24,822			2,122,711
96	SUBTOTAL (Enter Total of lines 86 thru 95)	170,796,327	5,603,777	2,108,544	163,575		174,455,135
97	(399) Other Tangible Property
98	(399.1) Asset Retirement Costs for General Plant
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	170,796,327	5,603,777	2,108,544	163,575		174,455,135
100	TOTAL (Accounts 101 and 106)	4,919,655,275	382,138,244	32,226,657	8,141,104	400,463	5,278,108,429
101	(102) Electric Plant Purchased (See Instr. 8)
102	(Less) (102) Electric Plant Sold (See Instr. 8)
103	(103) Experimental Plant Unclassified	4,092,785	151,388				4,244,173
104	TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)	4,923,748,060	382,289,632	32,226,657	8,141,104	400,463	5,282,352,602

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

12/31/2022

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: Organization

Montana operations


Line	Account	Beginning of Year	Additions	Retirements	Adjustments	Transfers	End of Year
No.	(a)	(b)	(c)	(d)	(e)	(f)	(g)
1	1. INTANGIBLE PLANT
2	(301) Organization	19,995	—	—	—	—	19,995
3	(302) Franchises and Consents	19,288,558	959,050	—	—	—	20,247,608
4	(303) Miscellaneous Intangible Plant	7,266,662	5,225,553	248,808	—	—	12,243,407
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and4)	26,575,215	6,184,603	248,808	—	—	32,511,010
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	446,126	—	—	—	—	446,126
9	(311) Structures and Improvements	28,016,189	263,464	29,133	—	—	28,250,520
10	(312) Boiler Plant Equipment	37,096,135	9,077,917	1,191,510	—	—	44,982,542
11	(313) Engines and Engine-Driven Generators	—	—	—	—	—	—
12	(314) Turbogenerator Units	21,259,205	1,004,205	8,324	—	—	22,255,086
13	(315) Accessory Electric Equipment	2,173,118	370,734	24,707	—	—	2,519,145
14	(316) Misc. Power Plant Equipment	22,952,383	17,517	22,226	—	—	22,947,674
15	(317) Asset Retirement Costs for Steam	19,799,959	—	—	—	—	19,799,959
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 14)	131,743,115	10,733,837	1,275,900	—	—	141,201,052
17	B. Nuclear Production Plant
18	(320) Land and Land Rights	—	—	—	—	—	—
19	(321) Structures and Improvements	—	—	—	—	—	—
20	(322) Reactor Plant Equipment	—	—	—	—	—	—
21	(323) Turbogenerator Units	—	—	—	—	—	—
22	(324) Accessory Electric Equipment	—	—	—	—	—	—
23	(325) Misc. Power Plant Equipment	—	—	—	—	—	—
24	TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 22)	—	—	—	—	—	—
25	C. Hydraulic Production Plant
26	(330) Land and Land Rights	5,900,898	40,780	—	—	—	5,941,678
27	(331) Structures and Improvements	125,423,708	1,530,923	266,668	—	—	126,687,963
28	(332) Reservoirs, Dams, and Waterways	177,907,561	18,172,843	454,449	—	—	195,625,955


29	(333) Water Wheels, Turbines, and Generators	151,379,698	29,192,061	3,786,313	—	—	176,785,446
30	(334) Accessory Electric Equipment	88,750,061	6,027,293	399,790	—	—	94,377,564
31	(335) Misc. Power Plant Equipment	20,419,217	306,547	—	—	—	20,725,764
32	(336) Roads, Railroads, and Bridges	2,493,836	458,810	5,550	—	—	2,947,096
33	TOTAL Hydraulic Production Plant (Enter Total of lines 25 thru 31)	572,274,979	55,729,257	4,912,770	—	—	623,091,466
34	D. Other Production Plant
35	(340) Land and Land Rights	3,819,385	—	—	—	—	3,819,385
36	(341) Structures and Improvements	59,449,471	—	—	—	—	59,449,471
37	(342) Fuel Holders, Products, and Accessories	21,230,045	—	—	—	—	21,230,045
38	(343) Prime Movers	104,189,627	(695)	1,957,034	—	—	102,231,898
39	(344) Generators	55,657,436	—	—	—	—	55,657,436
40	(345) Accessory Electric Equipment	19,203,828	—	39,824	—	—	19,164,004
41	(346) Misc. Power Plant Equipment	28,134,319	956,704	—	—	—	29,091,023
42	(347) Asset Retirement Costs for Other Production	3,686,815	—	—	—		3,686,815
43	TOTAL Other Production Plant (Enter Total of lines 34 thru 40)	295,370,926	956,009	1,996,858	—	—	294,330,077
44	TOTAL Production Plant (Enter Total of lines 15, 23, 32, and 41)	999,389,020	67,419,103	8,185,528	—	—	1,058,622,595
45	3. TRANSMISSION PLANT
46	(350) Land and Land Rights	40,237,210	(359,629)	—	305,787	(63,313)	40,120,055
47	(352) Structures and Improvements	38,688,898	7,752,986	4,500	1,260,743	1,241,202	48,939,329
48	(353) Station Equipment	310,674,496	22,833,736	948,940	2,399,114	3,692,781	338,651,187
49	(354) Towers and Fixtures	30,317,776	(230,191)	41,421	339,700	—	30,385,864
50	(355) Poles and Fixtures	427,533,321	40,563,531	3,046,372	1,221,670	(8,348,679)	457,923,471
51	(356) Overhead Conductors and Devices	174,615,906	5,670,666	355,827	1,448,089	(1,645,387)	179,733,447
52	(357) Underground Conduit	137,878	—	—	—	—	137,878
53	(358) Underground Conductors and Devices	1,935,349	—	—	—	—	1,935,349
54	(359) Roads and Trails	2,519,647	521,299	—	1,002,426	—	4,043,372
55	TOTAL Transmission Plant (Enter Total of lines 44 thru 52)	1,026,660,481	76,752,398	4,397,060	7,977,529	(5,123,396)	1,101,869,952
56	4. DISTRIBUTION PLANT
57	(360) Land and Land Rights	14,264,151	(20,183)	1,018	—	489,007	14,731,957
58	(361) Structures and Improvements	36,244,428	3,439,175	1	—	(1,191,998)	38,491,604
59	(362) Station Equipment	253,396,250	(2,149,123)	1,090,301	—	(3,741,985)	246,414,841
60	(363) Storage Battery Equipment	—	—	—	—	—	—


61	(364) Poles, Towers, and Fixtures	341,701,090	23,602,844	1,249,449	—	8,348,679	372,403,164
62	(365) Overhead Conductors and Devices	139,507,502	9,444,506	126,478	—	1,645,387	150,470,917
63	(366) Underground Conduit	155,966,720	12,210,184	258	—	—	168,176,646
64	(367) Underground Conductors and Devices	249,832,503	15,703,271	346,059	—	—	265,189,715
65	(368) Line Transformers	246,552,092	13,627,506	1,777,937	—	—	258,401,661
66	(369) Services	162,264,238	11,835,498	207,051	—	—	173,892,685
67	(370) Meters	65,110,678	17,233,387	5,381,997	—	26,400	76,988,468
68	(371) Installations on Customer Premises	—	—	—	—	—	—
69	(372) Leased Property on Customer Premises	—	—	—	—	—	—
70	(373&388) Street Lighting and Signal Systems	76,698,030	6,840,044	1,806,922	—	—	81,731,152
71	(374) Asset Retirement Costs for Distribution Plant	—	—	—	—	—	—
72	TOTAL Distribution Plant (Enter Total of lines 55 thru 68)	1,741,537,682	111,767,109	11,987,471	—	5,575,490	1,846,892,810
73	5. GENERAL PLANT
74	(389) Land and Land Rights	689,633	—	—	—	—	689,633
75	(390) Structures and Improvements	10,804,083	(27,095)	78,500	—	—	10,698,488
76	(391) Office Furniture and Equipment	1,590,880	84,728	466,240	—	—	1,209,368
77	(392) Transportation Equipment	62,881,984	3,345,441	474,406	—	(1)	65,753,018
78	(393) Stores Equipment	955,765	187,393	—	—	—	1,143,158
79	(394) Tools, Shop and Garage Equipment	10,229,526	540,102	202,069	—	—	10,567,559
80	(395) Laboratory Equipment	1,046,044	—	12,866	—	—	1,033,178
81	(396) Power Operated Equipment	5,897,811	701,087	56,062	—	1	6,542,837
82	(397) Communication Equipment	49,859,138	67,346	389,747	163,575	—	49,700,312
83	(398) Miscellaneous Equipment	2,110,622	36,910	24,822	—	—	2,122,710
84	SUBTOTAL (Enter Total of lines 71 thru 80)	146,065,486	4,935,912	1,704,712	163,575	—	149,460,261
85	(399) Other Tangible Property	—	—	—	—	—	—
86	TOTAL General Plant (Enter Total of lines 81 and 82)	146,065,486	4,935,912	1,704,712	163,575	—	149,460,261
87	TOTAL (Accounts 101 and 106)	3,940,227,884	267,059,125	26,523,579	8,141,104	452,094	4,189,356,628
88	(102) Electric Plant Purchased (See Instr. 8)	—	—				—
89	(Less) (102) Electric Plant Sold (See Instr. 8)	—	—				—
90	(103) Experimental Plant Unclassified	4,092,785	151,388	—	—	—	4,244,173
91	TOTAL Electric Plant in Service(Enter Total of lines 84 thru 87)	3,944,320,669	267,210,513	26,523,579	8,141,104	452,094	4,193,600,801

(b) Concept: FranchisesAndConsents

South Dakota Operations


Line	Account	Beginning of Year	Additions	Retirement	Adjustments	Transfers	End of Year	Plant
No.	(a)	(b)	(c)	(d)	(e)	(f)	(g)	Acct
1	1. INTANGIBLE PLANT
2	(301) Organization	—	—	—	—	—	—	(301)
3	(302) Franchises and Consents	—	—	—	—	—	—	(302)
4	(303) Miscellaneous Intangible Plant	8,304	25,232	—	—	(25,232)	8,304	(303)
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and4)	8,304	25,232	—	—	(25,232)	8,304
6	2. PRODUCTION PLANT						—
7	A. Steam Production Plant						—
8	(310) Land and Land Rights	366,511	—	—	—	—	366,511	(310)
9	(311) Structures and Improvements	27,166,811	112,262	6,730	—	—	27,272,343	(311)
10	(312) Boiler Plant Equipment	198,944,630	1,674,241	719,952	—	6,256	199,905,175	(312)
11	(313) Engines and Engine-Driven Generators	—	—	—	—	—	—	(313)
12	(314) Turbogenerator Units	26,291,674	321,704	1,431	—	—	26,611,947	(314)
13	(315) Accessory Electric Equipment	13,146,303	73,348	81,432	—	—	13,138,219	(315)
14	(316) Misc. Power Plant Equipment	2,975,920	224,458	100,005	—	—	3,100,373	(316)
15	(317) Asset Retirement Costs for Steam	2,663,711	—	—	—	—	2,663,711
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 14)	271,555,560	2,406,013	909,550	—	6,256	273,058,279
17	B. Nuclear Production Plant
18	(320) Land and Land Rights	—	—	—	—	—	—	(320)
19	(321) Structures and Improvements	—	—	—	—	—	—	(321)
20	(322) Reactor Plant Equipment	—	—	—	—	—	—	(322)
21	(323) Turbogenerator Units	—	—	—	—	—	—	(323)
22	(324) Accessory Electric Equipment	—	—	—	—	—	—	(324)
23	(325) Misc. Power Plant Equipment	—	—	—	—	—	—	(325)
24	TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 22)	—	—	—	—	—	—
25	C. Hydraulic Production Plant
26	(330) Land and Land Rights	—	—		—		—	(330)
27	(331) Structures and Improvements	—	—	—	—		—	(331)
28	(332) Reservoirs, Dams, and Waterways	—	—		—		—	(332)


29	(333) Water Wheels, Turbines, and Generators	—	—		—		—	(333)
30	(334) Accessory Electric Equipment	—	—		—		—	(334)
31	(335) Misc. Power Plant Equipment	—	—		—		—	(335)
32	(336) Roads, Railroads, and Bridges	—	—		—		—	(336)
33	TOTAL Hydraulic Production Plant (Enter Total of lines 25 thru 31)	—	—	—	—	—	—
34	D. Other Production Plant
35	(340) Land and Land Rights	82,483	—	—	—

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