FERC Form

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.

1/3-Q

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

Identification

01 Exact Legal Name of Respondent

NorthWestern Corporation

02 Year/ Period of Report

End of:

2023

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

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

3010 West 69th Street Sioux Falls, SD 57108

05 Name of Contact Person

Evan M. VerWey

06 Title of Contact Person

Manager of Financial Reporting

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

3010 West 69th Street, Sioux Falls, SD 57108

08 Telephone of Contact Person, Including Area Code

(605) 978-2906

09 This Report is An Original / A Resubmission

(1)

☑ An Original

(2)

☐ A Resubmission

10 Date of Report (Mo, Da, Yr)

03/31/2023

Quarterly 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)

05/08/2023

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:

03/31/2023

Year/Period of Report

End of:

2023

List of Schedules
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 (Electric Utility)	2
1	ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Quarter	108
2	ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet	110
3	ScheduleStatementOfIncomeAbstract Statement of Income for the Quarter	114
4	ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Quarter	118
5	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120
6	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122
7	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Comp Income, Comp Income, and Hedging Activities	122a
8	ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep	200
9	ScheduleElectricPlantInServiceAndAccumulatedProvisionForDepreciationByFunctionAbstract Electric Plant In Service and Accum Provision For Depr by Function	208
10	ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract Transmission Service and Generation Interconnection Study Costs	231
11	ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets	232
12	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278
13	ScheduleElectricOperatingRevenuesAbstract Elec Operating Revenues (Individual Schedule Lines 300-301)	300
14	ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1)	302	Not Applicable
15	ScheduleElectricProductionOtherPowerTransmissionRegionalExpensesAbstract Electric Prod, Other Power Supply Exp, Trans and Distrib Exp	324
16	ScheduleElectricCustomerAccountServiceSalesAdministrativeAndGeneralExpensesAbstract Electric Customer Accts, Service, Sales, Admin and General Expenses	325
17	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
18	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331	Not Applicable
19	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
20	ScheduleDepreciationDepletionAndAmortizationsAbstract Deprec, Depl and Amort of Elec Plant (403,403.1,404,and 405) (except Amortization of Acquisition Adjustments)	338
21	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts Included in ISO/RTO Settlement Statements	397
22	ScheduleMonthlyPeaksAndOutputAbstract Monthly Peak Loads and Energy Output	399
23	ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load	400
24	ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load	400a

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

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 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. As the terms of this agreement are not effective until January 1, 2026, and given the aforementioned conditions and approvals needed, no journal entries have been submitted to the Commission at this time.
4. None
5. None
6. See Note 6, "Financing Activities." Debt Issuance: FERC Order ES21-53-000 and MPSC Order Number 7804 Docket Number D2021.08.107.
7. None
8. None
9. See Note 8, "Commitments and Contingencies".
10. None
12. None
13. On January 1, 2023, Bob Rowe retired as Chief Executive Officer and Brian Bird was promoted to President and Chief Executive Officer. On January 1, 2023, Heather Grahame retired as General Counsel and Vice President - Regulatory and Federal Government Affairs. On this same day, Cyndee Fang was promoted to Vice President - Regulatory and Shannon Heim was promoted to Vice President - General Counsel. On April 28, 2023, Sherina Edwards was elected by our shareholders to the Board of Directors.
14. NA

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

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	7,631,179,228	7,591,279,874
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	330,874,246	300,649,215
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		7,962,053,474	7,891,929,089
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	2,819,903,362	2,786,711,964
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		5,142,150,112	5,105,217,125
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)		5,142,150,112	5,105,217,125
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)		357,585,527	357,585,527
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)		36,207,464	36,209,611
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	65,534
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	25,238,764	25,343,937
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228
24	OtherInvestments Other Investments (124)		21,976,708	21,035,719
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)		47,836,743	47,000,927
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		9,691,507	8,029,111
36	SpecialDeposits Special Deposits (132-134)		15,156,102	12,761,965
37	WorkingFunds Working Fund (135)		23,450	23,450
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		110,771,244	106,890,491
41	OtherAccountsReceivable Other Accounts Receivable (143)		11,503,913	26,793,907
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		2,854,255	2,451,237
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		3,709,019	3,143,188
45	FuelStock Fuel Stock (151)	227	8,873,016	7,724,941
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	80,198,029	71,154,248
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	26,733
55	GasStoredCurrent Gas Stored Underground - Current (164.1)		2,719,811	27,722,831
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57	Prepayments Prepayments (165)		(a) 20,537,926	23,739,745
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)		311,012	213,473
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		101,084,270	117,418,484
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		952,358	2,372,750
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)		362,704,135	405,537,347
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		10,389,498	9,254,937
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	726,637,645	729,084,376
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)		640,476	37,192
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	8,532,783	9,543,157
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) 21,912,191	22,619,741
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	157,140,884	163,943,624
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)		61,861,309	100,874,939
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		987,114,786	1,035,357,966
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		6,933,598,767	6,986,908,503

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: Prepayments

South Dakota Operations Prepayments (165) are $11,814,173 and $11,517,440 for 2023 and 2022, respectively.

Montana Operations Prepayments (165) are $8,723,753 and $12,222,305 for 2023 and 2022, respectively.

(b) Concept: UnamortizedLossOnReacquiredDebt

Montana Operations Unamortized Loss on Reacquired Debt (189) is $19,894,588 and $20,416,114 for 2023 and 2022, respectively.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

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	633,263	632,782
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	2,002,839,369	1,999,375,991
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	794,093,001	769,493,168
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	332,653	222,330
13	ReacquiredCapitalStock (Less) Reacquired Capital Stock (217)	250	98,470,962	98,392,040
14	NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218)
15	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	122(a)(b)	5,761,498	5,705,664
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		2,693,000,520	2,665,181,907
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	2,399,660,000	2,179,660,000
19	ReacquiredBonds (Less) Reacquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256	197,000,000	450,000,000
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		26,154	33,056
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		2,596,633,846	2,629,626,944
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		8,538,462	9,389,857
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		(a) 4,519,111	4,365,711
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		(b) 10,512,928	10,546,632
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)		68,493,189	72,588,961
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)		41,190,784	40,893,877
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		133,254,474	137,785,038
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)			92,402
38	AccountsPayable Accounts Payable (232)		113,391,326	214,538,891
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		4,423,110	4,356,816
41	CustomerDeposits Customer Deposits (235)		11,130,720	10,853,645
42	TaxesAccrued Taxes Accrued (236)	262	156,553,888	92,522,773
43	InterestAccrued Interest Accrued (237)		27,103,054	18,349,945
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		2,679,058	2,441,695
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		(c) 61,448,102	72,402,424
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		3,756,900	3,802,179
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)		380,486,158	419,360,770
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)		(d) 97,932,455	95,393,208
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	348,330	388,447
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	160,459,990	158,152,503
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	166,327,744	171,400,902
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reacquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		460,650,285	455,220,141
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		244,504,965	254,398,643
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		1,130,223,769	1,134,953,844
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		6,933,598,767	6,986,908,503

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: AccumulatedProvisionForInjuriesAndDamages

South Dakota Operations Provision for Injuries and Damages (228.2) are $530,826 and $480,925 for 2023 and 2022, respectively.

Montana Operations Provision for Injuries and Damages (228.2) are $3,988,284 and $3,884,786 for 2023 and 2022, respectively.

(b) Concept: AccumulatedProvisionForPensionsAndBenefits

Montana Operations Accumulated Provision for Pensions and Benefits (228.3) are $6,955,696 and $7,048,754 for 2023 and 2022, respectively.

Montana Operations Miscellaneous Current and Accrued Liabilities (242) are $50,382,252 and $60,534,114 for 2023 and 2022, respectively.

(d) Concept: CustomerAdvancesForConstruction

Montana Operations Customer Advances for Construction (252) are $97,932,455 and $95,393,208 for 2023 and 2022, respectively.

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

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	547,520,222	425,510,675	547,520,222	425,510,675	362,975,985	276,313,581	183,964,977	148,815,542	579,260	381,552
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	320,005,382	229,218,591	320,005,382	229,218,591	194,904,399	131,745,226	124,621,209	97,186,465	479,774	286,900
5	MaintenanceExpense Maintenance Expenses (402)	320	13,988,218	13,137,088	13,988,218	13,137,088	11,702,874	10,906,663	2,285,214	2,229,258	131	1,167
6	DepreciationExpense Depreciation Expense (403)	336	45,609,438	41,998,747	45,609,438	41,998,747	37,721,229	34,823,251	7,877,984	7,165,320	10,225	10,176
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	3,952,956	3,170,924	3,952,956	3,170,924	2,390,986	1,765,747	1,561,970	1,405,176
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336	3,775,443	3,775,443	3,775,443	3,775,443	3,987,069	3,987,069	211,626	211,626
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)		30,302,427	7,015,216	30,302,427	7,015,216	12,842,007	1,721,138	17,460,420	5,294,078
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		18,666,653	2,130,691	18,666,653	2,130,691	8,834,376	1,808,306	9,832,277	322,385
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	51,157,618	48,745,819	51,157,618	48,745,819	39,721,500	37,830,253	11,418,629	10,899,155	17,489	16,410
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	7,287,530	12,717,373	7,287,530	12,717,373	1,953,650	4,443,720	9,224,748	8,258,744	16,433	14,909
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	9,362,034	5,284,107	9,362,034	5,284,107	6,458,902	2,648,758	2,897,467	2,630,210	5,664	5,139
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	26,854,623	12,189,543	26,854,623	12,189,543	24,805,936	9,936,102	2,051,722	2,255,876	3,036	2,435
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	36,959,334	31,721,940	36,959,334	31,721,940	25,833,659	21,938,618	11,125,675	9,783,323
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	40,117	43,576	40,117	43,576	40,117	43,576
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		456,629,565	343,356,644	456,629,565	343,356,644	297,873,100	216,017,427	158,229,785	127,006,948	526,680	332,266
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		90,890,657	82,154,031	90,890,657	82,154,031	65,102,885	60,296,154	25,735,192	21,808,594	52,580	49,286
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)		153,311	103,207	153,311	103,207
32	CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)		34,735	38,773	34,735	38,773
33	RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417)		20,360	91,414	20,360	91,414
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		130,057	200,957	130,057	200,957
35	NonoperatingRentalIncome Nonoperating Rental Income (418)
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	110,323	162,444	110,323	162,444
37	InterestAndDividendIncome Interest and Dividend Income (419)		181,012	742,664	181,012	742,664
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		3,714,472	3,116,490	3,714,472	3,116,490
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		50,208	190,890	50,208	190,890
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		3,743,832	3,842,491	3,743,832	3,842,491
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		290,970	334,142	290,970	334,142
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)		116		116
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		194,510	112,320	194,510	112,320
49	OtherDeductions Other Deductions (426.5)		34,124	220,438	34,124	220,438
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		451,472	666,900	451,472	666,900
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	732	699	732	699
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	3,821,722	10,475,927	3,821,722	10,475,927
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	148,637	27,739	148,637	27,739
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	427,573	13,614,744	427,573	13,614,744
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	702,077	596,777	702,077	596,777
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)		3,399,313	2,515,000	3,399,313	2,515,000
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		106,953	660,591	106,953	660,591
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		26,990,006	22,159,342	26,990,006	22,159,342
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		491,476	301,225	491,476	301,225
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		703,600	702,482	703,600	702,482
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)		1,480,084	1,773,688	1,480,084	1,773,688
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		1,412,014	1,231,950	1,412,014	1,231,950
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		28,253,152	23,704,787	28,253,152	23,704,787
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		62,530,552	59,109,835	62,530,552	59,109,835
72	ExtraordinaryItemsAbstract Extraordinary Items
73	ExtraordinaryIncome Extraordinary Income (434)
74	ExtraordinaryDeductions (Less) Extraordinary Deductions (435)
75	NetExtraordinaryItems Net Extraordinary Items (Total of line 73 less line 74)
76	IncomeTaxesExtraordinaryItems Income Taxes-Federal and Other (409.3)	262
77	ExtraordinaryItemsAfterTaxes Extraordinary Items After Taxes (line 75 less line 76)
78	NetIncomeLoss Net Income (Total of line 71 and 77)		62,530,552	59,109,835	62,530,552	59,109,835

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

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		769,493,168	725,880,305
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)		62,640,875	183,675,024
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		38,041,042	140,062,161
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		38,041,042	140,062,161
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)		794,093,001	769,493,168
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)		794,093,001	769,493,168
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)
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)

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

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)	62,530,552	59,109,835
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	45,609,438	41,998,747
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of	7,728,399	6,946,367
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other Noncash Charges to Income, Net	(a) 4,153,257	5,122,256
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	10,379,215	6,514,430
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	40,117	43,576
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	11,246,428	2,247,630
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	14,784,431	10,503,744
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	13,811,562	52,150,046
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	15,570,413	6,421,947
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	5,073,158	2,150,389
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	3,714,472	3,116,490
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies	110,323	162,444
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other	(b) 56,753,435	27,500,502
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	213,091,276	195,843,373
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)	136,163,756	98,922,847
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant	4,128,803	20,179,426
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	3,714,472	3,116,490
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	136,578,087	115,985,783
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		567,360
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	136,578,087	116,553,143
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	220,000,000
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock		97,030
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
64.1	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Treasury Stock Activity	76,772	554,814
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other	(c) 92,403	92,403
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Line of Credit (Repayments) Borrowings, Net
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	219,984,369	559,441
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Debt Financing Costs	1,399,983
76.2	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Line of Credit (Repayments) Borrowings, Net	253,000,000	33,000,000
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock	38,041,042	33,900,926
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	72,456,656	67,460,367
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)	4,056,533	11,829,863
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	20,814,526	16,982,170
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	(d) 24,871,059	28,812,033

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: NoncashAdjustmentsToCashFlowsFromOperatingActivities


	3/31/2023	3/31/2022

Other Noncash Charges to Income, Net:
Amortization of debt issue costs, discount, and deferred hedge gain	1,133,310	1,926,400
Other noncash (gains) losses	(288,217)	438,391
Stock based compensation costs	3,308,164	2,757,465
	4,153,257	5,122,256
Other Assets and Liabilities, Net:
Net change - other current assets	4,524,672	3,246,393
Net change - accrued utility revenues	16,334,214	19,760,412
Net change - deferred debits	39,540,834	14,514,500
Net change - deferred credits	594,536	(2,572,943)
Net change - noncurrent liabilities	(4,240,821)	(7,447,860)
	56,753,435	27,500,502

(b) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

Refer to footnote (a) for details.

Increase in Notes payable (231)

(d) Concept: CashAndCashEquivalents


	3/31/2023	12/31/2022	3/31/2022	12/31/2021

Cash (131)	9,691,507	8,029,111	12,781,764	2,300,750
Working Funds (135)	23,450	23,450	23,250	23,250
Special Funds (125-128)	—	—	—	—
Other Special Deposits (134)	15,156,102	12,761,965	16,007,027	14,658,170

Total	24,871,059	20,814,526	28,812,041	16,982,170

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

NOTES TO FINANCIAL STATEMENTS

Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement.
Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock.
For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Commission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof.
Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However 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 preparation of financial statements in conformity with accounting requirements of the Federal Energy Regulatory Commission (FERC) as set forth in its applicable Uniform System of Accounts requires us 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. The unaudited Financial Statements reflect all adjustments (which unless otherwise noted are normal and recurring in nature) that are, in our opinion, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Events occurring subsequent to March 31, 2023 have been evaluated as to their potential impact to the Financial Statements through the date of issuance.

The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the FERC as set forth in its applicable Uniform System of Accounts. Certain information and footnote disclosures normally included in financial statements prepared in accordance with the accounting requirements of the FERC as set forth in its applicable Uniform System of Accounts and published accounting releases have been condensed or omitted pursuant to such rules and regulations; however, we believe that the condensed disclosures provided are adequate to make the information presented not misleading. We recommend that these Financial Statements be read in conjunction with the audited financial statements and related footnotes included in our Annual FERC Form 1 Report for the year ended December 31, 2022.

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 accounting principles generally accepted in the United States of America (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, and segment and related information, 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 $510.0 million and $502.2 million as of March 31, 2023 and December 31, 2022, 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 March 31, 2023 and December 31, 2022, respectively, in accordance with regulatory treatment, as compared to goodwill for GAAP purposes;

•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 March 31, 2023 and December 31, 2022, 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 classified in the Balance Sheets as capital leases in accordance with regulatory treatment, as compared to non-current assets for GAAP purposes;

•Operating lease liabilities are reflected as current and long term obligations under capital leases in the Balance Sheets, 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 postretirement 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 as Accrued utility revenue in accordance with regulatory treatment, as compared to Accounts receivable, net for GAAP purposes;

•Implementation costs associated with cloud computing arrangements are reflected 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 three months ended 2023 and 2022 (in millions):


	Three Months Ended March 31, 2023
	Total		Electric		Natural Gas		Other

GAAP Revenues	$	454.5	$	295.3	$	159.2	$	—
Revenue from equity investments	(0.7)		—		(0.7)		—
Grossing revenues / power purchases	32.8		32.8		—		—
Regulatory amortizations	52.6		26.4		26.2		—
Other	8.3		8.5		(0.8)		0.6
FERC Revenues	$	547.5	$	363.0	$	183.9	$	0.6


	Three Months Ended March 31, 2022
	Total		Electric		Natural Gas		Other

GAAP Revenues	$	394.5	$	271.7	$	122.8	$	—
Revenue from equity investments	(0.7)		—		(0.7)		—
Grossing revenues / power purchases	11.4		11.4		—		—
Regulatory amortizations	21.5		(5.7)		27.2		—
Other	(1.2)		(1.1)		(0.5)		0.4
FERC Revenues	$	425.5	$	276.3	$	148.8	$	0.4

Supplemental Cash Flow Information

The following table provides a reconciliation of cash, workings 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):


	March 31, 2023		December 31, 2022		March 31, 2022		December 31, 2021
Cash	$	9,692	$	8,029	$	12,782	$	2,301
Working funds	23		23		23		23
Other special funds	—		—		—		—
Special deposits	15,156		12,762		16,007		14,658
Total shown in the Statements of Cash Flows	$	24,871	$	20,814	$	28,812	$	16,982

(2) Regulatory Matters

Except as set forth below, the circumstances set forth in Note 3 - Regulatory Matters to the financial statements included in our Annual FERC Form 1 report for the year ended December 31, 2022 appropriately represent, in all material respects, the current status of our regulatory matters.

Montana Rate Review

On August 8, 2022, we filed a Montana electric and natural gas rate review with the Montana Public Service Commission (MPSC) requesting an annual increase to electric and natural gas utility rates. On September 28, 2022, the MPSC approved the recommendations of the MPSC Staff for interim rates effective October 1, 2022, subject to refund.

Subsequently, we modified our request through rebuttal testimony. On April 3, 2023, we filed a settlement with certain parties in our Montana electric and natural gas rate review, which is subject to approval by the MPSC. The details of our request, as so modified, the interim rates granted, and the settlement agreement are set forth below:


Requested Revenue Increase Through Rebuttal Testimony (in millions)
	Electric	Natural Gas
Base Rates	$90.6	$22.4
PCCAM(1)	$69.7	n/a
Property Tax (tracker true-up)(1)	$14.5	$4.2
Total Revenue Increase Requested through Rebuttal Testimony	$174.8	$26.6

Interim Revenue Increase Granted (in millions)
	Electric	Natural Gas
Base Rates	$29.4	$1.7
Power Cost & Credit Mechanism (PCCAM)(1)	$61.1	n/a
Property Tax (tracker true-up)(1)(2)	$10.8	$2.9
Total Interim Revenue Granted	$101.3	$4.6

Requested Revenue Increase Through Settlement Agreement (in millions)
	Electric	Natural Gas
Base Rates	$67.4	$14.1
PCCAM(1)	$69.7	n/a
Property Tax (tracker true-up)(1)	$14.5	$4.2
Total Revenue Increase Requested Through Settlement Agreement	$151.6	$18.3

(1) These items are flow-through costs.

(2) While our requested interim property tax base increases were denied from interim rates, these rates went into effect on January 1, 2023, as part of our 2023 property tax tracker period true-up.

The settlement includes, among other things, agreement on electric and natural gas base revenue increases, allocated cost of service, rate design, updates to the base amount of revenues associated with property taxes and electric supply costs, and regulatory policy issues related to requested changes in regulatory mechanisms. The settlement is based on a 48.02 percent equity component of our capital structure and an authorized return on equity of 9.65 percent for electric operations and 9.55 percent for natural gas operations, which are consistent with current authorized return on equity amounts.

The settlement agreement provides for an update to the PCCAM by adjusting the base costs from $138.7 million to $208.4 million and providing for more timely quarterly recovery of deferred balances instead of annual recovery. It also addresses the potential for future recovery of certain operating costs associated with the Yellowstone County Generating Station and provides for the deferral of incremental operating costs related to our Enhanced Wildfire Mitigation Plan. The settling parties agreed to terminate the pilot decoupling program (Fixed Cost Recovery Mechanism) and that the proposed business technology rider will not be implemented.

A hearing commenced on April 11, 2023 and concluded on April 18, 2023. Interim rates will remain in effect on a refundable basis until the MPSC issues a final order.

Holding Company Filings

As previously reported, on June 1, 2022, we filed a legal corporate restructuring application (Restructuring Plan) with the state commissions in Montana, South Dakota and Nebraska and the Federal Energy Regulatory Commission (FERC). Currently, our utility businesses are held in the same legal entity. Under the proposed Restructuring Plan, we would legally separate our Montana public utility business from our South Dakota and Nebraska public utility business and establish a holding company to hold the ownership interests of all of the subsidiaries. The purpose of the reorganization is to segregate our organizational structure to be more transparent and in line with the public utility industry.

The Restructuring Plan does not propose and we do not expect any procedural or substantive change in how the state public utility commissions regulate those services. Implementation of the Restructuring Plan is subject to receipt of all regulatory approvals. During 2022, we received approvals from the Nebraska Public Service Commission, South Dakota Public Service Commission, and the FERC. On February 21, 2023, the MPSC approved the Restructuring Plan. We are currently developing implementation timing to effectuate the Restructuring Plan.

(3) Income Taxes

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

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in thousands):


	Three Months Ended March 31,
	2023				2022
Income Before Income Taxes	$	72,434			$	60,050

Income tax calculated at federal statutory rate	15,211		21.0	%	12,610		21.0	%

Permanent or flow-through adjustments:
State income tax, net of federal provisions	959		1.3		400		0.7
Flow-through repairs deductions	(5,845)		(8.1)		(6,801)		(11.3)
Production tax credits	(3,199)		(4.4)		(3,824)		(6.5)
Amortization of excess deferred income tax	(799)		(1.1)		(255)		(0.4)
Reduction to previously claimed alternative minimum tax credit	3,186		4.4		—		—
Plant and depreciation of flow-through items	688		0.9		(253)		(0.4)
Share-based compensation	388		0.5		(411)		(0.7)
Other, net	(686)		(0.8)		(526)		(0.9)
	(5,308)		(7.3)		(11,670)		(19.5)

Income tax expense	$	9,903	13.7	%	$	940	1.5	%

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. We had unrecognized tax benefits of approximately $29.9 million as of March 31, 2023, including approximately $27.9 million that, if recognized, would impact our 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 in income tax expense. As of March 31, 2023, we have accrued $1.7 million for the payment of interest on the Balance Sheets. As of December 31, 2022, we had accrued $1.4 million for the payment of interest on the Balance Sheets.

Tax years 2019 and forward remain subject to examination by the Internal Revenue Service 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. This examination concluded in the first quarter of 2023 and resulted in a reduction to our previously claimed alternative minimum tax credit refund.

(4) Equity Investments

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


	March 31, 2023		December 31, 2022
Havre Pipeline Company, LLC	$	11,243	$	11,399
Canadian Montana Pipeline Corporation	5,038		4,984
NorthWestern Services, LLC	2,099		2,091
NorthWestern Energy Solutions, Inc.	5,738		5,738
Risk Partners Assurance, Ltd.	1,121		1,132
Total Investments in Subsidiary Companies	$	25,239	$	25,344

(5) Comprehensive Income

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


	Three Months Ended
	March 31, 2023						March 31, 2022
	Before- Tax Amount		Tax Expense (Benefit)		Net-of- Tax Amount		Before- Tax Amount		Tax Expense (Benefit)		Net-of- Tax Amount
Foreign currency translation adjustment	$	(1)	$	—	$	(1)	$	(1)	$	—	$	(1)
Reclassification of net income (loss) on derivative instruments	153		(40)		113		153		(40)		113
Postretirement medical liability adjustment	(212)		45		(167)		(212)		54		(158)
Other comprehensive income	$	(60)	$	5	$	(55)	$	(60)	$	14	$	(46)

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


	March 31, 2023		December 31, 2022
Foreign currency translation	$	1,434	$	1,435
Derivative instruments designated as cash flow hedges	(7,562)		(7,675)
Postretirement medical plans	367		534
Accumulated other comprehensive income	$	(5,761)	$	(5,706)

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


		Three Months Ended March 31, 2023
	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		$	(7,675)	$	534	$	1,435	$	(5,706)
Other comprehensive income before reclassifications		—		—		(1)		(1)
Amounts reclassified from AOCI	Interest on long-term debt	113		—		—		113
Amounts reclassified from AOCI		—		(167)		—		(167)
Net current-period other comprehensive income		113		(167)		(1)		(55)
Ending balance		$	(7,562)	$	367	$	1,434	$	(5,761)


		Three Months Ended March 31, 2022
	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		—		—		(1)		(1)
Amounts reclassified from AOCI	Interest on long-term debt	113		—		—		113
Amounts reclassified from AOCI		—		(158)		—		(158)
Net current-period other comprehensive income		113		(158)		(1)		(46)
Ending balance		$	(8,014)	$	1,358	$	1,442	$	(5,214)

(6) Financing Activities

On March 30, 2023, we issued and sold $239.0 million aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 5.57 percent maturing on March 30, 2033. On this same day, we issued and sold $31.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.57 percent maturing on March 30, 2033. We received proceeds totaling $220.0 million on March 30, 2023, and the remaining $50.0 million of proceeds, associated with the Montana First Mortgage Bonds, on May 1, 2023.

On May 1, 2023, we issued and sold $30.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.42 percent maturing on May 1, 2033.

These bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were used to repay a portion of our outstanding borrowings under our revolving credit facilities and for other general corporate purposes. The bonds are secured by our electric and natural gas assets in Montana and South Dakota.

(7) 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):


	March 31, 2023		December 31, 2022
Accounts Receivable from Associated Companies:
Havre Pipeline Company, LLC	$	3,767	$	3,201
NorthWestern Energy Solutions, Inc.	16		16
Risk Partners Assurance, Ltd.	(74)		(74)
	$	3,709	$	3,143

Accounts Payable to Associated Companies:
NorthWestern Services, LLC	$	2,057	$	2,312
Canadian Montana Pipeline Corporation	2,366		2,045
	$	4,423	$	4,357

(8) Employee Benefit Plans

We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for eligible employees. Net periodic benefit cost (credit) for our pension and other postretirement plans consists of the following (in thousands):


	Pension Benefits				Other Postretirement Benefits
	Three Months Ended March 31,				Three Months Ended March 31,
	2023		2022		2023		2022
Components of Net Periodic Benefit Cost (Credit)
Service cost	$	1,494	$	2,884	$	87	$	91
Interest cost	6,565		4,668		176		91
Expected return on plan assets	(6,686)		(6,052)		(275)		(262)
Amortization of prior service credit	—		—		29		(473)
Recognized actuarial loss (gain)	140		—		31		(14)
Net periodic benefit cost (credit)	$	1,513	$	1,500	$	48	$	(567)

We have not contributed to our pension plans during the three months ended March 31, 2023. We expect to contribute $11.2 million to our pension plans during the remainder of 2023.

(9) Commitments and Contingencies

Except as set forth below and in Note 2 - Regulatory Matters above, the circumstances set forth in Note 19 - Commitments and Contingencies to the financial statements included in our Annual FERC Form 1 Report for the year ended December 31, 2022 appropriately represent, in all material respects, the current status of our material commitments and contingent liabilities.


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 $21.3 million to $32.4 million. As of March 31, 2023, we had a reserve of approximately $26.1 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.

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 consolidated financial position or results of operations.

Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of greenhouse gas (GHG) including, most significantly, carbon dioxide (CO2) and methane emissions from natural gas. These actions include legislative proposals, Executive, Congressional and Environmental Protection Agency (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 due to their level of GHG emissions. We have joint ownership interests in four coal-fired electric generating plants, all of which are operated by other companies. We are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.

While numerous bills have been introduced that address climate change from different perspectives, Congress has not passed any federal climate change legislation regarding GHG emissions from coal fired plants, and we cannot predict the timing or form of any potential legislation. However, 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. EPA has acted on this authority, including in 2015 when it sought to implement the Clean Power Plan that would establish rules to control GHG emissions from existing power plants. However, neither the Clean Power Plan nor any other subsequent attempts by the EPA to regulate emissions from coal-fired plants has become effective due to litigation by various states and stakeholders. One of the key issues in the litigation revolves around whether EPA can use its CAA authority to compel fossil fuel sources to curtail operations and invest in renewable and other low carbon energy sources, in other words, establish a carbon emission cap based on a power generation source shift. The litigation culminated in the United States Supreme Court's June 30, 2022 ruling in West Virginia, et al., v. Environmental Protection Agency, et al, in which the Court held that the EPA does not have the authority to force major changes in the U.S. electric generation mix, as that would expand EPA's regulatory authority. In addition, the U.S. Supreme Court concluded that EPA could not meet its burden under the "major questions doctrine" to point to clear congressional authorization for this authority. The U.S. Supreme Court's ruling, however, declined to decide whether the Section 111(d) phrase "system of emissions reduction" refers exclusively to individual source control at coal-fired plants or broader energy-generating industry-wide approaches.

As expected, subsequent to that ruling, 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.

Therefore, we cannot predict whether or how future GHG emission regulations or litigation will impact our plants, including any actions taken by federal or state authorities, or courts. 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. 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 customers in our region.

Future additional environmental requirements - federal or state - 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.


LEGAL PROCEEDINGS

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 Montana, LLC (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 state and federal court, including before the United States Supreme Court, as detailed in Note 18 - Commitments and Contingencies to the financial statements included in our Annual FERC Form 1 Report for the year ended December 31, 2022. 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 navigability of the riverbeds associated with four of our hydroelectric facilities near Great Falls. A bench trial before the Federal District Court commenced January 4, 2022, and concluded on January 18, 2022, which addressed the issue of navigability concerning our other six facilities. Damages were bifurcated by agreement and will be tried separately should the Federal District Court find any segments navigable. While we await 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

The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. The six owners of Colstrip Units 3 and 4 currently share the operating costs pursuant to the terms of an Ownership and Operation Agreement (O&O Agreement). However, several of the owners are mandated by Washington and Oregon law to eliminate coal-fired resources in 2025 and 2029, respectively.

As a result of the mandate, the owners have disagreed on various operational funding decisions, including whether closure requires each owner’s consent under the O&O Agreement. On March 12, 2021, we initiated an arbitration under the O&O Agreement (the “Arbitration”), to resolve the issues of whether closure requires each owner's consent and to clarify each owner's obligations to continue to fund operations until all joint owners agree on closure. The owners previously initiated efforts to identify arbitrators and have agreed to stay the Arbitration while they explore a potential resolution to their disagreements.

Colstrip Coal Dust Litigation

On December 14, 2020, a claim was filed against Talen in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. Talen is one of the co-owners of Colstrip Unit 3, and the operator of Units 3 and 4. 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, 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.

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.

Yellowstone County Generating Station Air Permit

On October 21, 2021, the Montana Environmental Information Center (MEIC) and the Sierra Club filed a lawsuit in Montana State Court, against the Montana Department of Environmental Quality (MDEQ) and NorthWestern, alleging that the environmental analysis conducted by MDEQ prior to issuance of the Yellowstone County Generating Station's air quality construction permit was inadequate. The Montana District Court judge held oral argument on June 20, 2022. On April 4, 2023, the Montana District Court issued an order finding MDEQ's environmental analysis was deficient in not addressing exterior lighting and greenhouse gases. The Montana District Court remanded it back to MDEQ to address the deficiencies and vacated the air quality permit pending that remand. As a result of the vacatur of the permit, we are required to stop construction and will not be able to recommence construction until the permit is reissued. On April 14, 2023, following entry of final judgment, we filed our motion to stay the order vacating the air quality permit. On April 17, 2023, we filed a notice of appeal with the Montana Supreme Court. This lawsuit, as well as additional legal challenges related to the Yellowstone County Generating Station, could delay the project timing and increase costs. At this time, we still expect the plant to be operational by the end of 2024.

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:

03/31/2023

Year/Period of Report

End of:

2023

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		1,518,461		1,441,981	8,128,038		5,167,596
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income		(a) 158,410			(e) 113,032		45,378
3	Preceding Quarter/Year to Date Changes in Fair Value				(c) 859			859
4	Total (lines 2 and 3)		158,410		859	113,032		46,237	59,109,835	59,063,598
5	Balance of Account 219 at End of Preceding Quarter/Year		1,360,051		1,441,122	8,015,006		5,213,833
6	Balance of Account 219 at Beginning of Current Year		535,470		1,434,774	7,675,908		5,705,664
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income		(b) 167,561			(f) 113,033		54,528
8	Current Quarter/Year to Date Changes in Fair Value				(d) 1,306			1,306
9	Total (lines 7 and 8)		167,561		1,306	113,033		55,834	62,530,552	62,474,718
10	Balance of Account 219 at End of Current Quarter/Year		367,909		1,433,468	7,562,875		5,761,498

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

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:

03/31/2023

Year/Period of Report

End of:

2023

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)	6,895,076,881	5,305,998,157	1,319,594,314	(a) 1,528,963			267,955,447
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	41,353,746				(b) 40,209,537	(c) 1,144,209
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified	4,092,785	4,092,785
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	6,940,523,412	5,310,090,942	1,319,594,314	1,528,963	40,209,537	1,144,209	267,955,447
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	4,327,381	4,297,515	29,866
11	ConstructionWorkInProgress Construction Work in Progress	330,874,246	292,257,181	27,669,602				10,947,463
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	686,328,435	686,328,435
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	7,962,053,474	6,292,974,073	1,347,293,782	1,528,963	40,209,537	1,144,209	278,902,910
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	2,819,903,362	2,170,453,665	537,831,798	1,096,598	33,675,467		76,845,834
15	UtilityPlantNet Net Utility Plant (13 less 14)	5,142,150,112	4,122,520,408	809,461,984	432,365	6,534,070	1,144,209	202,057,076
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	2,538,643,635	1,968,715,270	481,680,067	1,096,598	33,675,467		53,476,233
19	AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService Amortization and Depletion of Producing Natural Gas Land and Land Rights	49,266,874		49,266,874
20	AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService Amortization of Underground Storage Land and Land Rights
21	AmortizationOfOtherUtilityPlantUtilityPlantInService Amortization of Other Utility Plant	55,090,521	24,836,063	6,884,857				23,369,601
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	2,643,001,030	1,993,551,333	537,831,798	1,096,598	33,675,467		76,845,834
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	176,902,332	176,902,332
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	2,819,903,362	2,170,453,665	537,831,798	1,096,598	33,675,467		76,845,834

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: UtilityPlantInServiceClassified

This column represents regulated propane.

(b) Concept: UtilityPlantInServicePropertyUnderCapitalLeases

This column represents the write-down of plant values associated with the 2002 acquisition of Montana Operations, and the reduction from fair value to regulated basis associated with the transfer of Colstrip Unit 4 to the regulated utility in 2009.

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

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

Electric Plant In Service and Accum Provision For Depr by Function
Report below the original cost of plant in service by function. In addition to Account 101, include Account 102, and Account 106. Report in column (b) the original cost of plant in service and in column(c) the accumulated provision for depreciation and amortization by function.
Line No.	Item (a)	Plant in Service Balance at End of Quarter (b)	Accumulated Depreciation And Amortization Balance at End of Quarter (c)
1	Intangible Plant	32,512,907	10,541,541
2	Steam Production Plant	416,001,347	150,771,599
3	Nuclear Production Plant
4	Hydraulic Production - Conventional	607,276,350	132,421,305
5	Hydraulic Production - Pumped Storage
6	Other Production	579,259,096	159,940,644
7	Transmission	1,338,020,974	505,028,100
8	Distribution	2,155,430,881	929,974,032
9	Regional Transmission and Market Operation
10	General	181,589,387	104,874,111
11	TOTAL (Total of lines 1 through 10)	5,310,090,942	1,993,551,333

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

Transmission Service and Generation Interconnection Study Costs
Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. List each study separately. In column (a) provide the name of the study. In column (b) report the cost incurred to perform the study at the end of period. In column (c) report the account charged with the cost of the study. In column (d) report the amounts received for reimbursement of the study costs at end of period. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.	DescriptionOfStudyPerformed Description (a)	StudyCostsIncurred Costs Incurred During Period (b)	StudyCostsAccountCharged Account Charged (c)	StudyCostsReimbursements Reimbursements Received During the Period (d)	StudyCostsAccountReimbursed Account Credited With Reimbursement (e)
1	Transmission Studies
2	FAC Studies	63,493	253	59,019	253
3	SIS Studies	130,705	253	129,396	253
4	Line Interconnection Studies	49,395	253	128,277	253
20	Total	243,593		316,692
21	Generation Studies
22	FAC Studies	245,610	253	1,434,673	253
23	SIS Studies	208,940	253	956,285	253
24	FEA Studies	169,110	253	441,524	253
25	Optional Studies	21,074	253	110,322	253
39	Total	644,734		2,942,804
40	Grand Total	888,327		3,259,496

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

OTHER REGULATORY ASSETS (Account 182.3)
Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Assets being amortized, show period of amortization.
				CREDITS
Line No.	DescriptionAndPurposeOfOtherRegulatoryAssets Description and Purpose of Other Regulatory Assets (a)	OtherRegulatoryAssets Balance at Beginning of Current Quarter/Year (b)	IncreaseDecreaseInOtherRegulatoryAssets Debits (c)	OtherRegulatoryAssetsWrittenOffAccountCharged Written off During Quarter/Year Account Charged (d)	OtherRegulatoryAssetsWrittenOffRecovered Written off During the Period Amount (e)	OtherRegulatoryAssets Balance at end of Current Quarter/Year (f)
1	Flow-through Income Taxes (Montana)	444,386,121	10,676,184	Various		455,062,305
2	Excess Deferred Income Taxes (Montana)	47,448,837		410.1	2,018,262	45,430,575
3	Basin Creek Capital Lease (Montana)	4,859,963		243	242,879	4,617,084
4	BPA Residential Exchange Program (Montana) - Docket 2018.8.49 Order 7630; Annual Amortization	1,193,372	1,344,638	254	1,307,685	1,230,325
5	Property Tax Tracker (Montana) - Docket 2017.11.86 - Order 7580a; Annual Amortization	11,432,710		(2)407	11,287,165	145,545
6	FAS 106 (Montana) - Docket 93.6.24 and Docket 2009.9.129	10,658,733	257,458	(2)926	394,930	10,521,261
7	FAS 112 (Montana) - Docket 93.6.24 and Docket 2009.9.129	5,879,275		(2)926		5,879,275
8	Compensated Absences (Montana) - Docket 97.11.219	11,382,102	480,334	242		11,862,436
9	Pension Plan (Montana)	80,885,087			1,081,413	79,803,674
10	Montana Consumer Counsel Tax (Montana) - Docket 2018.10.67 - Order 7637	639,407	104	Various		639,511
11	Montana Public Service Commission (Montana) - Docket 2017.9.78 - Order 7568	3,570,894	239,097		193,438	3,616,553
12	Natural Gas Transmission Verification Program (Montana) - Docket D2016.11.88	584,247		(2)407	152,590	431,657
13	Asset Retirement Obligation (Montana)	15,421,503	610,472			16,031,975
14	Flow-through Income Taxes (South Dakota)	64,652,202	717,036			65,369,238
15	Excess Deferred Income Taxes (South Dakota)	6,915,405			57,966	6,857,439
16	Pension Plan (South Dakota)	7,079,702				7,079,702
17	Manufactured Gas Plants (South Dakota) - Docket NG 11-003	10,962,729			46,777	10,915,952
18	Field Inventory (South Dakota) - Docket EL 14-106	262,191			22,479	239,712
19	Asset Retirement Obligation (South Dakota)	869,896	33,530			903,426
44	TOTAL	729,084,376	14,358,853		16,805,584	726,637,645

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

OTHER REGULATORY LIABILITIES (Account 254)
Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Liabilities being amortized, show period of amortization.
			DEBITS
Line No.	Description and Purpose of Other Regulatory Liabilities (a)	Balance at Beginning of Current Quarter/Year (b)	Account Credited (c)	Amount (d)	Credits (e)	Balance at End of Current Quarter/Year (f)
1	Excess Deferred Income Taxes (Montana)	129,066,336		2,697,303		126,369,033
2	Deferred Gas Storage Sales (Montana) - Docket D2001.1.1; Amortization 2001 - 2039	7,045,944	(2)407	105,128		6,940,816
3	Montana Public Service Commission Consumer Counsel Taxes (Montana) - Dockets 2017.9.78 and 2018.10.67	1,908,900	Various	14,176	103,178	1,997,902
4	CTC QF Over/Under Collections (Montana) - Docket 97.9.90 and Docket 2001.1.15; Annual Amortization	756,325			441,865	1,198,190
5	Property Tax Tracker (Montana) - Docket 2017.11.86 - Order 7580a; Annual Amortization	1		616,025	616,026
6	Natural Gas Regulatory Deferrals (Montana)	27,556		140,552	2,223,606	2,110,610
7	Excess Deferred Income Taxes (South Dakota)	19,922,861	(2)407	347,901		19,574,960
8	Current Ad Valorem True-Up (South Dakota) - Docket GE98-001	390,314	(2)407		135,278	525,592
9	Aberdeen Manufactured Gas Plant (South Dakota) - Docket NG 11-003	591,549		92,726		498,823
10	Tax Cut Jobs Act Deferral (South Dakota) - Docket NG-0095 and GE17-003	155,000				155,000
11	Unbilled Revenues (South Dakota)	11,536,118		4,579,300		6,956,818
41	TOTAL	171,400,902		8,593,111	3,519,953	166,327,744

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

Electric Operating Revenues
The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The average number of customers means the average of twelve figures at the close of each month. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.	Title of Account (a)	Operating Revenues Year to Date Quarterly/Annual (b)	Operating Revenues Previous year (no Quarterly) (c)	MEGAWATT HOURS SOLD Year to Date Quarterly/Annual (d)	MEGAWATT HOURS SOLD Amount Previous year (no Quarterly) (e)	AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly) (f)	AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly) (g)
1	SalesOfElectricityHeadingAbstract Sales of Electricity
2	ResidentialSalesAbstract (440) Residential Sales	145,233,398	116,336,219	1,066,482	1,013,598
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	130,317,374	104,626,503	996,876	951,108
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	19,259,439	18,302,487	181,076	191,259
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	4,762,043	3,992,067	10,163	10,942
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities	192,545	237,685	1,633	1,944
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales	304,572	220,497	2,285	1,928
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	300,069,371	243,715,458	2,258,515	2,170,779
11	SalesForResaleAbstract (447) Sales for Resale	31,265,354	9,686,325	247,126	281,055
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	331,334,725	253,401,783	2,505,641	2,451,834
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds	27,410	1,980,010
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	331,307,315	255,381,793	2,505,641	2,451,834
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	102,625	143,365
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	40,284	45,500
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	1,259,027	1,207,467
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(a) 11,178,313	701,201
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	19,088,421	20,236,657
23	RegionalTransmissionServiceRevenues (457.1) Regional Control Service Revenues
24	MiscellaneousRevenue (457.2) Miscellaneous Revenues
25	OtherMiscellaneousOperatingRevenues Other Miscellaneous Operating Revenues
25.1	OtherMiscellaneousOperatingRevenues (Less) (449.1) Provision for Rate Refunds
26	OtherOperatingRevenues TOTAL Other Operating Revenues	31,668,670	20,931,788
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	362,975,985	276,313,581
Line12, column (b) includes $ of unbilled revenues.
Line12, column (d) includes MWH relating to unbilled revenues

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: OtherElectricRevenue


	YTD Q1
Other Electric Revenue (456)	2023
Ancillary Services:
Scheduling, System Control and Dispatch	$	412,097
Regulation and Frequency Response	298,489
Energy Imbalance	10,688,824
Other Transmission Revenue	(1,463,116)
Low Income Housing	1,106,289
Steam Sales	118,971
Sale of Materials	16,639
Miscellaneous	120
	$	11,178,313

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

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

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

ELECTRIC PRODUCTION, OTHER POWER SUPPLY EXPENSES, TRANSMISSION AND DISTRIBUTION EXPENSES

Report Electric production, other power supply expenses, transmission, regional market, and distribution expenses through the reporting period.
Line No.	Account (a)	Year to Date Quarter (b)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION AND OTHER SUPPLY EXPENSES
2	SteamPowerGenerationOperationsExpense Steam Power Generation - Operation (500-509)	14,848,315
3	SteamPowerGenerationMaintenanceExpense Steam Power Generation – Maintenance (510-515)	3,039,563
4	PowerProductionExpensesSteamPower Total Power Production Expenses - Steam Power	17,887,878
5	NuclearPowerGenerationOperationsExpense Nuclear Power Generation – Operation (517-525)
6	NuclearPowerGenerationMaintenanceExpense Nuclear Power Generation – Maintenance (528-532)
7	PowerProductionExpensesNuclearPower Total Power Production Expenses - Nuclear Power
8	HydraulicPowerGenerationOperationsExpense Hydraulic Power Generation – Operation (535-540.1)	3,901,737
9	HydraulicPowerGenerationMaintenanceExpense Hydraulic Power Generation – Maintenance (541-545.1)	552,027
10	PowerProductionExpensesHydraulicPower Total Power Production Expenses - Hydraulic Power	4,453,764
11	RentsOtherPowerGeneration Other Power Generation – Operation (546-550.1)	14,289,799
12	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration Other Power Generation – Maintenance (551-554.1)	783,722
13	MaintenanceOfMiscellaneousOtherPowerGenerationPlant Total Power Production Expenses - Other Power	15,073,521
14	OtherPowerSuplyExpensesAbstract Other Power Supply Expenses
15	PurchasedPower (555) Purchased Power	92,783,479
15.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations
16	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	153,016
17	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	19,869,198
18	OtherPowerSupplyExpense Total Other Power Supply Expenses (line 15-17)	112,805,693
19	PowerProductionExpenses Total Power Production Expenses (Total of lines 4, 7, 10, 13 and 18)	150,220,856
20	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
21	TransmissionExpensesOperationAbstract Transmission Operation Expenses
22	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	1,311,580
24	LoadDispatchReliability (561.1) Load Dispatch-Reliability	252,184
25	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	197,804
26	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	281,958
27	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services
28	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	25,491
29	TransmissionServiceStudies (561.6) Transmission Service Studies
30	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
31	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services
32	StationExpensesTransmissionExpense (562) Station Expenses	501,768
32.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
33	OverheadLineExpense (563) Overhead Lines Expenses	264,073
34	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses
35	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	7,513,238
36	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	54,493
37	RentsTransmissionElectricExpense (567) Rents	215,747
38	OperationSuppliesAndExpensesTransmissionExpense (567.1) Operation Supplies and Expenses (Non-Major)
39	TransmissionOperationExpense TOTAL Transmission Operation Expenses (Lines 22 - 38)	10,618,336
40	TransmissionMaintenanceAbstract Transmission Maintenance Expenses
41	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	119,305
42	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	10,477
43	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	663,713
44	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	685
45	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment
46	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
47	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	164,427
47.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment	192,159
48	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines
49	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines
50	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant
51	MaintenanceOfTransmissionPlant (574) Maintenance of Transmission Plant
52	TransmissionMaintenanceExpenseElectric TOTAL Transmission Maintenance Expenses (Lines 41 – 51)	1,150,766
53	TransmissionExpenses Total Transmission Expenses (Lines 39 and 52)	11,769,102
54	RegionalMarketExpensesAbstract 3. REGIONAL MARKET EXPENSES
55	RegionalMarketExpensesOperationAbstract Regional Market Operation Expenses
56	OperationSupervision (575.1) Operation Supervision
57	DayAheadAndRealTimeMarketAdministration (575.2) Day-Ahead and Real-Time Market Facilitation	116,585
58	TransmissionRightsMarketAdministration (575.3) Transmission Rights Market Facilitation
59	CapacityMarketAdministration (575.4) Capacity Market Facilitation
60	AncillaryServicesMarketAdministration (575.5) Ancillary Services Market Facilitation	33,310
61	MarketMonitoringAndCompliance (575.6) Market Monitoring and Compliance	16,655
62	MarketFacilitationMonitoringAndComplianceServices (575.7) Market Facilitation, Monitoring and Compliance Services
63	RegionalMarketOperationExpense Regional Market Operation Expenses (Lines 55 - 62)	166,550
64	RegionalMarketExpensesMaintenanceAbstract Regional Market Maintenance Expenses
65	MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses (576.1) Maintenance of Structures and Improvements
66	MaintenanceOfComputerHardware (576.2) Maintenance of Computer Hardware
67	MaintenanceOfComputerSoftware (576.3) Maintenance of Computer Software
68	MaintenanceOfCommunicationEquipmentRegionalMarketExpenses (576.4) Maintenance of Communication Equipment
69	MaintenanceOfMiscellaneousMarketOperationPlant (576.5) Maintenance of Miscellaneous Market Operation Plant
70	RegionalMarketMaintenanceExpense Regional Market Maintenance Expenses (Lines 65-69)
71	RegionalMarketExpenses TOTAL Regional Control and Market Operation Expenses (Lines 63,70)	166,550
72	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
73	DistributionOperationExpensesElectric Distribution Operation Expenses (580-589)	4,001,323
74	DistributionMaintenanceExpenseElectric Distribution Maintenance Expenses (590-598)	4,924,448
75	DistributionExpenses Total Distribution Expenses (Lines 73 and 74)	8,925,771

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

Electric Customer Accts, Service, Sales, Admin and General Expenses
Report the amount of expenses for customer accounts, service, sales, and administrative and general expenses year to date.
Line No.	Account (a)	Year to Date Quarter (b)
-	CustomerAccountsExpensesOperationsAbstract Operation
1	CustomerAccountExpenses (901-905) Customer Accounts Expenses	2,965,269
2	CustomerServiceAndInformationExpenses (907-910) Customer Service and Information Expenses	968,311
3	SalesExpenses (911-917) Sales Expenses	72,303
4	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
5	AdministrativeAndGeneralExpensesOperationAbstract Operation
6	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	8,628,169
7	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	5,043,550
8	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	873,265
9	OutsideServicesEmployed (923) Outside Services Employed	1,958,955
10	PropertyInsurance (924) Property Insurance	869,233
11	InjuriesAndDamages (925) Injuries and Damages	2,723,789
12	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	5,993,177
13	FranchiseRequirements (927) Franchise Requirements
14	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	720,461
15	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.
16	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	102,286
17	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	4,813,535
18	RentsAdministrativeAndGeneralExpense (931) Rents	286,873
19	AdministrativeAndGeneralOperationExpense TOTAL Operation (Total of lines 6 thru 18)	30,266,763
20	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
21	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	1,252,348
22	AdministrativeAndGeneralExpenses TOTAL Administrative and General Expenses (Total of lines 19 and 21)	31,519,111

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c). Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c). In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain. Report in column (i) and (j) the total megawatthours received and delivered. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (0) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively. Footnote entries and provide explanations following all required data.
									TRANSFER OF ENERGY		REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Line No.	PaymentByCompanyOrPublicAuthority Payment By (Company of Public Authority) (Footnote Affiliation) (a)	TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName Energy Received From (Company of Public Authority) (Footnote Affiliation) (b)	TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c)	StatisticalClassificationCode Statistical Classification (d)	RateScheduleTariffNumber Ferc Rate Schedule of Tariff Number (e)	TransmissionPointOfReceipt Point of Receipt (Substation or Other Designation) (f)	TransmissionPointOfDelivery Point of Delivery (Substation or Other Designation) (g)	BillingDemand Billing Demand (MW) (h)	TransmissionOfElectricityForOthersEnergyReceived Megawatt Hours Received (i)	TransmissionOfElectricityForOthersEnergyDelivered Megawatt Hours Delivered (j)	Demand Charges ($) (k)	Energy Charges ($) (l)	Other Charges ($) (m)	RevenuesFromTransmissionOfElectricityForOthers Total Revenues ($) (k+l+m) (n)
1	MONTANA CHOICE TRANSMISSION
2	Ash Grove Cement	Energy Keepers Inc.	Ash Grove Cement	FNO	Montana OATT	Kerr	Clancy, MT	7	8,441	8,441	51,740			51,740
3	Aspen Air U.S., LLC	Talen Energy	Aspen Air Corporation	FNO	Montana OATT	Colstrip	Billings, MT	11	10,611	10,611	63,964			63,964
4	Barretts Minerals, Inc.	Energy Keepers inc.	Barretts Minerals, Inc.	FNO	Montana OATT	Kerr	Dillon, MT	6	7,642	7,642	38,138			38,138
5	Beartooth Electric Cooperative, Inc.	WAPA & Energy Keepers Inc.	Beartooth Electric Cooperative, Inc.	FNO	Montana OATT	Fort Peck & Kerr	Various in Montana	18	28,154	28,154	152,874			152,874
6	Benefis Health Systems	Energy Keepers inc.	Benefis Health Systems	FNO	Montana OATT	Kerr	Various in Montana	7	8,156	8,156	49,418			49,418
7	Big Horn County Electric Coop. Inc.	WAPA	Big Horn County Electric Coop. Inc.	FNO	Montana OATT	Various & Great Falls	Various in Montana	18	21,848	21,848	120,061			120,061
8	Bonneville Power Administration	BPA	Bonneville Power Administration	FNO	Montana OATT	BPAT.NWMT	Various in Montana	185	278,858	278,858	1,492,089			1,492,089
9	Basin Electric Power Cooperative	Morgan Stanley, Talen & WAPA	Basin Electric Power Cooperative	FNO	Montana OATT	Various in Montana	Various NWMT & WAUW	181	253,321	253,321	1,351,265			1,351,265
10	Basin Electric Power Cooperative	Basin Electric & WAPA	Basin Electric Power Cooperative	FNO	Montana OATT	Crossover	Various NWMT & WAUW	15	23,840	23,840	120,206			120,206
11	CHS, Inc.	Morgan Stanley	CHS, Inc.	FNO	Montana OATT	MATL.NWMT	Various in Montana	58	91,068	91,068	435,577			435,577
12	City of Great Falls	Energy Keepers Inc.	City of Great Falls	FNO	Montana OATT	Kerr	Various in Montana	6	4,541	4,541	24,721			24,721
13	Talen Montana, LLC	Avista Energy	Colstrip Steam Electric Station	FNO	Montana OATT	Colstrip	Nichols Pump Sub	10	6,880	6,880	38,443			38,443
14	Atlas Power, LLC	Portland General Electric	Atlas Power, LLC	FNO	Montana OATT	Colstrip	Butte, MT	75	36,314	36,314	390,159			390,159
15	Phillips 66 Company	Shell Energy	Phillips 66 Company	FNO	Montana OATT	BPAT.NWMT	Various in Montana	70	117,988	117,988	499,296			499,296
16	ExxonMobil Corporation	Talen Energy	ExxonMobil Corporation	FNO	Montana OATT	Colstrip	Billings, MT	35	68,808	68,808	263,450			263,450
17	General Mills Operations, LLC	Energy Keepers Inc.	General Mills Operations, LLC	FNO	Montana OATT	Kerr	Great Falls, MT	4	5,043	5,043	26,793			26,793
18	Great Falls Public Schools	Energy Keepers Inc.	Great Falls Public Schools	FNO	Montana OATT	Kerr	Great Falls, MT	3	2,777	2,777	14,537			14,537
19	GCC Three Forks, LLC	Energy Keepers Inc.	GCC Three Forks, LLC	FNO	Montana OATT	Kerr	Three Forks, MT	8	8,923	8,923	45,078			45,078
20	Magris Talc USA, Inc.	Energy Keepers Inc.	Magris Talc USA, Inc.	FNO	Montana OATT	Kerr	Three Forks, MT	6	7,124	7,124	37,529			37,529
21	DFA Dairy Brands Fluid, LLC	Talen Energy	DFA Dairy Brands Fluid, LLC	FNO	Montana OATT	Colstrip	Various in Montana	2	1,419	1,419	8,188			8,188
22	Calumet Refining, LLC	Talen Energy	Calumet Montana Refining Company, Inc.	FNO	Montana OATT	Colstrip	Great Falls, MT	25	30,433	30,433	119,919			119,919
23	Montana Resources	Energy Keepers, Inc.	Montana Resources	FNO	Montana OATT	BPAT.NWMT & Kerr	Butte, MT	50	90,042	90,042	412,101			412,101
24	REC Silicon Company	Morgan Stanley	REC Silicon Company	FNO	Montana OATT	Hardin	Butte, MT	117	124,991	124,991	664,490			664,490
25	Roseburg Forest Products Company	Shell Energy	Roseburg Forest Products Company	FNO	Montana OATT	BPAT.NWMT	Missoula, MT	8	10,895	10,895	57,691			57,691
26	Sibanye-Stillwater	Energy Keepers Inc.	Stillwater Mining Company	FNO	Montana OATT	Kerr	Various in Montana	46	70,862	70,862	326,709			326,709
27	Town of Philipsburg	Town of Philipsburg	Town of Philipsburg	FNO	Montana OATT	Philipsburg Substation	Philipsburg, MT		192	192	997			997
28	Western Area Power Administration	WAPA	Western Area Power Administration	FNO	Montana OATT	Crossover	Various NWMT & WAUW	4	2	2	6,678			6,678
29	Montana State University - Bozeman	WAPA	Montana State University - Bozeman	FNO	Montana OATT	Fort Peck West	Great Falls, MT	4	4,806	4,806	19,326			19,326
30	Western Area Power Administration	WAPA	Malmstrom Air Force Base	FNO	Montana OATT	Fort Peck West	Great Falls, MT	4	7,336	7,336	33,610			33,610
31	MONTANA POINT-TO-POINT
32	Avista Corporation	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		1,920	1,920		8,888		8,888
33	Avista Corporation	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT		24,747	24,747		114,441		114,441
34	Avista Corporation	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT		1,830	1,830		8,473		8,473
35	Avista Corporation	NWMT	BPAT	NF	MONTANA OATT	NWMTIMBALANC	BPAT.NWMT		200	200		926		926
36	Basin Electric Power Cooperative	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	GREATFALLS		39	39		181		181
37	Basin Electric Power Cooperative	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		501	501		2,320		2,320
38	Basin Electric Power Cooperative	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	GREATFALLS		252	252		1,167		1,167
39	Basin Electric Power Cooperative	NWMT	WAUW	NF	MONTANA OATT	COLSTRIP	GREATFALLS		108	108		500		500
40	Basin Electric Power Cooperative	PPW	NWMT	NF	MONTANA OATT	MLCK	NWMT.SYSTEM		67	67		310		310
41	Basin Electric Power Cooperative	PPW	NWMT	NF	MONTANA OATT	YTP	NWMT.SYSTEM		90	90		417		417
42	Basin Electric Power Cooperative	PPW	NWMT	SFP	MONTANA OATT	BRDY	NWMT.SYSTEM		600	600		2,775		2,775
43	Basin Electric Power Cooperative	PPW	NWMT	SFP	MONTANA OATT	YTP	NWMT.SYSTEM		1,008	1,008		4,656		4,656
44	Basin Electric Power Cooperative	PPW	PPW	NF	MONTANA OATT	BRDY	MLCK		67	67		310		310
45	Basin Electric Power Cooperative	PPW	WAPA	NF	MONTANA OATT	BRDY	GREATFALLS		231	231		1,070		1,070
46	Basin Electric Power Cooperative	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		650	650		3,010		3,010
47	Basin Electric Power Cooperative	PPW	WAPA	SFP	MONTANA OATT	YTP	GREATFALLS		1,176	1,176		5,432		5,432
48	Basin Electric Power Cooperative	WAPA	NWMT	SFP	MONTANA OATT	CROSSOVER	NWMT.SYSTEM		37,881	37,881		174,495		174,495
49	Basin Electric Power Cooperative	WAPA	WAPA	LFP	MONTANA OATT	CROSSOVER	GREATFALLS	31	66,929	66,929	312,542			312,542
50	Bonneville Power Administration	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	GREATFALLS		196	196		907		907
51	Brookfield Renewable Trading and Marketing LP	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		175	175		810		810
52	Brookfield Renewable Trading and Marketing LP	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		130	130		602		602
53	ConocoPhillips	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		64	64		296		296
54	ConocoPhillips	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		88	88		407		407
55	CP Energy Marketing (US) Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		408	408		1,889		1,889
56	CP Energy Marketing (US) Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		9	9		42		42
57	CP Energy Marketing (US) Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		32,267	32,267		149,384		149,384
58	CP Energy Marketing (US) Inc.	NWMT	BPAT	SFP	MONTANA OATT	MATL.NWMT	BPAT.NWMT		1,752	1,752		8,103		8,103
59	Cycle Power Partners, LLC	NWMT	PACE	NF	MONTANA OATT	HORSESHOE	BRDY		23	23		106		106
60	Cycle Power Partners, LLC	NWMT	PACE	NF	MONTANA OATT	HORSESHOE	JEFF		9,778	9,778		45,272		45,272
61	Dynasty Power Inc.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT		40	40		185		185
62	Dynasty Power Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		20	20		93		93
63	Dynasty Power Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		570	570		2,639		2,639
64	Dynasty Power Inc.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		5,987	5,987		27,691		27,691
65	Dynasty Power Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		3,565	3,565		16,503		16,503
66	Dynasty Power Inc.	WAPA	PPW	SFP	MONTANA OATT	CROSSOVER	YTP		408	408		1,887		1,887
67	EDF Trading North America, LLC	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		1,752	1,752		8,112		8,112
68	EDF Trading North America, LLC	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT		25	25
69	EDF Trading North America, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	COLSTRIP		699	699		3,236		3,236
70	EDF Trading North America, LLC	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		874	874		4,047		4,047
71	EDF Trading North America, LLC	NWMT	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		842	842		3,898		3,898
72	EDF Trading North America, LLC	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		14,614	14,614		67,655		67,655
73	EDF Trading North America, LLC	NWMT	BPAT	SFP	MONTANA OATT	COLSTRIP	BPAT.NWMT		600	600		2,775		2,775
74	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	COLSTRIP		702	702		3,250		3,250
75	EDF Trading North America, LLC	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	MATL.NWMT		156	156		722		722
76	EDF Trading North America, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY		7,616	7,616		35,251		35,251
77	EDF Trading North America, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	JEFF		810	810		3,750		3,750
78	EDF Trading North America, LLC	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP		40	40		185		185
79	EDF Trading North America, LLC	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	BRDY		5,160	5,160		23,865		23,865
80	EDF Trading North America, LLC	NWMT	PPW	SFP	MONTANA OATT	COLSTRIP	JEFF		3,504	3,504		16,206		16,206
81	EDF Trading North America, LLC	NWMT	WAPA	NF	MONTANA OATT	COLSTRIP	CROSSOVER		40	40		185		185
82	Energy Keepers Inc.	NWMT	AVA	SFP	MONTANA OATT	KERR	AVAT.NWMT		1,080	1,080		4,995		4,995
83	Energy Keepers Inc.	NWMT	BPAT	LFP	MONTANA OATT	KERR	BPAT.NWMT	40	86,360	86,360	403,280			403,280
84	Energy Keepers Inc.	NWMT	BPAT	NF	MONTANA OATT	KERR	BPAT.NWMT		42	42		194		194
85	Energy Keepers Inc.	NWMT	BPAT	SFP	MONTANA OATT	COLSTRIP	BPAT.NWMT		1,800	1,800		8,325		8,325
86	Energy Keepers Inc.	NWMT	BPAT	SFP	MONTANA OATT	KERR	BPAT.NWMT		9	9
87	Energy Keepers Inc.	NWMT	PACE	LFP	MONTANA OATT	KERR	BRDY	50	107,950	107,950	504,100			504,100
88	Energy Keepers Inc.	NWMT	PACE	NF	MONTANA OATT	KERR	BRDY		234	234		1,083		1,083
89	Energy Keepers Inc.	NWMT	PACE	SFP	MONTANA OATT	KERR	BRDY		7,848	7,848		36,261		36,261
90	Guzman Energy, LLC	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		36	36		167		167
91	Guzman Energy, LLC	PPW	AVA	SFP	MONTANA OATT	YTP	AVAT.NWMT		160,175	160,175		756,225		756,225
92	Guzman Energy, LLC	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		53,995	53,995		252,075		252,075
93	Guzman Energy, LLC	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		160	160		741		741
94	Guzman Energy, LLC	WAPA	BPAT	NF	MONTANA OATT	GREATFALLS	BPAT.NWMT		1	1		5		5
95	Guzman Energy, LLC	WAPA	BPAT	SFP	MONTANA OATT	CROSSOVER	BPAT.NWMT		6,048	6,048		27,936		27,936
96	Guzman Energy, LLC	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		1,640	1,640		7,593		7,593
97	Macquarie Energy, LLC	BPAT	AVA	SFP	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		33,600	33,600		168,050		168,050
98	Macquarie Energy, LLC	NWMT	AVA	NF	MONTANA OATT	JUDITHGAP	AVAT.NWMT		216	216		999		999
99	Macquarie Energy, LLC	PPW	AVA	SFP	MONTANA OATT	BRDY	AVAT.NWMT		600	600		2,775		2,775
100	Macquarie Energy, LLC	PPW	AVA	SFP	MONTANA OATT	YTP	AVAT.NWMT		138,986	138,986		652,034		652,034
101	Macquarie Energy, LLC	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		191	191		884		884
102	Macquarie Energy, LLC	PPW	BPAT	SFP	MONTANA OATT	BRDY	BPAT.NWMT		600	600		2,775		2,775
103	Macquarie Energy, LLC	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		18,625	18,625		84,025		84,025
104	Macquarie Energy, LLC	PPW	PPW	NF	MONTANA OATT	YTP	BRDY		1	1		5		5
105	Macquarie Energy, LLC	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		105	105		486		486
106	Macquarie Energy, LLC	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		147	147		681		681
107	MAG Energy Solutions	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		83	83		384		384
108	MAG Energy Solutions	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		2	2		9		9
109	MAG Energy Solutions	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY		42,489	42,489		195,694		195,694
110	MAG Energy Solutions	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	JEFF		3,192	3,192		14,779		14,779
111	MAG Energy Solutions	NWMT	PACE	SFP	MONTANA OATT	MATL.NWMT	BRDY		7,551	7,551		34,607		34,607
112	MAG Energy Solutions	NWMT	PACE	SFP	MONTANA OATT	MATL.NWMT	JEFF		1,089	1,089		4,989		4,989
113	MAG Energy Solutions	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT		134	134		620		620
114	MAG Energy Solutions	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	BRDY		3,730	3,730		17,253		17,253
115	MAG Energy Solutions	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		140	140		648		648
116	Mercuria Energy America, LLC	WAPA	BPAT	NF	MONTANA OATT	GREATFALLS	BPAT.NWMT		5,306	5,306		24,561		24,561
117	Mercuria Energy America, LLC	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	BRDY		6,719	6,719		31,097		31,097
118	Morgan Stanley Capital Group, Inc.	AVA	GWA	NF	MONTANA OATT	AVAT.NWMT	GLWND1		60	60		278		278
119	Morgan Stanley Capital Group, Inc.	AVA	NWMT	NF	MONTANA OATT	AVAT.NWMT	MATL.NWMT		3,297	3,297		15,273		15,273
120	Morgan Stanley Capital Group, Inc.	AVA	NWMT	SFP	MONTANA OATT	AVAT.NWMT	MATL.NWMT		4,947	4,947		22,617		22,617
121	Morgan Stanley Capital Group, Inc.	BPAT	GWA	NF	MONTANA OATT	BPAT.NWMT	GLWND1		1,234	1,234		5,713		5,713
122	Morgan Stanley Capital Group, Inc.	BPAT	GWA	NF	MONTANA OATT	BPAT.NWMT	GLWND2		587	587		2,718		2,718
123	Morgan Stanley Capital Group, Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		33,046	33,046		152,974		152,974
124	Morgan Stanley Capital Group, Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		218	218		1,009		1,009
125	Morgan Stanley Capital Group, Inc.	BPAT	NWMT	SFP	MONTANA OATT	BPAT.NWMT	MATL.NWMT		78,794	78,794		372,841		372,841
126	Morgan Stanley Capital Group, Inc.	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	JEFF		816	816		3,774		3,774
127	Morgan Stanley Capital Group, Inc.	BPAT	PPW	SFP	MONTANA OATT	BPAT.NWMT	YTP		2,400	2,400		11,100		11,100
128	Morgan Stanley Capital Group, Inc.	GWA	AVA	NF	MONTANA OATT	GLWND1	AVAT.NWMT		2,293	2,293		10,611		10,611
129	Morgan Stanley Capital Group, Inc.	GWA	AVA	NF	MONTANA OATT	GLWND2	AVAT.NWMT		1,070	1,070		4,954		4,954
130	Morgan Stanley Capital Group, Inc.	GWA	AVA	SFP	MONTANA OATT	GLWND1	AVAT.NWMT		1,296	1,296		5,994		5,994
131	Morgan Stanley Capital Group, Inc.	GWA	BPAT	NF	MONTANA OATT	GLWND1	BPAT.NWMT		59,299	59,299		274,279		274,279
132	Morgan Stanley Capital Group, Inc.	GWA	BPAT	NF	MONTANA OATT	GLWND2	BPAT.NWMT		35,257	35,257		163,061		163,061
133	Morgan Stanley Capital Group, Inc.	GWA	BPAT	SFP	MONTANA OATT	GLWND1	BPAT.NWMT		22,359	22,359		105,936		105,936
134	Morgan Stanley Capital Group, Inc.	GWA	BPAT	SFP	MONTANA OATT	GLWND2	BPAT.NWMT		16,234	16,234		76,766		76,766
135	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND1	MATL.NWMT		2,158	2,158		9,992		9,992
136	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND1	NWMT.SYSTEM		11	11		51		51
137	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND2	MATL.NWMT		211	211		977		977
138	Morgan Stanley Capital Group, Inc.	GWA	NWMT	NF	MONTANA OATT	GLWND2	NWMT.SYSTEM		5,910	5,910		27,375		27,375
139	Morgan Stanley Capital Group, Inc.	GWA	NWMT	SFP	MONTANA OATT	GLWND2	NWMT.SYSTEM		6,342	6,342		29,268		29,268
140	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND1	BRDY		271	271		1,255		1,255
141	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND1	JEFF		101	101		468		468
142	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND2	BRDY		69	69		319		319
143	Morgan Stanley Capital Group, Inc.	GWA	PPW	NF	MONTANA OATT	GLWND2	JEFF		70	70		324		324
144	Morgan Stanley Capital Group, Inc.	NWMT	AVA	NF	MONTANA OATT	HARDIN	AVAT.NWMT		4	4		19		19
145	Morgan Stanley Capital Group, Inc.	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT		6,913	6,913		32,001		32,001
146	Morgan Stanley Capital Group, Inc.	NWMT	AVA	SFP	MONTANA OATT	HARDIN	AVAT.NWMT		2,400	2,400		11,100		11,100
147	Morgan Stanley Capital Group, Inc.	NWMT	AVA	SFP	MONTANA OATT	MATL.NWMT	AVAT.NWMT		3,459	3,459		15,966		15,966
148	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		200	200		926		926
149	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	HARDIN	BPAT.NWMT		4,487	4,487		20,757		20,757
150	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	JUDITHGAP	BPAT.NWMT		50	50		232		232
151	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		125,567	125,567		580,681		580,681
152	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	SFP	MONTANA OATT	COLSTRIP	BPAT.NWMT		120	120		555		555
153	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	SFP	MONTANA OATT	HARDIN	BPAT.NWMT		4,752	4,752		21,978		21,978
154	Morgan Stanley Capital Group, Inc.	NWMT	BPAT	SFP	MONTANA OATT	MATL.NWMT	BPAT.NWMT		35,400	35,400		168,050		168,050
155	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	HARDIN	GLWND2		4	4		19		19
156	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	MATL.NWMT	GLWND1		454	454		2,102		2,102
157	Morgan Stanley Capital Group, Inc.	NWMT	GWA	NF	MONTANA OATT	MATL.NWMT	GLWND2		92	92		426		426
158	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	MATL.NWMT		8,433	8,433		39,133		39,133
159	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	HARDIN	MATL.NWMT		14,007	14,007		64,836		64,836
160	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	NF	MONTANA OATT	NWMTIMBALANC	MATL.NWMT		95	95		440		440
161	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	SFP	MONTANA OATT	COLSTRIP	MATL.NWMT		1,681	1,681		7,770		7,770
162	Morgan Stanley Capital Group, Inc.	NWMT	NWMT	SFP	MONTANA OATT	HARDIN	MATL.NWMT		8,274	8,274		37,944		37,944
163	Morgan Stanley Capital Group, Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	BRDY		2,192	2,192		10,139		10,139
164	Morgan Stanley Capital Group, Inc.	NWMT	PACE	NF	MONTANA OATT	MATL.NWMT	JEFF		221	221		1,023		1,023
165	Morgan Stanley Capital Group, Inc.	NWMT	PACE	SFP	MONTANA OATT	MATL.NWMT	BRDY		1,128	1,128		5,217		5,217
166	Morgan Stanley Capital Group, Inc.	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY		400	400		1,852		1,852
167	Morgan Stanley Capital Group, Inc.	PACE	NWMT	NF	MONTANA OATT	BRDY	MATL.NWMT		100	100		463		463
168	Morgan Stanley Capital Group, Inc.	PACE	NWMT	SFP	MONTANA OATT	BRDY	MATL.NWMT		1,416	1,416		6,549		6,549
169	Morgan Stanley Capital Group, Inc.	WAPA	AVA	NF	MONTANA OATT	GREATFALLS	AVAT.NWMT		1,486	1,486		6,880		6,880
170	Morgan Stanley Capital Group, Inc.	WAPA	BPAT	NF	MONTANA OATT	GREATFALLS	BPAT.NWMT		5,334	5,334		24,696		24,696
171	Morgan Stanley Capital Group, Inc.	WAPA	PPW	NF	MONTANA OATT	GREATFALLS	BRDY		48	48		222		222
172	Morgan Stanley Capital Group, Inc.	WAUW	NWMT	NF	MONTANA OATT	CROSSOVER	MATL.NWMT		1,440	1,440		6,660		6,660
173	Morgan Stanley Capital Group, Inc.	WAUW	NWMT	NF	MONTANA OATT	GREATFALLS	MATL.NWMT		3,400	3,400		15,742		15,742
174	Morgan Stanley Capital Group, Inc.	WAUW	NWMT	SFP	MONTANA OATT	CROSSOVER	MATL.NWMT		20,905	20,905		96,450		96,450
175	Naturener Power Watch, LLC	GWA	GWA	SFP	MONTANA OATT	GLWND1	GLWND2		10,795	10,795		50,415		50,415
176	PacifiCorp	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		3,500	3,500		16,205		16,205
177	PacifiCorp	PPW	BPAT	SFP	MONTANA OATT	YTP	BPAT.NWMT		140	140
178	Portland General Electric Company	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		102	102		472		472
179	Portland General Electric Company	NWMT	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		448	448		2,074		2,074
180	Portland General Electric Company	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		5,445	5,445		25,210		25,210
181	Portland General Electric Company	NWMT	NWMT	NF	MONTANA OATT	COLSTRIP	COLSTRIP		20	20		93		93
182	Portland General Electric Company	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	BRDY		180	180		833		833
183	Portland General Electric Company	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP		1,090	1,090		5,047		5,047
184	Portland General Electric Company	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		1,775	1,775		8,218		8,218
185	Powerex Corporation	AVA	PPW	NF	MONTANA OATT	AVAT.NWMT	YTP		840	840		3,889		3,889
186	Powerex Corporation	AVA	WAPA	NF	MONTANA OATT	AVAT.NWMT	CROSSOVER		287	287		1,329		1,329
187	Powerex Corporation	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		484	484		2,241		2,241
188	Powerex Corporation	BPAT	PPW	LFP	MONTANA OATT	BPAT.NWMT	BRDY	76	164,084	164,084	766,232			766,232
189	Powerex Corporation	BPAT	PPW	LFP	MONTANA OATT	BPAT.NWMT	JEFF	71	153,289	153,289	715,822			715,822
190	Powerex Corporation	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		10,515	10,515		48,684		48,684
191	Powerex Corporation	PACE	NWMT	NF	MONTANA OATT	YTP	COLSTRIP		1,361	1,361		6,301		6,301
192	Powerex Corporation	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		209	209		968		968
193	Powerex Corporation	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		5,445	5,445		25,188		25,188
194	Powerex Corporation	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		51,390	51,390		238,304		238,304
195	Powerex Corporation	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		5,968	5,968		27,614		27,614
196	Powerex Corporation	WAPA	PPW	SFP	MONTANA OATT	CROSSOVER	YTP		624	624		2,886		2,886
197	Powerex Corporation	WAUW	NWMT	NF	MONTANA OATT	CROSSOVER	COLSTRIP		1,806	1,806		8,360		8,360
198	Public Service Company of Colorado	NWMT	PPW	NF	MONTANA OATT	COLSTRIP	YTP		250	250		1,158		1,158
199	Puget Sound Energy Marketing	AVA	AVA	NF	MONTANA OATT	COLSTRIP	AVAT.NWMT		40	40		185		185
200	Puget Sound Energy Marketing	AVA	AVA	SFP	MONTANA OATT	COLSTRIP	AVAT.NWMT		2,208	2,208		10,212		10,212
201	Puget Sound Energy Marketing	NWMT	BPAT	NF	MONTANA OATT	COLSTRIP	BPAT.NWMT		3,941	3,941		18,233		18,233
202	Puget Sound Energy Marketing	NWMT	BPAT	SFP	MONTANA OATT	COLSTRIP	BPAT.NWMT		33,540	33,540		159,686		159,686
203	Rainbow Electric Marketing Corp.	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		9,992	9,992		46,219		46,219
204	Rainbow Electric Marketing Corp.	PPW	PPW	NF	MONTANA OATT	YTP	JEFF		30	30		139		139
205	Rainbow Electric Marketing Corp.	PPW	WAPA	NF	MONTANA OATT	BRDY	CROSSOVER		29	29		134		134
206	Rainbow Electric Marketing Corp.	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		1,532	1,532		7,093		7,093
207	Rainbow Electric Marketing Corp.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		1,111	1,111		5,141		5,141
208	Rainbow Electric Marketing Corp.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		20,561	20,561		95,149		95,149
209	Rainbow Electric Marketing Corp.	WAPA	PPW	SFP	MONTANA OATT	CROSSOVER	YTP		696	696		3,219		3,219
210	Shell Energy North America	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	MATL.NWMT		126	126		583		583
211	Shell Energy North America	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	BRDY		58	58		269		269
212	Shell Energy North America	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		20	20		93		93
213	Shell Energy North America	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		416	416		1,926		1,926
214	Shell Energy North America	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		250	250		1,158		1,158
215	Shell Energy North America	NWMT	NWMT	NF	MONTANA OATT	BGI	GTFALLSNWMT		24	24		111		111
216	Shell Energy North America	NWMT	NWMT	NF	MONTANA OATT	MATL.NWMT	NWMT.SYSTEM		15	15		69		69
217	Shell Energy North America	NWMT	NWMT	NF	MONTANA OATT	SOUTHPEAK	GTFALLSNWMT		13	13		60		60
218	Shell Energy North America	NWMT	WAUW	NF	MONTANA OATT	BGI	GREATFALLS		24	24		111		111
219	Shell Energy North America	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		49	49		227		227
220	Shell Energy North America	PPW	NWMT	NF	MONTANA OATT	BRDY	NWMT.SYSTEM		1,968	1,968		9,102		9,102
221	Shell Energy North America	PPW	NWMT	SFP	MONTANA OATT	BRDY	NWMT.SYSTEM		432	432		1,998		1,998
222	Shell Energy North America	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		19	19		88		88
223	The Energy Authority	BPAT	AVA	NF	MONTANA OATT	BPAT.NWMT	AVAT.NWMT		200	200		926		926
224	The Energy Authority	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		219	219		1,014		1,014
225	The Energy Authority	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		25	25		116		116
226	The Energy Authority	PPW	BPAT	NF	MONTANA OATT	BRDY	BPAT.NWMT		3,142	3,142		14,547		14,547
227	The Energy Authority	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		407	407		1,884		1,884
228	The Energy Authority	PPW	NWMT	NF	MONTANA OATT	YTP	NWMT.SYSTEM		1	1		5		5
229	The Energy Authority	PPW	WAPA	NF	MONTANA OATT	YTP	CROSSOVER		350	350		1,621		1,621
230	The Energy Authority	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		31,756	31,756		146,984		146,984
231	The Energy Authority	WAPA	BPAT	SFP	MONTANA OATT	CROSSOVER	BPAT.NWMT		70,378	70,378		335,334		335,334
232	The Energy Authority	WAPA	NWMT	NF	MONTANA OATT	CROSSOVER	NWMT.SYSTEM		425	425		1,968		1,968
233	The Energy Authority	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		3,266	3,266		15,122		15,122
234	Transalta Energy Marketing (US) Inc.	BPAT	NWMT	NF	MONTANA OATT	BPAT.NWMT	NWMT.SYSTEM		31	31		144		144
235	Transalta Energy Marketing (US) Inc.	BPAT	PPW	NF	MONTANA OATT	BPAT.NWMT	YTP		670	670		3,102		3,102
236	Transalta Energy Marketing (US) Inc.	BPAT	WAPA	NF	MONTANA OATT	BPAT.NWMT	CROSSOVER		903	903		4,181		4,181
237	Transalta Energy Marketing (US) Inc.	NWMT	AVA	NF	MONTANA OATT	MATL.NWMT	AVAT.NWMT		134	134		620		620
238	Transalta Energy Marketing (US) Inc.	NWMT	AVA	NF	MONTANA OATT	NWMTIMBALANC	AVAT.NWMT		20	20		93		93
239	Transalta Energy Marketing (US) Inc.	NWMT	BPAT	NF	MONTANA OATT	MATL.NWMT	BPAT.NWMT		9,329	9,329		43,193		43,193
240	Transalta Energy Marketing (US) Inc.	NWMT	BPAT	SFP	MONTANA OATT	MATL.NWMT	BPAT.NWMT		1,872	1,872		8,658		8,658
241	Transalta Energy Marketing (US) Inc.	PPW	BPAT	NF	MONTANA OATT	YTP	BPAT.NWMT		3,564	3,564		16,487		16,487
242	Transalta Energy Marketing (US) Inc.	WAPA	BPAT	NF	MONTANA OATT	CROSSOVER	BPAT.NWMT		4,761	4,761		22,023		22,023
243	Transalta Energy Marketing (US) Inc.	WAPA	BPAT	SFP	MONTANA OATT	CROSSOVER	BPAT.NWMT		816	816		3,774		3,774
244	Transalta Energy Marketing (US) Inc.	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		3,943	3,943		18,254		18,254
245	Transalta Energy Marketing (US) Inc.	WAPA	PPW	SFP	MONTANA OATT	CROSSOVER	YTP		5,355	5,355		24,975		24,975
246	Western Area Power Administration	NWMT	WAPA	NF	MONTANA OATT	CANYONFERRY	CROSSOVER		69,425	69,425		321,238		321,238
247	Western Area Power Administration	WAPA	NWMT	NF	MONTANA OATT	GREATFALLS	NWMT.SYSTEM		4,318	4,318		20,166		20,166
248	Western Area Power Administration	WAPA	PPW	NF	MONTANA OATT	CROSSOVER	YTP		10,227	10,227		47,342		47,342
249	Western Area Power Administration	WAPA	PPW	SFP	MONTANA OATT	CROSSOVER	YTP		40,404	40,404		191,577		191,577
250	Western Area Power Administration	WAPA	WAPA	NF	MONTANA OATT	GREATFALLS	CROSSOVER		20,088	20,088		90,747		90,747
251	Western Area Power Administration	WAPA	WAPA	SFP	MONTANA OATT	CROSSOVER	GREATFALLS		14,170	14,170		67,220		67,220
252	Western Area Power Administration	WAPA	WAPA	SFP	MONTANA OATT	GREATFALLS	CROSSOVER		20,860	20,860		100,830		100,830
253	SOUTH DAKOTA
254	BRYANT, CITY OF	WAPA	BRYANT	LFP	VOL 2	HURON 115 KV BUS	BRYANT 25 KV		1,237	1,237	8,629			8,629
255	GROTON, CITY OF	WAPA	GROTON	LFP	VOL 2	HURON 115 KV BUS	GROTON 69 KV		5,389	5,389	321			321
256	LANGFORD, CITY OF	WAPA	LANGFORD	LFP	VOL 2	HURON 115 KV BUS	LANGFORD 12.5 KV		907	907	6,410			6,410
257	Southwest Power Pool (SPP)	SPP	Various	LFP	SCH 7	Various	Various		0				(a) 55,403	55,403
258	Southwest Power Pool (SPP)	SPP	Various	NF	SCH 8	Various	Various						(b) 36,269	36,269
259	Southwest Power Pool (SPP)	SPP	Various	FNS	SCH 9	Various	Various		0				(c) 1,467,489	1,467,489
260	Southwest Power Pool (SPP)	SPP	Various	LFP	SCH 11	Various	Various						(d) 33,005	33,005
261	Rounding							0	1	1	1			1
35	TOTAL							1,251	3,611,953	3,611,953	9,582,382	7,913,873	1,592,166	19,088,421

Name of Respondent:

NorthWestern Corporation

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

03/31/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Firm and Non-Firm Point to Point Transmission Service

(b) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Non-Firm Point to Point Transmission Service

Network Integration Transmission Service

(d) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Firm and Non-Firm Point to Point Transmission Service

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. Enter ""TOTAL"" in column (a) as the last line. Footnote entries and provide explanations following all required data.
			TRANSFER OF ENERGY		EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.	NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	TransmissionOfElectricityByOthersEnergyReceived MegaWatt Hours Received (c)	TransmissionOfElectricityByOthersEnergyDelivered MegaWatt Hours Delivered (d)	DemandChargesTransmissionOfElectricityByOthers Demand Charges ($) (e)	EnergyChargesTransmissionOfElectricityByOthers Energy Charges ($) (f)	OtherChargesTransmissionOfElectricityByOthers Other Charges ($) (g)	ChargesForTransmissionOfElectricityByOthers Total Cost of Transmission ($) (h)
1	MONTANA
2	Vigilante Elec. Coop	OLF	4,543	4,543	13,067			13,067
3	Bonneville Power Admin	OLF					(a) 871,039	871,039
4	Southwester Power Pool (MT)	FNS	29,930	29,930	902,509			902,509
5	Sun River Elect Coop	OLF	3,708	3,708	21,210			21,210
6	Supply:
7	Avista	NF	1,140	1,140		15,551		15,551
8	Bonneville Power Admin	NF	109,713	109,713		371,335		371,335
9	Idaho Power Company	NF
10	Seattle City Light	NF	2,750	2,750		4,176		4,176
11	SOUTH DAKOTA
12	East River	FNS			389			389
13	West Central Elect COOP	FNS			8,935			8,935
14	Southwest Power Pool	FNS			5,305,027			5,305,027
15	Rounding
	TOTAL		151,784	151,784	6,251,137	391,062	871,039	7,513,238

Deprec, Depl and Amort of Elec Plant (403,403.1,404,and 405) (except Amortization of Acquisition Adjustments)
Report the year to date amounts of depreciation expense, asset retirement cost depreciation, depletion and amortization, except amortization of acquisition adjustments for the accounts indicated and classified according to the plant functional groups described.
Line No.	FunctionalClassificationAxis Functional Classification (a)	DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments Depreciation Expense (Account 403) (b)	DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	AmortizationOfLimitedTermPlantOrProperty Amortization of Limited Term Electric Plant (Account 404) (d)	AmortizationOfOtherElectricPlant Amortization of Other Electric Plant (Acc 405) (e)	DepreciationAndAmortization Total (f)
1	Intangible Plant			506,238		506,238
2	Steam Production Plant	1,951,653				1,951,653
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional	2,743,155				2,743,155
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant	4,945,221		884		4,946,105
7	Transmission Plant	7,421,325		125,279		7,546,604
8	Distribution Plant	16,109,846		6,408		16,103,438
9	General Plant	3,145,095				3,145,095
10	Common Plant-Electric	1,404,934		1,764,993		3,169,927
11	TOTAL	37,721,229		2,390,986		40,112,215




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

TRANSMISSION OF ELECTRICITY BY ISO/RTOs
Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided. In column (d) report the revenue amounts as shown on bills or vouchers. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line No.	Payment Received by (Transmission Owner Name) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Total Revenue by Rate Schedule or Tariff (d)	Total Revenue (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
40	TOTAL

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line No.	Description of Item(s) (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1	Energy
2	Net Purchases (Account 555)	32,202,034
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)	28,122,918
4	Transmission Rights
5	Ancillary Services	33,310
6	Other Items (list separately)
7	Day Ahead & Real Time Admin	116,585
8	Market Monitoring & Compliance	16,655
46	TOTAL	60,491,502

Monthly Peak Loads and Energy Output
Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. Report in column (b) by month the system’s output in Megawatt hours for each month. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.	MonthAxis Month (a)	Total Monthly Energy (MWH) (b)	Monthly Non-Requirements Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak Megawatts (See Instr. 4) (d)	DayOfMonthlyPeak Monthly Peak Day of Month (e)	HourOfMonthlyPeak Monthly Peak Hour (f)
	NAME OF SYSTEM: Montana Operations
1	January
2	February
3	March
4	Total for Quarter 1
5	April
6	May
7	June
8	Total for Quarter 2
9	July
10	August
11	September
12	Total for Quarter 3	(a) 0
41	Total
	NAME OF SYSTEM: South Dakota Operations
1	January
2	February
3	March
4	Total for Quarter 1
5	April
6	May
7	June
8	Total for Quarter 2
9	July
10	August
11	September
12	Total for Quarter 3
41	Total

MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Firm Network Service for Self (e)	Firm Network Service for Others (f)	Long-Term Firm Point-to-point Reservations (g)	Other Long-Term Firm Service (h)	Short-Term Firm Point-to-point Reservation (i)	Other Service (j)
	NAME OF SYSTEM: Montana Operations
1	January	1,939	30	19	1,092	686	275	0	2,567
2	February	2,055	22	19	1,098	784	275	0	1,580
3	March	1,790	8	8	1,098	716	275	0	1,582
4	Total for Quarter 1				3,288	2,186	825	0	5,729
5	April
6	May
7	June
8	Total for Quarter 2				0	0	0	0	0
9	July
10	August
11	September
12	Total for Quarter 3				0	0	0	0	0
13	October
14	November
15	December
16	Total for Quarter 4				0	0	0	0	0
17	Total				3,288	2,186	825	0	5,729	0
	NAME OF SYSTEM: South Dakota Operations
1	January
2	February
3	March
4	Total for Quarter 1
5	April
6	May
7	June
8	Total for Quarter 2
9	July
10	August
11	September
12	Total for Quarter 3
13	October
14	November
15	December
16	Total for Quarter 4
17	Total

Monthly ISO/RTO Transmission System Peak Load
Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f). Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Import into ISO/RTO (e)	Exports from ISO/RTO (f)	Through and Out Service (g)	Network Service Usage (h)	Point-to-Point Service Usage (i)	Total Usage (j)
	NAME OF SYSTEM: South Dakota Operations
1	January	285	31	8	0	0	0	299	14	313
2	February	291	22	11	0	0	0	305	14	319
3	March	240	14	8	0	0	0	252	12	264
4	Total for Quarter 1							856	40	896
5	April									0
6	May									0
7	June									0
8	Total for Quarter 2							0	0	0
9	July									0
10	August									0
11	September									0
12	Total for Quarter 3							0	0	0
13	October									0
14	November									0
15	December									0
16	Total for Quarter 4
17	Total Year to Date/Year							856	40	896

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