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FERC FINANCIAL REPORT
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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
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Exact Legal Name of Respondent (Company) |
Year/Period of Report End of: |
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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 |
| FERC FORM NO.
REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER |
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IDENTIFICATION |
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01 Exact Legal Name of Respondent
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02 Year/ Period of Report
End of: |
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03 Previous Name and Date of Change (If name changed during year)
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04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
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05 Name of Contact Person
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06 Title of Contact Person
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07 Address of Contact Person (Street, City, State, Zip Code)
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08 Telephone of Contact Person, Including Area Code
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09 This Report is An Original / A Resubmission
(1)
☑ An Original ☐ A Resubmission |
10 Date of Report (Mo, Da, Yr)
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| Annual Corporate Officer Certification | ||||
| The undersigned officer certifies that: I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material respects to the Uniform System of Accounts. | ||||
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03 Signature
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04 Date Signed (Mo, Da, Yr)
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| 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. | ||||
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
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LIST OF SCHEDULES (Electric Utility) |
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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". |
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| Line No. |
Title of Schedule (a) |
Reference Page No. (b) |
Remarks (c) |
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ScheduleIdentificationAbstract Identification |
1 | ||
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ScheduleListOfSchedulesAbstract List of Schedules |
2 | ||
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1 |
ScheduleGeneralInformationAbstract General Information |
101 | |
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2 |
ScheduleControlOverRespondentAbstract Control Over Respondent |
102 |
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3 |
ScheduleCorporationsControlledByRespondentAbstract Corporations Controlled by Respondent |
103 | |
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4 |
ScheduleOfficersAbstract Officers |
104 | |
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5 |
ScheduleDirectorsAbstract Directors |
105 | |
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6 |
ScheduleInformationOnFormulaRatesAbstract Information on Formula Rates |
106 | |
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7 |
ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Year |
108 | |
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8 |
ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet |
110 | |
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9 |
ScheduleStatementOfIncomeAbstract Statement of Income for the Year |
114 | |
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10 |
ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Year |
118 | |
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12 |
ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows |
120 | |
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12 |
ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements |
122 | |
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13 |
ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Other Comp Income, Comp Income, and Hedging Activities |
122a | |
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14 |
ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep |
200 | |
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15 |
ScheduleNuclearFuelMaterialsAbstract Nuclear Fuel Materials |
202 |
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16 |
ScheduleElectricPlantInServiceAbstract Electric Plant in Service |
204 | |
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17 |
ScheduleElectricPropertyLeasedToOthersAbstract Electric Plant Leased to Others |
213 |
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18 |
ScheduleElectricPlantHeldForFutureUseAbstract Electric Plant Held for Future Use |
214 | |
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19 |
ScheduleConstructionWorkInProgressElectricAbstract Construction Work in Progress-Electric |
216 | |
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20 |
ScheduleAccumulatedProvisionForDepreciationOfElectricUtilityPlantAbstract Accumulated Provision for Depreciation of Electric Utility Plant |
219 | |
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21 |
ScheduleInvestmentsInSubsidiaryCompaniesAbstract Investment of Subsidiary Companies |
224 | |
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22 |
ScheduleMaterialsAndSuppliesAbstract Materials and Supplies |
227 | |
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23 |
ScheduleAllowanceInventoryAbstract Allowances |
228 | |
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24 |
ScheduleExtraordinaryPropertyLossesAbstract Extraordinary Property Losses |
230a |
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25 |
ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract Unrecovered Plant and Regulatory Study Costs |
230b |
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26 |
ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract Transmission Service and Generation Interconnection Study Costs |
231 | |
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27 |
ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets |
232 | |
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28 |
ScheduleMiscellaneousDeferredDebitsAbstract Miscellaneous Deferred Debits |
233 | |
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29 |
ScheduleAccumulatedDeferredIncomeTaxesAbstract Accumulated Deferred Income Taxes |
234 | |
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30 |
ScheduleCapitalStockAbstract Capital Stock |
250 | |
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31 |
ScheduleOtherPaidInCapitalAbstract Other Paid-in Capital |
253 | |
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32 |
ScheduleCapitalStockExpenseAbstract Capital Stock Expense |
254b |
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33 |
ScheduleLongTermDebtAbstract Long-Term Debt |
256 | |
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34 |
ScheduleReconciliationOfReportedNetIncomeWithTaxableIncomeForFederalIncomeTaxesAbstract Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax |
261 | |
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35 |
ScheduleTaxesAccruedPrepaidAndChargedDuringYearDistributionOfTaxesChargedAbstract Taxes Accrued, Prepaid and Charged During the Year |
262 | |
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36 |
ScheduleAccumulatedDeferredInvestmentTaxCreditsAbstract Accumulated Deferred Investment Tax Credits |
266 | |
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37 |
ScheduleOtherDeferredCreditsAbstract Other Deferred Credits |
269 | |
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38 |
ScheduleAccumulatedDeferredIncomeTaxesAcceleratedAmortizationPropertyAbstract Accumulated Deferred Income Taxes-Accelerated Amortization Property |
272 |
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39 |
ScheduleAccumulatedDeferredIncomeTaxesOtherPropertyAbstract Accumulated Deferred Income Taxes-Other Property |
274 | |
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40 |
ScheduleAccumulatedDeferredIncomeTaxesOtherAbstract Accumulated Deferred Income Taxes-Other |
276 | |
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41 |
ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities |
278 | |
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42 |
ScheduleElectricOperatingRevenuesAbstract Electric Operating Revenues |
300 | |
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43 |
ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1) |
302 |
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44 |
ScheduleSalesOfElectricityByRateSchedulesAbstract Sales of Electricity by Rate Schedules |
304 | |
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45 |
ScheduleSalesForResaleAbstract Sales for Resale |
310 | |
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46 |
ScheduleElectricOperationsAndMaintenanceExpensesAbstract Electric Operation and Maintenance Expenses |
320 | |
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47 |
SchedulePurchasedPowerAbstract Purchased Power |
326 | |
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48 |
ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others |
328 | |
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49 |
ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs |
331 |
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50 |
ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others |
332 | |
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51 |
ScheduleMiscellaneousGeneralExpensesAbstract Miscellaneous General Expenses-Electric |
335 | |
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52 |
ScheduleDepreciationDepletionAndAmortizationAbstract Depreciation and Amortization of Electric Plant (Account 403, 404, 405) |
336 | |
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53 |
ScheduleRegulatoryCommissionExpensesAbstract Regulatory Commission Expenses |
350 | |
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54 |
ScheduleResearchDevelopmentOrDemonstrationExpendituresAbstract Research, Development and Demonstration Activities |
352 |
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55 |
ScheduleDistributionOfSalariesAndWagesAbstract Distribution of Salaries and Wages |
354 | |
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56 |
ScheduleCommonUtilityPlantAndExpensesAbstract Common Utility Plant and Expenses |
356 | |
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57 |
ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts included in ISO/RTO Settlement Statements |
397 | |
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58 |
SchedulePurchasesSalesOfAncillaryServicesAbstract Purchase and Sale of Ancillary Services |
398 | |
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59 |
ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load |
400 | |
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60 |
ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load |
400a | |
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61 |
ScheduleElectricEnergyAccountAbstract Electric Energy Account |
401a | |
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62 |
ScheduleMonthlyPeakAndOutputAbstract Monthly Peaks and Output |
401b | |
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63 |
ScheduleSteamElectricGeneratingPlantStatisticsAbstract Steam Electric Generating Plant Statistics |
402 | |
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64 |
ScheduleHydroelectricGeneratingPlantStatisticsAbstract Hydroelectric Generating Plant Statistics |
406 | |
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65 |
SchedulePumpedStorageGeneratingPlantStatisticsAbstract Pumped Storage Generating Plant Statistics |
408 |
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66 |
ScheduleGeneratingPlantStatisticsAbstract Generating Plant Statistics Pages |
410 | |
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ScheduleEnergyStorageOperationsLargePlantsAbstract Energy Storage Operations (Large Plants) |
414 |
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67 |
ScheduleTransmissionLineStatisticsAbstract Transmission Line Statistics Pages |
422 | |
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68 |
ScheduleTransmissionLinesAddedAbstract Transmission Lines Added During Year |
424 |
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69 |
ScheduleSubstationsAbstract Substations |
426 | |
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70 |
ScheduleTransactionsWithAssociatedAffiliatedCompaniesAbstract Transactions with Associated (Affiliated) Companies |
429 | |
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71 |
FootnoteDataAbstract Footnote Data |
450 | |
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StockholdersReportsAbstract Stockholders' Reports (check appropriate box) |
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Stockholders' Reports Check appropriate box:
☑ Two copies will be submitted ☐ No annual report to stockholders is prepared |
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
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GENERAL INFORMATION |
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1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general corporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the general corporate books are kept.
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2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized.
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3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased.
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4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated.
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5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant for your previous year's certified financial statements?
(1)
☐ Yes
(2)
☑ No |
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
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CONTROL OVER RESPONDENT |
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1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the respondent at the end of the year, state name of controlling corporation or organization, manner in which control was held, and extent of control. If control was in a holding company organization, show the chain of ownership or control to the main parent company or organization. If control was held by a trustee(s), state name of trustee(s), name of beneficiary or beneficiaries for whom trust was maintained, and purpose of the trust. |
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
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CORPORATIONS CONTROLLED BY RESPONDENT |
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| Line No. |
NameOfCompanyControlledByRespondent Name of Company Controlled (a) |
CompanyControlledByRespondentKindOfBusinessDescription Kind of Business (b) |
VotingStockOwnedByRespondentPercentage Percent Voting Stock Owned (c) |
FootnoteReferences Footnote Ref. (d) |
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
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OFFICERS |
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| Line No. |
OfficerTitle Title (a) |
OfficerName Name of Officer (b) |
OfficerSalary Salary for Year (c) |
DateOfficerIncumbencyStarted Date Started in Period (d) |
DateOfficerIncumbencyEnded Date Ended in Period (e) |
| 1 | (a) |
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| 2 | (b) |
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| 3 | (c) |
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
| FOOTNOTE DATA |
| (a) Concept: OfficerTitle |
| (b) Concept: OfficerTitle |
| (c) Concept: OfficerTitle |
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
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DIRECTORS |
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| Line No. |
NameAndTitleOfDirector Name (and Title) of Director (a) |
PrincipalBusinessAddress Principal Business Address (b) |
MemberOfTheExecutiveCommittee Member of the Executive Committee (c) |
ChairmanOfTheExecutiveCommittee Chairman of the Executive Committee (d) |
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| 9 | (a) |
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| 10 | (b) |
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
| FOOTNOTE DATA |
| (a) Concept: NameAndTitleOfDirector |
| (b) Concept: NameAndTitleOfDirector |
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
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INFORMATION ON FORMULA RATES |
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Does the respondent have formula rates? |
☑ Yes ☐ No |
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| Line No. |
RateScheduleTariffNumber FERC Rate Schedule or Tariff Number (a) |
ProceedingDocketNumber FERC Proceeding (b) |
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding |
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Does the respondent file with the Commission annual (or more frequent) filings containing the inputs to the formula rate(s)? |
☑ Yes ☐ No |
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| Line No. |
AccessionNumber Accession No. (a) |
DocumentDate Document Date / Filed Date (b) |
DocketNumber Docket No. (c) |
DescriptionOfFiling Description (d) |
RateScheduleTariffNumber Formula Rate FERC Rate Schedule Number or Tariff Number (e) |
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
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INFORMATION ON FORMULA RATES - Formula Rate Variances |
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| Line No. |
PageNumberOfFormulaRateVariances Page No(s). (a) |
ScheduleOfFormulaRateVariances Schedule (b) |
ColumnOfFormulaRateVariances Column (c) |
LineNumberOfFormulaRateVariances Line No. (d) |
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
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IMPORTANT CHANGES DURING THE QUARTER/YEAR |
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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.
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
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COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) |
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| 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) |
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1 |
UtilityPlantAbstract UTILITY PLANT |
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2 |
UtilityPlant Utility Plant (101-106, 114) |
200 |
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3 |
ConstructionWorkInProgress Construction Work in Progress (107) |
200 |
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4 |
UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3) |
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5 |
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) |
200 |
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6 |
UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5) |
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7 |
NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1) |
202 |
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8 |
NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly Nuclear Fuel Materials and Assemblies-Stock Account (120.2) |
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9 |
NuclearFuelAssembliesInReactorMajorOnly Nuclear Fuel Assemblies in Reactor (120.3) |
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10 |
SpentNuclearFuelMajorOnly Spent Nuclear Fuel (120.4) |
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11 |
NuclearFuelUnderCapitalLeases Nuclear Fuel Under Capital Leases (120.6) |
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12 |
AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) |
202 |
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13 |
NuclearFuelNet Net Nuclear Fuel (Enter Total of lines 7-11 less 12) |
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14 |
UtilityPlantAndNuclearFuelNet Net Utility Plant (Enter Total of lines 6 and 13) |
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15 |
OtherElectricPlantAdjustments Utility Plant Adjustments (116) |
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16 |
GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117) |
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17 |
OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS |
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18 |
NonutilityProperty Nonutility Property (121) |
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19 |
AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122) |
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20 |
InvestmentInAssociatedCompanies Investments in Associated Companies (123) |
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21 |
InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1) |
224 |
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23 |
NoncurrentPortionOfAllowances Noncurrent Portion of Allowances |
228 |
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24 |
OtherInvestments Other Investments (124) |
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25 |
SinkingFunds Sinking Funds (125) |
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26 |
DepreciationFund Depreciation Fund (126) |
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27 |
AmortizationFundFederal Amortization Fund - Federal (127) |
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28 |
OtherSpecialFunds Other Special Funds (128) |
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29 |
SpecialFunds Special Funds (Non Major Only) (129) |
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30 |
DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175) |
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31 |
DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176) |
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32 |
OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31) |
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33 |
CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS |
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34 |
CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130) |
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35 |
Cash Cash (131) |
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36 |
SpecialDeposits Special Deposits (132-134) |
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37 |
WorkingFunds Working Fund (135) |
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38 |
TemporaryCashInvestments Temporary Cash Investments (136) |
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39 |
NotesReceivable Notes Receivable (141) |
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40 |
CustomerAccountsReceivable Customer Accounts Receivable (142) |
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41 |
OtherAccountsReceivable Other Accounts Receivable (143) |
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42 |
AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) |
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43 |
NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145) |
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44 |
AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146) |
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45 |
FuelStock Fuel Stock (151) |
227 |
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46 |
FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152) |
227 |
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47 |
Residuals Residuals (Elec) and Extracted Products (153) |
227 |
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48 |
PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154) |
227 |
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49 |
Merchandise Merchandise (155) |
227 |
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50 |
OtherMaterialsAndSupplies Other Materials and Supplies (156) |
227 |
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51 |
NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157) |
202/227 |
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52 |
AllowanceInventoryAndWithheld Allowances (158.1 and 158.2) |
228 |
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53 |
NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances |
228 |
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54 |
StoresExpenseUndistributed Stores Expense Undistributed (163) |
227 |
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55 |
GasStoredCurrent Gas Stored Underground - Current (164.1) |
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56 |
LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) |
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57 |
Prepayments Prepayments (165) |
(a) |
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58 |
AdvancesForGas Advances for Gas (166-167) |
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59 |
InterestAndDividendsReceivable Interest and Dividends Receivable (171) |
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60 |
RentsReceivable Rents Receivable (172) |
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61 |
AccruedUtilityRevenues Accrued Utility Revenues (173) |
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62 |
MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174) |
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63 |
DerivativeInstrumentAssets Derivative Instrument Assets (175) |
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|
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) |
|
|
|
|
68 |
DeferredDebitsAbstract DEFERRED DEBITS |
|||
|
69 |
UnamortizedDebtExpense Unamortized Debt Expenses (181) |
|
|
|
|
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 |
|
|
|
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) |
|
|
|
|
77 |
TemporaryFacilities Temporary Facilities (185) |
|||
|
78 |
MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186) |
233 |
|
|
|
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) |
|
|
|
82 |
AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190) |
234 |
|
|
|
83 |
UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191) |
|
|
|
|
84 |
DeferredDebits Total Deferred Debits (lines 69 through 83) |
|
|
|
|
85 |
AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84) |
|
|
|
|
Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
| FOOTNOTE DATA |
| (a) Concept: Prepayments |
South Dakota Operations Prepayments (165) are $14,201,612 and $12,840,333 for 2021 and 2020, respectively.
Montana Operations Prepayments (165) are $8,488,780 and $2,535,118 for 2021 and 2020, respectively.
|
| (b) Concept: UnamortizedLossOnReacquiredDebt |
|
Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
|
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS) |
||||
| Line No. |
Title of Account (a) |
Ref. Page No. (b) |
Current Year End of Quarter/Year Balance (c) |
Prior Year End Balance 12/31 (d) |
|
1 |
ProprietaryCapitalAbstract PROPRIETARY CAPITAL |
|||
|
2 |
CommonStockIssued Common Stock Issued (201) |
250 |
|
|
|
3 |
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 |
|
|
|
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 |
|
|
|
12 |
UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1) |
118 |
|
|
|
13 |
ReacquiredCapitalStock (Less) Reaquired Capital Stock (217) |
250 |
|
|
|
14 |
NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218) |
|||
|
15 |
AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219) |
122(a)(b) |
|
|
|
16 |
ProprietaryCapital Total Proprietary Capital (lines 2 through 15) |
|
|
|
|
17 |
LongTermDebtAbstract LONG-TERM DEBT |
|||
|
18 |
Bonds Bonds (221) |
256 |
|
|
|
19 |
ReacquiredBonds (Less) Reaquired Bonds (222) |
256 |
||
|
20 |
AdvancesFromAssociatedCompanies Advances from Associated Companies (223) |
256 |
||
|
21 |
OtherLongTermDebt Other Long-Term Debt (224) |
256 |
|
|
|
22 |
UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225) |
|||
|
23 |
UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226) |
|
||
|
24 |
LongTermDebt Total Long-Term Debt (lines 18 through 23) |
|
|
|
|
25 |
OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES |
|||
|
26 |
ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227) |
|
|
|
|
27 |
AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1) |
|||
|
28 |
AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2) |
(a) |
|
|
|
29 |
AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3) |
(b) |
|
|
|
30 |
AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4) |
|
|
|
|
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) |
|
|
|
|
35 |
OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34) |
|
|
|
|
36 |
CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES |
|||
|
37 |
NotesPayable Notes Payable (231) |
|
||
|
38 |
AccountsPayable Accounts Payable (232) |
(c) |
|
|
|
39 |
NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233) |
|||
|
40 |
AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234) |
|
|
|
|
41 |
CustomerDeposits Customer Deposits (235) |
|
|
|
|
42 |
TaxesAccrued Taxes Accrued (236) |
262 |
(d) |
|
|
43 |
InterestAccrued Interest Accrued (237) |
|
|
|
|
44 |
DividendsDeclared Dividends Declared (238) |
|||
|
45 |
MaturedLongTermDebt Matured Long-Term Debt (239) |
|||
|
46 |
MaturedInterest Matured Interest (240) |
|||
|
47 |
TaxCollectionsPayable Tax Collections Payable (241) |
|
|
|
|
48 |
MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242) |
(e) |
|
|
|
49 |
ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243) |
|
|
|
|
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) |
|
|
|
|
55 |
DeferredCreditsAbstract DEFERRED CREDITS |
|||
|
56 |
CustomerAdvancesForConstruction Customer Advances for Construction (252) |
(f) |
|
|
|
57 |
AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255) |
266 |
|
|
|
58 |
DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256) |
|||
|
59 |
OtherDeferredCredits Other Deferred Credits (253) |
269 |
|
|
|
60 |
OtherRegulatoryLiabilities Other Regulatory Liabilities (254) |
278 |
|
|
|
61 |
UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257) |
|||
|
62 |
AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281) |
272 |
||
|
63 |
AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282) |
|
|
|
|
64 |
AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283) |
|
|
|
|
65 |
DeferredCredits Total Deferred Credits (lines 56 through 64) |
|
|
|
|
66 |
LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) |
|
|
|
|
Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
| FOOTNOTE DATA |
| (a) Concept: AccumulatedProvisionForInjuriesAndDamages |
South Dakota Operations Provision for Injuries and Damages (228.2) are $570,311 and $581,272 for 2021 and 2020, respectively.
Montana Operations Provision for Injuries and Damages (228.2) are $6,491,517 and $5,469,372 for 2021 and 2020, respectively.
|
| (b) Concept: AccumulatedProvisionForPensionsAndBenefits |
| (c) Concept: AccountsPayable |
| (d) Concept: TaxesAccrued |
| (e) Concept: MiscellaneousCurrentAndAccruedLiabilities |
Montana Operations Miscellaneous Current and Accrued Liabilities (242) are $46,613,454 and $60,393,837 for 2021 and 2020, respectively.
Montana Operations unfunded reserve for Miscellaneous Current and Accrued Liabilities (242) are $19,780,351 and $17,592,544 for 2021 and 2020, respectively.
|
| (f) Concept: CustomerAdvancesForConstruction |
|
Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
|
STATEMENT OF INCOME |
|||||||||||||
|
Quarterly
Annual or Quarterly if applicable
|
|||||||||||||
| 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 |
|
|
|
|
|
|
|
|
|||
|
3 |
OperatingExpensesAbstract Operating Expenses |
||||||||||||
|
4 |
OperationExpense Operation Expenses (401) |
320 |
|
|
|
|
|
|
|
|
|||
|
5 |
MaintenanceExpense Maintenance Expenses (402) |
320 |
|
|
|
|
|
|
|
|
|||
|
6 |
DepreciationExpense Depreciation Expense (403) |
336 |
|
|
|
|
|
|
|
|
|||
|
7 |
DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1) |
336 |
|||||||||||
|
8 |
AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405) |
336 |
|
|
|
|
|
|
|||||
|
9 |
AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406) |
336 |
|
|
(b) |
|
|
|
|||||
|
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) |
|
|
|
|
|
|
||||||
|
13 |
RegulatoryCredits (Less) Regulatory Credits (407.4) |
|
|
|
|
|
|
||||||
|
14 |
TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1) |
262 |
|
|
|
|
|
|
|
|
|||
|
15 |
IncomeTaxesOperatingIncome Income Taxes - Federal (409.1) |
262 |
|
|
|
|
|
|
|||||
|
16 |
IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1) |
262 |
|
|
|
|
|||||||
|
17 |
ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1) |
234, 272 |
|
|
|
|
|
|
|
|
|||
|
18 |
ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1) |
234, 272 |
|
|
|
|
|
|
|||||
|
19 |
InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4) |
266 |
|
|
|
|
|
|
|||||
|
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) |
|
|
|
|
|
|
|
|
||||
|
27 |
NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25) |
|
|
|
|
|
|
|
|
||||
|
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) |
|
|
||||||||||
|
32 |
CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) |
|
|
||||||||||
|
33 |
RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417) |
|
|
||||||||||
|
34 |
ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1) |
|
|
||||||||||
|
35 |
NonoperatingRentalIncome Nonoperating Rental Income (418) |
||||||||||||
|
36 |
EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1) |
119 |
|
|
|||||||||
|
37 |
InterestAndDividendIncome Interest and Dividend Income (419) |
|
|
||||||||||
|
38 |
AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1) |
|
|
||||||||||
|
39 |
MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421) |
|
|
||||||||||
|
40 |
GainOnDispositionOfProperty Gain on Disposition of Property (421.1) |
||||||||||||
|
41 |
OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40) |
|
|
||||||||||
|
42 |
OtherIncomeDeductionsAbstract Other Income Deductions |
||||||||||||
|
43 |
LossOnDispositionOfProperty Loss on Disposition of Property (421.2) |
||||||||||||
|
44 |
MiscellaneousAmortization Miscellaneous Amortization (425) |
||||||||||||
|
45 |
Donations Donations (426.1) |
|
|
||||||||||
|
46 |
LifeInsurance Life Insurance (426.2) |
||||||||||||
|
47 |
Penalties Penalties (426.3) |
|
|
||||||||||
|
48 |
ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4) |
|
|
||||||||||
|
49 |
OtherDeductions Other Deductions (426.5) |
|
|
||||||||||
|
50 |
OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49) |
|
|
||||||||||
|
51 |
TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions |
||||||||||||
|
52 |
TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2) |
262 |
|
|
|||||||||
|
53 |
IncomeTaxesFederal Income Taxes-Federal (409.2) |
262 |
|
|
|||||||||
|
54 |
IncomeTaxesOther Income Taxes-Other (409.2) |
262 |
|
|
|||||||||
|
55 |
ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2) |
234, 272 |
(a) |
|
|||||||||
|
56 |
ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2) |
234, 272 |
|
|
|||||||||
|
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) |
|
|
||||||||||
|
60 |
NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59) |
|
|
||||||||||
|
61 |
InterestChargesAbstract Interest Charges |
||||||||||||
|
62 |
InterestOnLongTermDebt Interest on Long-Term Debt (427) |
|
|
||||||||||
|
63 |
AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428) |
|
|
||||||||||
|
64 |
AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1) |
|
|
||||||||||
|
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) |
|
|
||||||||||
|
69 |
AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) |
|
|
||||||||||
|
70 |
NetInterestCharges Net Interest Charges (Total of lines 62 thru 69) |
|
|
||||||||||
|
71 |
IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70) |
|
|
||||||||||
|
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) |
|
|
||||||||||
|
Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
| FOOTNOTE DATA |
| (a) Concept: ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Included in the Provision for Deferred Income Taxes, in the Statements of Income, is amortization of the excess and deficient ADIT's as follows:
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| (b) Concept: AmortizationOfElectricPlantAcquisitionAdjustments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amort. of Utility Plant Acq. Adj. of $15,948,277 consists of $14,747,883 for Montana Operations and $1,200,394 for South Dakota Operations.
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
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STATEMENT OF RETAINED EARNINGS |
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| 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) |
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UnappropriatedRetainedEarningsAbstract UNAPPROPRIATED RETAINED EARNINGS (Account 216) |
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1 |
UnappropriatedRetainedEarnings Balance-Beginning of Period |
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2 |
ChangesAbstract Changes |
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3 |
AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439) |
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4 |
AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit |
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9 |
AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439) |
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10 |
AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit |
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15 |
AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439) |
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16 |
BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1) |
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17 |
AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436) |
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22 |
AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436) |
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23 |
DividendsDeclaredPreferredStockAbstract Dividends Declared-Preferred Stock (Account 437) |
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29 |
DividendsDeclaredPreferredStock TOTAL Dividends Declared-Preferred Stock (Acct. 437) |
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30 |
DividendsDeclaredCommonStockAbstract Dividends Declared-Common Stock (Account 438) |
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30.1 |
DividendsDeclaredCommonStock |
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36 |
DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438) |
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37 |
TransfersFromUnappropriatedUndistributedSubsidiaryEarnings Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings |
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38 |
UnappropriatedRetainedEarnings Balance - End of Period (Total 1,9,15,16,22,29,36,37) |
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39 |
AppropriatedRetainedEarningsAbstract APPROPRIATED RETAINED EARNINGS (Account 215) |
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45 |
AppropriatedRetainedEarnings TOTAL Appropriated Retained Earnings (Account 215) |
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AppropriatedRetainedEarningsAmortizationReserveFederalAbstract APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1) |
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46 |
AppropriatedRetainedEarningsAmortizationReserveFederal TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1) |
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47 |
AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46) |
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48 |
RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1) |
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UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly) |
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49 |
UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit) |
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50 |
EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1) |
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51 |
DividendsReceived (Less) Dividends Received (Debit) |
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52 |
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year |
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53 |
UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52) |
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
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STATEMENT OF CASH FLOWS |
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| 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) |
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1 |
NetCashFlowFromOperatingActivitiesAbstract Net Cash Flow from Operating Activities |
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2 |
NetIncomeLoss Net Income (Line 78(c) on page 117) |
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3 |
NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income: |
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4 |
DepreciationAndDepletion Depreciation and Depletion |
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5 |
NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details) |
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5.1 |
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription |
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5.2 |
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription |
(a) |
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8 |
DeferredIncomeTaxesNet Deferred Income Taxes (Net) |
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9 |
InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net) |
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10 |
NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables |
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11 |
NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory |
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12 |
NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory |
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13 |
NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses |
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14 |
NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets |
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15 |
NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities |
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16 |
AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction |
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17 |
UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies |
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18 |
OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote): |
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18.1 |
OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription |
(b) |
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22 |
NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21) |
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24 |
CashFlowsFromInvestmentActivitiesAbstract Cash Flows from Investment Activities: |
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25 |
ConstructionAndAcquisitionOfPlantIncludingLandAbstract Construction and Acquisition of Plant (including land): |
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26 |
GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities Gross Additions to Utility Plant (less nuclear fuel) |
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27 |
GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel |
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28 |
GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant |
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29 |
GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant |
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30 |
AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction |
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31 |
OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote): |
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34 |
CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33) |
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36 |
AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d) |
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37 |
ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d) |
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39 |
InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Investments in and Advances to Assoc. and Subsidiary Companies |
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40 |
ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies Contributions and Advances from Assoc. and Subsidiary Companies |
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41 |
DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract Disposition of Investments in (and Advances to) |
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42 |
DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Disposition of Investments in (and Advances to) Associated and Subsidiary Companies |
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44 |
PurchaseOfInvestmentSecurities Purchase of Investment Securities (a) |
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45 |
ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a) |
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46 |
LoansMadeOrPurchased Loans Made or Purchased |
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47 |
CollectionsOnLoans Collections on Loans |
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49 |
NetIncreaseDecreaseInReceivablesInvestingActivities Net (Increase) Decrease in Receivables |
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50 |
NetIncreaseDecreaseInInventoryInvestingActivities Net (Increase) Decrease in Inventory |
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51 |
NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities Net (Increase) Decrease in Allowances Held for Speculation |
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52 |
NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities Net Increase (Decrease) in Payables and Accrued Expenses |
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53 |
OtherAdjustmentsToCashFlowsFromInvestmentActivities Other (provide details in footnote): |
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53.1 |
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription |
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57 |
CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55) |
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59 |
CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities: |
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60 |
ProceedsFromIssuanceAbstract Proceeds from Issuance of: |
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61 |
ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b) |
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62 |
ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock |
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63 |
ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock |
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64 |
OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote): |
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64.1 |
OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription |
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66 |
NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c) |
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67 |
OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote): |
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67.1 |
DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities |
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70 |
CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69) |
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72 |
PaymentsForRetirementAbstract Payments for Retirement of: |
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73 |
PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b) |
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74 |
PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock |
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75 |
PaymentsForRetirementOfCommonStockFinancingActivities Common Stock |
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76 |
OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote): |
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76.1 |
DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities |
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76.2 |
DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities |
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78 |
NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c) |
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80 |
DividendsOnPreferredStock Dividends on Preferred Stock |
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81 |
DividendsOnCommonStock Dividends on Common Stock |
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83 |
CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81) |
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85 |
NetIncreaseDecreaseInCashAndCashEquivalentsAbstract Net Increase (Decrease) in Cash and Cash Equivalents |
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86 |
NetIncreaseDecreaseInCashAndCashEquivalents Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83) |
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88 |
CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period |
(c) |
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90 |
CashAndCashEquivalents Cash and Cash Equivalents at End of Period |
(d) |
(e) |
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
| FOOTNOTE DATA |
| (a) Concept: NoncashAdjustmentsToCashFlowsFromOperatingActivities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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| (b) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (c) Concept: CashAndCashEquivalents | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The following table provides a reconciliation of cash, cash equivalents, other special funds, and other special deposits reported within the Balance Sheets that sum to the total cash and cash equivalents amounts reflected in the Statement of Cash Flows:
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| (d) Concept: CashAndCashEquivalents | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (e) Concept: CashAndCashEquivalents | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The following table provides a reconciliation of cash, cash equivalents, other special funds, and other special deposits reported within the Balance Sheets that sum to the total cash and cash equivalents amounts reflected in the Statement of Cash Flows:
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
|
NOTES TO FINANCIAL STATEMENTS |
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NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and / or natural gas to approximately 753,600 customers in Montana, South Dakota, Nebraska and Yellowstone National Park. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have generated and distributed electricity and distributed natural gas in Montana since 2002. The Financial Statements for the periods included herein have been prepared by NorthWestern Corporation (NorthWestern, we or us), pursuant to the rules and regulations of the Federal Energy Regulatory Commission (FERC) as set forth in its applicable Uniform System of Accounts and published accounting releases. The preparation of financial statements in conformity with the accounting requirements of the FERC as set forth in its applicable Uniform System of Accounts and published accounting releases requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. Management has evaluated the impact of events occurring after December 31, 2021 up to February 11, 2022, the date that NorthWestern's financial statements prepared in accordance with the accounting principles generally accepted in the United States of America (GAAP) were issued, and has updated such evaluation for disclosure purposes through March 4, 2022. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.
Financial Statement Presentation The financial statements are presented on the basis of the accounting requirements of the FERC as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than GAAP. This report differs from GAAP due to FERC requiring the presentation of subsidiaries on the equity method of accounting, which differs from Accounting Standards Codification (ASC) 810, Consolidation. ASC 810 requires that all majority-owned subsidiaries be consolidated (see Note 4). The other significant differences consist of the following: •Earnings per share and footnotes for revenue from contracts with customers, segment and related information, and quarterly financial data (unaudited) are not presented; •Removal and decommissioning costs of generation, transmission and distribution assets are reflected in the Balance Sheets as a component of accumulated depreciation of $479.3 million and $464.7 million as of December 31, 2021 and December 31, 2020, respectively, in accordance with regulatory treatment as compared to regulatory liabilities for GAAP purposes; •Goodwill is reflected in the Balance Sheets as a utility plant adjustments of $357.6 million as of December 31, 2021 and December 31, 2020, respectively, in accordance with regulatory treatment, as compared to goodwill for GAAP purposes (see Note 8); •The write-down of plant values associated with the 2002 acquisition of the Montana operations is reflected in the Balance Sheets as a component of accumulated depreciation of $147.6 million for December 31, 2021 and December 31, 2020, respectively, in accordance with regulatory treatment as compared to plant for GAAP purposes; •The current portion of gas stored underground is reflected in the Balance Sheets as current and accrued assets, as compared to inventory for GAAP purposes; •Operating lease right of use assets are reflected in the Balance Sheets as capital leases of $2.1 million and $2.9 million as of December 31, 2021 and December 31, 2020, respectfully, in accordance with regulatory treatment, as compared to non-current assets for GAAP purposes; •Operating lease liabilities are reflected in the Balance Sheets as current and long term obligations under capital leases of $2.1 million and $2.9 million as of December 31, 2021 and December 31, 2020, respectfully, in accordance with regulatory treatment, as compared to accrued expenses and long term liabilities for GAAP purposes; •Unamortized debt expense is classified in the Balance Sheets as deferred debits in accordance with regulatory treatment, as compared to long-term debt for GAAP purposes; •Current and long-term debt is classified in the Balance Sheets as all long-term debt in accordance with regulatory treatment, while current and long-term debt are presented separately for GAAP reporting; •The current portion of the provision for injuries and damages and the expected insurance proceeds receivable related to the provision for injuries and damages are reported as a current liability for GAAP purposes, as compared to a non-current liability for FERC purposes; •Accumulated deferred tax assets and liabilities are classified in the Balance Sheets as gross non-current deferred debits and credits, respectively, while GAAP presentation reflects a net non-current deferred tax liability; •Stranded tax effects associated with the Tax Cuts and Jobs Act are included in accumulated other comprehensive income (AOCI) in accordance with regulatory treatment, while included in retained earnings for GAAP purposes; •Uncertain tax positions related to temporary differences are classified in the Balance Sheets within the deferred tax accounts in accordance with regulatory treatment, as compared to other noncurrent liabilities for GAAP purposes. In addition, interest related to uncertain tax positions is recognized in interest expense in accordance with regulatory treatment, as compared to income tax expense for GAAP purposes; •Net periodic benefit costs and net periodic post retirement benefit costs are reflected in operating expense for FERC purposes, as compared to the GAAP presentation, which reflects the current service costs component of the net periodic benefit costs in operating expenses and the other components outside of income from operations. In addition, only the service cost component of net periodic benefit cost is eligible for capitalization for GAAP purposes, as compared to the total net periodic benefit costs for FERC purposes; •Regulatory assets and liabilities are reflected in the Balance Sheets as non-current items, while current and non-current amounts are presented separately for GAAP; •Unbilled revenue is reflected in the Balance Sheets in Accrued utility revenues in accordance with regulatory treatment, as compared to Accounts receivable, net for GAAP purposes; •Implementation costs associated with cloud computing arrangements are reflected on the Balance Sheets as Miscellaneous Intangible Plant in accordance with regulatory treatment, as compared to Other current assets for GAAP purposes. Additionally, these cash outflows are presented within investing activities cash outflows in the Statement of Cash Flows in accordance with regulatory treatment, as compared to operating activities cash outflows for GAAP purposes; and •GAAP revenue differs from FERC revenue primarily due to the equity method of accounting as discussed above, netting of electric purchases and sales for resale in revenue for the GAAP presentation as compared to a gross presentation for FERC purposes (with the exception of those transactions in a regional transmission organization (RTO)), the netting of RTO transmission transactions for the GAAP presentation as compared to a gross presentation for FERC purposes, and the classification of regulatory amortizations in revenue for GAAP purposes as compared to expense for FERC purposes. The following table reconciles GAAP revenues to FERC revenues by segment for the twelve months ended December 31, 2021 and 2020 (in millions):
Use of Estimates The preparation of financial statements in conformity with the regulatory basis of accounting requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Financial Statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for such items as long-lived asset values and impairment charges, long-lived asset useful lives, tax provisions, uncertain tax position reserves, asset retirement obligations, regulatory assets and liabilities, allowances for uncollectible accounts, our Qualifying Facilities liability, environmental liabilities, unbilled revenues and actuarially determined benefit costs and liabilities. We revise the recorded estimates when we receive better information or when we can determine actual amounts. Those revisions can affect operating results. Revenue Recognition The Company recognizes revenue as customers obtain control of promised goods and services in an amount that reflects consideration expected in exchange for those goods or services. Generally, the delivery of electricity and natural gas results in the transfer of control to customers at the time the commodity is delivered and the amount of revenue recognized is equal to the amount billed to each customer, including estimated volumes delivered when billings have not yet occurred. Cash Equivalents We consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents. Accounts Receivable, Net Accounts receivable are net of allowances for uncollectible accounts of $2.3 million and $5.6 million at December 31, 2021 and December 31, 2020. Unbilled revenues were $98.1 million and $80.5 million at December 31, 2021 and December 31, 2020, respectively. Inventories Inventories are stated at average cost. Inventory consisted of the following (in thousands):
Regulation of Utility Operations Our regulated operations are subject to the provisions of ASC 980, Regulated Operations. Regulated accounting is appropriate provided that (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise's cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be charged to and collected from customers. Our Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. The economic effects of regulation can result in regulated companies recording costs that have been, or are deemed probable to be, allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (Accumulated Provision for Rate Refunds). If we were required to terminate the application of these provisions to our regulated operations, all such deferred amounts would be recognized in the Statements of Income at that time. This would result in a charge to earnings and AOCI, net of applicable income taxes, which could be material. In addition, we would determine any impairment to the carrying costs of deregulated plant and inventory assets. Derivative Financial Instruments We account for derivative instruments in accordance with ASC 815, Derivatives and Hedging. All derivatives are recognized in the Balance Sheets at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). For fair-value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash-flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in AOCI and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For other derivative contracts that do not qualify or are not designated for hedge accounting, changes in the fair value of the derivatives are recognized in earnings each period. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Statements of Cash Flows, depending on the underlying nature of the hedged items. Revenues and expenses on contracts that are designated as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but on an accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric and gas operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the exceptions, the fair value of the related contract would be reflected as an asset or liability and immediately recognized through earnings. See Note 9 - Risk Management and Hedging Activities, for further discussion of our derivative activity. Utility Plant Utility plant stated at original cost, including contracted services, direct labor and material, allowance for funds used during construction (AFUDC), and indirect charges for engineering, supervision and similar overhead items. All expenditures for maintenance and repairs of utility plant are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal. Also included in plant and equipment are assets under finance lease, which are stated at the present value of minimum lease payments. AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to net interest charges, while the equity component is included in other income. This rate averaged 6.6% and 6.7% for Montana for 2021 and 2020, respectively. This rate averaged 6.4% and 6.7% for South Dakota for 2021 and 2020, respectively. AFUDC capitalized totaled $15.9 million and $9.8 million for the years ended December 31, 2021 and 2020, respectively, for Montana and South Dakota combined. We record provisions for depreciation at amounts substantially equivalent to calculations made on a straight-line method by applying various rates based on useful lives of the various classes of properties (ranging from 2 to 96 years) determined from engineering studies. As a percentage of the depreciable utility plant at the beginning of the year, our provision for depreciation of utility plant was approximately 2.8% for 2021 and 2020. Depreciation rates include a provision for our share of the estimated costs to decommission our jointly owned plants at the end of the useful life. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in accumulated depreciation. Pension and Postretirement Benefits We have liabilities under defined benefit retirement plans and a postretirement plan that offers certain health care and life insurance benefits to eligible employees and their dependents. The costs of these plans are dependent upon numerous factors, assumptions and estimates, including determination of discount rate, expected return on plan assets, rate of future compensation increases, age and mortality and employment periods. In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in material changes in the cost and liabilities we recognize. Income Taxes We follow the liability method in accounting for income taxes. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized. Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ from these estimates. The resolution of tax matters in a particular future period could have a material impact on our Statements of Income and provision for income taxes. Environmental Costs We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset if there is precedent for recovering similar costs from customers in rates. Otherwise, we expense the costs. If an environmental cost is related to facilities we currently use, such as pollution control equipment, then we may capitalize and depreciate the costs over the remaining life of the asset, assuming the costs are recoverable in future rates or future cash flows. Our remediation cost estimates are based on the use of an environmental consultant, our experience, our assessment of the current situation and the technology currently available for use in the remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, then we estimate and record only our share of the cost. Supplemental Cash Flow Information
(1) See Note 12 - Long-Term Debt for further information regarding these non-cash transactions. The following table provides a reconciliation of cash, working funds, other special funds, and special deposits reported within the Balance Sheets that sum to the total of the same such amounts shown in the Statements of Cash Flows (in thousands):
Other special funds and special deposits consist primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements. Accounting Standards Issued At this time, we are not expecting the adoption of recently issued accounting standards to have a material impact to our financial condition, results of operations, and cash flows.
Power Costs and Credits Adjustment Mechanism (PCCAM) - Montana We track electric supply costs for our Montana electric utility, such as purchased power and fuel, against a forecast of costs approved by the Montana Public Service Commission (MPSC). This forecast is referred to as the power costs and credits adjustment mechanism base (PCCAM Base). If our actual costs exceed the approved PCCAM Base revenues on an annual basis, we can recover 90% of the excess costs, with the non-recoverable 10% impacting net income. Our QF power purchase costs are recoverable through rates separate from the PCCAM Base. The MPSC reviews these costs annually, with NorthWestern receiving an automatic adjustment through interim rates, subject to refund, effective on October 1 of each year. During the twelve months ended December 31, 2021 we recognized $5.4 million of non-recoverable excess PCCAM supply costs, compared to $0.8 million of non-recoverable excess PCCAM supply costs for the twelve months ended December 31, 2020. The current PCCAM Base, approved in 2019, no longer reflects an accurate current forecast of our fuel and power costs. In April 2021, we filed an application with the MPSC for approval to increase the PCCAM Base by approximately $17.0 million. On June 29, 2021, the MPSC approved interim rates reflecting our request, subject to refund. On August 2, 2021, the MCC filed a motion asking the MPSC to dismiss the application arguing that the MPSC issued a Final Order in 2018 prohibiting NorthWestern from requesting an update to the PCCAM Base, except in a general rate case. NorthWestern argued that the tariff, which the MPSC approved as implementing the Final Order, allows us to file an application outside of a general rate case. On October 5, 2021, the MPSC voted to grant the MCC’s motion to dismiss. The MPSC issued the final written order on December 2, 2021, dismissing our application. As of December 31, 2021, we had deferred revenue of approximately $8.2 million, which we expect to refund in 2022, associated with these interim rates, including interest. Montana Community Renewable Energy Projects (CREPs) We were required to acquire, as of December 31, 2020, approximately 65 MW of CREPs. While we made progress towards meeting this obligation by acquiring approximately 50 MW of CREPs, we were unable to acquire the remaining MWs required for various reasons, including the fact that proposed projects fail to qualify as CREPs or do not meet the statutory cost cap. The MPSC granted us waivers for 2012 through 2016. The validity of the MPSC’s action as it related to waivers granted for 2015 and 2016 has been challenged legally and was fully briefed before the Montana Supreme Court. On May 14, 2021, the Montana Governor signed a bill that eliminated the state's Renewable Portfolio Standard, including repeal of the CREP requirement. We notified the Montana Supreme Court of the repeal. We also dismissed our pending application filed with the MPSC for a waiver from full compliance for years 2017 through 2020. On September 7, 2021, the Montana Supreme Court remanded the case challenging the 2015 and 2016 waivers to the District Court to determine whether the repeal of the CREP requirement made the petition moot. The matter has been fully briefed before the District Court. In that briefing, the Montana Environmental Information Center requested the District Court to amend its previous judgment and penalize us $2.5 million for failure to comply with the CREP requirement in 2015 and 2016. We responded to this request arguing that it was unlawful for the District Court to penalize us. We expect a decision from the District Court in the first half of 2022. If the Montana Courts and/or MPSC determine that the repeal should not be applied retroactively and find that waivers should not be granted, we could be liable for penalties. However, we do not believe any such penalties would be material. FERC Financial Audit We are subject to FERC’s jurisdiction and regulations with respect to rates for electric transmission service in interstate commerce and electricity sold at wholesale rates, the issuance of certain securities, and incurrence of certain long-term debt, among other things. The Division of Audits and Accounting in the Office of Enforcement of FERC has initiated a routine audit of NorthWestern Corporation for the period of January 1, 2018 to the present to evaluate our compliance with FERC accounting and financial reporting requirements. We have responded to several sets of data requests as part of the audit process. An audit report has not yet been received from FERC, but is expected during the first quarter of 2022. Management is unable to predict the outcome or timing of the final resolution of the audit.
The following table presents our equity investments reflected in the investments in subsidiary companies on the Balance Sheets (in thousands):
We prepare our Financial Statements in accordance with the provisions of ASC 980, as discussed in Note 2 - Significant Accounting Policies. Pursuant to this guidance, certain expenses and credits, normally reflected in income as incurred, are deferred and recognized when included in rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded based on management's assessment that it is probable that a cost will be recovered or that an obligation has been incurred. Accordingly, we have recorded the following major classifications of regulatory assets and liabilities that will be recognized in expenses and revenues in future periods when the matching revenues are collected or refunded. These regulatory items have corresponding assets and liabilities that will be paid for or refunded in future periods.
Income Taxes Flow-through income taxes primarily reflect the effects of plant related temporary differences such as flow-through of depreciation, repairs related deductions, and removal costs that we will recover or refund in future rates. We amortize these amounts as temporary differences reverse. Excess deferred income tax assets and liabilities are recorded as a result of the Tax Cuts and Jobs Act and will be recovered or refunded in future rates. See Note 14 - Income Taxes for further discussion. Pension and Employee Related Benefits We recognize the unfunded portion of plan benefit obligations in the Balance Sheets, which is remeasured at each year end, with a corresponding adjustment to regulatory assets/liabilities as the costs associated with these plans are recovered in rates. The MPSC allows recovery of pension costs on a cash funding basis. The portion of the regulatory asset related to our Montana pension plan will amortize as cash funding amounts exceed accrual expense under GAAP. The SDPUC allows recovery of pension costs on an accrual basis. The MPSC allows recovery of postretirement benefit costs on an accrual basis. State & Local Taxes & Fees (Montana Property Tax Tracker) Under Montana law, we are allowed to track the changes in the actual level of state and local taxes and fees and recover the increase in rates, less the amount allocated to FERC jurisdictional customers and net of the related income tax benefit. Environmental Clean-up Environmental clean-up costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss the specific sites and clean-up requirements further in Note 19 - Commitments and Contingencies. Environmental clean-up costs are typically recoverable in customer rates when they are actually incurred. When cost projections become known and measurable, we coordinate with the appropriate regulatory authority to determine a recovery period. Gas Storage Sales A regulatory liability was established in 2000 and 2001 based on gains on cushion gas sales in Montana. This gain is being flowed to customers over a period that matches the depreciable life of surface facilities that were added to maintain deliverability from the field after the withdrawal of the gas. This regulatory liability is a reduction of rate base. Unbilled Revenue In accordance with regulatory guidance in South Dakota, we recognize revenue when it is billed. Accordingly, we record a regulatory liability to offset unbilled revenue.
The following table presents the major classifications of our net utility plant (in thousands):
Net utility plant under capital (finance) lease were $9.2 million and $11.3 million as of December 31, 2021 and 2020, respectively, which included $9.0 million and $11.1 million as of December 31, 2021 and 2020, respectively, related to a long-term power supply contract with the owners of a natural gas fired peaking plant, which has been accounted for as a finance lease. Jointly Owned Electric Generating Plant We have an ownership interest in four base-load electric generating plants, all of which are coal fired and operated by other companies. We have an undivided interest in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated. Our interest in each plant is reflected in the Balance Sheets on a pro rata basis and our share of operating expenses is reflected in the Statements of Income. The participants each finance their own investment. Information relating to our ownership interest in these facilities is as follows (in thousands):
We are obligated to dispose of certain long-lived assets upon their abandonment. We recognize a liability for the legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event. We measure the liability at fair value when incurred and capitalize a corresponding amount as part of the book value of the related assets, which increases our utility plant and asset retirement obligations (ARO). The increase in the capitalized cost is included in determining depreciation expense over the estimated useful life of these assets. Since the fair value of the ARO is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period and recorded as a regulatory asset until the settlement of the liability. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a regulatory asset or liability for the difference, which will be surcharged/refunded to customers through the rate making process. We record regulatory assets and liabilities for differences in timing of asset retirement costs recovered in rates and AROs recorded since asset retirement costs are recovered through rates charged to customers. Our AROs relate to the reclamation and removal costs at our jointly-owned coal-fired generation facilities, U.S. Department of Transportation requirements to cut, purge and cap retired natural gas pipeline segments, our obligation to plug and abandon oil and gas wells at the end of their life, and to remove all above-ground wind power facilities and restore the soil surface at the end of their life. The following table presents the change in our ARO (in thousands):
During the twelve months ended December 31, 2021 our ARO liability decreased $2.9 million for partial settlement of the legal obligations at our jointly-owned coal-fired generation facilities. Additionally, during the twelve months ended December 31, 2021, our ARO liability decreased $4.1 million related to changes in both the timing and amount of retirement cost estimates. In addition, we have identified removal liabilities related to our electric and natural gas transmission and distribution assets that have been installed on easements over property not owned by us. The easements are generally perpetual and only require remediation action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as we intend to utilize these properties indefinitely. In the event we decide to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time. We also identified AROs associated with our hydroelectric generating facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the Financial Statements. We collect removal costs in rates for certain transmission and distribution assets that do not have associated AROs. Generally, the accrual of future non-ARO removal obligations is not required; however, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates.
We completed our annual utility plant adjustments impairment test as of April 1, 2021 and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections.
Nature of Our Business and Associated Risks We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. We rely on market purchases to fulfill a portion of our electric and natural gas supply requirements. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations. Objectives and Strategies for Using Derivatives To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide greater price stability for consumers. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes consistent with regulatory guidelines. In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt. Accounting for Derivative Instruments We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale (NPNS); cash flow hedge; fair value hedge; and mark-to-market. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction. Normal Purchases and Normal Sales We have applied the NPNS scope exception to our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no unrealized amounts recorded in the Financial Statements at December 31, 2021 and 2020. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered. Credit Risk Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We limit credit risk in our commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. We are exposed to credit risk through buying and selling electricity and natural gas to serve customers. We may request collateral or other security from our counterparties based on the assessment of creditworthiness and expected credit exposure. It is possible that volatility in commodity prices could cause us to have material credit risk exposures with one or more counterparties. We enter into commodity master enabling agreements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are: (1) Western Systems Power Pool agreements – standardized power purchase and sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements – standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements – standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements – standardized power sales contracts in the electric industry. Many of our forward purchase contracts contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our credit rating were to fall below investment grade, the counterparties could require immediate payment or demand immediate and ongoing full overnight collateralization on contracts in net liability positions. Interest Rate Swaps Designated as Cash Flow Hedges We have previously used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. We have no interest rate swaps outstanding. These swaps were designated as cash flow hedges with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in AOCI. We reclassify these gains from AOCI into interest on long-term debt during the periods in which the hedged interest payments occur. The following table shows the effect of these interest rate swaps previously terminated on the Financial Statements (in thousands):
A pre-tax loss of approximately $14.0 million is remaining in AOCI as of December 31, 2021, and we expect to reclassify approximately $0.6 million of pre-tax losses from AOCI into interest on long-term debt during the next twelve months. These amounts relate to terminated swaps.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs. Applicable accounting guidance establishes a hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows: •Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities; •Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and •Level 3 – Significant inputs that are generally not observable from market activity. We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. Due to the short-term nature of cash and cash equivalents, accounts receivable, net, and accounts payable, the carrying amount of each such items approximates fair value. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. NPNS transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 9 - Risk Management and Hedging Activities for further discussion. We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented.
Special deposits represent amounts held in money market mutual funds. Rabbi trust investments represent assets held for non-qualified deferred compensation plans, which consist of our common stock and actively traded mutual funds with quoted prices in active markets. Financial Instruments The estimated fair value of financial instruments is summarized as follows (in thousands):
The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange. We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.
Credit Facility We have a $425 million Credit Facility which matures September 2, 2023. The Credit Facility includes uncommitted features that allow us to request up to two one-year extensions to the maturity date and increase the size by an additional $75 million with the consent of the lenders. The facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to the Eurodollar rate, plus a margin of 112.5 to 175.0 basis points, or a base rate, plus a margin of 12.5 to 75.0 basis points. A total of ten banks participate in the facility, with no one bank providing more than 16 percent of the total availability. Commitment fees for the Credit Facility were $0.4 million and $0.6 million for the years ended December 31, 2021 and 2020. The availability under the facilities in place for the years ended December 31 is shown in the following table (in millions):
The Credit Facility includes covenants that require us to meet certain financial tests, including a maximum debt to capitalization ratio not to exceed 65 percent. The facility also contains covenants which, among other things, limit our ability to engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, and enter into transactions with affiliates. A default on the South Dakota or Montana First Mortgage Bonds would trigger a cross default on the Credit Facility; however, a default on the Credit Facility would not trigger a default on the South Dakota or Montana First Mortgage Bonds.
Long-term debt consisted of the following (in thousands):
Secured Debt First Mortgage Bonds and Pollution Control Obligations The South Dakota First Mortgage Bonds are a series of general obligation bonds issued under our South Dakota indenture. These bonds are secured by substantially all of our South Dakota and Nebraska electric and natural gas assets. The Montana First Mortgage Bonds and Montana Pollution Control Obligations are secured by substantially all of our Montana electric and natural gas assets. In May 2020, we issued $100 million principal amount of Montana First Mortgage Bonds and $50 million principal amount of South Dakota First Mortgage Bonds, each at a fixed interest rate of 3.21 percent maturing on May 15, 2030. These bonds were issued in a transaction 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. In March 2021, we issued and sold $100 million aggregate principal amount of Montana First Mortgage Bonds (the bonds) at a fixed interest rate of 1.00 percent maturing on March 26, 2024. The net proceeds were used to repay in full our outstanding $100 million term loan that was due April 2, 2021. We may redeem some or all of the bonds at any time in whole, or from time to time in part, at our option, on or after March 26, 2022, at a redemption price equal to 100% of the principal amount of the bonds to be redeemed, plus accrued and unpaid interest on the principal amount of the bonds being redeemed to, but excluding, the redemption date. The bonds are secured by our electric and natural gas assets in Montana and Wyoming. As of December 31, 2021, we were in compliance with our financial debt covenants. Other Long-Term Debt In July 2021, our two loans totaling $27.0 million associated with the New Market Tax Credit (NMTC) financing agreement were extinguished. These loans were satisfied with our $18.2 million investment in the entities created in relation to the NMTC transaction, investor forgiveness of $7.9 million for substantially all of the benefits derived from the tax credits, and cash payment of $0.9 million. In accordance with our last rate case filing in the state of Montana, the portion of the loan forgiven, less unamortized debt issuance costs of $1.3 million, was recorded as a reduction to the cost of the office building associated with the NMTC financing agreement. This cash payment is reflected within the financing activities section of our Statement of Cash Flows for the year ended December 31, 2021; however, the remaining reduction to Long-term debt, Other investments, and Utility plant are non-cash financing activities that are not reflected within our Statement of Cash Flows for the year ended December 31, 2021. Maturities of Long-Term Debt The aggregate minimum principal maturities of long-term debt, during the next five years are $517.7 million in 2023, $100.0 million in 2024, $300.0 million in 2025 and $105.0 million in 2026.
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):
Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities. The components of the net deferred income tax assets and liabilities recognized in our Balance Sheets are related to the following temporary differences (in thousands):
Uncertain Tax Positions We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The change in unrecognized tax benefits is as follows (in thousands):
Our unrecognized tax benefits include approximately $28.1 million and $28.0 million related to tax positions as of December 31, 2021 and 2020 that if recognized, would impact our annual effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months. Our policy is to recognize interest related to uncertain tax positions in interest expense. As of December 31, 2021, we have accrued $0.5 million for the payment of interest in the Balance Sheets. As of December 31, 2020, we did not have any amounts accrued for the payment of interest. Tax years 2018 and forward remain subject to examination by the IRS and state taxing authorities.
The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands):
Balances by classification included within AOCI on the Balance Sheets are as follows, net of tax (in thousands):
The following table displays the changes in AOCI by component, net of tax (in thousands):
Pension and Other Postretirement Benefit Plans We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for eligible employees. The pension plan for our South Dakota and Nebraska employees is referred to as the NorthWestern Corporation plan, and the pension plan for our Montana employees is referred to as the NorthWestern Energy plan, and collectively they are referred to as the Plans. We utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. The Plans' funded status is recognized as an asset or liability in our Financial Statements. See Note 5 - Regulatory Assets and Liabilities, for further discussion on how these costs are recovered through rates charged to our customers. Benefit Obligation and Funded Status Following is a reconciliation of the changes in plan benefit obligations and fair value of plan assets, and a statement of the funded status (in thousands):
(1) In December 2021, we entered into a group annuity contract from an insurance company to provide for the payment of pension benefits to 1,062 NorthWestern Energy Pension Plan participants. We purchased the contract with $93.5 million of plan assets. The insurance company took over the payments of these benefits starting January 1, 2022. This transaction settled $93.5 million of our NorthWestern Energy Pension Plan obligation. As a result of this transaction, during the twelve months ended December 31, 2021, we recorded a non-cash, non-operating settlement charge of $11.3 million. This charge is recorded within operating expenses, net on the Statements of Income. As discussed within Note 5 – Regulatory Assets and Liabilities, this charge was deferred as a regulatory asset on the Balance Sheets, with a corresponding decrease to operating expenses on the Statements of Income. The actuarial gain/loss is primarily due to the change in discount rate assumption and actual asset returns compared with expected amounts. The total projected benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were as follows (in millions):
_____________________ As of December 31, 2021, the fair value of the NorthWestern Corporation pension plan assets exceed the total projected and accumulated benefit obligation and are therefore excluded from this table. (1) Fair value of plan assets was impacted by the group annuity contract discussed above. Net Periodic Cost (Credit) The components of the net costs (credits) for our pension and other postretirement plans are as follows (in thousands):
_________________________ (1) Settlement loss is related to partial annuitization of NorthWestern Energy Pension Plan effective December 1, 2021. (2) Net periodic benefit costs for pension and postretirement benefit plans are recognized for financial reporting based on the authorization of each regulatory jurisdiction in which we operate. A portion of these costs are recorded in regulatory assets and recognized in the Statements of Income as those costs are recovered through customer rates. For purposes of calculating the expected return on pension plan assets, the market-related value of assets is used, which is based upon fair value. The difference between actual plan asset returns and estimated plan asset returns are amortized equally over a period not to exceed five years. Actuarial Assumptions The measurement dates used to determine pension and other postretirement benefit measurements for the plans are December 31, 2021 and 2020. The actuarial assumptions used to compute net periodic pension cost and postretirement benefit cost are based upon information available as of the beginning of the year, specifically, market interest rates, past experience and management's best estimate of future economic conditions. Changes in these assumptions may impact future benefit costs and obligations. In computing future costs and obligations, we must make assumptions about such things as employee mortality and turnover, expected salary and wage increases, discount rate, expected return on plan assets, and expected future cost increases. Two of these assumptions have the most impact on the level of cost: (1) discount rate and (2) expected rate of return on plan assets. On an annual basis, we set the discount rate using a yield curve analysis. This analysis includes constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year, projected benefit cash flow from our plans. The increase in the discount rate during 2021 decreased our projected benefit obligation by approximately $45.1 million. In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions. Based on the target asset allocation for our pension assets and future expectations for asset returns, we increased our long term rate of return on assets assumption for NorthWestern Energy Pension Plan to 4.26 percent and decreased our assumption on the NorthWestern Corporation Pension Plan to 2.66 percent for 2022. The weighted-average assumptions used in calculating the preceding information are as follows:
The postretirement benefit obligation is calculated assuming that health care costs increase by a 5.00 percent fixed rate. The company contribution toward the premium cost is capped, therefore future health care cost trend rates are expected to have a minimal impact on company costs and the accumulated postretirement benefit obligation. Investment Strategy Our investment goals with respect to managing the pension and other postretirement assets are to meet current and future benefit payment needs while maximizing total investment returns (income and appreciation) after inflation within the constraints of diversification, prudent risk taking, Prudent Man Rule of the Employee Retirement Income Security Act of 1974 and liability-based considerations. Each plan is diversified across asset classes to achieve optimal balance between risk and return and between income and growth through capital appreciation. Our investment philosophy is based on the following: •Each plan should be substantially invested as long-term cash holdings reduce long-term rates of return; •Pension Plan portfolio risk is described by volatility in the funded status of the Plans; •It is prudent to diversify each plan across the major asset classes; •Equity investments provide greater long-term returns than fixed income investments, although with greater short-term volatility; •Fixed income investments of the plans should strongly correlate with the interest rate sensitivity of the plan’s aggregate liabilities in order to hedge the risk of change in interest rates negatively impacting the pension plans overall funded status, (such assets will be described as Liability Hedging Fixed Income assets); •Allocation to foreign equities increases the portfolio diversification and thereby decreases portfolio risk while providing for the potential for enhanced long-term returns; •Active management can reduce portfolio risk and potentially add value through security selection strategies; •A portion of plan assets should be allocated to passive, indexed management funds to provide for greater diversification and lower cost; and •It is appropriate to retain more than one investment manager, provided that such managers offer asset class or style diversification. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies. The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense. In the optimization study, assumptions are formulated about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period. Based on this, the target asset allocation established, within an allowable range of plus or minus 5 percent, is as follows:
The actual allocation by plan is as follows:
Generally, the asset mix will be rebalanced to the target mix as individual portfolios approach their minimum or maximum levels. Debt securities consist of U.S. and international instruments. Core domestic portfolios can be invested in government, corporate, asset-backed and mortgage-backed obligation securities. While the portfolio may invest in high yield securities, the average quality must be rated at least “investment grade" by rating agencies. Performance of fixed income investments is measured by both traditional investment benchmarks as well as relative changes in the present value of the plan's liabilities. Equity investments consist primarily of U.S. stocks including large, mid and small cap stocks, which are diversified across investment styles such as growth and value. We also invest in global equities with exposure to developing and emerging markets. Derivatives, options and futures are permitted for the purpose of reducing risk but may not be used for speculative purposes. Our plan assets are primarily invested in common collective trusts (CCTs), which are invested in equity and fixed income securities. In accordance with our investment policy, these pooled investment funds must have an adequate asset base relative to their asset class and be invested in a diversified manner and have a minimum of three years of verified investment performance experience or verified portfolio manager investment experience in a particular investment strategy and have management and oversight by an investment advisor registered with the Securities and Exchange Commission (SEC). Investments in a collective investment vehicle are valued by multiplying the investee company’s net asset value per share with the number of units or shares owned at the valuation date. Net asset value per share is determined by the trustee. Investments held by the CCT, including collateral invested for securities on loan, are valued on the basis of valuations furnished by a pricing service approved by the CCT’s investment manager, which determines valuations using methods based on quoted closing market prices on national securities exchanges, or at fair value as determined in good faith by the CCT’s investment manager if applicable. The funds do not contain any redemption restrictions. The direct holding of NorthWestern Corporation stock is not permitted; however, any holding in a diversified mutual fund or collective investment fund is permitted. During 2019, due to proposed changes in the John Hancock participating group annuity contract held by the NorthWestern Corporation plan, we elected to discontinue the contract effective January 1, 2020. Cash Flows In accordance with the Pension Protection Act of 2006 (PPA), and the relief provisions of the Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), we are required to meet minimum funding levels in order to avoid required contributions and benefit restrictions. We have elected to use asset smoothing provided by the WRERA, which allows the use of asset averaging, including expected returns (subject to certain limitations), for a 24-month period in the determination of funding requirements. Additional funding relief was passed in the American Rescue Plan Act of 2021, providing for longer amortization and interest rate smoothing, which we elected to use. We expect to continue to make contributions to the pension plans in 2022 and future years that reflect the minimum requirements and discretionary amounts consistent with the amounts recovered in rates. Additional legislative or regulatory measures, as well as fluctuations in financial market conditions, may impact our funding requirements. Due to the regulatory treatment of pension costs in Montana, pension expense for 2021 and 2020 was based on actual contributions to the plan. Annual contributions to each of the pension plans are as follows (in thousands):
We estimate the plans will make future benefit payments to participants as follows (in thousands):
Defined Contribution Plan Our defined contribution plan permits employees to defer receipt of compensation as provided in Section 401(k) of the Internal Revenue Code. Under the plan, employees may elect to direct a percentage of their gross compensation to be contributed to the plan. We contribute various percentage amounts of the employee's gross compensation contributed to the plan. Matching contributions for the years ended December 31, 2021 and 2020 were $11.8 million and $11.1 million, respectively.
We grant stock-based awards through our Amended and Restated Equity Compensation Plan (ECP), which includes restricted stock awards and performance share awards. As of December 31, 2021, there were 828,486 shares of common stock remaining available for grants. The remaining vesting period for awards previously granted ranges from one to five years if the service and/or performance requirements are met. Nonvested shares do not receive dividend distributions. The long-term incentive plan provides for accelerated vesting in the event of a change in control. We account for our share-based compensation arrangements by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. The compensation cost is based on the fair value of the grant on the date it was awarded. Performance Unit Awards Performance unit awards are granted annually under the ECP. These awards vest at the end of the three-year performance period if we have achieved certain performance goals and the individual remains employed by us. The exact number of shares issued will vary from 0 percent to 200 percent of the target award, depending on actual company performance relative to the performance goals. These awards contain both market- and performance-based components. The performance goals are independent of each other and equally weighted, and are based on two metrics: (i) EPS growth level and average return on equity; and (ii) total shareholder return (TSR) relative to a peer group. Fair value is determined for each component of the performance unit awards. The fair value of the earnings per share component is estimated based upon the closing market price of our common stock as of the date of grant less the present value of expected dividends, multiplied by an estimated performance multiple determined on the basis of historical experience, which is subsequently trued up at vesting based on actual performance. The fair value of the TSR portion is estimated using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. The following summarizes the significant assumptions used to determine the fair value of performance shares and related compensation expense as well as the resulting estimated fair value of performance shares granted:
The risk-free interest rate was based on the U.S. Treasury yield of a three-year bond at the time of grant. The expected term of the performance shares is three years based on the performance cycle. Expected volatility was based on the historical volatility for the peer group. Both performance goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest. A summary of nonvested shares as of and changes during the year ended December 31, 2021, are as follows:
We recognized compensation expense of $3.9 million and $2.2 million for the years ended December 31, 2021 and 2020, respectively, and related income tax benefit of $(0.2) million and $(0.6) million for the years ended December 31, 2021 and 2020, respectively. As of December 31, 2021, we had $5.7 million of unrecognized compensation cost related to the nonvested portion of outstanding awards, which is reflected as nonvested stock as a portion of additional paid in capital in our Statements of Common Shareholders' Equity. The cost is expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested was $4.2 million and $5.1 million for the years ended December 31, 2021 and 2020, respectively. Retirement/Retention Restricted Share Awards In December 2011, an executive retirement / retention program was established that provides for the annual grant of restricted share units. These awards are subject to a five-year performance and vesting period. The performance measure for these awards requires net income for the calendar year of at least three of the five full calendar years during the performance period to exceed net income for the calendar year the awards are granted. Once vested, the awards will be paid out in shares of common stock in five equal annual installments after a recipient has separated from service. The fair value of these awards is measured based upon the closing market price of our common stock as of the date of grant less the present value of expected dividends. A summary of nonvested shares as of and changes during the year ended December 31, 2021, are as follows:
Director's Deferred Compensation Nonemployee directors may elect to defer up to 100 percent of any qualified compensation that would be otherwise payable to him or her, subject to compliance with our 2005 Deferred Compensation Plan for Nonemployee Directors and Section 409A of the Internal Revenue Code. The deferred compensation may be invested in NorthWestern stock or in designated investment funds. Compensation deferred in a particular month is recorded as a deferred stock unit (DSU) on the first of the following month based on the closing price of NorthWestern stock or the designated investment fund. The DSUs are marked-to-market on a quarterly basis with an adjustment to director’s compensation expense. Based on the election of the nonemployee director, following separation from service on the Board, other than on account of death, he or she shall be paid a distribution either in a lump sum or in approximately equal installments over a designated number of years (not to exceed 10 years). Following is a summary of the components of DSUs issued and compensation expense attributable to the DSUs (in millions, except DSU amounts):
We have 250,000,000 shares authorized consisting of 200,000,000 shares of common stock with a $0.01 par value and 50,000,000 shares of preferred stock with a $0.01 par value. Of these shares, 2,865,957 shares of common stock are reserved for the incentive plan awards. For further detail of grants under this plan see Note 17 - Stock-Based Compensation. Repurchase of Common Stock Shares tendered by employees to us to satisfy the employees' tax withholding obligations in connection with the vesting of restricted stock awards totaled 16,880 and 35,378 during the years ended December 31, 2021 and 2020, respectively, and are reflected in reacquired capital stock. These shares were credited to reacquired capital stock based on their fair market value on the vesting date. Issuance of Common Stock In April 2021, we entered into an Equity Distribution Agreement with BofA Securities, Inc., CIBC World Markets Corp, Credit Suisse Securities (USA) LLC, and J.P. Morgan Securities LLC, collectively the sales agents, pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $200.0 million, through an At-the-Market (ATM) offering program, including an equity forward sales component. This is a three-year agreement, expiring on February 11, 2024. During the twelve months ended December 31, 2021, we issued 1,966,117 shares of our common stock under the ATM program at an average price of $63.81, for net proceeds of $124.2 million, which is net of sales commissions and other fees paid of approximately $1.3 million. We do not anticipate needing to issue equity through the ATM program during 2022. On November 17, 2021, we announced a registered public offering of 6,074,767 shares of our common stock at a public offering price of $53.50 per share, for an issuance amount of $325.0 million. In conjunction with this offering, we granted the underwriters an option to purchase up to 911,215 additional shares, which was subsequently exercised in full, for an additional issuance amount of $48.8 million. Of the total 6,985,982 shares of common stock offered, we initially sold 1,401,869 shares, $75.0 million in gross proceeds, directly to the underwriters in the offering, with cash proceeds received at closing. The remaining 5,584,113 shares were sold under forward sales agreements which provide for settlement on a settlement date or dates to be specified at our discretion, but which is expected to occur on or prior to February 28, 2023. The cumulative shares issued under the forward sales agreement is limited to one and one-half times the base number of shares within the agreement, or 8,376,170 shares. The forward sales agreements will be physically settled with common shares issued by us, unless we elect to settle the agreements in cash or to net share settle the agreements, subject to certain conditions. On a settlement date or dates, if we decide to physically settle the forward sales agreement, we will issue shares of common stock to the forward purchaser at the then-applicable forward sale price and receive issuance proceeds at that time. The forward sale price will initially be $51.8950 per share, which is subject to adjustment based on a floating interest rate factor equal to the overnight bank funding rate less a spread of 75 basis points, and will be subject to decrease on certain dates specified in the forward sale agreement by amounts related to expected dividends on shares of common stock during the term of the forward sale agreement. At December 31, 2021, we could have settled the forward sale agreement with physical delivery of 5,584,113 shares of common stock to the counterparty in exchange for cash of $286.1 million. The forward sale could have also been settled at December 31, 2021, with delivery of approximately $24.2 million of cash or approximately 435,522 shares of common stock to the counterparty, if we had elected to net cash or net share settle, respectfully. The forward sale agreement has been classified as an equity transaction because it is indexed to our common stock, physical settlement is within our control, and the other requirements necessary for equity classification are met. As a result of the equity classification, no gain or loss will be recognized within earnings due to subsequent changes in the fair value of the forward sales agreement.
Qualifying Facilities Liability Our QF liability primarily consists of unrecoverable costs associated with three contracts covered under the Public Utility Regulatory Practices Act (PURPA). These contracts require us to purchase minimum amounts of energy at prices ranging from $64 to $136 per MWH through 2029. As of December 31, 2021, our estimated gross contractual obligation related to these contracts was approximately $466.9 million through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $388.4 million through 2029. As contractual obligations are settled, the related purchases and sales are recorded within Operation expenses and Operating revenues in our Statements of Income. The present value of the remaining liability is recorded in Accumulated miscellaneous operating provisions in our Balance Sheets. The following summarizes the change in the liability (in thousands):
______________________ (1) The settlements amount includes (i) a higher periodic adjustment of $4.3 million due to actual price escalation, which was more than previously modeled; (ii) lower costs of approximately $1.7 million, due to a $2.6 million reduction in costs for the adjustment to actual output and pricing for the current contract year as compared with a $0.9 million reduction in costs in the prior period; and (iii) a favorable adjustment of approximately $7.0 million decreasing the QF liability associated with a one-time clarification in contract term. The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands):
_____________________ (1) This net unrecoverable amount represents the undiscounted difference between the total gross obligations and recoverable amounts. The ending QF liability in the table above represents the present value of this net unrecoverable amount. Long Term Supply and Capacity Purchase Obligations We have entered into various commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 24 years. Costs incurred under these contracts are included in Operating expenses in the Statements of Income and were approximately $286.7 million and $206.6 million for the years ended December 31, 2021 and 2020, respectively. As of December 31, 2021, our commitments under these contracts were $283.2 million in 2022, $269.7 million in 2023, $221.8 million in 2024, $219.4 million in 2025, $172.2 million in 2026, and $1.5 billion thereafter. These commitments are not reflected in our Financial Statements. Hydroelectric License Commitments With the 2014 purchase of hydroelectric generating facilities and associated assets located in Montana, we assumed two Memoranda of Understanding (MOUs) existing with state, federal and private entities. The MOUs are periodically updated and renewed and require us to implement plans to mitigate the impact of the projects on fish, wildlife and their habitats, and to increase recreational opportunities. The MOUs were created to maximize collaboration between the parties and enhance the possibility to receive matching funds from relevant federal agencies. Under these MOUs, we have a remaining commitment to spend approximately $26.7 million between 2022 and 2040. These commitments are not reflected in our Financial Statements.
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 $24.1 million to $30.7 million. As of December 31, 2021, we had a reserve of approximately $26.9 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 financial position or results of operations. The following summarizes the change in our environmental liability (in thousands):
Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as available and applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our financial position or results of operations. Manufactured Gas Plants - Approximately $22.1 million of our environmental reserve accrual is related to the following manufactured gas plants. South Dakota - A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies, implementing remedial actions pursuant to work plans approved by the South Dakota Department of Agriculture and Natural Resources, and conducting ongoing monitoring and operation and maintenance activities. As of December 31, 2021, the reserve for remediation costs at this site was approximately $8.1 million, and we estimate that approximately $3.0 million of this amount will be incurred through 2025. Nebraska - We own sites in North Platte, Kearney, and Grand Island, Nebraska on which former manufactured gas facilities were located. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations. Montana - We own or have responsibility for sites in Butte, Missoula, and Helena, Montana on which former manufactured gas plants were located. The Butte and Helena sites, both listed as high priority sites on Montana’s state superfund list, were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with the MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remedial actions and/or investigations, if any, at the Butte site. In August 2016, the MDEQ sent us a Notice of Potential Liability and Request for Remedial Action regarding the Helena site. In October 2019, we submitted a third revised Remedial Investigation Work Plan (RIWP) for the Helena site addressing MDEQ comments. The MDEQ approved the RIWP in March 2020 and we expect work at the Helena site to continue into 2022. MDEQ has indicated it expects to proceed in listing the Missoula site as a Montana superfund site. After researching historical ownership, we have identified another potentially responsible party with whom we have entered into an agreement allocating third-party costs to be incurred in addressing the site. The other party has assumed the lead role at the site and has submitted a voluntary remediation plan for the Missoula site to MDEQ. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula site. Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of greenhouse gas (GHG) including, most significantly, carbon dioxide (CO2). These actions include legislative proposals, Executive 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. In 2019, the EPA finalized the Affordable Clean Energy Rule (ACE), which repealed the 2015 Clean Power Plan (CPP) in regulating GHG emissions from coal-fired plants. The U.S. Court of Appeals for the District of Columbia Circuit issued an opinion on January 19, 2021, vacating the ACE and remanding it to EPA for further action. The United States Supreme Court agreed to review the case in October 2021 and oral argument regarding the scope of EPA’s authority to regulate GHG emissions is scheduled to take place February 28, 2022, with a decision expected the following summer. It also is widely expected that the Biden Administration will develop an alternative plan for reducing GHG emissions from coal-fired plants, and in a memorandum dated February 12, 2021, EPA stated its belief that the January 19, 2021 opinion left neither the ACE nor the CPP rules in place. We cannot predict whether or how GHG emission regulations will be applied to our plants, including any actions taken by the relevant state authorities. In addition, it is unclear how pending or future litigation relating to GHG matters will impact us. 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 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, 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. Clean Air Act Rules and Associated Emission Control Equipment Expenditures - The EPA has proposed or issued a number of rules under different provisions of the Clean Air Act (CAA) that could require the installation of emission control equipment at the generation plants in which we have joint ownership. Air emissions at our thermal generating plants are managed by the use of emissions and combustion controls and monitoring, and sulfur dioxide allowances. These measures are anticipated to be sufficient to permit the facilities to continue to meet current air emissions compliance requirements. Regional Haze Rules - In January 2017, the EPA published amendments to the requirements under the CAA for state plans for protection of visibility - regional haze rules. Among other things, these amendments revised the process and requirements for the state implementation plans and extended the due date for the next periodic comprehensive regional haze state implementation plan revisions from 2018 to 2021. The states of Montana, North Dakota and South Dakota are expected to develop and submit to EPA, for its approval, their respective State Implementation Plans (SIP) for Regional Haze compliance. While these states, among others, did not meet the EPA’s July 31, 2021 submission deadline, we still expect each state to submit its SIP in 2022. The draft Montana SIP does not require any additional controls at Colstrip Units 3 and 4. The draft North Dakota SIP does not require any additional controls at the Coyote generating facility, however the EPA, following a preliminary review, has asked North Dakota to reassess its determination regarding Coyote. The draft South Dakota SIP does not require any additional controls at the Big Stone generating facility. Until these SIPs are submitted and approved by EPA, the potential remains that installation of additional emissions controls might be required at these facilities. Jointly Owned Plants - We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa, and Montana that are or may become subject to the various regulations discussed above that have been or may be issued or proposed. Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment. We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties: •We may not know all sites for which we are alleged or will be found to be responsible for remediation; and •Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.
Pacific Northwest Solar Litigation Pacific Northwest Solar, LLC (PNWS) is a solar QF developer seeking to construct small solar facilities in Montana. We began negotiating with PNWS in early 2016 to purchase the output from 21 of its proposed facilities pursuant to our standard QF-1 Tariff, which is applicable to projects no larger than 3 MWs. On June 16, 2016, however, the MPSC suspended the availability of the QF-1 Tariff standard rates for that category of solar projects, which included the projects proposed by PNWS. The MPSC exempted from the suspension any projects for which a QF had both submitted a signed power purchase agreement and had executed an interconnection agreement with us by June 16, 2016. Although we had signed four power purchase agreements with PNWS as of that date, we had not entered into interconnection agreements with PNWS for any of those projects. As a result, none of the PNWS projects in Montana qualified for the exemption. In November 2016, PNWS sued us in state court seeking unspecified damages for breach of contract and a judicial declaration that some or all of the 21 proposed power purchase agreements it had proposed to us were in effect despite the MPSC's Order. We removed the state lawsuit to the United States District Court for the District of Montana (Court). PNWS also requested the MPSC to exempt its projects from the tariff suspension and allow those projects to receive the QF-1 tariff rate that had been in effect prior to the suspension. We joined in PNWS’s request for relief with respect to four of the projects, but the MPSC did not grant any of the relief requested by PNWS or us. In August 2017, we entered into a non-monetary, partial settlement with PNWS in which PNWS amended its original complaint to limit its claims for enforcement and/or damages to only four of the 21 power purchase agreements. As a result, the damages sought by the plaintiff was reduced to approximately $8 million for the alleged breach of the four power purchase agreements. We participated in an unsuccessful mediation on January 24, 2019 and subsequent settlement efforts also have been unsuccessful. On August 31, 2021, the Court ruled that the four agreements are valid and enforceable contracts and that NorthWestern breached the agreements on June 16, 2016 by refusing to go forward with the projects in spite of the MPSC's Orders. On December 15, 2021, after a three-day trial, the jury determined that PNWS had sustained $0.4 million in damages and the judge subsequently entered judgment against us in that amount. We filed a post-trial motion on January 13, 2022 seeking to have the judgement set aside. On February 9, 2022, the judge denied our post-trial potion. The plaintiff did not seek any post-trial relief and the deadline for doing so has passed. On March 2, 2022, we filed a Notice of Appeal to the U.S. Court of Appeals for the Ninth Circuit. The plaintiff has fifteen days in which to file a cross-appeal. 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 2012, the United States Supreme Court issued a decision holding that the Montana Supreme Court erred in not considering a segment-by-segment approach to determine navigability and relying on present day recreational use of the rivers. It also held that what it referred to as the Great Falls Reach “at least from the head of the first waterfall to the foot of the last” was not navigable for title purposes, and thus the State did not own the riverbeds in that segment. The United States Supreme Court remanded the case to the Montana Supreme Court for further proceedings not inconsistent with its opinion. Following the 2012 remand, the case laid dormant for four years until the State’s Complaint was filed with the State District Court. On April 20, 2016, we removed the case from State District Court to the United States District Court for the District of Montana (Federal District Court). The State filed a motion to remand. Following briefing and argument, on October 10, 2017, the Federal District Court entered an order denying the State’s motion. Because the State’s Complaint included a claim that the State owned the riverbeds in the Great Falls Reach, on October 16, 2017, we and Talen renewed our earlier-filed motions seeking to dismiss the portion of the State’s Complaint concerning the Great Falls Reach in light of the United States Supreme Court’s decision. On August 1, 2018, the Federal District Court granted the motions to dismiss the State’s Complaint as it pertains to approximately 8.2 miles of riverbed from “the head of the Black Eagle Falls to the foot of the Great Falls.” In particular, the dismissal pertained to the Black Eagle Dam, Rainbow Dam and reservoir, Cochrane Dam and reservoir, and Ryan Dam and reservoir. While the dismissal of these four facilities may be subject to appeal, that appeal would not likely occur until after judgment in the case. On February 12, 2019, the Federal District Court granted our motion to join the United States as a defendant to the litigation. As a result, on October 31, 2019, the State filed and served an Amended Complaint including the United States as a defendant and removing claims of ownership for the hydroelectric facilities on the Great Falls Reach, except for the Morony and the Black Eagle Developments. We and Talen filed answers to the Amended Complaint on December 13, 2019, and the United States answered on February 5, 2020. A bench trial before the Federal District Court commenced January 4, 2022 and concluded on January 18, 2022. This bench trial addressed the issue of navigability of the segments at issue. The parties must submit amended findings of fact and conclusions of law, along with post-trial briefing, by April 29, 2022. A decision on navigability is expected following such submissions. Damages were bifurcated by agreement and will be tried separately, should the Federal District Court find any segments navigable. We dispute the State’s claims and intend to vigorously defend the lawsuit. At this time, we cannot predict an outcome. If the Federal District Court determines the riverbeds are navigable under the remaining six facilities that were not dismissed and if it calculates damages as the State District Court did in 2008, we estimate the annual rents could be approximately $3.8 million commencing when we acquired the facilities in November 2014. We anticipate that any obligation to pay the State rent for use and occupancy of the riverbeds would be recoverable in rates from customers, although there can be no assurances that the MPSC would approve any such recovery. Colstrip Arbitration and Litigation As part of the settlement of litigation brought by the Sierra Club and the Montana Environmental Information Center against the owners and operator of Colstrip, the owners of Units 1 and 2 agreed to shut down those units no later than July 2022. In January 2020, the owners of Units 1 and 2 closed those two units. We do not have ownership in Units 1 and 2, and decisions regarding those units, including their shut down, were made by their respective owners. The six owners of Units 3 and 4 currently share the operating costs pursuant to the terms of an operating agreement among them, the Ownership and Operation Agreement (O&O Agreement). Costs of common facilities were historically shared among the owners of all four units. With the closure of Units 1 and 2, we have incurred additional operating costs with respect to our interest in Unit 4 and expect to experience a negative impact on our transmission revenue due to reduced amounts of energy transmitted across our transmission lines. We expect to incorporate any reduction in revenue in our next general electric rate filing, resulting in lower revenue credits to certain customers. The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. Recovery of costs associated with the closure of the facility is subject to MPSC approval. Three of the joint owners of Units 3 and 4 are subject to regulation in Washington and in May 2019, the Washington state legislature enacted a statute mandating Washington electric utilities to “eliminate coal-fired resources from [their] allocation of electricity” on or before December 31, 2025, after which date they may no longer include their share of coal-fired resources in their regulated electric supply portfolio. As a result of the Washington legislation, four of the six joint owners of Units 3 and 4 requested the operator prepare a 2021 budget reflecting closure of Units 3 and 4 by 2025, and alternately a closure of Unit 3 by 2025 and a closure of Unit 4 by 2027. Differing viewpoints on closure dates delayed approval of the 2021 budget, until it was approved on March 22, 2021. Budgeting for 2022 was also delayed, with the same four joint owners demanding substantial budget reductions, but was ultimately approved on January 21, 2022. Such budgeting pressures may result in future budgets that may not be sufficient to maintain the reliability of Units 3 and 4. While we believe closure requires each owner’s consent, there are differences among the owners as to this issue under the O&O Agreement. On March 12, 2021, we initiated an arbitration under the O&O Agreement (the “Arbitration”), which seeks to resolve the primary issue of whether closure of Units 3 and 4 can be accomplished without each joint owner's consent and to clarify the obligations of the joint owners to continue to fund operations until all joint owners agree on closure. The Arbitration has given rise to three lawsuits concerning the number of arbitrators, the venue and the applicable arbitration laws. The four joint owners from the Pacific Northwest assert the Arbitration must be conducted under the O&O Agreement, with one arbitrator, in Spokane County, Washington, and pursuant to the Washington Arbitration Act. The fifth joint owner asserts the Arbitration must be conducted per the terms of Montana Senate Bill 265 (SB 265), which requires the Arbitration be conducted, with three arbitrators, in Montana and pursuant to the Montana Uniform Arbitration Act. The three initiated lawsuits do not make direct financial demands, and instead, are intended to address issues related to process for the Arbitration. Since the Arbitration was initiated, and despite the litigation, we have worked and continue to work with the other joint owners to arrive at an agreed upon process for the Arbitration. Colstrip Coal Dust Litigation On December 14, 2020, a claim was filed against Talen Montana, LLC, the operator of the Colstrip Steam Plant, in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. The plaintiffs allege they have suffered adverse effects from coal dust generated during operations associated with the Colstrip Steam Plant. On August 26, 2021, the claim was amended to add in excess of 100 plaintiffs. It also added NorthWestern, as well as the other owners of the Colstrip Steam Plant, 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 is in its early stages, we are unable to predict outcomes or estimate a range of reasonably possible losses. Other Legal Proceedings We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows. |
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STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES |
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| (e) Concept: AccumulatedOtherComprehensiveIncomeLossOtherCashFlowHedgesInterestRateSwapsReclassificationsToNetIncomeLoss |
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SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION |
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DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION |
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32 |
AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment |
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(c) |
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33 |
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32) |
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Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
| FOOTNOTE DATA |
| (a) Concept: UtilityPlantAcquisitionAdjustment |
| (b) Concept: AmortizationOfOtherUtilityPlantUtilityPlantInService |
Amortization of Other South Dakota Electric Plant was $0 and $(61,194) for 2021 and 2020, respectively.
Amortization of Other Montana Electric Plant was $22,153,646 and $21,935,205 for 2021 and 2020, respectively
|
| (c) Concept: AmortizationOfPlantAcquisitionAdjustment |
| (d) Concept: UtilityPlantInServiceClassified |
| (e) Concept: UtilityPlantInServicePropertyUnderCapitalLeases |
| (f) Concept: UtilityPlantInServicePropertyUnderCapitalLeases |
|
Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
|
NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157) |
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| Line No. |
Description of item (a) |
Balance Beginning of Year (b) |
Changes during Year Additions (c) |
Changes during Year Amortization (d) |
Changes during Year Other Reductions (Explain in a footnote) (e) |
Balance End of Year (f) |
|
1 |
Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1) |
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2 |
Fabrication |
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3 |
Nuclear Materials |
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4 |
Allowance for Funds Used during Construction |
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5 |
(Other Overhead Construction Costs, provide details in footnote) |
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6 |
SUBTOTAL (Total 2 thru 5) |
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7 |
Nuclear Fuel Materials and Assemblies |
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8 |
In Stock (120.2) |
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9 |
In Reactor (120.3) |
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10 |
SUBTOTAL (Total 8 & 9) |
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11 |
Spent Nuclear Fuel (120.4) |
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12 |
Nuclear Fuel Under Capital Leases (120.6) |
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13 |
(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5) |
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14 |
TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) |
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15 |
Estimated Net Salvage Value of Nuclear Materials in Line 9 |
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16 |
Estimated Net Salvage Value of Nuclear Materials in Line 11 |
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17 |
Est Net Salvage Value of Nuclear Materials in Chemical Processing |
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18 |
Nuclear Materials held for Sale (157) |
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19 |
Uranium |
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20 |
Plutonium |
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21 |
Other (Provide details in footnote) |
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22 |
TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21) |
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|
Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
|
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) |
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| Line No. |
Account (a) |
Balance Beginning of Year (b) |
Additions (c) |
Retirements (d) |
Adjustments (e) |
Transfers (f) |
Balance at End of Year (g) |
|
1 |
1. INTANGIBLE PLANT |
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2 |
(301) Organization |
(a) |
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3 |
(302) Franchise and Consents |
(b) |
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4 |
(303) Miscellaneous Intangible Plant |
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5 |
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) |
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6 |
2. PRODUCTION PLANT |
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7 |
A. Steam Production Plant |
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8 |
(310) Land and Land Rights |
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9 |
(311) Structures and Improvements |
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10 |
(312) Boiler Plant Equipment |
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11 |
(313) Engines and Engine-Driven Generators |
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12 |
(314) Turbogenerator Units |
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13 |
(315) Accessory Electric Equipment |
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14 |
(316) Misc. Power Plant Equipment |
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15 |
(317) Asset Retirement Costs for Steam Production |
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16 |
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) |
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17 |
B. Nuclear Production Plant |
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18 |
(320) Land and Land Rights |
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19 |
(321) Structures and Improvements |
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20 |
(322) Reactor Plant Equipment |
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21 |
(323) Turbogenerator Units |
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22 |
(324) Accessory Electric Equipment |
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23 |
(325) Misc. Power Plant Equipment |
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24 |
(326) Asset Retirement Costs for Nuclear Production |
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25 |
TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) |
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26 |
C. Hydraulic Production Plant |
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27 |
(330) Land and Land Rights |
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28 |
(331) Structures and Improvements |
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29 |
(332) Reservoirs, Dams, and Waterways |
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30 |
(333) Water Wheels, Turbines, and Generators |
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31 |
(334) Accessory Electric Equipment |
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32 |
(335) Misc. Power Plant Equipment |
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33 |
(336) Roads, Railroads, and Bridges |
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34 |
(337) Asset Retirement Costs for Hydraulic Production |
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35 |
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) |
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36 |
D. Other Production Plant |
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37 |
(340) Land and Land Rights |
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38 |
(341) Structures and Improvements |
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39 |
(342) Fuel Holders, Products, and Accessories |
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40 |
(343) Prime Movers |
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41 |
(344) Generators |
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42 |
(345) Accessory Electric Equipment |
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43 |
(346) Misc. Power Plant Equipment |
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44 |
(347) Asset Retirement Costs for Other Production |
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44.1 |
(348) Energy Storage Equipment - Production |
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45 |
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) |
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46 |
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) |
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47 |
3. Transmission Plant |
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48 |
(350) Land and Land Rights |
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48.1 |
(351) Energy Storage Equipment - Transmission |
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49 |
(352) Structures and Improvements |
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50 |
(353) Station Equipment |
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51 |
(354) Towers and Fixtures |
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52 |
(355) Poles and Fixtures |
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53 |
(356) Overhead Conductors and Devices |
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54 |
(357) Underground Conduit |
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55 |
(358) Underground Conductors and Devices |
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56 |
(359) Roads and Trails |
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57 |
(359.1) Asset Retirement Costs for Transmission Plant |
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58 |
TOTAL Transmission Plant (Enter Total of lines 48 thru 57) |
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59 |
4. Distribution Plant |
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60 |
(360) Land and Land Rights |
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61 |
(361) Structures and Improvements |
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62 |
(362) Station Equipment |
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63 |
(363) Energy Storage Equipment – Distribution |
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64 |
(364) Poles, Towers, and Fixtures |
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65 |
(365) Overhead Conductors and Devices |
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66 |
(366) Underground Conduit |
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67 |
(367) Underground Conductors and Devices |
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68 |
(368) Line Transformers |
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69 |
(369) Services |
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70 |
(370) Meters |
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71 |
(371) Installations on Customer Premises |
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72 |
(372) Leased Property on Customer Premises |
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73 |
(373) Street Lighting and Signal Systems |
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74 |
(374) Asset Retirement Costs for Distribution Plant |
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75 |
TOTAL Distribution Plant (Enter Total of lines 60 thru 74) |
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76 |
5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT |
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|
77 |
(380) Land and Land Rights |
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78 |
(381) Structures and Improvements |
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79 |
(382) Computer Hardware |
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80 |
(383) Computer Software |
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81 |
(384) Communication Equipment |
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82 |
(385) Miscellaneous Regional Transmission and Market Operation Plant |
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83 |
(386) Asset Retirement Costs for Regional Transmission and Market Oper |
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84 |
TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) |
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85 |
6. General Plant |
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86 |
(389) Land and Land Rights |
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87 |
(390) Structures and Improvements |
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88 |
(391) Office Furniture and Equipment |
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89 |
(392) Transportation Equipment |
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90 |
(393) Stores Equipment |
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91 |
(394) Tools, Shop and Garage Equipment |
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92 |
(395) Laboratory Equipment |
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93 |
(396) Power Operated Equipment |
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94 |
(397) Communication Equipment |
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95 |
(398) Miscellaneous Equipment |
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96 |
SUBTOTAL (Enter Total of lines 86 thru 95) |
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97 |
(399) Other Tangible Property |
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98 |
(399.1) Asset Retirement Costs for General Plant |
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99 |
TOTAL General Plant (Enter Total of lines 96, 97, and 98) |
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100 |
TOTAL (Accounts 101 and 106) |
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101 |
(102) Electric Plant Purchased (See Instr. 8) |
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102 |
(Less) (102) Electric Plant Sold (See Instr. 8) |
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|
103 |
(103) Experimental Plant Unclassified |
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|
104 |
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) |
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|
Name of Respondent: |
This report is: (1) ☑ An Original (2) ☐ A Resubmission |
Date of Report: |
Year/Period of Report End of: |
| FOOTNOTE DATA |
| (a) Concept: Organization | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Montana operations
| |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||