FERC Form

THIS FILING IS

Item 1:

☑ An Initial (Original) Submission

OR

☐ Resubmission No.




FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and 18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and other sanctions as provided by law. The Federal Energy Regulatory Commission does not consider these reports to be of confidential nature

Exact Legal Name of Respondent (Company)

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

Year/Period of Report

End of:

2021

/

Q4

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

GENERAL INFORMATION

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

What and Where to Submit

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

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

The CPA Certification Statement should:

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

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

Schedules	Pages
Comparative Balance Sheet	110-113
Statement of Income	114-117
Statement of Retained Earnings	118-119
Statement of Cash Flows	120-121
Notes to Financial Statements	122-123

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

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

GENERAL INSTRUCTIONS

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

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

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

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

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

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

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

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

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

AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment.

DEFINITIONS

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

EXCERPTS FROM THE LAW

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

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

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

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

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

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

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

"Sec. 304.

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

"Sec. 309.

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

GENERAL PENALTIES

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

FERC FORM NO.

1

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

IDENTIFICATION

01 Exact Legal Name of Respondent

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

02 Year/ Period of Report

End of:

2021

/

Q4

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

/

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

284 South Avenue, Poughkeepsie, NY 12601

05 Name of Contact Person

Christopher M. Capone

06 Title of Contact Person

Executive VP and CFO

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

284 South Avenue, Poughkeepsie, NY 12601

08 Telephone of Contact Person, Including Area Code

(845) 486-5439

09 This Report is An Original / A Resubmission

(1)

☑ An Original

(2)

☐ A Resubmission

10 Date of Report (Mo, Da, Yr)

04/18/2022

Annual Corporate Officer Certification

The undersigned officer certifies that:

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

01 Name

Christopher M. Capone

02 Title

Executive VP and CFO

03 Signature

Christopher M. Capone

04 Date Signed (Mo, Da, Yr)

04/18/2022

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

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line No.	Title of Schedule (a)	Reference Page No. (b)	Remarks (c)
	ScheduleIdentificationAbstract Identification	1
	ScheduleListOfSchedulesAbstract List of Schedules	2
1	ScheduleGeneralInformationAbstract General Information	101
2	ScheduleControlOverRespondentAbstract Control Over Respondent	102
3	ScheduleCorporationsControlledByRespondentAbstract Corporations Controlled by Respondent	103
4	ScheduleOfficersAbstract Officers	104
5	ScheduleDirectorsAbstract Directors	105
6	ScheduleInformationOnFormulaRatesAbstract Information on Formula Rates	106
7	ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Year	108
8	ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet	110
9	ScheduleStatementOfIncomeAbstract Statement of Income for the Year	114
10	ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Year	118
12	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120
12	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122
13	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Other Comp Income, Comp Income, and Hedging Activities	122a
14	ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep	200
15	ScheduleNuclearFuelMaterialsAbstract Nuclear Fuel Materials	202
16	ScheduleElectricPlantInServiceAbstract Electric Plant in Service	204
17	ScheduleElectricPropertyLeasedToOthersAbstract Electric Plant Leased to Others	213
18	ScheduleElectricPlantHeldForFutureUseAbstract Electric Plant Held for Future Use	214
19	ScheduleConstructionWorkInProgressElectricAbstract Construction Work in Progress-Electric	216
20	ScheduleAccumulatedProvisionForDepreciationOfElectricUtilityPlantAbstract Accumulated Provision for Depreciation of Electric Utility Plant	219
21	ScheduleInvestmentsInSubsidiaryCompaniesAbstract Investment of Subsidiary Companies	224
22	ScheduleMaterialsAndSuppliesAbstract Materials and Supplies	227
23	ScheduleAllowanceInventoryAbstract Allowances	228
24	ScheduleExtraordinaryPropertyLossesAbstract Extraordinary Property Losses	230a
25	ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract Unrecovered Plant and Regulatory Study Costs	230b
26	ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract Transmission Service and Generation Interconnection Study Costs	231
27	ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets	232
28	ScheduleMiscellaneousDeferredDebitsAbstract Miscellaneous Deferred Debits	233
29	ScheduleAccumulatedDeferredIncomeTaxesAbstract Accumulated Deferred Income Taxes	234
30	ScheduleCapitalStockAbstract Capital Stock	250
31	ScheduleOtherPaidInCapitalAbstract Other Paid-in Capital	253
32	ScheduleCapitalStockExpenseAbstract Capital Stock Expense	254b
33	ScheduleLongTermDebtAbstract Long-Term Debt	256
34	ScheduleReconciliationOfReportedNetIncomeWithTaxableIncomeForFederalIncomeTaxesAbstract Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax	261
35	ScheduleTaxesAccruedPrepaidAndChargedDuringYearDistributionOfTaxesChargedAbstract Taxes Accrued, Prepaid and Charged During the Year	262
36	ScheduleAccumulatedDeferredInvestmentTaxCreditsAbstract Accumulated Deferred Investment Tax Credits	266
37	ScheduleOtherDeferredCreditsAbstract Other Deferred Credits	269
38	ScheduleAccumulatedDeferredIncomeTaxesAcceleratedAmortizationPropertyAbstract Accumulated Deferred Income Taxes-Accelerated Amortization Property	272
39	ScheduleAccumulatedDeferredIncomeTaxesOtherPropertyAbstract Accumulated Deferred Income Taxes-Other Property	274
40	ScheduleAccumulatedDeferredIncomeTaxesOtherAbstract Accumulated Deferred Income Taxes-Other	276
41	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278
42	ScheduleElectricOperatingRevenuesAbstract Electric Operating Revenues	300
43	ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1)	302
44	ScheduleSalesOfElectricityByRateSchedulesAbstract Sales of Electricity by Rate Schedules	304
45	ScheduleSalesForResaleAbstract Sales for Resale	310
46	ScheduleElectricOperationsAndMaintenanceExpensesAbstract Electric Operation and Maintenance Expenses	320
47	SchedulePurchasedPowerAbstract Purchased Power	326
48	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
49	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331
50	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
51	ScheduleMiscellaneousGeneralExpensesAbstract Miscellaneous General Expenses-Electric	335
52	ScheduleDepreciationDepletionAndAmortizationAbstract Depreciation and Amortization of Electric Plant (Account 403, 404, 405)	336
53	ScheduleRegulatoryCommissionExpensesAbstract Regulatory Commission Expenses	350
54	ScheduleResearchDevelopmentOrDemonstrationExpendituresAbstract Research, Development and Demonstration Activities	352
55	ScheduleDistributionOfSalariesAndWagesAbstract Distribution of Salaries and Wages	354
56	ScheduleCommonUtilityPlantAndExpensesAbstract Common Utility Plant and Expenses	356
57	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts included in ISO/RTO Settlement Statements	397
58	SchedulePurchasesSalesOfAncillaryServicesAbstract Purchase and Sale of Ancillary Services	398
59	ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load	400
60	ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load	400a
61	ScheduleElectricEnergyAccountAbstract Electric Energy Account	401a
62	ScheduleMonthlyPeakAndOutputAbstract Monthly Peaks and Output	401b
63	ScheduleSteamElectricGeneratingPlantStatisticsAbstract Steam Electric Generating Plant Statistics	402
64	ScheduleHydroelectricGeneratingPlantStatisticsAbstract Hydroelectric Generating Plant Statistics	406
65	SchedulePumpedStorageGeneratingPlantStatisticsAbstract Pumped Storage Generating Plant Statistics	408
66	ScheduleGeneratingPlantStatisticsAbstract Generating Plant Statistics Pages	410
0	ScheduleEnergyStorageOperationsLargePlantsAbstract Energy Storage Operations (Large Plants)	414
67	ScheduleTransmissionLineStatisticsAbstract Transmission Line Statistics Pages	422
68	ScheduleTransmissionLinesAddedAbstract Transmission Lines Added During Year	424
69	ScheduleSubstationsAbstract Substations	426
70	ScheduleTransactionsWithAssociatedAffiliatedCompaniesAbstract Transactions with Associated (Affiliated) Companies	429
71	FootnoteDataAbstract Footnote Data	450
	StockholdersReportsAbstract Stockholders' Reports (check appropriate box)
	Stockholders' Reports Check appropriate box: ☐ Two copies will be submitted ☐ No annual report to stockholders is prepared

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general corporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the general corporate books are kept. Christopher M. Capone Executive Vice President and Chief Financial Officer 284 South Ave, Poughkeepsie, NY 12601
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized. State of Incorporation: NY Date of Incorporation: 1926-12-31 Incorporated Under Special Law: Transportationn Corporation Law
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased. (a) Name of Receiver or Trustee Holding Property of the Respondent: (b) Date Receiver took Possession of Respondent Property: (c) Authority by which the Receivership or Trusteeship was created: (d) Date when possession by receiver or trustee ceased:
4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated. Electricity for light, heat and power.Natural Gas (not less than 1,000 BTUs) for heating, cooling and industrial purposes. All operations in New York State
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant for your previous year's certified financial statements? (1) ☐ Yes (2) ☑ No

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

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

In April 1998, Central Hudson Gas & Electric Corporation formed a wholly-owned subsidiary named CH Energy Group, Inc., which after a one-for-one share exchange on December 15, 1999 became the holding company parent of Central Hudson and its existing subsidiaries.On February 21, 2012, CH Energy Group announced that it had entered into an agreement and plan of merger under which it agreed, subject to shareholder approval and approval of applicable regulatory authorities, to be acquired by Fortis, Inc. for $65 per share of common stock in cash. On June 13, 2013, the New York Public Service Commission voted to approve acquisition of CH Energy Group by Fortis, Inc. On June 27, 2013 after receipt, review and acceptance of the Order Authorizing Acquisition Subject to Conditions, the acquisition was completed. All of CH Energy Group's common stock is indirectly owned by Fortis, Inc.

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

CORPORATIONS CONTROLLED BY RESPONDENT
Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests. Definitions See the Uniform System of Accounts for a definition of control. Direct control is that which is exercised without interposition of an intermediary. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line No.	NameOfCompanyControlledByRespondent Name of Company Controlled (a)	CompanyControlledByRespondentKindOfBusinessDescription Kind of Business (b)	VotingStockOwnedByRespondentPercentage Percent Voting Stock Owned (c)	FootnoteReferences Footnote Ref. (d)
1
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3
4
5
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7
8
9
10
11
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Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

OFFICERS
Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made.
Line No.	OfficerTitle Title (a)	OfficerName Name of Officer (b)	OfficerSalary Salary for Year (c)	DateOfficerIncumbencyStarted Date Started in Period (d)	DateOfficerIncumbencyEnded Date Ended in Period (e)
1	Executive Vice President & Chief Financial Officer	Christopher M. Capone	486,000
2	President & CEO, Director	Charles A. Freni	610,000
3	Treasurer	Stacey A. Renner	280,000
4	Vice President – Electric Engineering & Operations	Ryan G. Hawthorne	225,000	2021-01-01
5	Senior Vice President – Customer Services & Gas Operations	Anthony S. Campagiorni	329,000
6	Senior Vice President - Human Resources & Safety	Sharon A. McGinnis	317,000
7	Chief Technology Officer	Donna Kladis	320,000
8	General Counsel & Corporate Secretary	(a) Joseph B. Koczko

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: OfficerName

Notes:

- Joseph R. Koczko, General Counsel and Corporate Secretary, is employed by the respondent's outside Legal Council, and does not receive compensation directly from the respondent.

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

DIRECTORS
Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), name and abbreviated titles of the directors who are officers of the respondent. Provide the principle place of business in column (b), designate members of the Executive Committee in column (c), and the Chairman of the Executive Committee in column (d).
Line No.	NameAndTitleOfDirector Name (and Title) of Director (a)	PrincipalBusinessAddress Principal Business Address (b)	MemberOfTheExecutiveCommittee Member of the Executive Committee (c)	ChairmanOfTheExecutiveCommittee Chairman of the Executive Committee (d)
1	Charles A. Freni, President and Chief Executive Officer,	Poughkeepsie, NY
2	Central Hudson
3	NOTE:
4	Charles A. Freni, an employee of Central Hudson Gas and
5	Electric during 2021, was appointed to the Board of
6	Directors on September 15, 2018 and as such did not receive
7	an annual retainer of fees for attendance at Board meetings.
8	Compensation is shown on page 104.

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

INFORMATION ON FORMULA RATES
Does the respondent have formula rates?		☐ Yes ☐ No
Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No) accepting the rate(s) or changes in the accepted rate.
Line No.	RateScheduleTariffNumber FERC Rate Schedule or Tariff Number (a)	ProceedingDocketNumber FERC Proceeding (b)
1
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32
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34
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36
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38
39
40
41

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent) filings containing the inputs to the formula rate(s)?			☐ Yes ☑ No (Checked by default - Not explicitly defined)
If yes, provide a listing of such filings as contained on the Commission's eLibrary website.
Line No.	AccessionNumber Accession No. (a)	DocumentDate Document Date / Filed Date (b)	DocketNumber Docket No. (c)	DescriptionOfFiling Description (d)	RateScheduleTariffNumber Formula Rate FERC Rate Schedule Number or Tariff Number (e)
1
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5
6
7
8
9
10
11
12
13
14
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44
45
46

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

INFORMATION ON FORMULA RATES - Formula Rate Variances
If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from amounts reported in the Form 1. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the Form 1. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line No.	PageNumberOfFormulaRateVariances Page No(s). (a)	ScheduleOfFormulaRateVariances Schedule (b)	ColumnOfFormulaRateVariances Column (c)	LineNumberOfFormulaRateVariances Line No. (d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
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33
34
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39
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42
43
44

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

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

1. None
2. None
3. None
4. None
5. There were no important extensions/reductions in transmission/distribution systems. No new territories were added. Regarding the Company's natural gas supplies and storage capabilities, there were no major new sources of natural gas made available from purchases, developments, purchase-contract or otherwise. All major contracts for 2021 were effectively the same as those which had been in effect at December 31, 2020. There were no significant changes in pipeline or storage capabilities during 2021. Effective August 1, 2020 Central Hudson has entered into an Asset Management Agreement with a third party related to its natural gas transport and storage capacity. Central Hudson continues to make purchases of natural gas in advance of the peak winter season to hedge against price volatility for its customers. However, based on the terms of the agreement, the third party will provide physical storage levels in line with our virtual hedge purchases at the beginning of each winter season and will maintain control and title over the physical gas in storage until the end of the contract term.
6. See Notes 9, 10, and 11 of the Notes to the Annual Financial Statements on FERC filing pages 123–123.XX.
7. None
8. None
9. For more information about developments regarding legal proceedings, please see Note 14 Commitments and Contingencies of the Notes to the Annual Financial Statements on FERC filing pages 123–123.XX.
10. None
12. N/A
13. Changes to officers and directors of Central Hudson for the year ended December 31, 2021 are as follows: Jocelyn Perry resigned from the Central Hudson Board of Directors effective March 31, 2021. Effective April 1, 2021, Susan Gray joined the Central Hudson Board of Directors. James P. Laurito resigned from the Central Hudson Board of Directors effective December 31, 2021. Effective January 1, 2022, James R. Reid joined the Central Hudson Board of Directors. Anthony S. Campagiorni’s title changed from VP of Customer Services and Gas Operations to Senior VP of Customer Services and Gas Operations effective January 1, 2022. Sharon A McGinnis’s title changed from VP of Human Resources and Safety to Senior VP of Human Resources and Safety effective January 1, 2022.
14. N/A

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlant Utility Plant (101-106, 114)	200	2,854,306,923	2,649,647,148
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	118,181,553	126,011,785
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		2,972,488,476	2,775,658,933
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	693,501,938	652,369,206
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		2,278,986,538	2,123,289,727
7	NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)	202
8	NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
9	NuclearFuelAssembliesInReactorMajorOnly Nuclear Fuel Assemblies in Reactor (120.3)
10	SpentNuclearFuelMajorOnly Spent Nuclear Fuel (120.4)
11	NuclearFuelUnderCapitalLeases Nuclear Fuel Under Capital Leases (120.6)
12	AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)	202
13	NuclearFuelNet Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
14	UtilityPlantAndNuclearFuelNet Net Utility Plant (Enter Total of lines 6 and 13)		2,278,986,538	2,123,289,727
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		524,237	524,237
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228
24	OtherInvestments Other Investments (124)		40,197,800	32,965,704
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)		14,934,406	11,710,802
29	SpecialFunds Special Funds (Non Major Only) (129)
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		55,656,443	45,200,743
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		3,735,888	3,852,165
36	SpecialDeposits Special Deposits (132-134)		11,010,885	1,548,308
37	WorkingFunds Working Fund (135)		15,016	15,016
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		113,046,185	72,654,832
41	OtherAccountsReceivable Other Accounts Receivable (143)		16,736,131	10,670,745
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		11,200,000	10,400,000
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		35,546	189,008
45	FuelStock Fuel Stock (151)	227	490,486	372,604
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227
47	Residuals Residuals (Elec) and Extracted Products (153)	227
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	23,624,491	23,303,920
49	Merchandise Merchandise (155)	227
50	OtherMaterialsAndSupplies Other Materials and Supplies (156)	227
51	NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157)	202/227
52	AllowanceInventoryAndWithheld Allowances (158.1 and 158.2)	228
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227	795	871
55	GasStoredCurrent Gas Stored Underground - Current (164.1)
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57	Prepayments Prepayments (165)		37,400,008	33,750,847
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)		241,759	188,955
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		26,890,808	27,836,404
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		75,749	75,749
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		164,160
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)		222,267,907	164,059,424
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		5,101,845	4,747,888
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	140,724,324	201,615,853
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)		834,212	817,494
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	770,687	389,938
79	DeferredLossesFromDispositionOfUtilityPlant Def. Losses from Disposition of Utility Plt. (187)
80	ResearchDevelopmentAndDemonstrationExpenditures Research, Devel. and Demonstration Expend. (188)	352	543,703
81	UnamortizedLossOnReacquiredDebt Unamortized Loss on Reaquired Debt (189)		1,507,601	1,860,470
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	140,330,137	129,094,837
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		289,812,509	338,526,480
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		2,846,723,397	2,671,076,374

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

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	84,310,435	84,310,435
3	PreferredStockIssued Preferred Stock Issued (204)	250	100	100
4	CapitalStockSubscribed Capital Stock Subscribed (202, 205)
5	StockLiabilityForConversion Stock Liability for Conversion (203, 206)
6	PremiumOnCapitalStock Premium on Capital Stock (207)		63,840,146	63,840,146
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	216,611,522	210,611,522
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	4,632,842	4,632,842
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	572,037,794	498,611,137
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)	18,651	161,194
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		932,185,806	852,579,304
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	922,800,000	836,950,000
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)		922,800,000	836,950,000
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		3,154,594	3,281,106
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		5,005,936	4,969,544
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		100,277,313	17,667,888
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)		3,102,160	1,854,174
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		89,014,623	27,772,712
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)		107,000,000	15,000,000
38	AccountsPayable Accounts Payable (232)		68,194,824	63,650,458
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		822,830	931,478
41	CustomerDeposits Customer Deposits (235)		7,539,437	7,564,422
42	TaxesAccrued Taxes Accrued (236)	262	4,353,812	8,593,745
43	InterestAccrued Interest Accrued (237)		8,159,849	7,584,534
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		846,905	247,110
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		21,107,815	21,753,421
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		432,742	345,001
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		5,959,106	2,134,951
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)		224,417,320	127,805,120
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)		12,783,554	3,370,194
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	113,735,904	120,676,286
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	304,604,307	314,422,629
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)		256,583,807	238,118,907
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		168,627,322	149,381,222
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		856,334,894	825,969,238
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		2,846,723,397	2,671,076,374

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

STATEMENT OF INCOME
Quarterly Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k) the quarter to date amounts for other utility function for the current year quarter. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l) the quarter to date amounts for other utility function for the prior year quarter. If additional columns are needed, place them in a footnote. Annual or Quarterly if applicable Do not report fourth quarter data in columns (e) and (f) Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility column in a similar manner to a utility department. Spread the amount(s) over Lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above. Use page 122 for important notes regarding the statement of income for any account thereof. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases. Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases, and a summary of the adjustments made to balance sheet, income, and expense accounts. If any notes appearing in the report to stockholders are applicable to the Statement of Income, such notes may be included at page 122. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line No.	Title of Account (a)	(Ref.) Page No. (b)	Total Current Year to Date Balance for Quarter/Year (c)	Total Prior Year to Date Balance for Quarter/Year (d)	Current 3 Months Ended - Quarterly Only - No 4th Quarter (e)	Prior 3 Months Ended - Quarterly Only - No 4th Quarter (f)	Electric Utility Current Year to Date (in dollars) (g)	Electric Utility Previous Year to Date (in dollars) (h)	Gas Utiity Current Year to Date (in dollars) (i)	Gas Utility Previous Year to Date (in dollars) (j)	Other Utility Current Year to Date (in dollars) (k)	Other Utility Previous Year to Date (in dollars) (l)
1	UtilityOperatingIncomeAbstract UTILITY OPERATING INCOME
2	OperatingRevenues Operating Revenues (400)	300	796,283,158	711,889,037			623,770,816	551,787,726	172,512,342	160,101,311
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	467,363,751	404,600,011			374,868,147	325,118,270	92,495,604	79,481,741
5	MaintenanceExpense Maintenance Expenses (402)	320	60,530,337	57,576,832			52,060,602	48,729,544	8,469,735	8,847,288
6	DepreciationExpense Depreciation Expense (403)	336	59,120,980	54,769,154			44,264,357	41,157,867	14,856,623	13,611,287
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	14,275,369	12,607,613			11,515,193	10,099,897	2,760,176	2,507,716
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336
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)		1,500,000				1,500,000
13	RegulatoryCredits (Less) Regulatory Credits (407.4)
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	71,122,928	67,617,864			52,123,145	50,646,293	18,999,783	16,971,571
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	476,000	215,484			424,800	218,188	51,200	2,704
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	1,829,000	280,620			1,461,300	240,172	367,700	40,448
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	51,497,567	36,481,203			38,626,681	24,807,883	12,870,886	11,673,320
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	35,081,426	20,792,172			27,395,405	15,608,136	7,686,021	5,184,036
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)		692,634,505	613,356,609			549,448,819	485,409,978	143,185,686	127,946,631
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		103,648,653	98,532,428			74,321,997	66,377,748	29,326,656	32,154,680
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)		1,563,164	1,154,372
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		3,430,724	2,993,207
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		715,456	519,480
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		5,709,344	4,667,059
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		269,601	282,439
46	LifeInsurance Life Insurance (426.2)		532,564	521,884
47	Penalties Penalties (426.3)		20,000	140,047
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		155,362	72,610
49	OtherDeductions Other Deductions (426.5)		996,589	332,416
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		908,987	305,628
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	112,346	111,433
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	476,000	234,000
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	157,000	79,000
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	199,600	615,400
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	177,600	20,200
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)		897,854	796,767
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		5,698,211	5,158,198
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		33,549,947	31,977,445
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		368,694	389,249
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		352,869	516,120
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)		3,189,573	3,405,463
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		1,540,875	1,541,802
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		35,920,208	34,746,475
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		73,426,657	68,944,151
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)		73,426,657	68,944,151

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

STATEMENT OF RETAINED EARNINGS
Do not report Lines 49-53 on the quarterly report. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436-439 inclusive). Show the contra primary account affected in column (b). State the purpose and amount for each reservation or appropriation of retained earnings. List first Account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items, in that order. Show dividends for each class and series of capital stock. Show separately the State and Federal income tax effect of items shown for Account 439, Adjustments to Retained Earnings. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated. If any notes appearing in the report to stockholders are applicable to this statement, attach them at page 122.
Line No.	Item (a)	Contra Primary Account Affected (b)	Current Quarter/Year Year to Date Balance (c)	Previous Quarter/Year Year to Date Balance (d)
	UnappropriatedRetainedEarningsAbstract UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1	UnappropriatedRetainedEarnings Balance-Beginning of Period		498,611,137	430,866,986
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
10.1	AdjustmentsToRetainedEarningsDebit Cumulative effect adjustment related to the adoption of CECL			1,200,000
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)			1,200,000
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		73,426,657	68,944,151
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)
23	DividendsDeclaredPreferredStockAbstract Dividends Declared-Preferred Stock (Account 437)
29	DividendsDeclaredPreferredStock TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30	DividendsDeclaredCommonStockAbstract Dividends Declared-Common Stock (Account 438)
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)
37	TransfersFromUnappropriatedUndistributedSubsidiaryEarnings Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38	UnappropriatedRetainedEarnings Balance - End of Period (Total 1,9,15,16,22,29,36,37)		572,037,794	498,611,137
39	AppropriatedRetainedEarningsAbstract APPROPRIATED RETAINED EARNINGS (Account 215)
45	AppropriatedRetainedEarnings TOTAL Appropriated Retained Earnings (Account 215)
	AppropriatedRetainedEarningsAmortizationReserveFederalAbstract APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46	AppropriatedRetainedEarningsAmortizationReserveFederal TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		572,037,794	498,611,137
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)
51	DividendsReceived (Less) Dividends Received (Debit)
52	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

STATEMENT OF CASH FLOWS
Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost.
Line No.	Description (See Instructions No.1 for explanation of codes) (a)	Current Year to Date Quarter/Year (b)	Previous Year to Date Quarter/Year (c)
1	NetCashFlowFromOperatingActivitiesAbstract Net Cash Flow from Operating Activities
2	NetIncomeLoss Net Income (Line 78(c) on page 117)	73,426,657	68,944,151
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	58,909,724	54,558,098
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Intangible Utility Plant Assets	13,805,509	12,305,251
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Prepaid and accrued income taxes	31,000	272,554
5.3	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Net Increase (Decrease) in Accrued Interest	575,315	586,774
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	16,038,697	15,093,833
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	53,542,023	14,289,011
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	438,377	2,533,954
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	4,487,214	9,019,411
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	39,993,948	9,351,648
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	15,054,348	21,440,179
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	3,430,724	2,993,208
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Provision for uncollectibles	6,074,390	10,009,950
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Pension expense	400,632	2,340,221
18.3	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription OPEB expense	6,047,561	6,355,109
18.4	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Special deposits	3,996,823	5,423,654
18.5	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Pension plan contributions	1,474,707	1,129,915
18.6	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription OPEB contribution	812,444	1,080,799
18.7	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Customer advances	2,812,415	389,157
18.8	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Accrued pension	5,051,788	4,287,101
18.9	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Accrued OPEB	379,125	352,901
18.10	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other, net	3,147,270	12,358,736
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	53,190,977	130,443,461
24	CashFlowsFromInvestmentActivitiesAbstract Cash Flows from Investment Activities:
25	ConstructionAndAcquisitionOfPlantIncludingLandAbstract Construction and Acquisition of Plant (including land):
26	GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities Gross Additions to Utility Plant (less nuclear fuel)	165,731,748	194,473,396
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant	69,507,862	61,376,474
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	3,430,724	2,993,208
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Capitalized depreciation	2,075,631	2,156,352
31.2	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription SERP funding	6,723,439	5,890,760
31.3	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Other	22,090	248,438
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	236,434,604	256,839,508
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)
39	InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Investments in and Advances to Assoc. and Subsidiary Companies
40	ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies Contributions and Advances from Assoc. and Subsidiary Companies
41	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract Disposition of Investments in (and Advances to)
42	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
44	PurchaseOfInvestmentSecurities Purchase of Investment Securities (a)
45	ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a)
46	LoansMadeOrPurchased Loans Made or Purchased
47	CollectionsOnLoans Collections on Loans
49	NetIncreaseDecreaseInReceivablesInvestingActivities Net (Increase) Decrease in Receivables
50	NetIncreaseDecreaseInInventoryInvestingActivities Net (Increase) Decrease in Inventory
51	NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities Net (Increase) Decrease in Allowances Held for Speculation
52	NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities Net Increase (Decrease) in Payables and Accrued Expenses
53	OtherAdjustmentsToCashFlowsFromInvestmentActivities Other (provide details in footnote):
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	236,434,604	256,839,508
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	130,000,000	130,000,000
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
64.1	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Contributions and Advances from Subsidiaries and Associated Companies	6,000,000	12,000,000
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)	92,000,000	15,000,000
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	228,000,000	157,000,000
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	44,150,000	40,000,000
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Debt issuance costs	722,650	746,744
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	183,127,350	116,253,256
85	NetIncreaseDecreaseInCashAndCashEquivalentsAbstract Net Increase (Decrease) in Cash and Cash Equivalents
86	NetIncreaseDecreaseInCashAndCashEquivalents Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83)	116,277	10,142,791
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	3,867,181	14,009,972
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	(a) 3,750,904	3,867,181

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: CashAndCashEquivalents


Schedule Page 120: Line: 90

Reconciliation of Cash and Cash Equivalents:	Year to date	Previous Year
	Current	to date
	Period

Cash (131)	3,735,888	3,852,165
Working Funds (135)	15,016	15,016

Total Cash and Cash Equivalents	3,750,904	3,867,181

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

NOTES TO FINANCIAL STATEMENTS

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

NOTE 1 – Basis of Presentation- FERC Form 1

The financial statements of Central Hudson Gas & Electric Corporation are presented on the basis of accounting requirements of the Federal Energy Regulatory Commission (FERC) as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America (GAAP).

The principal differences from the GAAP financial statements include the following:

•Cost of removal obligations are included in the accumulated provision for depreciation and reported as a regulatory liability in the GAAP financial statements.

•Long-term debt is presented as a long-term liability rather than both a current and long-term liability in the GAAP financial statements.

•Accumulated deferred income taxes are reported on a gross basis for FERC reporting and a net basis for GAAP reporting.

•Prefunded pension costs are recorded net for GAAP reporting purposes within accrued pension and are separately reported within the Other Property and Investments for FERC reporting.

•Deferred compensation and other investments are presented as a long-term asset for GAAP reporting and recorded within Other Property and Investments for FERC.

•Unamortized debt expense is presented net within long-term debt for GAAP reporting and a long-term asset for FERC reporting.

•The classification of certain assets and liabilities between current and long-term presentation and the gross and net basis.

•Certain income tax expenses are presented within operating expenses and other income for FERC reporting purposes.

•Restricted cash is included in the cash and cash equivalents balances in the GAAP financial statements.

•The non-service cost component of Post Retirement Benefits costs is reported in operating expenses for FERC reporting and in other income and deductions for GAAP reporting.

•In accordance with guidance under ASC 980, disallowed NWA incentives under GAAP reporting have been adjusted out of the related FERC reporting balances.

•In accordance with guidance under ASC 842, ROU asses are presented as utility plant for FERC reporting and as other long-term assets in the GAAP financial statements.

The notes provided herein were derived from the notes appearing in the Consolidated Annual Report of CH Energy Group, Inc. and Central Hudson Gas & Electric Corporation.

NOTE 1A – Summary of Significant Accounting Policies

Corporate Structure

CH Energy Group is the holding company parent corporation of four principal, wholly owned subsidiaries, Central Hudson Gas & Electric Corporation (“Central Hudson” or the “Company”), Central Hudson Electric Transmission LLC (“CHET”), Central Hudson Enterprises Corporation (“CHEC”) and Central Hudson Gas Transmission LLC (“CHGT”). CH Energy Group’s common stock is indirectly owned by Fortis Inc. (“Fortis”), which is a leader in the North American regulated electric and gas utility industry. Central Hudson is a regulated electric and natural gas transmission and distribution utility. CH Energy Group formed CHET to hold its 6.1% ownership interest in New York Transco LLC (“Transco”). CHGT was formed to hold CH Energy Group’s ownership stake in possible gas transmission pipeline opportunities in New York State. As of December 31, 2019 there has been no activity in CHGT. CHEC has ownership interests in certain non-regulated subsidiaries that are less than 100% owned.

Basis of Presentation

This Annual Financial Report is a combined report of CH Energy Group and Central Hudson. The Notes to the Consolidated Financial Statements apply to both CH Energy Group and Central Hudson. CH Energy Group’s Consolidated Financial Statements include the accounts of CH Energy Group and its wholly owned subsidiaries, which include Central Hudson, CHET, CHGT and CHEC. All intercompany balances and transactions have been eliminated in consolidation. CHEC’s investments in limited partnerships and limited liability companies and CHET’s investment in Transco are accounted for under the equity method.

The Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”), which for regulated utilities, includes specific accounting guidance for regulated operations.

Preparation of the financial statements in accordance with GAAP includes the use of estimates and assumptions by management that affect the reported amounts of assets, liabilities and the disclosures of the contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. As with all estimates, actual results may differ

from those estimated. Estimates may be subject to future uncertainties, including the continued evolution of the novel Coronavirus pandemic (“COVID-19”), which could affect the allowance for uncollectible accounts, as well as the total impact and potential recovery of incremental costs associated with COVID-19.

Estimates are also reflected for certain commitments and contingencies where there is sufficient basis to project a future obligation. Disclosures related to these certain commitments and contingencies are included in Note 14 - “Commitments and Contingencies”.

Regulatory Accounting Policies

Central Hudson is subject to cost-based rate regulation. As a result, the effects of regulatory actions are required to be reflected in the financial statements. Regulatory accounting guidance results in differences in the application of GAAP between regulated and non-regulated businesses and requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as expense or revenue in non-regulated businesses. Regulated utilities, such as Central Hudson, defer costs and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those costs and revenues will be recoverable/refundable through the rate-making process in a period different from when they otherwise would have been reflected in income. For Central Hudson, these deferred regulatory assets and liabilities, and the related deferred taxes, are recovered from or reimbursed to customers either by offset as directed by the New York State Public Service Commission (“PSC” or “Commission”), through an approved surcharge mechanism or through incorporation in the determination of revenue requirement used to set new rates. Changes in regulatory assets and liabilities are reflected in the Consolidated Statement of Income either in the period in which the amounts are recovered through a surcharge, are reflected in rates or when the criteria for recording the revenues is met. Current accounting practices reflect the regulatory accounting authorized in Central Hudson’s most recent Rate Orders. On June 14, 2018, the PSC issued an Order Approving Rate Plan in Cases 17-E-0459 and 17-G-0460 (the “2018 Rate Order”) and on November 18, 2021, the PSC issued an Order Approving Rate Plan in Cases 20-E-0428 and 20-G-0429 (the “2021 Rate Order”). See Note 4 – “Regulatory Matters” for additional information regarding regulatory accounting.

Management periodically assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to Central Hudson and other regulated entities, and the status of any pending or potential deregulation legislation. Based on this assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels and is subject to change in the future. If future recovery of costs ceases to be probable, the regulatory asset would be written-off, which would materially impact earnings. Additionally, the regulatory agencies can provide flexibility in the manner and timing of recovery of regulatory assets.

Rates, Revenues, and Cost Adjustment Mechanisms

Central Hudson’s electric and natural gas retail rates are regulated by the PSC. Wholesale transmission rates, facilities charges, and rates for electricity sold for resale in interstate commerce are regulated by the Federal Energy Regulatory Commission (“FERC”) and are collected via the Open Access Transmission Tariff (“OATT”) administered by the New York Independent System Operator (“NYISO”) or directly by the Company.

Central Hudson’s tariffs for retail electric and natural gas service include purchased electricity and purchased natural gas cost adjustment mechanisms by which electric and natural gas rates are set to recover the actual purchased electricity and purchased natural gas costs including hedging costs

incurred in providing these services. In addition, the tariffs include adjustment mechanisms to recover from or refund to customers certain revenues and costs that have been deferred such as RDMs, Rate Moderators, incentives earned or other Earnings Adjustment Mechanisms (“EAMs”), and other specified accumulated deferred balances recovered via the RAM as defined in the Rate Orders. See Note 4 – “Regulatory Matters” for definitions. RDMs generally provide the ability to record revenue equal to revenue targets authorized by the PSC and used for the development of rates for most of Central Hudson’s customers.

Revenue Recognition

Revenue from Contracts with Customers

Central Hudson records revenue as electric and natural gas is delivered based on either the customers’ meter read or estimated usage for the month. For full service customers, this includes delivery and supply of electricity and natural gas. For retail choice customers, this includes delivery only as these customers purchase supply from a retail marketer. Customers simultaneously receive and consume the benefits provided by Central Hudson. Revenue consists of a fixed customer charge and a charge per kWh or Ccf, that is fixed at the time of delivery. Additionally, certain non-residential electric service customers pay a per KW demand charge which is also fixed at the time of delivery. All performance obligations are satisfied for tariff sales at the time of delivery. Amounts billed to customers are due within 20 days from the date the bill was rendered, and any payment not received by the due date is considered delinquent and incurs a late payment fee. Effective April 1, 2020, Central Hudson temporarily suspended finance charges on past due balances to help mitigate the impacts of the COVID-19 pandemic on our customers.

Central Hudson records an estimate of unbilled revenue for service rendered to customers subsequent to their billing date and through the end of the month. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales and customer usage patterns.

Central Hudson receives payments from certain customers based on a predetermined budget billing schedule. Budget billing does not represent a contract asset or liability but rather just a receivable/liability because there are no further performance obligations required to be satisfied before the Company has the right to collect/refund the customer’s consideration. Consideration is due when control of the energy is transferred to the customer and is satisfied with the passage of time. Budget billing liability balances are recorded within the customer advances line item in the balance sheet.

Central Hudson provides discounts through certain customer assistance programs intended to help low to moderate income families manage their energy burden as prescribed in the 2021 Rate Order with a full deferral mechanism. Discounts available under these programs are determined at the time the performance obligation is satisfied and are recorded as an expense to match revenue collected in rates for the benefit of eligible customers.

Alternative Revenues

In accordance with Accounting Standard Codification (“ASC”) 980, and as authorized by the PSC, Central Hudson records alternative revenues in response to past activities or completed events, if certain criteria are met. Central Hudson has identified alternative revenue programs in both its electric and natural gas revenues. Alternative revenues are generally intended to compensate a regulated

utility for fluctuations in revenue due to weather abnormalities, external factors and demand side initiatives promoted by the regulator, as well as incentive awards if the utility achieves certain objectives, such as reducing costs, reaching specified milestones, or improving customer service. Central Hudson recognizes alternative revenues when the criteria associated with the mechanism and ASC 980 have been met and not when billed to customers.

Other Revenues

Other revenues, which are not contract revenues, consist of pole attachment rents, finance charges, miscellaneous fees and other revenue adjustments. Included in other revenue adjustments is the reversal of previously recognized deferrals as they are billed (collected/refunded to customers) pursuant to PSC Orders.

Cash and Cash Equivalents

CH Energy Group and Central Hudson consider temporary cash investments with a maturity (when purchased) of three months or less to be cash equivalents.

Restricted Cash

Restricted cash primarily consists of cash collected from developers and held in escrow related to a System Deliverability Upgrade project pursuant to terms and conditions of the NYISO OATT.

The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported on the Balance Sheets for CH Energy Group and Central Hudson that sum to the total of the same such amounts shown in the corresponding Statements of Cash Flows.


CH Energy Group
(In Thousands)
		December 31,		December 31,
		2021		2020
Cash and cash equivalents		$	7,339	$	11,480
Restricted cash included in other long-term assets			10,790		1,327
	Total cash, cash equivalents and restricted cash shown in the statement of cash flows	$	18,129	$	12,807

Central Hudson
(In Thousands)
		December 31,		December 31,
		2021		2020
Cash and cash equivalents		$	3,751	$	3,867
Restricted cash included in other long-term assets			10,790		1,327
	Total cash, cash equivalents and restricted cash shown in the statement of cash flows	$	14,541	$	5,194

Supplemental Cash Flow Information


	December 31,		December 31,
	2021		2020
Supplemental Information:
Interest Paid, Net of Amounts Capitalized	$	31,841,519	$	30,161,902
Federal and State Income Taxes (Refunded) Paid		2,021,000		501,372

Non-cash Investing Activities:
Additions to Utility Plant Assets included in Liabilities		21,683,264		21,241,240

Accounts Receivable and Allowance for Uncollectible Accounts

Beginning on January 1, 2020, receivables and unbilled utility revenues are carried at net realizable value based on the allowance for credit losses model. The accounts receivable balance also reflects Central Hudson’s purchase of receivables from energy service companies to support the retail choice programs. The allowance for uncollectible accounts reflects management’s best estimate of expected credit losses to reduce accounts receivable for amounts estimated to be uncollectible. Estimates for uncollectible accounts are based on accounts receivable aging data, as well as consideration of various quantitative and qualitative factors, including special collection issues and current and forecasted economic conditions. Interest can be charged on accounts receivable balances that have been outstanding for more than 20 days. See Note 2 – “Revenues and Receivables” for a discussion of the impact of COVID-19 on interest charges and other revenue.

Financial Instruments

Effective January 1, 2020, CH Energy Group and Central Hudson adopted accounting guidance that requires the use of reasonable and supportable forecasts in the estimate of credit losses and the recognition of expected losses upon initial recognition of a financial instrument, in addition to using past events and current conditions. CH Energy Group and Central Hudson’s allowance for credit losses increased $1.2 million as a result of the adoption of this accounting standard and was recorded as a cumulative adjustment to retained earnings effective January 1, 2020. At December 31, 2021 and December 31, 2020 there are no expected credit losses on financial instruments other than those on accounts receivable and unbilled utility revenues.

Fuel, Materials & Supplies

The following is a summary of CH Energy Group’s and Central Hudson’s inventory of Fuel, Materials & Supplies valued using the average cost method (In Thousands):


		December 31,		December 31,
		2021		2020
Fuel used in electric generation			491		373
Materials and supplies			23,625		23,305
	Total	$	24,116	$	23,677

Effective August 1, 2020 Central Hudson entered into an Asset Management Agreement (“AMA”) with a third party related to its natural gas transport and storage capacity. Central Hudson continues to make purchases of natural gas in advance of the peak winter season to hedge against price volatility for its customers. However, based on the terms of the agreement, the third party will maintain control and title over the physical gas in storage until the end of the contract term. Amounts related to the AMA are recorded in “Special deposits and prepayments” in CH Energy Group’s and Central Hudson’s Balance Sheets.

Utility Plant - Central Hudson

The regulated assets of Central Hudson include electric, natural gas and common assets, which are listed under the heading “Utility Plant” on CH Energy Group’s Consolidated Balance Sheet and Central Hudson’s Balance Sheet. The accumulated depreciation associated with these regulated assets is also reported on the Balance Sheets.

The cost of additions to utility plant and replacements of retired units of property are capitalized at original cost. Capitalized costs include labor, materials and supplies, indirect charges for items such as transportation, certain administrative costs, certain taxes, service cost components of pension and other employee benefits, and allowances for funds used during construction (“AFUDC”); less contributions in aid of construction.

AFUDC is defined as the net cost of borrowed funds used for construction purposes and a reasonable rate on other funds when so used. The concurrent credit for the amount so capitalized is reported in the Consolidated Statement of Income as follows: the portion applicable to borrowed funds is reported as a reduction of interest charges while the portion applicable to other funds (the equity component) is reported as other income. The AFUDC rate was 6.2% in 2021, 5.95% in 2020 and 6.4% in 2019.

The replacement of minor items of property is included in operating expenses. The original cost of property, together with removal cost less salvage, is charged to accumulated depreciation at the time the property is retired and removed from service as required by the PSC.

For additional information see Note 3 – “Utility Plant – Central Hudson.”

Depreciation and Amortization

Central Hudson’s depreciation and amortization provisions are computed on the straight-line method using PSC approved rates. The anticipated costs of removing assets upon retirement are generally provided for over the life of those assets as a component of depreciation expense and, for regulatory reporting purposes, is reflected in accumulated depreciation until the costs are incurred, which is consistent with industry practice. Current accounting guidance related to asset retirement precludes the recognition of expected future retirement obligations as a component of depreciation expense or accumulated depreciation. Central Hudson, however, is required to use depreciation methods and rates approved by the PSC under regulatory accounting. Central Hudson reclassifies cost of removal recovered in excess of amounts incurred to date from accumulated depreciation to regulatory liabilities for presentation in its Balance Sheet in accordance with GAAP.

Central Hudson performs depreciation studies periodically and, upon approval by the PSC, adjusts the depreciation rates of its various classes of depreciable property. Central Hudson’s composite rates for depreciation, inclusive of intangible amortization, was 2.92% in 2021, 2.90% in 2020 and in 2019 was 2.77% of the original average cost of depreciable property. The ratio of the amount of accumulated depreciation to the original cost of depreciable property at December 31, 2021, 2020, and 2019 was 23.0%, 23.3% and 23.9%, respectively.

Asset Retirement Obligations

Central Hudson records Asset Retirement Obligations (“AROs”) for the incremental removal costs, resulting from legal and environmental obligations associated with the retirement of certain utility plant assets, as a liability at fair value with a corresponding increase to utility capital assets, in the period in which the costs are known and estimable. The fair value of AROs is based on an estimate of the

present value of expected future cash outlays, discounted at a credit-adjusted risk-free interest rate. AROs are adjusted at the end of each reporting period to accrete the liability for the passage of time and record any changes in the estimated future cash flows of the incremental obligation. Accretion and depreciation expense associated with AROs are recorded as regulatory assets. Actual costs incurred reduce the liability. The regulatory assets for accretion and depreciation are recovered through the accumulated depreciation reserve upon retirement of the asset.

Impairment of Long-Lived Assets

Central Hudson reviews long-lived assets for impairment, at least annually. Asset-impairment testing at the regulated utilities is carried out at the enterprise level to determine if assets are impaired. The recovery of regulated assets’ carrying value, including a fair rate of return, is provided through customer electricity and natural gas delivery rates approved by the PSC. The net cash flows for regulated entities are not asset-specific, but are pooled for the entire regulated utility.

Leases

Beginning on January 1, 2019, when a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. Central Hudson measures the right-of-use asset and lease liability at the present value of future lease payments excluding variable payments based on usage or performance. Central Hudson calculates the present value using a lease-specific secured borrowing rate based on the remaining lease term. Central Hudson has elected the practical expedient to combine lease components (e.g., rent, real estate taxes and insurance costs) and non-lease components (e.g., common area maintenance costs) and account for them as a single lease component. Central Hudson includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with a term, including renewal options, of twelve months or less are not recorded on the balance sheet.

Research and Development

Central Hudson is engaged in the conduct and support of research and development (“R&D”) activities that are focused on the improvement of existing energy technologies and the development of new technologies for the delivery and customer use of energy. R&D expenditures are provided for in Central Hudson’s rates charged to customers for electric and natural gas delivery service, with any differences between actual R&D expense and the rate allowances deferred for future recovery from or return to customers. See Note 7 – “Research and Development” for additional details.

Debt Issuance Costs

Expenses incurred in connection with CH Energy Group’s or Central Hudson’s debt issuance and any discount or premium on debt are deferred and amortized over the lives of the related issues. When long-term debt is reacquired or redeemed, regulatory accounting permits deferral of related unamortized debt expense and reacquisition costs to be amortized over the remaining original life of the debt retired. The amortization of debt costs for reacquired debt is incorporated in the revenue requirement for delivery rates as authorized by the PSC. See Note 11 – “Capitalization – Long-Term Debt” for additional details.

Income Tax

CH Energy Group and its subsidiaries file consolidated federal income tax returns with FortisUS Inc. (“FortisUS”) and, depending on the state, either standalone or consolidated state income tax returns.

Income taxes are deferred for all temporary differences between the financial statement and the tax basis of assets and liabilities, under the asset and liability method in accordance with current accounting guidance for income taxes. Certain deferred income taxes are recorded with offsetting regulatory assets or liabilities by Central Hudson to recognize that income taxes will be recovered or refunded through future rates. For federal and state income tax purposes, CH Energy Group and its subsidiaries use an accelerated method of depreciation and generally use the shortest life permitted for each class of assets. Central Hudson follows the normalization method of accounting, which spreads the tax benefits associated with utility assets over the same time period that the costs of those assets are recovered from customers. Normalization is required as a prerequisite for utilities claiming accelerated depreciation and certain tax credits. Deferred investment tax credits are amortized over the estimated life of the properties giving rise to the credits. For state income tax purposes, Central Hudson uses book depreciation for property placed in service in 1999 or earlier in accordance with transition property rules under Article 9-A of the New York State Tax Law. See Note 5 – “Income Tax” for additional information regarding income taxes and the Tax Cuts and Jobs Act.

Post-Employment and Other Benefits

Central Hudson sponsors a noncontributory Retirement Income Plan (“Retirement Plan”) for all management, professional and supervisory employees hired before January 1, 2008 and for all Union employees hired before May 1, 2008. Benefits are based on years of service and compensation. Additionally, Central Hudson maintains a Supplemental Executive Retirement Plan (“SERP”) for certain members of management. Central Hudson also provides OPEB plans, which include certain health care and life insurance benefits for retirees hired within the same time periods as stated above.

Central Hudson recognizes the funded status of the Retirement Plan and SERP (collectively “Pension”) and OPEB defined benefit plans on its balance sheet. The funded status is measured as the difference between the fair value of qualified plans’ assets and the projected benefit obligation (“PBO”) for the plans. The Pension funded status includes the SERP PBO although it does not take into consideration the SERP trust assets. The SERP is a non-qualified plan under the Employee Retirement Income Security Act guidelines and therefore, although funded annually to achieve 110% of the plan’s accumulated benefit obligation, the trust assets of this plan are not included in the calculation of the funded status for accounting purposes. Central Hudson recognizes a regulatory liability or asset for the portion of the over or underfunded amount that is probable of return to or recovery from customers in future rates. The amounts reported as a component of other comprehensive income, net of tax, relate to a former Central Hudson officer who transferred to an affiliated company. The related amounts are charged to and reimbursed by the affiliated company.

Pension and OPEB benefit expenses are determined by actuarial valuations based on assumptions that Central Hudson evaluates annually. Central Hudson capitalizes a portion of the service cost component. The PSC has authorized deferral accounting treatment for any variations between actual Pension and OPEB expenses and the amount included in the current delivery rate structure.

Any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations, which are recoverable from Central Hudson customers and would otherwise be recognized in accumulated other comprehensive income, are subject to deferral accounting treatment.

Central Hudson also sponsors a contributory 401(k) retirement plan (“401(k) plan”) for its employees. The 401(k) plan provides for employee tax-deferred salary deductions for participating employees as well as employer contributions.

For more information see Note 12 – “Post-Employment Benefits”.

Additionally, Central Hudson sponsors a contributory Deferred Compensation Plan (“Deferred Compensation Plan”) for certain members of management and members of the Central Hudson Board of Directors. Although the Deferred Compensation Plan is a non-qualified plan, Central Hudson has established a trust for funding the associated liability to participants. For more information, see Note 17 – “Other Fair Value Measurements”.

Equity-Based Compensation

Officers of CH Energy Group and Central Hudson were granted Share Unit Plan shares (“SUPs”) under various plans as part of the officers’ long-term incentives. Compensation expense and the related liability associated with the SUPs is recorded based on the fair value at each reporting date until settlement, reflecting expected future payout and time elapsed within the terms of the award, typically at the end of the three year vesting period. The fair value of the SUPs’ liability is based on Fortis’ common share 5 day volume weighted average trading price at the end of each reporting period. CH Energy Group and Central Hudson have elected to recognize forfeitures when they occur due to the limited number of participants in the equity-based compensation plans. For more information, see Note 13 – “Equity-Based Compensation”.

Common Stock Dividends

CH Energy Group’s ability to pay dividends is affected by the ability of its subsidiaries to pay dividends. The Federal Power Act limits the payment of annual dividends by Central Hudson to its retained earnings. More restrictive is the PSC’s limit on the dividends Central Hudson may pay to CH Energy Group. See Note 10 – “Capitalization-Common and Preferred Stock” for additional information. CH Energy Group’s other subsidiaries do not have express restrictions on their ability to pay dividends.

Derivatives

From time to time, Central Hudson enters into derivative contracts in conjunction with the Company’s enterprise risk management program to hedge certain risk exposures related to its business operations. Central Hudson uses derivative contracts to reduce the impact of volatility in the supply prices of natural gas and electricity and to hedge exposure to volatility in interest rates for its variable rate long-term debt. Central Hudson records all derivatives at fair value with certain exceptions including those derivatives that qualify for the normal purchase exception. The fair value of derivative instruments are estimates of the amounts that Central Hudson would receive or have to pay to terminate the outstanding contracts at the balance sheet dates. Unrealized gains and losses on Central Hudson’s derivative contracts have no impact on earnings since the energy contracts are subject to regulatory deferral.

Realized gains and losses on Central Hudson’s derivative instruments are returned to or recovered from customers through PSC-authorized deferral accounting mechanisms, with no material impact on cash flows, results of operations or liquidity. Realized gains and losses on Central Hudson’s energy derivative instruments and all associated costs are reported as part of purchased natural gas and purchased electricity in CH Energy Group’s and Central Hudson’s Statements of Income as the corresponding amounts are either recovered from or returned to customers through fuel cost adjustment mechanisms in revenues. See Note 16 – “Accounting for Derivative Instruments and Hedging Activities” for further details.

Normal Purchases and Normal Sales

Central Hudson enters into forward energy purchase contracts, including options, with counterparties that have generating capacity to support current load forecasts or counterparties that can meet Central

Hudson’s load serving obligations. Central Hudson has elected the normal purchase exception for these contracts, which are not required to be measured at fair value and are accounted for on an accrual basis. See Note 14 – “Commitments and Contingencies” for further details.

Reclassification

Certain amounts shown in Note 4 – “Regulatory Matters” related to prior year, have been reclassified to conform to the 2021 presentation. These reclassifications had no effect on the reported results of operations.

Recently Adopted Accounting Pronouncements

Income Taxes

Effective January 1, 2021, CH Energy Group and Central Hudson adopted Accounting Standards Update (“ASU”) No. 2019-12, Simplifying the Accounting for Income Taxes, which simplifies the accounting for income taxes by eliminating certain exceptions to the guidance in ASC 740 related to the approach for intra-period tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplified aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. CH Energy Group and its subsidiaries’ earnings, financial position, cash flows and disclosures were not impacted by this adoption.

Note 2 - Revenues and Receivables

Central Hudson disaggregates revenue by segment (electric and natural gas operations) and by revenue type (revenue from contract with customers, alternative revenue programs and other revenue).

Revenue from Contracts with Customers

Central Hudson records revenue as electricity and natural gas is delivered based on either the customers’ meter read or estimated usage for the month. For full-service customers, this includes delivery and supply of electricity and natural gas. For retail choice customers, this includes delivery only as these customers purchase supply from a retail marketer. Sales and usage-based taxes are excluded from revenues. Consideration received from customers on a billing schedule is not adjusted for the effect of a significant finance component because the period between a transfer of goods or services will be one year or less.

Alternative Revenues

Central Hudson’s alternative revenue programs include: electric and natural gas RDMs, the 2020 three-month postponement of the electric and natural gas delivery rate increases for Rate Year (“RY”) 3; see Note 4 – “Regulatory Matters” for details, the electric and natural gas make whole provision and lost finance charges as established in the 2021 Rate Order, Gas Merchant Function Charge lost revenue, and revenue requirement effect for incremental Leak Prone Pipe (“LPP”) miles replaced above the PSC targets. In addition, Central Hudson records alternative revenues related to Positive Revenue Adjustments and EAMs related to New York State clean energy goals, when prescribed targets are met.

Other Revenues

Other revenues consist of pole attachment rents, finance charges, miscellaneous fees and other revenue adjustments. Included in other revenue adjustments are changes to regulatory deferral balances to reverse the impact of refunds (collections) of previously recognized deferrals and Negative Revenue Adjustments (“NRAs”) pursuant to PSC Orders.

The following summary presents CH Energy Group’s and Central Hudson’s operating revenues disaggregated by segment and revenue source (In Thousands):


	Year Ended December 31,
Electric	2021			2020	2019
Revenues from Contracts with Customers (ASC 606)	$	596,007	$	547,586	$	512,787
Alternative Revenues (Non ASC 606)		(10,887)		(18,268)		(11,755)
Other Revenue Adjustments (Non ASC 606)		38,703		22,684		28,428
Total Operating Revenues Electric	$	623,823	$	552,002	$	529,460
Natural Gas
Revenues from Contracts with Customers (ASC 606)	$	170,233	$	155,391	$	161,385
Alternative Revenues (Non ASC 606)		8,484		9,281		4,664
Other Revenue Adjustments (Non ASC 606)		(6,292)		(4,779)		(3,846)
Total Operating Revenues Natural Gas	$	172,425	$	159,893	$	162,203

The year over year increase in electric and natural gas revenues from contracts with customers was primarily driven by higher sales and billed purchased commodity costs. Further impacting the revenue from contract with customers were higher sales for resale and surcharges coupled with lower bill credits in 2021 when compared to 2020, which did not impact total revenues as the offset is reflected in other revenue in 2021.

The increase in electric alternative revenue programs for 2021 is due to the recovery of suspended finance charges as approved in the 2021 Rate Order and due to lower actual billed revenues compared to the Rate Order prescribed targets. The decrease in natural gas alternative revenue programs for 2021 when compared to 2020 is due to actual billed revenues above the prescribed targets partially offset by the recovery of suspended finance charges as approved in the 2021 Rate Order.

The increase in other electric revenue adjustments is due to higher customer credits for previously deferred revenues in excess of the 2018 Rate Order prescribed targets partially offset by NRAs recorded related to electric service interruptions which were above the PSC prescribed targets for the System Average Interruption Frequency Index (“SAIFI”) and Customer Average Interruption Duration Index (“CAIDI”). The decrease in other natural gas revenue adjustments is primarily due to higher recovery of previously deferred revenues below those prescribed in the 2018 Rate Order. Further impacting these decreases is additional deferrals for net plant and depreciation targets, as a result of delays in the completion of certain capital projects as compared to levels included in rates.

Allowance for Uncollectible Accounts

Accounts receivable are recorded net of an allowance for uncollectible accounts based on the allowance for credit losses model. A summary of all changes in the allowance for uncollectible accounts receivable and accrued unbilled utility revenue balance is as follows:


		Year Ended
		December 31,
			2021			2020
Balance at Beginning of Period	$	(10,400)		$	(4,500)


Accounting Standard Adoption – cumulative effect adjustment		-		(1,200)
Uncollectible expense		(6,075)		(10,010)
Bad debt write-offs (recoveries) - net		5,275		5,310
Balance at End of Period	$	(11,200)	$	(10,400)

During the twelve months ended December 31, 2021, management recorded an additional increase to the allowance for uncollectible accounts of $0.8 million based on a quantitative and qualitative assessment of forecasted economic conditions primarily related to COVID-19. This assessment included a historical analysis of the relationship of write-offs to accounts receivable balances in arrears and taking into consideration certain qualitative factors differentiating this current situation from other significant events in the historical period, including the nature and cause of this economic downturn, as well as legislative and governmental actions taken to provide relief and assistance to customers financially impacted by the COVID-19 pandemic. Central Hudson continues to proactively contact customers regarding past due balances to advise them of financial assistance programs available and is also working with local agencies and municipalities to obtain funding for its customers which has been made available through federal and state programs. No further increase to the reserve has been recorded at December 31, 2021 based on the potential available funding from these programs.

NOTE 3 – Utility Plant - Central Hudson

The following summarizes the type and amount of assets included in the electric, natural gas, and common categories of Central Hudson’s utility plant balances (In Thousands):


		Estimated Depreciable Life in Years	Utility Plant
			December 31,		December 31,
			2021		2020
Electric:
	Production	25-95	$	43,719	$	42,992
	Transmission	30-90		449,054		435,855
	Distribution	8-80		1,187,608		1,139,941
	Other	40		6,910		6,908
	Total		$	1,687,291	$	1,625,696
Natural Gas:
	Transmission	19-85	$	63,284	$	61,476
	Distribution	28-95		670,439		615,728
	Other	N/A		442		442
	Total		$	734,165	$	677,646
Common:
	Land and Structures	50	$	113,200	$	88,310
	Office and Other Equipment, Radios and Tools	8-35		85,404		79,429
	Transportation Equipment	10-12		78,349		77,668
	Other	3-15		149,017		93,922
	Total		$	425,970	$	339,329
Gross Utility Plant			$	2,847,426	$	2,642,671

The borrowed component of funds used during construction and recorded as a reduction of interest expense was $1.5 million for each of the years ended December 31, 2021 and 2020 and $1.2 million for the year ended December 31, 2019. The equity component reported as other income was $3.4 million, $3.0 million and $2.3 million for the years ended December 31, 2021, 2020 and 2019, respectively.

Included in the Net Utility Plant balance of $2.3 billion and $2.2 billion at December 31, 2021 and 2020 is $181.0 million and $141.7 million of intangible utility plant assets, comprised primarily of computer software costs, land, transmission, and water and other rights, and the related accumulated amortization of $78.5 million and $64.7 million, respectively. Amortization expense is estimated to average approximately $10.5 million annually for each of the next five years.

As of December 31, 2021 and 2020, Central Hudson has reclassified from accumulated depreciation $42.8 million and $40.4 million, respectively, of cost of removal recovered through the rate-making process in excess of amounts incurred to date as a regulatory liability.

As of December 31, 2021 and 2020, AROs for Central Hudson were approximately $3.1 million and $1.9 million, respectively. These amounts have been classified in the above chart under “Electric - Other” and “Common - Other” based on the nature of the ARO and are reflected as “Other - long-term liabilities” in the CH Energy Group and Central Hudson Balance Sheets.

NOTE 4 – Regulatory Matters

Summary of Regulatory Assets and Liabilities

Based on previous, existing or expected regulatory orders or decisions, the following table sets forth amounts that are expected to be recovered from, or refunded to customers in future periods (In Thousands):


				December 31,			December 31,
	2021			2020
Regulatory Assets:
	Deferred purchased electric costs (Note 1)	$	17,319		$	3,470
	Deferred purchased natural gas costs (Note 1)		8,057			4,453
	Deferred unrealized losses on derivatives - electric and natural gas (Note 16)		7,563			2,153
	RAM - electric		15,258			13,866
	RAM - natural gas		3,397			3,418
	EAMs - electric		3,570			3,410
	SC 8 Street Lighting		-			1,678
	Delayed electric and natural gas delivery rate increase		-			4,596
	RDM and carrying charges - natural gas		2,942			3,778
	Energy efficiency programs and carrying charges		16,819	(2)		1,260
	Revenue requirement of LPP replacement		-			1,696
	Deferred pension costs (Note 12)		-			7,551
	Demand management programs		8,809			11,032
	Deferred and accrued costs - SIR (Note 14)		76,032			84,370
	Deferred storm costs		13,742			19,902
	Deferred vacation pay accrual		9,753			10,197
	Income taxes recoverable through future rates		35,784			26,968
	Tax reform - unprotected impacts (Note 5)		23,733			13,464
	Other		10,554	(1)		10,140	(1)
			$	253,332		$	227,402
			$	78,849		$	57,079
			$	174,483		$	170,323
Regulatory Liabilities:


	Rate moderator - electric	$	19,371		$	15,786
	Rate moderator - natural gas		10,115			6,247
	RDM and carrying charges - electric		-			22,073
	Deferred unrealized gains on derivatives - electric and natural gas (Note 16)		1,768			-
	Clean Energy Fund and carrying charges		52,584			57,893	(2)
	Tax reform - protected deferred tax liability (Note 5)		179,900			183,915
	Deferred cost of removal (Note 3)		42,794			40,384
	Deferred pension costs (Note 12)		90,934			-
	Income taxes refundable through future rates		9,027			9,149
	Deferred OPEB costs (Note 12)		31,032			13,540
	Low income program		5,289			4,722
	Net plant and depreciation targets		-			10,193
	Fast charging infrastructure program and carrying charges		5,455			5,124
	Deferred unbilled revenue		5,082			5,082
	Other		4,626	(1)		5,038	(1)
			$	457,977		$	379,146
			$	63,456		$	89,006
			$	394,521		$	290,140
			$	(204,645)		$	(151,744)

(1) Other includes estimated netting on the balance sheet of certain regulatory asset carrying charges to be offset against regulatory liabilities and collected through Rate Case offset.
(2) In accordance with Order 18-M-0084, during 2021, accumulated Clean Energy Fund carrying charges of $4.7 million were transferred to fund Energy Efficiency Programs.

The significant regulatory assets and liabilities include:

Rate Adjustment Mechanism: Mechanism prescribed in the 2018 Rate Order and continued in the 2021 Rate Order to recover from or refund to customers previously deferred balances related to major storms, energy efficiency programs and environmental site investigation and remediation costs in excess of the three year cumulative rate allowance, incentives earned, unencumbered NRAs, deferred property taxes and accrued carrying charges.

Earnings Adjustment Mechanism: Mechanism prescribed in the 2018 Rate Order and continued in the 2021 Rate Order to recover from customers incentives earned related to energy efficiency targets met.

SC8 Street Lighting: This regulatory asset represents the deferral to reassign the collection of revenues amongst certain service classes during the term of the 2018 Rate Order.

Delayed electric and natural gas delivery rate increase: This regulatory asset represents the deferral of the electric and natural gas delivery rate increases as prescribed in the June 11, 2020 Order as further discussed below.

Revenue Decoupling Mechanism and carrying charges: Mechanism prescribed in the 2018 Rate Order and continued in the 2021 Rate Order to recover from or refund to customers difference between actual revenues and forecasted revenues.

Energy Efficiency Programs: This regulatory asset/liability represents amounts spent on Central Hudson’s internally administered programs either below or in excess of amounts collected in rates.

Revenue requirement of LPP replacement: This regulatory asset represents the deferral of the revenue requirement impact related to the replacement of LPP as prescribed in the 2018 Rate Order.

Demand Management Programs: This regulatory asset represents deferred balances for costs incurred and incentives earned in excess of amounts collected related to Central Hudson’s Non-Wires Alternative and Dynamic Load Management initiatives.

Deferred Storm Costs: Central Hudson’s rates include a collection of funds for a major storm reserve, which are deferred as an offset against incremental costs incurred for major storm restoration. Incremental costs incurred in excess of the reserve funds to be collected in the current rate term are authorized to be collected via its RAM, to the extent sufficient.

Deferred Vacation Pay Accrual: In accordance with Rate Order 84-2 a regulatory asset has been established to offset the accrued vacation liability since the accrued compensation is included in future allowable costs on an as paid basis and there is reasonable assurance of recovery.

Income Taxes Recoverable: This regulatory asset has been established to offset certain deferred tax liabilities because Central Hudson believes it is probable that they will be recoverable from customers.

Rate Moderator – Electric and Natural Gas: This regulatory liability balance represents the net balance after offset under the terms of the 2018 and 2021 Rate Orders, which were and will be used for future customer rate moderation, as well as deferred Danskammer Generating Station delivery revenues for future natural gas rate moderation.

Clean Energy Fund: This regulatory liability represents amounts collected from customers primarily under the Clean Energy Fund, the Renewable Portfolio Standards and System Benefit Charge (as prescribed in the Clean Energy Fund, 2018 and 2021 Rate Orders), in excess of amounts remitted to the New York State Energy Research and Development Authority (“NYSERDA”) to fund its energy efficiency programs.

Income Taxes Refundable: This regulatory liability was established to offset certain deferred tax assets because Central Hudson believes it is probable that the related balances will be refundable to customers.

Low Income Program: This regulatory liability represents deferred balances for amounts collected in excess of credits provided for low income programs.

Net Plant and Depreciation Targets: This regulatory liability represents a deferral of the revenue requirement effect of net plant in service and depreciation expense below the defined targets as prescribed in the 2018 Rate Order.

Fast Charging Station Infrastructure Program and carrying charges: This regulatory liability represents amounts provided by NYSERDA and collected from customers to fund the fast charging stations’ annual incentive payments as prescribed in the related Order.

Deferred Unbilled Electric and Natural Gas Revenue: On July 20, 2016, the PSC issued the “Order Approving Accounting Change with Modification”, allowing Central Hudson to realize unbilled revenue as revenue on the income statement but required that $5.1 million of unbilled revenues remain as a regulatory liability.


In terms of the expected timing for recovery, regulatory asset balances reflect the following amounts (In Thousands):
		December 31,
		2021		2020
Balances with offsetting accrued liability balances recoverable when future costs are actually incurred:
	Deferred pension related to underfunded status	$	-	$	7,551
	Income taxes recoverable through future rates		35,784		26,968
	Deferred unrealized losses on derivatives - electric		7,563		2,122
	Deferred unrealized losses on derivatives - natural gas		-		31
	Accrued SIR costs		71,653		74,903
	Deferred ARO		583		406
	Deferred vacation pay accrual		9,753		10,197
	Other		404		-
		$	125,740	$	122,178
Balances earning a return via inclusion in rates and/or the application of carrying charges:
	Energy efficiency programs and carrying charges	$	16,819	$	1,260
	OPEB reserve carrying charges		-		1,828
	Deferred storm costs		13,742		19,902
	Deferred SIR costs, net of recoveries		4,379		9,467
	Deferred debt expense on re-acquired debt		1,508		1,860
	Tax reform - unprotected impacts		23,733		13,464
	Other		4,814		5,340
		$	64,995	$	53,121
Subject to current recovery:
	Deferred purchased electric costs	$	17,319	$	3,470
	Deferred purchased natural gas costs		8,057		4,453
	Delayed electric and natural gas delivery rate increase		-		4,596
	RAM - electric and natural gas		18,655		17,285
	EAMs - electric and natural gas		4,102		3,936	(2)
	RDM - electric and natural gas		3,027		3,778
	Demand management programs(1)		8,809		11,032
	Other		2,830		4,542	(2)
		$	62,799	$	53,092
Accumulated carrying charges:
	Carrying charges balancing	$	(218)	$	(1,010)
	Other		16		21
		$	(202)	$	(989)
	Total Regulatory Assets	$	253,332	$	227,402

(1)	These amounts are subject to recovery over prescribed PSC timeframes unique to each program (most over 5 or 10 years). Balances subject to recovery over a period greater than 1 year are authorized to earn carrying charges at the pre-tax weighted average cost of capital
(2)	Certain amounts shown for the period ended December 31, 2020 have been reclassified to conform to the December 31, 2021 presentation.

PSC Proceedings

2018 Rate Order / 2021 Rate Order

On June 14, 2018, the PSC issued an Order Approving Rate Plan in Cases 17-E-0459 and 17-G-0460, the “2018 Rate Order” as defined, adopting the terms set forth in the April 18, 2018 Joint Proposal with

minor modifications. The 2018 Rate Order was effective July 1, 2018, with Rate Year RY1, RY2, and RY3 defined as the twelve months ending June 30, 2019, June 30, 2020, and June 30, 2021, respectively.

On June 11, 2020, the Commission issued an Order Postponing Approved Electric and Gas Delivery Rate Increases, which approved Central Hudson’s petition to ease the financial impact on customers during the critical months of the COVID-19 pandemic. The Order postponed for three months Central Hudson’s approved RY3 electric and natural gas delivery rate increase scheduled to take effect on July 1 to October 1, 2020, with the forgone revenues recovered over the remaining nine months of the rate year ending June 30, 2021. The Order also stated that no carrying charges would be applied to the delayed recovery of these revenues and that Central Hudson would adjust the RDM targets to be consistent with the delayed electric and natural gas delivery rate increase implementation.

On November 18, 2021, the PSC issued an Order Approving Rate Plan in Cases 20-E-0428 and 20-G-0429, the “2021 Rate Order” as defined. The 2021 Rate Order adopts the terms set forth in the August 24, 2021 Joint Proposal. The 2021 Rate Order also fully and finally resolves all issues associated with the Sales Tax Refund Proceeding (Case 20-M-0134). The 2021 Rate Order was effective December 1, 2021, and includes a make-whole provision that provides new rates to become effective retroactive to July 1, 2021, with RY1, RY2, and RY3 defined as the twelve months ending June 30, 2022, June 30, 2023, and June 30, 2024, respectively.

A summary of the key terms of the 2018 and 2021 Rate Orders are as follows:


		2018 Rate Order (dollars in millions)			2021 Rate Order (dollars in millions)
	Description	RY1	RY2	RY3	RY1	RY2	RY3
Electric delivery rate increase/(decrease)		$19.7	$18.6	$25.1	($3.1)	$19.5	$20.7
Natural gas delivery rate increases		$6.7	$6.7	$8.2	$4.7	$6.3	$6.4
Return on Equity		8.80%	8.80%	8.80%	9.00%	9.00%	9.00%
Earnings sharing		Yes(1)	Yes(1)	Yes(1)	Yes(2)	Yes(2)	Yes(2)
Capital structure – common equity		48%	49%	50%	50%	49%	48%
Bill Credits/(surcharge) - Electric		$6.0	$9.0	$11.0	($2.0)	$9.5	$21.5
Bill Credits - Natural Gas		$3.5	$4.0	$4.0	$0.8	$3.2	$5.6
RDMs – electric and natural gas		Yes	Yes	Yes	Yes	Yes	Yes

(1)	Return on equity ("ROE") > 9.3% and up to 9.8%, is shared 50% to customers, > 9.8% and up to 10.3%, is shared 80% to customers, and > 10.3% is shared 90% to customers.

(2)	ROE > 9.5% and up to 10.0%, is shared 50% to customers, > 10.0% and up to 10.5%, is shared 75% to customers, and > 10.5% is shared 90% to customers.

The 2021 Rate Order utilizes existing regulatory balances to reduce bill impacts for customers during the term of the agreement. The 2021 Rate Order also reflects a postponement of certain capital projects, as well as reductions to operations and maintenance (“O&M”) costs to help manage customer bill impacts. The total electric revenue (decrease)/increase (after bill credits) is (0.2)%, 1.2%, and 1.2% for RY1 through RY3, respectively, and the total natural gas revenue increase (after bill credits) is 1.9%, 1.8%, and 1.8% for RY1 through RY3, respectively. The rate plan also includes an allowed ROE of 9.0% and an equity ratio of 50%, 49% and 48% for RY1 through RY3, respectively.

The 2021 Rate Order:

•establishes the Company’s future energy infrastructure investments, programs and operations;

•stabilizes electric delivery rates in the first year with a slight decrease for residential customers;

•reflects modest increases in gas delivery rates producing bill impacts just under two percent each RY;

•includes increased electric bill discounts for income qualified households and expanded access into Central Hudson’s Energy Affordability Program;

•reflects investments in clean energy efficiency ground and air-source electric heat pumps, electric vehicle charging, and system upgrades that support utilization of renewable sources;

•implements ten EAMs which reflect a maximum earnings potential of 100 basis points;

•maintains the current CAIDI metric and reflects increasingly stringent SAIFI targets, continues and further enhances existing gas safety performance metrics and public safety programs, and includes higher performance requirements for Customer Service Performance Indicators with a net increase in total potential NRAs;

•provides Central Hudson with required resources to support ongoing O&M and necessary investments to reinforce electric and gas system reliability and resiliency through storm hardening, expanded vegetation management/tree trimming, continued investment for LPP replacement or elimination, and deployment of new technologies, as well as information technology systems to further protect against cyber security risks and;

•includes several deferrals that provide the Company authorization to defer COVID-19 Incremental O&M Costs net of savings, lost revenues (finance charges and reconnection fee revenues), and uncollectible write-offs.

Central Hudson 2021 Financing Order

On November 18, 2021, the Commission approved the Company's request under Section 69 of the Public Service Law authorizing Central Hudson to enter into multi-year credit agreements in an aggregate amount not to exceed $250 million; and approval to issue and sell new long-term debt from time to time through December 31, 2024, in an aggregate amount not to exceed $445.7 million, including $412 million for traditional utility purposes and up to $33.7 million to refinance its variable interest debt. Central Hudson filed a letter indicating its unconditional acceptance of the November 18, 2021 Order on December 6, 2021.

August 2020 Tropical Storm Isaias

On August 5, 2020, the New York State Governor instituted proceeding 20-01633 directing the Commission to initiate an investigation of certain New York State utilities’ responses to Tropical Storm Isaias, which impacted Central Hudson’s service territory on August 4, 2020. On November 19, 2020, New York State Department of Public Service (“DPS”) issued an interim Storm Report setting forth preliminary findings, including purported failures by the identified utilities to comply with their respective Commission approved Emergency Response Plans and Show Cause (“Show Cause Order”) that initiated proceedings against Central Hudson and the other utilities. The Show Cause Order identified 32 apparent violations by Central Hudson, which, if established, could have resulted in up to $16 million of penalties. Central Hudson filed its response to the Show Cause Order on December 21, 2020. The Company performed a thorough investigation and, as indicated in its response, believed no penalty should be issued because the facts demonstrated that Central Hudson fully complied with its Commission-approved Emergency Response Plan, which served as the standard against which Central Hudson should be evaluated. On February 23, 2021, Central Hudson filed a Notice of Impending Settlement Negotiations. On July 7, 2021, Central Hudson and New York State DPS entered into a Settlement Agreement, which included a commitment by Central Hudson to establish a $1.5 million regulatory liability to be used by Central Hudson to support or advance storm restoration and/or electric system resiliency and reliability in excess of amounts funded by customers. The Commission approved the Settlement Agreement within the Order Granting Motion and Adopting Settlement Agreement on July 15, 2021. The Settlement Agreement does not include any finding or admission of any violation by Central Hudson, and it specifies that the settlement amount is not a penalty.

Central Hudson Reverse Sales Tax Refund

On March 16, 2020, Central Hudson filed a petition for the disposition of a sales tax refund, pursuant to PSL Section 113(2) under Case 20-M-0134. The tax refund is the result of a reverse sales tax audit that Central Hudson initiated with the New York State Department of Taxation & Finance for the claim period of June 1, 2017 through December 31, 2018. The Commission solicited comments on the filing via notice published in the April 22, 2020 edition of the New York State Register. Central Hudson asked the Commission to take notice of a tax refund received from the New York State Department of Taxation and Finance, in the amount of approximately $3.4 million on October 16, 2019 and waive the rule requiring the Company to give the Commission notice of the refund within 60 days. Central Hudson proposed that the refund received be allocated (1) for the benefit of ratepayers; and (2) to reimburse the costs incurred by Central Hudson in securing the refund. The Company proposed to retain approximately $0.6 million, or 24% of the refund, net of costs to achieve. Most of the refund has been credited to plant as the majority of the refund related to sales taxes that were capitalized as part of plant costs. The petition requested the PSC approve Central Hudson retaining the portion of the net refund related to amounts that were previously recorded to sales tax expense. Staff’s testimony in the August 2020 filing requested that this proceeding be incorporated into the Rate Case filing rather than ruled upon separately. On August 12, 2021, a Notice of Impending Settlement Negotiations was filed in both the Company’s rate proceedings, Cases 20-E-0428 and 20-G-0429, and the Sales Tax Refund Proceeding, Case 20-M-0134, stating that in connection with the previously noticed settlement discussions in the rate proceedings, the Company and Staff had agreed to initiate confidential settlement negotiations regarding the Refund Petition. The parties’ settlement negotiations in the rate cases and the Sales Tax Refund Proceeding were successful and resulted in the filing of the Joint Proposal. The 2021 Rate Order fully and finally resolves all issues and concerns raised and/or asserted, or that could have been raised and/or asserted in the Sales Tax Refund Proceeding Case 20-M-0134.

Federal Energy Regulatory Commission System Deliverability Upgrades Proceeding

On December 31, 2019, Central Hudson submitted to FERC a new rate schedule pursuant to Rate Schedule 12 of the NYISO OATT to establish a Facilities Charge for System Deliverability Upgrades (“SDU”) being installed on Central Hudson’s transmission facilities, which are required to provide four Large Generating Facility Developers with Capacity Resource Interconnection Service. This charge provides Central Hudson with full recovery of all reasonably incurred costs related to the development, construction, operation and maintenance of the SDU and a reasonable return on its investment. Project costs to be recovered by Central Hudson and allocated to the Load Serving Entities (“LSEs”) pursuant to Rate Schedule 12 of the NYISO OATT are expected to be approximately $2.6 million plus operation, maintenance and other applicable costs and will be updated annually. Parties submitted an Offer of Settlement with the FERC on June 30, 2021, which included an updated ROE of 9.4% plus a 50 basis point adder for a total ROE of 9.9%. The settlement was certified as uncontested by the designated settlement judge on August 3, 2021 and was subsequently approved by FERC on October 4, 2021.

NOTE 5 – Income Tax

Uncertain Tax Positions

In September of 2010, Central Hudson filed a request with the Internal Revenue Service (“IRS”) to change its tax accounting method related to costs to repair and maintain utility assets. The change was effective for the tax year ended December 31, 2009. This change allows Central Hudson to take a current tax repair deduction for a significant amount of repair costs that were previously capitalized for tax purposes.

IRS guidance, with respect to repair deductions taken on Gas Transmission and Distribution repairs is still pending. Therefore, tax reserves related to the gas repair deduction continue to be shown as “Tax Reserve” under the Deferred Credits and Other Liabilities section of the CH Energy Group and Central Hudson Balance Sheets.

Changes in the tax reserve reflect the ongoing uncertainty related to gas transmission and distribution repair deductions taken in the current period.

The following is a summary of activity related to the uncertain tax position (In Thousands):



		CH Energy Group				Central Hudson
		Year Ended				Year Ended
		December 31,				December 31,
		2021		2020		2021		2020
Tax reserve balance at the beginning of the period		$	-	$	3,126	$	-	$	2,910
Change in natural gas transmission and distribution repair deduction			1,476		985		1,476		985
Change in tax benefit offset (1)			(1,476)		(4,111)		(1,476)		(3,895)
Tax reserve balance at the end of the period		$	-	$	-	$	-	$	-

(1)	Amounts are classified as a deferred tax asset per ASU No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.


Income Tax Examinations

Jurisdiction						Tax Years Open for Audit
Federal						2018 – 2020
New York State						2018 – 2020

Components of Tax Reform Regulatory Balances

As a result of the Tax Cuts and Jobs Act, the Company was required to revalue its deferred tax assets and liabilities at the federal corporate income tax rate of 21%. Central Hudson recorded a regulatory liability due to the revaluation of plant related deferred tax liabilities which are protected under tax normalization rules. The regulatory liability is adjusted monthly to reflect the amortization of the balance to the income statement under the normalization rules. The Company also recorded a regulatory asset due to the revaluation of non-plant related deferred taxes, which is not subject to the normalization rules.



The following is a summary of Central Hudson's activity in its regulatory liability balance related to the protected deferred tax liability (In Thousands):

	December 31,		December 31,
	2021		2020
Protected Regulatory Liability at the beginning of the period	$	183,915	$	189,447
Amortization of Protected Tax Liability		(4,015)		(5,532)
Protected Regulatory Liability at the end of the period	$	179,900	$	183,915

The following is a summary of Central Hudson's activity in its regulatory asset balance related to the unprotected impacts (In Thousands):

	December 31,		December 31,


	2021		2020
Unprotected Regulatory Asset at the beginning of the period	$	13,464	$	13,464
Change in Unprotected Tax Asset		10,269		-
Unprotected Regulatory Asset at the end of the period	$	23,733	$	13,464

The unprotected regulatory tax asset consisted of an excess deferred tax asset balance, which was partially offset by a regulatory liability resulting from the overcollection of tax from the effective date of the Tax Cuts and Jobs Act and the date delivery rates were reset. The increase of $10.3 million in 2021 resulted from the utilization of the overcollection for rate moderation per the 2021 Rate Order. The remaining excess deferred tax balance of $23.7 million will be addressed in the Company’s next rate case filing.

CARES Act

The CARES Act was signed into law on March 27, 2020. As permitted under the CARES Act, Central Hudson deferred payment of the employer share of the Social Security tax on its payroll during 2020. The deferred payroll tax can be paid over two years; with half of the required amount paid by December 31, 2021 and the other half by December 31, 2022. There was no impact on earnings or on the effective tax rate resulting from the delayed payment of employer payroll tax under the CARES Act. As of December 31, 2021, the liability for the deferred payment of the employer’s portion of Social Security tax on payroll is $2.6 million reflected in “Other current liabilities” in the CH Energy Group and Central Hudson Balance Sheets and will be paid in December 2022. As of December 31, 2020, the liability for the deferred payment of the employer’s portion of Social Security tax on payroll was $5.2 million, with $2.6 million reflected in Other liabilities current and $2.6 million in Other long-term liabilities in the CH Energy Group and Central Hudson Balance Sheets.

New York State 2022 budget bill

On April 6, 2021 the New York State fiscal year 2022 budget bill was enacted. The budget bill included an increase in the corporate tax rate for businesses with taxable income over $5 million from 6.5% to 7.25% for tax years beginning on or after January 1, 2021 and before January 1, 2024 and extending the capital base tax which was set to phase out in 2021. For tax years beginning on or after January 1, 2021 and before January 1, 2024, the business capital tax rate would be 0.1875% and would phase out for tax years beginning on and after January 1, 2024. CH Energy Group and Central Hudson have state Net Operating Losses that are expected to reduce taxable income below the $5 million threshold for the duration of the increased tax rate period and therefore that provision is not expected to have an impact on the Company’s earnings or cash flows. Both CH Energy Group and Central Hudson are expecting to be subject to the capital base tax during this period. For the year ended December 31, 2021, Central Hudson has recorded $1.7 million of Capital Base Tax, which is included in “Taxes, other than income tax” in the CH Energy Group and Central Hudson Statements of Income. The increase in Capital Base Tax is included in the tax calculation used to set rates in the 2021 Rate Order.

Reconciliation - CH Energy Group

The following is a reconciliation between the amount of federal income tax computed on income before taxes at the statutory rate and the amount reported in CH Energy Group’s Consolidated Statement of

Income (In Thousands):


	Year Ended December 31,
	2021		2020		2019
Net income	$	73,953	$	69,103	$	64,566
Current federal income tax (benefit)		(62)		(20)		(886)


Current state income tax (benefit)expense			225		100		(90)
Deferred federal income tax expense			11,897		9,930		10,957
Deferred state income tax expense			4,756		5,252		4,753
	Income before income taxes	$	90,769	$	84,365	$	79,300

Computed federal tax at 21%		$	19,061	$	17,717	$	16,653
State income tax net of federal tax benefit			3,935		4,224		3,797
Amortization of protected deferred tax liability(1)			(3,093)		(4,339)		(3,983)
State income tax prior period adjustment			-		4		(113)
Depreciation flow-through			(552)		(706)		466
Cost of removal			(2,220)		(1,926)		(1,910)
Other			(315)		288		(176)
	Total income tax expense	$	16,816	$	15,262	$	14,734

Effective tax rate - federal			13.0%		11.7%		12.7%
Effective tax rate - state			5.5%		6.4%		5.9%
Effective tax rate - combined			18.5%		18.1%		18.6%

(1) Under normalization rules, plant-related deferred taxes reverse at the same rate as the original deferral.

For the years ended December 31, 2021 and 2020, the combined effective tax rate for CH Energy Group is lower than the statutory rate due to tax normalization rules and the timing of flow through tax items related to capital expenses. For the year ended December 31, 2019, the lower combined effective tax rate was driven by the reduction in the federal income tax rate from 35% to 21%, in accordance with the Tax Cuts and Jobs Act, and the impact of tax normalization rules.


The following is a summary of the components of deferred taxes as reported in CH Energy Group’s Consolidated Balance Sheets (In Thousands):

		December 31,
		2021		2020
Accumulated Deferred Income Tax Asset:
	Unbilled revenues	$	3,300	$	1,615
	Plant-related		2,712		6,812
	Tax reform - protected deferred tax liability		47,468		48,688
	Pension costs		1,539		1,135
	Income taxes refundable through future rates		9,027		7,294
	OPEB costs		-		1,067
	Federal Net Operating Loss ("NOL") carryforwards		10,595		941
	New York State NOL carryforwards		9,734		4,495
	Clean Energy Fund		9,192		14,451
	Rate moderator		7,706		5,758
	Contributions in aid of construction		9,407		9,429
	Directors and officers deferred compensation		15,102		13,766
	RDM		-		4,781
	Deferred payroll taxes		680		1,361
	Cost of removal		946		-
	Fast charging infrastructure		1,426		1,339
	Low income bill program		1,671		1,234
	Other		2,117		3,518


Accumulated Deferred Income Tax Asset		$	132,622	$	127,684

Accumulated Deferred Income Tax Liability:
	Depreciation	$	259,986	$	243,015
	Repair allowance		3,927		4,143
	Repair deduction		104,519		92,420
	Income taxes recoverable through future rates		17,269		13,540
	Tax reform - unprotected deferred tax asset		6,203		3,519
	Cost of removal		-		4,981
	Deferred SIR costs		1,144		2,474
	RDM		790		-
	Demand management programs		2,301		2,884
	Purchased electric costs		4,526		907
	Delayed rate increase		-		1,201
	Purchased natural gas costs		2,106		1,164
	Storm costs		3,591		5,202
	RAM		4,875		4,517
	Other		7,384		6,642
Accumulated Deferred Income Tax Liability		$	418,621	$	386,609
Net Deferred Income Tax Liability		$	285,999	$	258,925

Reconciliation – Central Hudson

The following is a reconciliation between the amount of federal income tax computed on income before taxes at the statutory rate and the amount reported in Central Hudson’s Statement of Income (In Thousands)


		Year Ended December 31,
		2021		2020		2019
Net income		$	73,623	$	69,141	$	64,862
Current federal income tax (benefit)			-		(18)		(889)
Current state income tax (benefit)			-		-		(189)
Deferred federal income tax expense			11,313		9,952		10,462
Deferred state income tax expense			4,795		5,211		4,884
	Income before income taxes	$	89,731	$	84,286	$	79,130

Computed federal tax at 21%		$	18,844	$	17,700	$	16,617
State income tax net of federal tax benefit			3,788		4,117		3,898
Amortization of protected deferred tax liability(1)			(3,093)		(4,339)		(3,983)
State income tax prior period adjustment			-		-		(189)
Depreciation flow-through			(552)		(706)		466
Cost of removal			(2,220)		(1,926)		(1,910)
Other			(659)		299		(631)
	Total income tax expense	$	16,108	$	15,145	$	14,268

Effective tax rate - federal			12.6%		11.8%		12.1%
Effective tax rate - state			5.4%		6.2%		5.9%
Effective tax rate - combined			18.0%		18.0%		18.0%

(1)

Under normalization rules, plant-related deferred taxes reverse at the same rate as the original deferral.

For the year ended December 31, 2021, the combined effective tax rate for Central Hudson is lower than the statutory rate due to tax normalization rules and the timing of flow through tax items related to capital expenditures. For the year ended December 31, 2020, the combined effective tax rate for Central Hudson is lower than the statutory rate due to tax normalization rules. For the year ended December 31, 2019, the lower combined effective tax rate was driven by the reduction in the federal income tax rate from 35% to 21%, and the impact of tax normalization rules.


The following is a summary of the components of deferred taxes as reported in Central Hudson’s Balance Sheet (In Thousands):
		December 31,
		2021		2020
Accumulated Deferred Income Tax Asset:
	Unbilled revenues	$	3,300	$	1,615
	Plant-related		2,712		6,812
	Tax reform - protected deferred tax liability		47,828		48,688
	Pension costs		1,539		1,135
	Income taxes refundable through future rates		9,027		7,294
	OPEB costs		-		1,067
	Federal NOL carryforwards		11,327		1,127
	New York State NOL carryforwards		9,801		4,537
	Clean energy fund		9,192		14,451
	Rate moderator		7,706		5,758
	Contributions in aid of construction		9,407		9,429
	Directors and officers deferred compensation		13,902		12,866
	RDM		-		4,781
	Cost of removal		946		-
	Fast charging infrastructure		1,426		1,339
	Deferred payroll taxes		680		1,361
	Low income bill program		1,671		1,234
	Other		1,772		3,263
Accumulated Deferred Income Tax Asset		$	132,236	$	126,757

Accumulated Deferred Income Tax Liability:
	Depreciation	$	259,624	$	242,572
	Repair allowance		3,927		4,143
	Repair deduction		104,519		92,420
	Income taxes recoverable through future rates		17,269		13,540
	Tax reform - unprotected deferred tax asset		6,203		3,519
	Cost of removal		-		4,981
	Deferred SIR costs		1,144		2,474
	RDM		790		-
	Demand management programs		2,301		2,884
	Purchased electric costs		4,526		907
	Delayed rate increase		-		1,201
	Purchased natural gas costs		2,106		1,164
	Storm costs		3,591		5,202
	RAM		4,875		4,517


	Other		6,236		5,563
Accumulated Deferred Income Tax Liability		$	417,111	$	385,087
Net Deferred Income Tax Liability		$	284,875	$	258,330

NOTE 6 – Investments in Unconsolidated Affiliates

In April 2019, National Grid and Transco were awarded the Segment B portion of one of its proposals related to the AC Transmission Order with NYISO for a transmission project that will improve the flow of power from upstate renewable resources to meet downstate demand and enhance the reliability and resilience of the grid (“AC Project”). Transco is authorized to earn a return on equity invested in the project (up to 53% of the project cost) of 9.65%, with up to an additional 1% available for incentives. The project has an estimated cost of $600 million plus interconnection costs, and CHET’s equity funding requirement of this cost as a 6.1% owner of Transco is expected to be $19.4 million. As of December 31, 2021, CHET has made capital contributions of $5.4 million to Transco to fund a portion of the Segment B project costs. At December 31, 2021 and 2020, CHET's investment in Transco was approximately $15.0 million and $9.2 million, respectively.

In November 2018, the Transco limited liability company agreement was amended (“Transco Amendment”) to allow Transco to pursue additional projects that might result from future NYISO Public Policy Transmission Planning Processes (“PPTP Processes”). Under the Transco Amendment, CHET would have a 10% ownership stake in transmission solutions related to future projects that result from future PPTP Processes. CHET would also be allocated 10% of future development costs for any new transmission projects as part of future PPTP Processes. In response to a Long Island Offshore Wind Export Public Policy Transmission Need Project Solicitation issued by the NYISO on August 12, 2021, Transco, partnering with the New York Power Authority (“NYPA”), submitted to NYISO on October 11, 2021, four separate proposed solutions to upgrade existing transmission facilities on Long Island to accommodate 3,000 MWs of anticipated offshore wind generated electricity while also proposing three alternative expansion solutions. Three unrelated developers proposed 12 other solutions. NYISO’s response to the solicitation proposals, including the Transco-NYPA proposals, is expected to be issued in the fourth quarter of 2022. In the event, that a Transco-NYPA proposal is accepted by NYISO, CHET would own, and fund the equity investment associated with Transco’s portion of the project.

During 2020, CHEC had equity investments in various limited partnerships, one of which held investments in energy sector start-up companies. This equity investment was terminated and liquidated at its approximate book value during 2020. The value of CHEC's equity investments at December 31, 2021 and 2020 was approximately $0.2 million, respectively; and the investments are not considered to be a part of the core business.

NOTE 7 – Research and Development

Central Hudson’s R&D expenditures were $4.1 million in 2021, $3.7 million in 2020 and $3.5 million in 2019. These expenditures were for internal research programs and for contributions to research administered by NYSERDA, the Electric Power Research Institute and other industry organizations.

Note 8 – Leases

At December 31, 2021, CH Energy Group did not have any leases other than leases from Central Hudson. Central Hudson’s leasing activities accounted for as operating leases include office facilities and equipment with remaining terms of approximately three to eight years and communication tower space with remaining terms of approximately three to 15 years including options to renew existing leases for an additional 10 to 15 years. Most leases include one or more options to renew, with renewal

terms that may extend the lease term from 15 to 20 years. Certain lease agreements include periodic escalation clauses based on an index or fixed rate or require Central Hudson to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises.

The following table details supplemental balance sheet information related to CH Energy Group and Central Hudson’s operating leases (In Thousands):


Leases	Classification	December 31, 2021		December 31, 2020
Operating Lease Assets	Other Assets	$	3,488	$	3,586

Current Operating Lease Liabilities	Other Current Liabilities	$	433	$	345
Noncurrent Operating Lease Liabilities	Other Liabilities		3,155		3,281
Total Lease Liabilities		$	3,588	$	3,626

Operating and variable lease costs, as well as short-term lease cost for the years ended December 31, 2021, 2020, and 2019 were not material to CH Energy Group or Central Hudson’s results of operations.

As of December 31, 2021, CH Energy Group and Central Hudson had the following minimum future maturities of operating lease liabilities (In Thousands):


Year Ending December 31,	Operating Leases
2022	$	537
2023	545
2024	506
2025	451
2026	404
Thereafter	1,701
Total Lease Payments	4,144
Less: Imputed Interest	556
Total Lease Liabilities	3,588
Less: Current Portion	433
Total Non-Current Lease Liabilities	$	3,155

The following table includes supplemental information related to CH Energy Group and Central Hudson’s operating leases:


	December 31, 2021		December 31, 2020

Weighted-Average Remaining Lease Term (years)		8.4		9.7
Weighted-Average Discount Rate		3.11%		3.26%

NOTE 9 – Short-Term Borrowing Arrangements

Committed Credit Facilities

On July 10, 2015, CH Energy Group entered into a Third Amended and Restated Credit Agreement with four commercial banks. The credit commitment of the banks under the agreement was $50 million with

a maturity date of July 10, 2020. CH Energy Group did not replace this credit agreement upon its maturity.

On March 13, 2020, Central Hudson entered into a $200 million, five-year revolving credit agreement with five commercial banks to replace the agreement that was set to expire on October 15, 2020. Proceeds received from the revolving credit agreement are used for working capital needs and for general corporate purposes. Letters of credit are available up to $15 million from three participating banks.

The Central Hudson credit agreement includes a covenant that its total funded debt to total capital will not exceed 0.65 to 1.00. The credit agreement is also subject to certain restrictions and conditions, including that there will be no event of default, and subject to certain exceptions, that Central Hudson will not sell, lien, or otherwise encumber its assets or enter into certain transactions including certain transactions with affiliates. Central Hudson is also required to pay a commitment fee calculated at a rate based on the applicable Standard and Poor’s or Moody’s rating on the average daily unused portion of the credit facility. At December 31, 2021, Central Hudson was in compliance with all financial debt covenants.

Uncommitted Credit

At December 31, 2021 and 2020, Central Hudson had uncommitted short-term credit arrangements with two commercial banks totaling $30 million. Proceeds from these credit arrangements are used to diversify cash sources and provide competitive options to minimize Central Hudson's cost of short-term debt.

Balances outstanding under the various credit arrangements are as follows (Dollars in Thousands):


		CH Energy Group					Central Hudson
		December 31,		December 31,			December 31,		December 31,
		2021		2020			2021		2020

	Committed Credit	$	100,000	$	-	1	$	100,000	$	-
	Uncommitted Credit	1	7,000		15,000			7,000		15,000
	Total	$	107,000	$	15,000		$	107,000	$	15,000
Weighted Average Interest Rate		1	0.99%		0.90%			0.99%		0.90%

NOTE 10 – Capitalization – Common and Preferred Stock

Capital Contributions

During 2021, CH Energy Group received a contribution of approximately $5.0 million under the tax sharing agreement with its parent FortisUS. Additionally, during 2021 CH Energy Group received capital contributions of $4.4 million from FortisUS, and Central Hudson received a capital contribution of $6.0 million from its parent company CH Energy Group. During 2021, CHET received capital contributions of $4.0 million from its parent CH Energy Group in order to fund capital expenditures related to the Transco AC Project.

During 2020, CH Energy Group received capital contributions of $15.0 million from its parent FortisUS, and Central Hudson received capital contributions of $12.0 million from its parent company CH Energy

Group. Additionally during 2020, CHET received a $0.3 million capital contribution from its parent CH Energy Group.

During 2019, CH Energy Group received capital contributions of $29.5 million from FortisUS, and Central Hudson received capital contributions of $11.0 million from its parent CH Energy Group. Additionally during 2019, CHET received a $1.1 million capital contribution from its parent CH Energy Group.

These contributions were recorded as paid in capital, see CH Energy Group’s and Central Hudson’s Consolidated Statements of Equity.

Common Stock Dividends

CH Energy Group’s ability to pay dividends is affected by the ability of its subsidiaries to pay dividends. The Federal Power Act limits the payment of annual dividends by Central Hudson to its retained earnings. More restrictive is the PSC’s limit on the dividends Central Hudson may pay to CH Energy Group, which is 100% of the average annual income available for common stock, calculated on a two-year rolling average basis. Based on this calculation, Central Hudson was restricted to a maximum annual payment of $71.0 million, $67.0 million, and $61.5 million in dividends to CH Energy Group for the periods ended December 31, 2021, 2020, and 2019, respectively. Central Hudson’s ability to pay dividends would be reduced to 75% of its average annual income in the event of a downgrade of its senior debt rating below “BBB+” by more than one rating agency, if the stated reason for the downgrade is related to any of CH Energy Group’s or Central Hudson’s affiliates. Further restrictions are imposed for rating downgrades below this level. In addition, Central Hudson would not be allowed to pay dividends if its average common equity ratio for the 13 months prior to a proposed dividend was more than 200 basis points below the ratio used in setting rates. CH Energy Group’s other subsidiaries do not have express restrictions on their ability to pay dividends.

In 2021 and 2020, CH Energy Group did not pay any dividends to FortisUS, the sole shareholder of CH Energy Group. In 2019, the Board of Directors of CH Energy Group declared and paid dividends of $16.5 million to FortisUS.

Central Hudson did not pay any dividends to its parent CH Energy Group in 2021, 2020, and 2019.

CHET did not pay dividends to its parent CH Energy Group during 2021 and 2020. CHET declared and paid dividends of $0.9 million to its parent CH Energy Group during 2019.

CHEC declared and paid dividends of $1.0 million to its parent CH Energy Group in 2021. CHEC did not pay any dividends to its parent CH Energy Group during 2020 and 2019.

Preferred Stock

Other than one share of Junior Preferred Stock, Central Hudson had no outstanding preferred stock as of December 31, 2021 and 2020.

NOTE 11 – Capitalization – Long-Term Debt

The majority of the long-term debt instruments are redeemable at the discretion of CH Energy Group and Central Hudson, at any time, at the greater of par or a specified price as defined in the respective long-term debt agreements, together with accrued and unpaid interest.

A summary of CH Energy Group’s and Central Hudson’s long-term debt is as follows (In Thousands):

December 31, 2021

December 31, 2020


				Unamortized				Unamortized
				Debt Issuance				Debt Issuance
Series	Maturity Date	Principal		Costs		Principal		Costs
Central Hudson:
Promissory Notes:
2006 Series E (5.76%)(4)	Nov. 17, 2031	$	27,000	$	171	$	27,000	$	188
1999 Series B(1),(2)	Jul. 01, 2034		33,700		216		33,700		233
2005 Series E (5.84%)(4)	Dec. 05, 2035		24,000		139		24,000		149
2007 Series F (5.804%)(5)	Mar. 23, 2037		33,000		211		33,000		225
2009 Series F (5.80%)(5)	Nov. 01, 2039		24,000		193		24,000		204
2010 Series B (5.64%)(6)	Sep. 21, 2040		24,000		94		24,000		99
2010 Series G (4.15%)(6)	Apr. 01, 2021		-		-		44,150		11
2010 Series G (5.716%)(6)	Apr. 01, 2041		30,000		199		30,000		209
2011 Series G (3.378%)(6)	Apr. 01, 2022		23,400		7		23,400		37
2011 Series G (4.707%)(6)	Apr. 01, 2042		10,000		88		10,000		92
2012 Series G (4.776%)(6)	Apr. 01, 2042		48,000		429		48,000		450
2012 Series G (4.065%)(6)	Oct. 01, 2042		24,000		259		24,000		271
2013 Series D (4.09%)(7)	Dec. 2, 2028		16,700		72		16,700		83
2014 Series E (7),(10)	Mar. 26, 2024		30,000		45		30,000		66
2015 Series F (2.98%)(7)	Mar. 31, 2025		20,000		51		20,000		67
2016 Series H (2.56%)(8)	Oct. 28, 2026		10,000		44		10,000		53
2016 Series I (3.63%)(8)	Oct. 28, 2046		20,000		117		20,000		122
2017 Series J (4.05%)(8)	Aug. 31, 2047		30,000		164		30,000		170
2017 Series K (4.20%)(8)	Aug. 31, 2057		30,000		171		30,000		176
2018 Series L (4.27%)(8)	Jun. 15, 2048		25,000		169		25,000		175
2018 Series M (3.99%)(8)	Oct. 28, 2026		40,000		149		40,000		180
2018 Series N (4.21%)(8)	Oct. 28, 2033		40,000		196		40,000		213
2019 Series O (3.89%)(9)	Oct. 28, 2049		50,000		259		50,000		269
2019 Series P (3.99%)(9)	Oct. 28, 2059		50,000		264		50,000		271
2020 Series Q (3.42%)(9)	May 14 2050		30,000		166		30,000		172
2020 Series R (3.62%)(9)	Jul. 14, 2060		30,000		169		30,000		174
2020 Series S (2.03%)(9)	Sep. 28, 2030		40,000		192		40,000		214
2020 Series T (2.03%)(9)	Nov. 17, 2030		30,000		157		30,000		175
2021 Series U (3.29%)(9)	Mar. 16, 2051		75,000		406		-		-
2021 Series V (3.22%)(9)	Oct. 30, 2051		55,000		305		-		-
Total Central Hudson		$	922,800	$	5,102	$	836,950	$	4,748
Less: Current Portion of Long-term Debt			(23,400)				(44,150)
Central Hudson Net Long-term Debt		$	899,400			$	792,800
CH Energy Group:
Promissory Notes:
2009 Series B (6.80%)(3)	Dec. 15, 2025	$	8,710	$	37	$	10,547	$	47
Less: Current Portion of Long-term Debt			(1,964)				(1,837)


CH Energy Group Net Long-term Debt	$	906,146	$	5,139	$	801,510	$	4,795

(1) Promissory Notes issued in connection with the sale by NYSERDA of tax-exempt pollution control revenue bonds.
(2) Variable (auction) rate notes.
(3) The maturity date represents the final repayment date, principal repayments are due semi-annually.
(4) Issued pursuant to a 2004 PSC Order approving the issuance by Central Hudson prior to December 31, 2006, of up to $85 million of unsecured medium-term notes.
(5) Issued pursuant to a 2006 PSC Order approving the issuance by Central Hudson prior to December 31, 2009, of up to $120 million of unsecured medium-term notes.
(6) Issued pursuant to a 2009 PSC Order approving the issuance by Central Hudson prior to December 31, 2012, of up to $250 million of unsecured medium-term notes or other forms of long-term indebtedness.
(7) Issued pursuant to a 2012 PSC Order approving the issuance by Central Hudson prior to December 31, 2015, of up to $250 million of unsecured medium-term notes or other forms of long-term indebtedness.
(8) Issued pursuant to a 2015 PSC Order approving the issuance by Central Hudson prior to December 31, 2018, of up to $350 million of unsecured medium-term notes or other forms of long-term indebtedness.
(9) Issued pursuant to a 2018 PSC Order approving the issuance by Central Hudson prior to December 31, 2021, of up to $425 million of unsecured medium-term notes or other forms of long-term indebtedness.
(10) Variable rate notes.

On March 16, 2021, Central Hudson issued $75 million of Series U Senior Notes, with an interest rate of 3.29% per annum and a maturity date of March 16, 2051. On October 28, 2021, Central Hudson issued $55 million of Series V Senior Notes, with an interest rate of 3.22% per annum and a maturity date of October 30, 2051. Central Hudson used the proceeds from the sale of the Senior Notes for general corporate purposes, including the repayment of $44.2 million of maturing debt on April 1, 2021 and the repayment of short-term borrowings.

During 2020, Central Hudson issued $130 million in unsecured Senior Notes, with various interest rates and maturities ranging from 10 to 40 years. Central Hudson used the proceeds from the sale of the Senior Notes to repay $40 million of maturing debt and for general corporate purposes, including the funding of capital expansion and improvement projects and the repayment of short-term borrowings.

At December 31, 2021, Central Hudson had $30 million of 2014 Series E 10-year notes with a floating interest rate of 3-month LIBOR plus 1%. To mitigate the potential cash flow impact from unexpected increases in short-term interest rates, Central Hudson purchased a four-year interest rate cap that will expire on March 26, 2024. The rate cap has a notional amount equal to the outstanding principal amount of the 2014 Series E notes and is based on the quarterly reset of the LIBOR rate on the quarterly interest payment dates. Central Hudson would receive a payout if the LIBOR rate exceeds 3% at the start of any quarterly interest period during the term of the cap. This interest rate cap replaced a similar interest rate cap that expired on March 26, 2020. There have been no payouts on these interest rate caps during the years ended December 31, 2021 and 2020.

The principal amount of Central Hudson’s outstanding 1999 Series B NYSERDA Bonds totaled $33.7 million at December 31, 2021. These are tax-exempt multi-modal bonds that are currently in a variable rate mode and mature in 2034. To mitigate the potential cash flow impact from unexpected increases in short-term interest rates on Series B NYSERDA Bonds, Central Hudson purchased a three-year interest rate cap. The rate cap has a notional amount equal to the outstanding principal amount of the Series B bonds and expires on April 1, 2022. The cap is based on the monthly weighted average of an index of tax-exempt variable rate debt, multiplied by 175%. Central Hudson would receive a payout if the adjusted index exceeds 4% for a given month. There was no payout on this interest rate cap during the year ended December 31, 2021 and Central Hudson received a payout of $0.03 million during the year ended December 31, 2020.

See Note 16 – “Accounting for Derivative Instruments and Hedging Activities” for fair value disclosures related to these interest rate cap agreements.

In its 2021 Rate Order, the PSC extended the continued deferral accounting treatment for variations in the interest costs of the 1999 Series B NYSERDA Bonds and the Series E 10-year notes. As such, variations between the actual interest rates on these bonds and the interest rate included in the current delivery rate structure for these bonds are deferred for future recovery from or refund to customers and therefore do not impact earnings. The regulatory asset or liability related to the variable rate note is included in the “other” category, See Note 4 – “Regulatory Matters”.

Long-Term Debt Maturities

See Note 17 – “Other Fair Value Measurements” for a schedule of long-term debt maturing or to be redeemed during the next five years and thereafter.

Financing Petition

By Order issued and effective November 22, 2021, the PSC authorized Central Hudson to enter into multi-year credit agreements in an aggregate amount not to exceed $250 million; and to issue and sell new long-term debt in an aggregate amount not to exceed $412 million through December 2024. The Order also allows Central Hudson to refinance $33.7 million of existing variable-rate debt obligations prior to December 31, 2024.

The continuation of our current revolving credit agreement of $200 million and the ability to increase the limit to $250 million of credit provides liquidity to support construction forecasts, seasonality, volatile energy markets, adverse borrowing environments, and other unforeseen events. See Note 9 – “Short-Term Borrowing Arrangements” for additional information on the committed credit funding.

The approval to issue and sell up to $412 million of long-term debt provides Central Hudson with additional means to fund operational needs, continued capital investments and repay maturing debt.

Debt Covenants

CH Energy Group’s $8.7 million of privately placed notes require compliance with certain covenants including maintaining a ratio of total consolidated debt to total consolidated capitalization of no more than 0.65 to 1.00 and not permitting certain debt, other than the privately placed notes, associated with the unregulated operations of CH Energy Group to exceed 10% of total consolidated assets.

Central Hudson, under the terms of the various note purchase agreements, is subject to similar financial covenants and restrictions to those of CH Energy Group, including restrictions with respect to Central Hudson’s indebtedness and assets.

As of December 31, 2021, CH Energy Group and Central Hudson were in compliance with all covenants.

NOTE 12 – Post-Employment Benefits

In its Orders, the PSC has authorized deferral accounting treatment for any variations between actual Pension and OPEB expense and the amount included in the current delivery rate structure. As a result, variations in expenses for post-employment benefit plans at Central Hudson do not have any impact on earnings.

Pension Benefits

Central Hudson has a non-contributory Retirement Plan covering substantially all of its employees hired before January 1, 2008 and a non-qualified SERP for certain executives. The Retirement Plan is a defined benefit plan, which provides pension benefits based on an employee’s compensation and years of service. In 2007, Central Hudson amended the Retirement Plan to eliminate these benefits for managerial, professional, and supervisory employees hired on or after January 1, 2008. The Retirement Plan for unionized employees was similarly amended for all employees hired on or after May 1, 2008. As of December 31, 2021, 33% of all active employees were eligible to participate in the Retirement Plan. The Retirement Plan’s assets are held in a trust fund. Central Hudson has provided periodic updates to the benefit formulas stated in the Retirement Plan.

Central Hudson’s funded status for Pension benefits was $68.7 million at December 31, 2021 and a liability of $26.8 million at December 31, 2020. The fluctuation in Central Hudson’s under-funded liability status to a prefunded status of approximately $95.5 million was the result of a decrease in the PBO liabilities of approximately $47.6 million coupled with a $47.9 million increase in plan assets. The decrease in liabilities was primarily driven by an increase in the discount rate and the increase in plan assets was primarily driven by investment gains.

The funded status includes the difference between the PBO for the Retirement Plan and the market value of the pension assets, net of any liability for the non-qualified SERP. The funded status does not reflect approximately $40.1 million and $32.9 million of SERP trust assets at December 31, 2021 and 2020.

The cumulative amount of net periodic benefit cost in excess of employer contributions at December 31, 2021 and December 31, 2020 was $26.1 million and $25.8 million, respectively. This does not include any cumulative contributions to the SERP as it is a non-qualified plan.

The difference between these amounts and the prefunded asset/(accrued liability balance), totaling $94.8 million at December 31, 2021 and ($1.1) million at December 31, 2020, represents the required funded status adjustment and will be recognized in Central Hudson’s future expense. Gains or losses and prior service costs or credits that arise during the period, but that are not recognized as components of net periodic pension cost, would typically be recognized as a component of other comprehensive income (“OCI”), net of tax. However, Central Hudson has PSC approval to record regulatory assets or liabilities rather than adjusting comprehensive income to offset the funding status adjustment for amounts recoverable from customers in future rates. Therefore, these funded status adjustments have been recorded as a regulatory asset/liability for the portion recoverable/refundable from/to Central Hudson customers in accordance with the 1993 PSC Policy and as OCI for the portion, net of tax, that relates to a former Central Hudson officer who transferred to an affiliated company. These amounts reported as OCI are charged to and reimbursed by the affiliated company.

The funded status of Central Hudson's pension costs is as follows (In Thousands):




		December 31,		December 31,
		2021(1)(2)		2020(1)(2)
Prefunded/(accrued) pension costs		$	68,728	$	(26,813)

(1)	Includes approximately $0.2 million at December 31, 2021 and 2020 of accrued pension liability recorded at CH Energy Group as a result of the resignation in 2014 of a CH Energy Group officer with a change in control agreement.
(2)	Includes approximately $1.5 million at December 31, 2021 and 2020 that is reflected in the Balance Sheet under other current liabilities for pension payments expected to be made over the next twelve months

The following reflects the impact of the recording of funding status adjustments on the Balance Sheets of CH Energy Group and Central Hudson (In Thousands):



	December 31,		December 31,
	2021(1)(2)		2020(1)(2)
Accrued pension costs prior to funding status adjustment	$	(26,068)	$	(25,751)
Funding status adjustment required		94,796		(1,062)
Prefunded (Accrued) pension costs	$	68,728	$	(26,813)

Offset to funding status adjustment - regulatory (liability) assets - pension plan	$	(94,773)	$	851
Offset to funding status adjustment - accumulated OCI, net of tax of ($6) and $55, respectively	$	(17)	$	156

(1) Includes approximately $0.2 million at December 31, 2021 and 2020 of accrued pension liability recorded at CH Energy Group as a result of the resignation in 2014 of a CH Energy Group officer with a change in control agreement.
(2) Includes approximately $1.5 million at December 31, 2021 and 2020 that is reflected in the Balance Sheet under other current liabilities for pension payments expected to be made over the next twelve months.

Decisions to fund Central Hudson’s Retirement Plan are based on several factors, including, but not limited to, the funded status, corporate resources, projected investment returns, actual investment returns, inflation, regulatory considerations, interest rate assumptions and the requirements of the Pension Protection Act of 2006 (“PPA”). Based on the funding requirements of the PPA, Central Hudson plans to make contributions that maintain the target funded percentage at 80% or higher. Actual contributions could vary significantly based upon a range of factors that Central Hudson considers in its funding decisions.

In accordance with the terms of the Trust agreement for the SERP, following the acquisition of CH Energy Group, Inc. by Fortis on June 27, 2013, Central Hudson is required to maintain a funding level for the SERP at 110% of the present value of the accrued benefits payable under the Plan on an annual basis.

Contributions to the Central Hudson Retirement and SERP Plans are as follows (In Thousands):


		Year Ended December 31,
		2021		2020		2019
Retirement Plan	1	$	-	$	-	$	-
SERP		$	8,115	$	6,998	$	-

Retirement Plan Discount Rate

The valuation of the current and prior year PBO was determined using discount rates of 2.76% and 2.34% for December 31, 2021 and 2020, respectively, as determined from the Mercer Pension Discount Yield Curve reflecting projected pension cash flows. A 1.0% increase in the discount rate would decrease the projection of the pension PBO by approximately $98.4 million. Central Hudson accounts for pension activity in accordance with PSC-prescribed provisions, which among other things, requires a ten-year amortization of actuarial gains and losses.

The 2018 and 2021 Rate Orders include rate allowances for pension and OPEB expense which approximate the recent cost of providing these benefits. Authorization remains in effect for the deferral

of any differences between rate allowances and actual costs under the 1993 PSC Policy to counteract the volatility of these costs.

Retirement Plan Expected Long-Term Rates of Return

The expected long-term rate of return on the Retirement Plan assets utilized in the calculation of the net periodic benefit cost, net of investment expense for December 31, 2021 and 2020 is 4.60% and 5.09%, respectively. In determining the expected long-term rate of return on plan assets, Central Hudson considered forward-looking estimated returns evaluated in light of current economic conditions and based on internally consistent economic models. The expected long-term rate of return is a weighted average based on each plan's investment mix and the forward-looking estimated returns for each investment class. Central Hudson monitors actual performance against target asset allocations and adjusts actual allocations and targets in accordance with the Retirement Plan strategy. A 1.0% decrease in the expected long-term rate of return would have increased the 2021 net periodic benefit cost by approximately $8.1 million.

Retirement Plan Policy and Strategy

Central Hudson’s Retirement Plan investment policy seeks to reduce the plan’s funded status volatility while targeting a rate of growth equivalent to that of the liability within reasonable risk tolerance levels. In addition to traditional risk and return measures, the policy reflects liability-based considerations, including the Retirement Plan’s funded status, contribution requirements and financial statement items. Due to market fluctuations, Retirement Plan assets require rebalancing from time to time to maintain the asset allocation within target ranges.

Asset allocation targets in effect as of December 31, 2021, as well as actual asset allocations as of December 31, 2021, and December 31, 2020 expressed as a percentage of the market value of Retirement Plan assets, are summarized in the table below:


Asset Class		Minimum	Target Average	Maximum	December 31, 2021	December 31, 2020
Equity Securities		45%	50%	55%	53.2%	52.4%
Debt Securities		45%	50%	55%	45.3%	45.9%
Other(1)		0%	0%	10%	1.5%	1.7%

(1)	Consists of temporary cash investments, as well as receivables for investments sold and interest and payables for investments purchased, which have not settled as of that date.

Retirement Plan Investment Valuation

The Retirement Plan assets consist primarily of investment funds which are valued using Net Asset Value, which is not considered fair value. For those assets that are valued under the current fair value framework, the inputs or methodology used are not necessarily an indication of the risk associated with investing in those securities. See Note 16 – “Accounting for Derivative Instruments and Hedging Activities” for further discussion regarding the definition and levels of fair value hierarchy established by accounting guidance.

Below is a listing of the major categories of plan assets held as of December 31, 2021 and 2020, that are reported at net asset value or fair value, as indicated (Dollars in Thousands):


Investment Type		Value at 12/31/21		% of Total		Value at 12/31/20		% of Total
At Net Asset Value:
	Investment Funds - Equities	$	466,054	53.2	%	$	433,637	52.4	%
	Investment Funds - Fixed Income		135,040	15.4			128,325	15.5
At Fair Value:
Level 2:
	Cash Equivalents		11,203	1.3			12,599	1.5
	Investment Funds - Fixed Income		261,887	29.9			251,767	30.4
	Other Investments		1,875	0.2			1,842	0.2
		$	876,059	100	%	$	828,170	100	%

Other Post-Retirement Benefits

Central Hudson also provides certain health care and life insurance benefits for certain retired employees through its post-retirement benefit plans. Substantially all of Central Hudson’s unionized employees and managerial, professional and supervisory employees (“non-union”) hired prior to January 1, 2008, may become eligible for these benefits if they reach retirement age while employed by Central Hudson. Central Hudson amended its OPEB programs for existing non-union and certain retired employees effective January 1, 2008, which eliminated post-retirement benefits for non-union employees hired on or after January 1, 2008. OPEB plans were also amended to eliminate post-retirement benefits for union employees hired on or after May 1, 2008. Benefits for retirees and active employees are provided through insurance companies whose premiums are based on the benefits paid during the year.

The significant assumptions used to account for these benefits are the discount rate, the expected long-term rate of return on plan assets and the health care cost trend rate. Central Hudson currently selects the discount rate using the Mercer Pension Discount Yield Curve reflecting projected cash flows. The expected long-term rates of return and the investment policy and strategy for these plan assets are similar to those used for pension benefits previously discussed in this Note. The estimates of health care cost trend rates are based on a review of actual recent trends and projected future trends.

Central Hudson fully recovers its net periodic post-retirement benefit costs in accordance with the 1993 PSC Policy. Under these guidelines, the difference between the amounts of post-retirement benefits recoverable in rates and the amounts of post-retirement benefits determined by an actuarial consultant in accordance with current accounting guidance related to OPEB is deferred as either a regulatory asset or a regulatory liability, as appropriate.

Central Hudson’s asset (i.e. the over-funded status) for OPEB was $30.5 million and $6.5 million at December 31, 2021 and 2020, respectively. The increase in the over-funded status of approximately $24.0 million resulted from a $16.1 million increase in plan assets coupled with a decrease in plan liabilities of approximately $7.9 million. The increase in plan assets was primarily driven by investment gains. The decrease in plan liabilities was primarily driven by an increase in the discount rate.

The cumulative amount of net periodic benefit cost in excess of employer contributions at December 31, 2021 and December 31, 2020 was $0.6 million and $7.2 million, respectively. The difference between these amounts and the over-funded asset balance, totaling $31.1 million at December 31, 2021 and $13.7 million at December 31, 2020 will be recognized as a credit in Central Hudson’s future expense and has been recorded as a regulatory liability in accordance with the 1993 PSC Policy.

Contribution levels to the OPEB Plans are determined by various factors including the discount rate, expected return on plan assets, medical claims assumptions used, mortality assumptions used, benefit changes, corporate resources and regulatory considerations.

Contributions to the Central Hudson OPEB Plans were as follows (In Thousands):


	Year Ended December 31,
	2021		2020		2019
OPEB Plans	$	812	$	1,081	$	1,001


OPEB Healthcare Cost Trend Rate

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. A 1.0% change in assumed health care cost trend rates would have the following effects (In Thousands)

	One Percentage Point
	Increase		Decrease
Effect on total of service and interest cost components for 2021	$	835	$	(655)
Effect on year-end 2021 post-retirement benefit obligation	$	15,775	$	(12,828)

OPEB Discount Rate

The PBO for Central Hudson’s obligation for OPEB costs was determined using a discount rate of 2.74% and 2.32% for December 31, 2021 and 2020, respectively. This rate was determined using the Mercer Pension Discount Yield Curve reflecting projected cash flows. A 1.0% increase in the discount rate for 2021 would have decreased the projection of the OPEB obligation by approximately $18.0 million.

OPEB Expected Long-Term Rates of Return

The expected long-term rate of return on OPEB assets utilized in the calculation of the net periodic benefit cost, net of investment expense for December 21, 2021 and 2020 is 5.01% and 5.55%, respectively. In determining the expected long-term rate of return on plan assets, Central Hudson considered forward-looking estimated returns for each asset class evaluated in light of current economic conditions. The expected long-term rate of return is a weighted average based on each plan's investment mix and the forward-looking estimated returns for each investment class. A 1.0% decrease in the expected long-term rate of return would have increased the 2021 net periodic benefit cost by $1.6 million. Central Hudson monitors actual performance against target asset allocations and adjusts actual allocations and targets as deemed appropriate in accordance with the OPEB plan’s strategy.

OPEB Policy and Strategy

Central Hudson currently funds its union OPEB obligations through a voluntary employee’s beneficiary association (“VEBA”), and funds its management OPEB liabilities through a 401(h) plan. The VEBA and 401(h) plan are both a form of trust fund. Central Hudson’s VEBA investment policy seeks to achieve a rate of return for the VEBA over the long term that contributes to meeting the VEBA’s current and future obligations, including interest and benefit payment obligations. The policy also seeks to earn long-term returns from capital appreciation and current income that at least keep pace with inflation over the long term. Central Hudson’s 401(h) plan is invested with the previously mentioned Retirement Plan’s investments. However, there are no assurances that the OPEB plan’s return objectives will be achieved.

The asset allocation strategy employed in the VEBA reflects Central Hudson’s return objectives and what management believes is an acceptable level of short-term volatility in the market value of the VEBA's assets in exchange for potentially higher long-term returns. The mix of assets shall be broadly diversified by asset class and investment styles within asset classes, based on the following asset allocation targets, expressed as a percentage of the market value of the VEBA’s assets, summarized in

the table below:


Asset Class	Minimum	Target Average	Maximum	December 31, 2021	December 31, 2020
Equity Securities	55%	65%	75%	68.7%	67.9%
Debt Securities	25%	35%	45%	30.9%	31.7%
Other	- %	- %	- %	0.4%	0.4%

Due to market value fluctuations, the OPEB plan’s assets require periodic rebalancing from time to time to maintain the asset allocation within target ranges.

Management uses outside consultants and outside investment managers to aid in the determination of the OPEB plan’s asset allocation and to provide the management of actual plan assets, respectively.

OPEB Investment Valuation

The OPEB plan’s assets consist primarily of investment funds which are valued using Net Asset Value, which is not considered fair value. For those assets that are valued under the current fair value framework, the inputs or methodology used are not necessarily an indication of the risk associated with investing in those securities. See Note 16 – “Accounting for Derivative and Hedging Activities” for further discussion regarding the definition and levels of fair value hierarchy established by guidance.

Below is a listing of the major categories of plan assets held as of December 31, 2021 and 2020, that are reported at net asset value or fair value, as indicated (Dollars in Thousands):


401(h) Plan Assets

Investment Type		Market Value at 12/31/21		% of Total		Market Value at 12/31/20		% of Total
At Net Asset Value:
	Investment Funds - Equities	$	18,429	53.2	%	$	17,080	52.4	%
	Investment Funds - Fixed Income		5,340	15.4			5,055	15.5
At Fair Value:
Level 2:
	Cash Equivalents		439	1.3			502	1.5
	Investment Funds - Fixed Income		10,356	29.9			9,917	30.4
	Other Investments		78	0.2			67	0.2


$	34,642	100	%	$	32,621	100	%


Union VEBA Plan Assets

Investment Type		Market Value at 12/31/21		% of Total		Market Value at 12/31/20		% of Total
At Fair Value:
Level 1:
	Cash Equivalents	$	628	0.4	%	$	549	0.4	%
	Investment Funds - Equities		99,598	68.7			88,914	67.9
	Investment Funds - Fixed Income		44,849	30.9			41,554	31.7
		$	145,075	100	%	$	131,017	100	%


Detail of the change in Central Hudson’s Pension and OPEB benefit obligations, fair value of plan assets and funded status as of and for the periods ended December 31, 2021 and 2020 is as follows (In Thousands):

		Pension Benefits(1)				Other Post Retirement Benefits
		2021		2020		2021		2020
Change in Benefit Obligation:
Benefit Obligation at beginning of year		$	854,983	$	746,774	$	157,141	$	134,943
	Service cost		15,053		13,453		1,875		1,671
	Interest cost		19,849		23,688		3,568		4,193
	Participant contributions		-		-		1,332		1,234
	Benefits paid		(36,012)		(33,818)		(7,609)		(7,676)
	Actuarial (gain)/loss		(46,542)		104,886		(7,070)		22,776
Benefit Obligation at end of year		$	807,331	$	854,983	$	149,237	$	157,141
Change in Value of Plan Assets:
Fair Value of Plan Assets at beginning of year		$	828,170	$	734,470	$	163,638	$	147,458
	Actual return on plan assets		84,281		128,554		21,848		21,401
	Employer contributions		1,476		1,131		812		1,081
	Participant contributions		-		-		1,332		1,234
	Benefits paid		(36,012)		(33,818)		(7,609)		(7,676)
	Other		(1,856)		(2,167)		(304)		140
Fair Value of Plan Assets at end of year		$	876,059	$	828,170	$	179,717	$	163,638
	Funded Status at end of year	$	68,728	$	(26,813)	$	30,480	$	6,497

(1) The plan assets as presented in this chart do not include approximately $40.1 million and $32.9 million of SERP trust assets at December 31, 2021 and 2020
The following table summarizes the employee future benefit assets and liabilities and their classifications on the Consolidated Balance Sheets and Statements of Comprehensive Income at December 31 (In Thousands):

		Pension Benefits(1)				Other Post Retirement Benefits
		2021		2020		2021		2020
Amounts Recognized on Balance Sheet:
	Noncurrent assets	$	70,222	$	-	$	30,480	$	6,497
	Current liabilities		(1,494)		(1,473)		-		-
	Noncurrent liabilities				(25,340)		-		-
	Funded Status at end of year	$	68,728	$	(26,813)	$	30,480	$	6,497
	Regulatory asset(liability):
	Net actuarial gain	$	(96,441)	$	(1,109)	$	(29,264)	$	(11,435)
	Prior service costs (credit)	$	1,645	$	2,171	$	(1,841)	$	(2,303)
	Other comprehensive income:


	Net actuarial (gain)/loss, net of tax	$	(18)	$	39	$	(2)	$	1
	Prior service costs, net of tax	$	1	$	117	$	-	$	4

(1) The funded status in this chart does not reflect approximately $40.1 million and $32.9 million of SERP trust assets at December 31, 2021 and 2020


Central Hudson's net periodic benefit costs for its Pension and OPEB plans for the periods ended December 31, 2021 and 2020 are as follows (In Thousands):

		Pension Benefits				Other Post Retirement Benefits
		2021		2020		2021		2020
Components of Net Periodic Benefit Cost:
	Service cost	$	15,053	$	13,453	$	1,875	$	1,671
	Interest cost		19,849		23,688		3,568		4,193
	Expected return on plan assets		(36,168)		(35,346)		(7,944)		(7,941)
	Amortization of prior service cost (credit)		527		647		(456)		(456)
	Amortization of recognized actuarial net (gain)/loss		2,532		1,605		(2,601)		(3,916)
Net Periodic (Benefit) Cost		$	1,793	$	4,047	$	(5,558)	$	(6,449)

The following table provides the components recognized in net periodic benefit cost and as regulatory assets which otherwise would have been recognized in comprehensive income, as well as the weighted average assumptions used in the periods (Dollars In Thousands):

		Pension Benefits(1)				Other Post Retirement Benefits
		2021		2020		2021		2020
Other Changes in Plan Assets and Benefit Obligation Recognized in Regulatory Assets/Liabilities:
	Net (gain)/loss	$	(92,801)	$	13,846	$	(20,431)	$	9,359
	Amortization of actuarial net (loss) gain		(2,532)		(1,605)		2,601		3,916
	Amortization of prior service (cost) credit		(527)		(647)		456		456
Total recognized in regulatory asset		$	(95,860)	$	11,594	$	(17,374)	$	13,731
Total recognized in net periodic benefit cost and regulatory asset		$	(94,067)	$	15,641	$	(22,932)	$	7,282


Weighted-average assumptions used to determine benefit obligations:
	Discount rate	2.76%	2.34%	2.74%	2.32%
	Rate of compensation increase (average)	3.90%	3.90%	3.90%	3.90%
	Measurement date	12/31/21	12/31/20	12/31/21	12/31/20
Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31:
	Discount rate	2.34%	3.20%	2.32%	3.18%
	Expected long-term rate of return on plan assets	4.60%	5.09%	5.01%	5.55%
	Rate of compensation increase (average)	3.90%	4.00%	3.90%	4.00%
Assumed health care cost trend rates at December 31:
	Health care cost trend rate assumed for next year	N/A	N/A	6.00%	5.52%


	Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)		N/A		N/A	4.00%	4.50%
	Year that the rate reaches the ultimate trend rate		N/A		N/A	2046	2038
Accumulated Benefit Obligation		$	756,806	$	795,099	N/A	N/A

(1) The fair value of plan assets presented in this chart does not include approximately $40.1 million and $32.9 million of SERP trust assets at December 31, 2021 and 2020.

Estimated net gain of $14.7 million and prior service cost of $0.5 million for the defined benefit pension plans will be amortized from regulatory liability and OCI respectively, into net periodic benefit cost over the next fiscal year. Estimated net gain of $5.7 million and prior service credit of $0.5 million for the other defined benefit post-retirement plans will be amortized from regulatory liability and OCI respectively, into net periodic benefit cost over the next fiscal year. The amount of transitional obligation to be amortized from regulatory liabilities and OCI is immaterial.


Estimated Future Benefit Payments

The following benefit payments, which reflect expected future service as appropriate, are expected to be paid (In Thousands):

Year	Pension Benefits - Gross		Other Benefits - Gross		Other Benefits - Net(1)
2022	$	38,677	$	7,869	$	7,335
2023		39,272		8,223		7,682
2024		39,938		8,489		7,936
2025		40,628		8,612		8,042
2026		41,465		8,886		8,304
Next five years		211,566		43,995		40,792

(1) Estimated benefit payments reduced by estimated gross amount of Medicare Act of 2003 subsidy receipts expected

401(k) Retirement Plan

Central Hudson sponsors a 401(k) plan for its employees. The 401(k) plan provides for employee tax-deferred salary deductions for participating employees and employer matches. The matching benefit varies by employee group. Central Hudson’s matching contributions for the years ended December 31, 2021, 2020 and 2019 were $5.8 million, $5.6 million, and $5.2 million, respectively. Central Hudson also provides an additional contribution of 4% to the 401(k) plan of annualized base salary for eligible employees who do not qualify for Central Hudson’s Retirement Income Plan. The additional non-discretionary contribution was approximately $2.8 million, $2.7 million and $2.3 million for 2021, 2020, and 2019, respectively.

NOTE 13 – Equity-Based Compensation

Share Unit Plan Units

In January 2021, officers of Central Hudson were granted 14,249 Units under the 2021 Fortis Restricted Share Unit Plan (“2021 RSUP”), representing a portion of the officers’ long-term incentives. The issued 2021 Restricted Units granted are time-based and vest at the end of the three-year period without regard to performance. Each 2021 RSUP Unit granted has an underlying value equivalent to the value of one common share of Fortis and if earned and vested is paid in cash, unless a participant does not satisfy their share ownership requirements or chooses to settle in shares. The settlement in shares by a participant will result in the modification from a liability award to an equity award and an election to settle in shares cannot be made later than 30 days prior to the awards vesting. The foreign exchange rate utilized for cash payout in the US dollar equivalent for each plan corresponds to the exchange rate

on the business day prior to the date of that 2021 RSUP Unit grant. Each 2021 RSUP Unit accrues notional dividend equivalents equal to the dividends declared by the Fortis Board of Directors on Fortis common shares.

In January 2021, officers of Central Hudson were granted 28,497 Units under the Central Hudson 2021 Share Unit Plan (“2021 SUP”), representing a portion of the officers’ long-term incentives. The issued 2021 SUP Units granted are performance based and vest at the end of the three-year performance period upon achievement of specified cumulative performance goals. Each 2021 SUP Unit granted has an underlying value equivalent to the value of one common share of Fortis and if earned and vested is paid in cash. The foreign exchange rate utilized for cash payout in the US dollar equivalent for each plan corresponds to the exchange rate on the business day prior to the date of that 2021 SUP Unit grant. Each 2021 SUP Unit accrues notional dividend equivalents equal to the dividends declared by the Fortis Board of Directors on Fortis common shares.

In 2020, officers of CH Energy Group and Central Hudson were granted Units under the 2020 Fortis Restricted Share Unit Plan (“2020 RSUP”), representing a portion of the officers’ long-term incentives. The issued 2020 Restricted Units granted are time-based and vest at the end of the three-year period without regard to performance. Each 2020 RSUP Unit granted has an underlying value equivalent to the value of one common share of Fortis and if earned and vested is paid in cash, unless a participant does not satisfy their share ownership requirements or chooses to settle in shares. The settlement in shares by a participant will result in the modification from a liability award to an equity award and an election to settle in shares cannot be made later than 30 days prior to the awards vesting. The foreign exchange rate utilized for cash payout in the US dollar equivalent for each plan corresponds to the exchange rate on the business day prior to the date of the 2020 RSUP Unit grant. Each 2020 RSUP Unit accrues notional dividend equivalents equal to the dividends declared by the Fortis Board of Directors on Fortis common shares.

In prior periods, CH Energy Group granted Units to an officer of CH Energy Group under Performance Share Unit Plans, the (“2020 PSUP”) in 2020, the (“2019 PSUP”) in 2019, and in 2018 the (“2018 PSUP”), (collectively “PSUP”). The PSUP Units granted under these plans are primarily performance based and vest upon achievement of specified performance goals over the applicable three-year performance period. The 2019 PSUP also included the grant of time-based awards that vest at the end of the three-year period without regard to performance. Each PSUP Unit has an underlying value equivalent to the value of one common share of Fortis and if earned and vested is paid in cash. The foreign exchange rate utilized for cash payout in the US dollar equivalent corresponds to the exchange rate on the business day prior to the date of the PSUP Unit grant. Each PSUP Unit accrues notional dividend equivalents equal to the dividends declared by the Fortis Board of Directors on Fortis common shares.

Officers of Central Hudson were granted Units under the Central Hudson 2020 (“2020 SUP”), the 2019 (“2019 SUP”), and the 2018 (“2018 SUP”) Share Unit Plans, collectively the (“SUP plans”); representing a portion of the officers’ long-term incentives. The issued 2020 SUP Units granted are performance based and vest at the end of the three-year performance period upon achievement of specified cumulative performance goals. Two-thirds of the SUP Units granted under the 2019 SUP and 2018 SUP plans are performance based and vest at the end of the respective three-year performance period upon achievement of specified cumulative performance goals. The remaining SUP Units that were granted under the 2019 SUP and 2018 SUP plans are time-based and vest at the end of the respective three-year period without regard to performance. For all grants issued under the SUP plans, each SUP Unit is equivalent to the value of one common share of Fortis and if earned and vested is paid in cash. The foreign exchange rate utilized for cash payout in the US dollar equivalent for each plan corresponds to the exchange rate on the business day prior to the date of that SUP Unit grant. Each SUP Unit accrues notional dividend equivalents equal to the dividends declared by the Fortis Board of Directors on Fortis common shares.

Awards granted under the 2018 PSUP and 2018 SUP Plans vested and were paid out during the first quarter of 2021.


CH Energy Group:			Grant Date	Time Based		Performance Based
	Grant Date		Fair Value	Granted	Outstanding(6)	Granted	Outstanding(6)
2020 RSUP(5)	January 1, 2020	$	41.55	7,257	7,811	-	-
2020 PSUP(5)	January 1, 2020	$	41.55	-	-	21,770	23,433
2019 PSUP	January 1, 2019	$	33.1	8,838	9,858	26,514	29,573
2018 PSUP(1)	January 1, 2018	$	36.59	-	-	29,514	-

Central Hudson:			Grant Date	Time Based		Performance Based
	Grant Date		Fair Value	Granted	Outstanding(2)(6)	Granted	Outstanding(2)(6)
2021 RSUP	January 1, 2021	$	41.12	14,249	14,794	-	-
2021 SUP	January 1, 2021	$	41.12	-	-	28,497	29,587
2020 RSUP(5)	January 1, 2020	$	41.55	12,655	13,622	-	-
2020 SUP(5)	January 1, 2020	$	41.55	-	-	25,311	27,244
2019 SUP(4)	January 1, 2019	$	33.1	15,691	13,917	31,383	32,739
2018 SUP(3)(1)	January 1, 2018	$	36.59	16,337	-	32,675	-

(1)In the first quarter of 2021, 49,732 units under the 2018 SUP and 32,998 units under the 2018 PSUP vested and were paid out at $41.64 per unit for a total of approximately $4.1 million.
(2)In the second quarter of 2019, 3,337 2017 SUP units, 2,814 2018 SUP units, and 3,075 2019 SUP units were forfeited following the resignation of an Officer.
(3)In the third quarter of 2020, per the 2018 SUP agreement, time based units were paid out related to Officer retirements at 859 shares at $42.93 per unit and 1,140 shares at $44.91 per unit.
(4)In the third quarter of 2020, per the 2019 SUP agreement, time based units were paid out related to Officer retirements at 942 shares at $39.57 per unit and 1,336 shares at $41.39 per unit.
(5)During 2020, the grant date fair value share price was corrected from the previously disclosed Canadian dollar share price of CAD$53.97 to the US dollar share price. There was no financial statement impact resulting from the change to the disclosure
(6)Includes notional dividends accrued as of December 31, 2021.


Compensation Expense

The following table summarizes compensation expense for share unit plan units as follows (In Thousands):

	Year Ended December 31,
	2021		2020		2019
CH Energy Group	$	2,617	$	2,434	$	3,023
Central Hudson	$	2,618	$	2,435	$	3,012

The liabilities associated with the annual RSUP, SUP and PSUP plans are recorded at fair value at each reporting date until settlement, recognizing compensation expense over the vesting period on a straight-line basis. The fair value of the respective liabilities is based on the Fortis common share 5 day

volume weighted average trading price at the end of each reporting period and the expected payout based on management's best estimate in accordance with the defined metrics of each grant.

Under the annual RSUP, SUP and PSUP agreements (“the Plans”), the amount of any outstanding awards payable to an employee who retires during the term of the grant and who has 15 years of service and provides at least six months prior notice of retirement under the terms of the Plans, is determined as if the employee continued to be an employee through the end of the performance period. In accordance with ASU 2014-12, in this situation, compensation expense for that individual is recognized over the requisite service period, instead of the performance period. In all periods presented, additional expense was recognized in accordance with ASU 2014-12 for Central Hudson officers who are retirement eligible under terms of the Plans in which they have attained the required retirement age and met the required 15 years of service. Fluctuations in compensation expense in the comparative periods can result from changes in the Fortis Inc. common stock share price and the projected performance payout percentages.

Employee Share Purchase Plan

Effective May 17, 2017, the Company adopted the Fortis Amended and Restated 2012 Employee Share Purchase Plan (“ESPP”). Fortis authorized 600,000 of its common shares to be offered under the ESPP. The ESPP allows eligible employees of Fortis and adopting subsidiaries to contribute during any investment period an amount not less than 1% and not more than 10% of their eligible compensation to purchase Fortis’ common shares. Under the ESPP, employees are entitled to fund contributions through interest free loans from the Company. At December 31, 2021 and 2020, employee loans due to the Company related to the ESPP were approximately $0.2 million and $0.3 million, respectively.

The ESPP provides that the Company will contribute as additional salary an amount equal to 10% of an employee’s contribution up to a maximum contribution of 1% of eligible compensation. The Company will also contribute an amount equal to 10% of all dividends payable by Fortis on all common stock allocated to an employee’s ESPP account. Common shares are purchased under the ESPP concurrent with the quarterly dividend payment dates of March 1, June 1, September 1 and December 1.

NOTE 14 – Commitments and Contingencies

Electricity Purchase Commitments

Central Hudson meets its capacity and electricity obligations through contracts with capacity and energy providers, purchases from the NYISO energy and capacity markets and its own generating capacity.

Energy Credit Purchase Obligations

In August 2016, the PSC issued Order 15-E-0302 adopting a Clean Energy Standard that includes Renewable Energy Credits (“RECs”) and Zero-Emissions Credit (“ZECs”) requirements. Since 2017, LSEs, which include Central Hudson, have been required to obtain Tier 1 RECs and ZECs in amounts determined by the PSC. LSEs may satisfy their REC obligation by either purchasing RECs acquired through central procurement by NYSERDA, by self-supply through direct purchase of tradable RECs, through value stack Tier 1 offset payments, or by making alternative compliance payments. Through March 31, 2022, LSEs will purchase ZECs from NYSERDA at tranche prices approved by the PSC based on qualifying in-state nuclear plant output and Central Hudson’s full-service customer New York Control Area load-ratio share. Central Hudson’s ZEC obligation is comprised of an administratively

determined ZEC price, Central Hudson’s monthly load volume, as defined by NYISO billing data, and a load modifier adjustment factor. The actual obligation will be determined and is contingent upon actual load served. In October 2020, the PSC issued an Order that revised the Tier 1 REC obligations through calendar year 2023 and set requirements for Tier 2 Competitive RECs through calendar year 2025. NYSERDA introduced indexed Tier 1 RECs beginning January 1, 2021. REC pricing will change each quarter (weighted average of vintage fixed and new indexed RECs) and the alternative compliance payment will be set in advance of the compliance year. These future costs are recoverable from customers through electric cost adjustment mechanisms.

At December 31, 2021, based on Central Hudson’s estimated annual load to be served through March 31, 2022, the total obligation to procure ZECs is estimated to be approximately $3.0 million. The requirement to procure ZECs will continue based upon Central Hudson’s future load served to its customers through 2029. The current obligation to procure Tier 1 RECs is defined as a percentage of load served in the state through December 31, 2023 and as a “pay as you go” load basis for Tier 2 RECs; the combined Tier 1 and Tier 2 REC obligation is estimated for Central Hudson to be approximately $9.8 million through December 31, 2025.

Natural Gas Commitments

Central Hudson meets its natural gas capacity and supply obligations through firm natural gas supply contracts with energy providers for the purchase of natural gas including peak demand supply. Gas supply contracts are generally short term in nature. Central Hudson also enters into contracts associated with natural gas interstate pipeline capacity, and supply contracts for storage of natural gas.


Commitments

The following is a summary of commitments for CH Energy Group and its affiliates as of December 31, 2021 (In Thousands):

	Projected Payments Due By Period
	Year Ending 2022		Year Ending 2023		Year Ending 2024		Year Ending 2025		Year Ending 2026		Thereafter		Total
Recorded Contractual Obligations:
Operating Leases	$	537		545	$	506	$	451	$	404	$	1,701	$	4,144
Repayments of Long-Term Debt		25,364		2,100		32,245		22,401		50,000		799,400		931,510
Stock-based compensation obligations		5,250		3,580		1,628		-		-		-		10,458


Unrecorded Contractual Obligations:
Purchased Electric Contracts		(1)		17,461		3,042		143		143		143		274		21,206
Energy Credit Purchase Agreements				5,211		5,047		1,311		1,311		-		-		12,880
Purchased Natural Gas Contracts		(1)		31,487		16,688		12,987		6,168		5,169		11,776		84,275
Interest Obligations on Long-Term Debt				35,234		34,703		34,284		33,739		33,318		558,923		730,201
	Total		$	120,544	$	65,705	$	83,104	$	64,213	$	89,034	$	1,372,074	$	1,794,674

(1)	Purchased electric and purchased natural gas costs for Central Hudson are fully recovered via their respective regulatory cost adjustment mechanisms.


The following is a summary of commitments for Central Hudson as of December 31, 2021 (In Thousands):

			Projected Payments Due By Period
			Year Ending 2022		Year Ending 2023		Year Ending 2024		Year Ending 2025		Year Ending 2026		Thereafter		Total
Recorded Contractual Obligations:
Operating Leases			$	537	$	545	$	506	$	451	$	404	$	1,701	$	4,144
Repayments of Long-Term Debt				23,400		-		30,000		20,000		50,000		799,400		922,800
Stock-based compensation obligations				2,870		1,885		1,628		-		-		-		6,383
Unrecorded Contractual Obligations:
Purchased Electric Contracts		(1)		17,461		3,042		143		143		143		274		21,206
Energy Credit Purchase Agreements				5,211		5,047		1,311		1,311		-		-		12,880
Purchased Natural Gas Contracts		(1)		31,487		16,688		12,987		6,168		5,169		11,776		84,275
Interest Obligations on Long-Term Debt				34,675		34,279		34,005		33,616		33,318		558,924		728,817
	Total		$	115,641	$	61,486	$	80,580	$	61,689	$	89,034	$	1,372,075	$	1,780,505

(1)

Purchased electric and purchased natural gas costs for Central Hudson are fully recovered via their respective regulatory cost adjustment mechanisms.

Other Commitments

Capital Expenditures

Central Hudson is a regulated utility and, as such, is obligated to provide service to customers within its service territory. Central Hudson’s capital expenditures are largely driven by the need to ensure the continued and enhanced reliability and safety of the electric and natural gas systems for the long-term benefit of customers.

Pension Benefit and OPEB Funding Contributions

Central Hudson is subject to certain contractual benefit payment obligations. Decisions about how to fund the Retirement and OPEB Plans to meet these obligations are made annually and are primarily affected by the discount rate used to determine benefit obligations, current asset values, corporate resources and the projection of Retirement and OPEB Plan assets. Based on the funding requirements of the Pension Protection Act of 2006, Central Hudson plans to make contributions that maintain the target funded percentage for the Retirement Plan at 80% or higher. Actual contributions could vary significantly based upon economic growth, projected investment returns, inflation and interest rate assumptions. Actual funded status could vary significantly based on asset returns and changes in the discount rate used to estimate the present value of future obligations. In January 2022, Central Hudson made a contribution of $0.5 million to the 401(h) Plan to fund the management OPEB liabilities, in accordance with Central Hudson’s OPEB policy and strategy. No funding contributions are expected to be made to the Retirement and VEBA Plans for the 2021 Plan years. See Note 19 – “Subsequent Events” for details of the January payment.

Supplemental Executive Retirement Plan

As a result of the acquisition of CH Energy Group, Inc. by Fortis on June 27, 2013, and in accordance with the terms of the Trust agreement for the SERP, Central Hudson is required to maintain a funding level at 110% of the present value of the accrued benefits payable under the Plan on an annual basis. Annual contributions to the SERP could vary based on investment returns, discount rates, and participant demographics. At December 31, 2021 the SERP was fully funded for 2021, in accordance with the requirements of the Trust agreement.

Parental Guarantee

CHET was established to be an investor in Transco, which was created to develop, own and operate electric transmission projects in New York State. On July 16, 2020, CH Energy Group’s parental guarantee to Transco was adjusted from $182 million to $73.7 million. The Transco Board of Directors approved the reduction based on CHET’s maximum commitment associated with the AC Project, the only project remaining under Transco’s original FERC application and the initial guarantee. As of December 31, 2021, the amount of the outstanding parental guarantee is $65.7 million. CHET’s investment in Transco was approximately $15.0 million at December 31, 2021, and CH Energy Group is currently not aware of any existing condition that would require any payments under this guarantee.

Contingencies

Environmental Matters

Central Hudson

•Site Investigation and Remediation Program

Central Hudson has been notified by the New York State Department of Environmental Conservation (“DEC”) that it believes Central Hudson or its predecessors at one time owned and/or operated manufactured gas plants (“MGP”) to serve their customers’ heating and lighting needs, at seven sites in Central Hudson’s franchise territory. The DEC has further requested that Central Hudson investigate and, if necessary, remediate these sites. In addition, Central Hudson is also performing environmental SIR at two non-MGP sites within its service territory, Little Britain Road and Eltings Corners.

Central Hudson accrues for remediation costs based on the amounts that can be reasonably estimated at a point in time. At December 31, 2021, Central Hudson has accrued $71.7 million with respect to all SIR activities, including operation, maintenance and monitoring costs (“OM&M”), of which $5.9 million is anticipated to be spent in the next twelve months.

SIR can be divided into various stages of completion based on the milestones of activities completed and reports reviewed. The types of costs accrued during the various stages include:

1.Investigation – Begins with preliminary investigations and is completed upon filing and approval by DEC of a Remedial Investigation (“RI”) Report. Central Hudson accrues for estimated investigation costs.

2.Remedial Alternatives Analysis (“RAA”) – Engineering analysis of alternatives for remediation based on the RI is compiled into a RAA Report. Management accrues for an estimate of remediation costs developed and quantified in the RAA based on DEC approved methods, as well as an estimate of post-remediation OM&M. These amounts represent a significant portion of the total costs to remediate and are subject to change based on further investigations, final remedial design and associated engineering estimates, regulatory comments and requests, remedial design changes/negotiations and changed or unforeseen conditions during the remediation or additional requirements following the remediation. Prior to the completion of the RAA, management cannot reasonably estimate what cost will be incurred for remediation or post-remediation activities.

3.Remedial Design - Upon approval of the RAA and final decision of remediation approach based on alternatives presented, a Remedial Design (“RD”) or Remedial Action Work Plan is developed and filed with the DEC for approval.

4.Remediation – Completion of the work plan as defined in the approved RD. Upon completion, final reports are filed with the DEC for approval and may include a Construction Completion Report, Final Engineering Report, or other reports required by the DEC based on the work performed.

5.Post-Remediation Monitoring – Entails the OM&M as directed by the DEC based on the approved final report of remediation. The activities are typically defined in a Site Management Plan, which is approved by the DEC. The extent of activities during this phase may increase or decrease based on the results of ongoing monitoring being performed and future potential usage of the property.

6.No Action Required – No further investigation or remedial action is currently required. No further costs are expected, and no amounts are accrued related to this site.

These stages, the costs accrued and the sites currently in each stage include (dollars in millions):


Stage	Sites	Total Accrued Cost at December 31, 202		Estimated spend in the next twelve months
Investigation	Little Britain Road	$	2.1	$	0.1	1
Remedial Alternatives Analysis			-		-	1
Remedial Design			-		-	1
Remediation	North Water Street		65.3		5.6	1
Post-Remediation Monitoring	Newburgh Areas A, B & C, Laurel Street, Catskill, Kingston, and Eltings Corners		4.3		0.2	1
No Action Required	Beacon and Bayeaux Street		-		-	1
Total		$	71.7	$	5.9	1

There were no significant updates during the year ended December 31, 2021 or changes in the nature and amounts of Central Hudson’s contingencies related to environmental matters, except as noted below.

•Remediation in Progress - Site – North Water Street

•In the first quarter of 2020, Central Hudson revised its estimate and recorded the low end of the range of projected costs for remediation activities associated with this site based on an assessment of a high-solids hydraulic dredging remedial alternative including predictive cost modeling for a pilot test and full-scale remediation.

•In September 2020, the New York State DEC approved the Hydraulic Dredging Pilot Test (“HDPT”) Work Plan and Water Supply Protection and Contingency Plan. Preliminary site monitoring and mobilization activities commenced in October 2020 and pilot test activities, including demobilization, were completed in January 2021.

•The goals of the pilot study were successfully achieved. Hydraulic dredging was completed in three areas with different degrees of impacted sediment (no impact, medium impact and high impact). A draft hydraulic dredge pilot test evaluation summary report was prepared which summarized the data compiled related to:

•production rates associated with the hydraulic dredge equipment in each area including the impacts of the protective shroud attached for additional protection,

•impacts of sheening events that occurred, the ability to contain them and the related work stoppages during the pilot,

•impact of prescribed protective measures regarding the placement of daily clean cover and backfill on the riverbed, and

•debris encountered in the river and the related mechanical removal.

•The report concluded that the use of hydraulic dredging was technically feasible. However, there were several factors (as noted above) that impacted the previously estimated production rates able to be achieved during the pilot. When extrapolated to full-scale remediation, the cumulative effect of these impacts on the production rates observed during the HDPT significantly increased the total estimated time to complete the dredging and backfilling remediation and, as a result of this increased time frame, also equated to a significant increase in the projected cost.

•Based on the increase in the projected time frame and cost, it was concluded by the project’s Engineer of Record (“EOR”) that full-scale hydraulic dredging is not practical to pursue as the sole remedial approach. Following review of the evaluation summary report, the DEC concurred that this timeframe was not practical and agreed with the conclusion of the report. At this point, the DEC has communicated that removal of source material is still the best long-term remedy for the site and as such is directing

Central Hudson to examine other methods, including a mix of alternative approaches taking into consideration the extent of removal that may be feasible.

•A scope of work for limited upland remedial activities was submitted to and approved by the DEC in May 2021. The activities were completed in June 2021.

•During 2021, Central Hudson worked with the EOR to evaluate remedial alternative approaches, including some that still fit within the framework of the DEC approved Work Plan and achieved the established regulatory clean-up objectives within a reasonable time period, as well as other approaches that considered capping or monitoring-only activities. A Focused Remedial Alternatives Analysis (“FRAA”) report presenting the evaluation of alternative approaches was submitted to the DEC in November 2021. A preliminary follow up discussion was held with the DEC in December 2021. The DEC did not provide any initial feedback regarding the alternatives at this time and requested further time to review the report and that additional meetings be held with all parties to discuss next steps.

•A draft Air Bubble Curtain (“ABC”) Bench Scale Work Plan is currently under internal review. It is anticipated that the laboratory bench scale testing will be conducted in the first half of 2022. Based on the results of the laboratory testing, in-river testing may be conducted in the latter half of 2022.

•The total accrual for remediation as of December 31, 2021 for this site of $65.3 million reflects management’s estimate of the low end of a predictive cost estimate range of potential alternatives, plus additional costs associated with the ABC, continued work of the EOR on the development of design and analysis of the FRAA based on future discussions with other parties, and other associated fees. The FRAA included potential alternatives for remediation with costs estimated as high as $95 million. The accrual will be updated as the alternative remedial approaches are discussed, and a path forward is agreed upon by all involved parties.

•The estimated spending as of December 31, 2021 for the next 12 months of approximately $5.6 million is primarily based on anticipated efforts to perform the additional analysis requested, conduct laboratory bench scale testing of an ABC and possible in-river testing, and continued alternative remedial approach discussions/design.

Future remediation activities, including OM&M and related costs may vary significantly from the assumptions used in Central Hudson's current cost estimates and these costs could have a material adverse effect (the extent of which cannot be reasonably determined) on the financial condition, results of operations and cash flows of CH Energy Group and Central Hudson if Central Hudson were unable to recover all or a substantial portion of these costs via collection in rates from customers and/or through insurance.

Central Hudson expects to recover its remediation costs from its customers. The current components of this recovery include:

•As part of the 2021 Rate Order, Central Hudson maintained previously granted deferral authority and future recovery for the differences between actual Environmental SIR costs (both MGP and non-MGP) and the associated rate allowances, with carrying charges to be accrued on the deferred balances at the authorized pre-tax rate of return.

•The 2021 Rate Order includes cash recovery of approximately $24.2 million during the three-year rate plan period ending June 30, 2024, with $3.8 million recovered through December 31, 2021. The 2018 Rate Order included cash recovery of $25.7 million through the rate plan period ended June 30, 2021, all of which had been fully recovered.

•The total spending related to site investigation and remediation for the years ended December 31, 2021 and 2020 was approximately $3.3 million and $11.2 million, respectively.

•The regulatory asset balance as of December 31, 2021 and 2020, was $76.0 million and $84.4 million, respectively, which represents the cumulative difference between amounts spent or

currently accrued as a liability and the amounts recovered to date through rates or insurance recoveries.

Central Hudson has put its insurers on notice and intends to seek reimbursement from its insurers for its costs. Certain of these insurers have denied coverage. There were no insurance recoveries during the years ended December 31, 2021 and 2020. We do not expect insurance recoveries to offset a meaningful portion of total costs.

Litigation

Asbestos Litigation

Central Hudson is involved in various asbestos lawsuits.

As of December 31, 2021, of the 3,383 asbestos cases brought against Central Hudson, 1,164 remain pending. Of the cases no longer pending against Central Hudson, 2,056 have been dismissed or discontinued without payment by Central Hudson and Central Hudson has settled 163 cases. Central Hudson is presently unable to assess the validity of the remaining asbestos lawsuits; however, based on information known to Central Hudson at this time, including Central Hudson’s experience in settling asbestos cases and in obtaining dismissals of asbestos cases, Central Hudson believes that the costs which may be incurred in connection with the remaining lawsuits will not have a material adverse effect on the financial position, results of operations or cash flows of either CH Energy Group or Central Hudson.

Other Litigation

CH Energy Group and Central Hudson are involved in various other legal and administrative proceedings incidental to their businesses, which are in various stages. While these matters collectively could involve substantial amounts, based on the facts currently known, it is the opinion of management that their ultimate resolution will not have a material adverse effect on either CH Energy Group’s or Central Hudson’s financial positions, results of operations or cash flows. CH Energy Group and Central Hudson expense legal costs as incurred.

NOTE 15 – Segments and Related Information

CH Energy Group's reportable operating segments are the regulated electric utility business and regulated natural gas utility business of Central Hudson. Other activities of CH Energy Group, which do not constitute a business segment, include CHEC’s investments in limited partnerships, CHET’s investment in Transco (a regulated entity), CHGT which has no current activity, and the holding company’s activities, which consist primarily of financing its subsidiaries, and are reported under the heading “Other Businesses and Investments.”

General corporate expenses and Central Hudson’s property common to both electric and natural gas segments have been allocated in accordance with practices established for regulatory purposes. The common allocation per the terms of the 2021 and 2018 Rate Order is 80% for electric and 20% for natural gas.


CH Energy Group Segment Disclosure
(In Thousands)	Year Ended December 31, 2021
	Segments				Other
	Central Hudson				Businesses
			Natural		and
	Electric		Gas		Investments			Eliminations	Total
Revenues from external customers	$	623,823	$	172,425	$	-	$	-	$	796,248
Intersegment revenues		59		243		-		(302)		-
Total operating revenues		623,882		172,668		-		(302)		796,248
Energy supply costs		178,795		48,504		-		(302)		226,997
Operating expenses		320,246		76,256		218		-		396,720
Depreciation and amortization		55,234		17,481		-		-		72,715
Operating income (loss)		69,607		30,427		(218)		-		99,816
Other income, net		20,344		5,273		1,937		-		27,554
Interest charges		25,384		10,536		681		-		36,601
Income before income taxes		64,567		25,164		1,038		-		90,769
Income tax expense		10,700		5,408		708		-		16,816
Net Income Attributable to CH Energy Group	$	53,867	$	19,756	$	330	$	-	$	73,953
Segment Assets at December 31, 2021	$	2,169,728	$	805,355	$	22,458	$	(882)	$	2,996,659
Capital Expenditures	$	156,918	$	74,664	$	-	$	-	$	231,582



CH Energy Group Segment Disclosure
(In Thousands)	Year Ended December 31, 2020
	Segments				Other
	Central Hudson				Businesses
			Natural		and
	Electric		Gas		Investments			Eliminations	Total
Revenues from external customers	$	552,002	$	159,893	$	-	$	-	$	711,895
Intersegment revenues		52		209		-		(261)		-
Total operating revenues		552,054		160,102		-		(261)		711,895
Energy supply costs		136,182		37,430		-		(261)		173,351
Operating expenses		302,534		72,132		241		-		374,907
Depreciation and amortization		50,847		16,016		-		-		66,863
Operating income (loss)		62,491		34,524		(241)		-		96,774
Other income, net		17,000		5,018		1,120		-		23,138
Interest charges		25,099		9,648		800		-		35,547
Income before income taxes		54,392		29,894		79		-		84,365
Income tax expense		9,058		6,087		117		-		15,262
Net Income(Loss) Attributable to CH Energy Group	$	45,334	$	23,807	$	(38)	$	-	$	69,103
Segment Assets at December 31, 2020	$	1,886,780	$	737,757	$	20,805	$	(1,218)	$	2,644,124
Capital Expenditures	$	170,931	$	81,926	$	-	$	-	$	252,857


CH Energy Group Segment Disclosure
(In Thousands)	Year Ended December 31, 2019
	Segments				Other
	Central Hudson				Businesses
			Natural		and
	Electric		Gas		Investments			Eliminations	Total
Revenues from external customers	$	529,460	$	162,203	$	-	$	-	$	691,663
Intersegment revenues		46		299		-		(345)		-
Total operating revenues		529,506		162,502		-		(345)		691,663
Energy supply costs		142,131		49,729		-		(345)		191,515
Operating expenses		272,357		67,121		208		-		339,686
Depreciation and amortization		45,204		14,161		-		-		59,365
Operating income (loss)		69,814		31,491		(208)		-		101,097
Other income, net		8,892		2,464		1,299		-		12,655
Interest charges		24,851		8,680		921		-		34,452
Income before income taxes		53,855		25,275		170		-		79,300
Income tax expense		10,151		4,117		466		-		14,734
Net Income (Loss) Attributable to CH Energy Group	$	43,704	$	21,158	$	(296)	$	-	$	64,566
Segment Assets at December 31, 2019	$	1,730,543	$	669,656	$	18,349	$	(709)	$	2,417,839
Capital Expenditures	$	162,023	$	76,694	$	-	$	-	$	238,717

NOTE 16 – Accounting for Derivative Instruments and Hedging Activities

Purpose of Derivatives

Central Hudson enters into derivative contracts in conjunction with the Company’s energy risk management program to hedge certain risk exposure related to its business operations. The derivative contracts are typically either exchange-traded or over-the-counter (“OTC”) instruments. The primary risks the Company seeks to manage by using derivative instruments are interest rate risk, commodity price risk and adverse or unexpected weather conditions. Central Hudson uses derivative contracts to reduce the impact of volatility in the prices of natural gas and electricity and to hedge exposure to volatility in interest rates for its variable rate long-term debt. Derivative transactions are not used for speculative purposes. Central Hudson’s derivative activities consist of the following:

•Interest rate caps are used to minimize interest rate risks and to improve the matching of assets and liabilities. An interest rate cap is an interest rate option agreement in which payments are made by the seller of the option when the reference rate exceeds the specified strike rate (or the set rate at which the option contract can be exercised). The purpose of these agreements is to reduce exposure to rising interest rates while still having the ability to take advantage of falling interest rates by putting a “cap” on the interest rate Central Hudson pays on debt for which such caps are purchased. See Note 11 - “Capitalization – Long-Term Debt” for further details regarding Central Hudson’s interest rate cap agreements.

•Natural gas futures are used to mitigate commodity price volatility for natural gas purchases. A natural gas futures contract is a standardized contract to buy or sell a specified commodity (natural gas) of standardized quantity at a certain date in the future, at a market determined price (the futures price). Central Hudson’s reason for purchasing these contracts is to moderate price fluctuations for natural gas and the impact of volatility in the commodity markets on its customers.

•Electricity swaps are used to mitigate commodity price volatility for electricity purchases for Central Hudson’s full service customers. A swap contract or a contract for differences is the exchange of two payment streams between two counterparties where the cash flows are dependent on the price of the underlying commodity. In an effort to moderate commodity price volatility, Central Hudson enters into contracts to pay a fixed price and receive a market price for a defined commodity and volume. These contracts are aligned with Central Hudson’s actual commodity purchases at market price, resulting in a net fixed price payment.

•Weather derivative contracts are used to hedge the effect of significant variances in weather conditions from normal patterns on purchased electricity and natural gas costs, and on the related revenues. Heating Degree Days (“HDD”) are used to measure winter temperature risk where an HDD index is calculated by subtracting the average of the daily high and low temperatures from 65 degrees fahrenheit, representing the point where space heating is typically switched on. In recent years these daily HDD values are accumulated over the seasonal period of December 1st to March 31st where a strike price is triggered to protect the Company from price volatility when the HDD value is 45 degrees below the stated 65 degree starting point. Prior to 2021, premiums were paid for these weather related instruments and they were amortized based on the pattern of normal purchases of electricity or natural gas over the term of the contract and any payouts earned were recorded as a reduction of the cost. In 2021, instead of paying an upfront premium for our weather derivative contracts, an additional feature was added to pay the financial institution if and when weather is warmer than normal during the winter seasonal period. While customers are protected by price volatility at 45 degrees below 65 degrees fahrenheit, there is now a trigger to pay the financial institution when the HDD daily calculation does not fall 20.5 degrees below its 65 degree starting point. These values are accumulated daily and any payouts earned will continue to be netted with costs over the term of the contract.

Energy Contracts Subject to Regulatory Deferral

Central Hudson has been authorized to fully recover certain risk management costs through its natural gas and electricity cost adjustment mechanisms. Risk management costs are defined by the PSC as costs associated with transactions that are intended to reduce price volatility or reduce overall costs to customers. These costs include transaction costs and gains and losses associated with risk management instruments. The related gains and losses associated with Central Hudson’s derivatives are included as part of Central Hudson's commodity cost and/or price-reconciled in its natural gas and electricity cost adjustment charge mechanisms and are not designated as hedges.

The percentage of Central Hudson’s electric and natural gas requirements covered with fixed price forward purchases at December 31, 2021 are as follows:


Central Hudson						% of Requirement Hedged (1)
Electric Derivative Contracts:						0.5 million MWh
January 2022 – August 2022						29.9%
Natural Gas Derivative Contracts:						0.3 million Dth
January 2022 – March 2022						6.9%

(1) Projected coverage as of December 31, 2021.

In 2021, OTC derivative contracts covered approximately 29.6% of Central Hudson’s total electricity supply requirements as compared to 32.1% in 2020.

Cash Flow Hedges

Central Hudson has been authorized to fully recover the interest costs associated with its $33.7 million Series B NYSERDA Bonds and its $30.0 million of variable rate debt, which includes costs and gains or losses associated with its interest rate cap contracts.

Derivative Risks

The basic types of risks associated with derivatives are market risk (that the value of the derivative will be adversely impacted by changes in the market, primarily the change in commodity prices and interest rates) and credit risk (that the counterparty will not perform according to the terms of the contract). The market risk of the derivatives generally offset the market risk associated with the hedged commodity.

The majority of Central Hudson’s derivative instruments contain provisions that require Central Hudson to maintain specified issuer credit ratings and financial strength ratings. Should Central Hudson’s ratings fall below these specified levels, it would be in violation of the provisions and the derivatives’ counterparties could terminate the contracts and request immediate payment.

To help limit the credit exposure of derivatives, Central Hudson enters into master netting agreements with counterparties whereby contracts in a gain position can be offset against contracts in a loss position. Of the 26 total agreements held by Central Hudson, 11 agreements contain credit risk contingent features. As of December 31, 2021, two open contracts with credit risk contingent features were in a liability position. The aggregate fair value of the open derivative contracts that contain contingent features and the amount that would be required to settle these instruments on December 31, 2021 if the contingent features were triggered, are described below.


Contingent Contracts
(Dollars In Thousands)
		As of December 31, 2021
Triggering Event		# of Contracts in a Liability Position Containing the Triggering Feature	Gross Fair Value of Contract		Cost to Settle if Contingent Feature is Triggered (net of collateral)
Central Hudson:
Credit Rating Downgrade		2	$	(7,563)	$	(7,183)
	Total Central Hudson	2	$	(7,563)	$	(7,183)

Derivative Contracts

CH Energy Group and Central Hudson have elected gross presentation for their derivative contracts under master netting agreements and collateral positions. On December 31, 2021 and December 31, 2020 Central Hudson did not have collateral posted against the fair value amount of derivatives.

The net presentation for CH Energy Group's and Central Hudson's derivative assets and liabilities are as follows (In Thousands):


				Gross		Net Amount
				Amounts		of Assets		Gross Amounts Not Offset in the
		Gross		Offset in the		Presented in		Statement of Financial Position
		Amounts of		Statement		the Statement				Cash
		Recognized		of Financial		of Financial		Financial		Collateral		Net
Description		Assets		Position		Position		Instruments		Received		Amount
As of December 31, 2021(1)
Derivative Contracts:
	Central Hudson - electric	$	1,604	$	-	$	1,604	$	380	$	-	$	1,224
	Central Hudson - natural gas		164		-		164		-		-		164
	Total CH Energy Group and Central Hudson Assets	$	1,768	$	-	$	1,768	$	380	$	-	$	1,388
As of December 31, 2020(1)
Derivative Contracts:
	Central Hudson - electric	$	-	$	-	$	-	$	-	$	-	$	-
	Central Hudson - natural gas		18		-		18		14		-		4
	Total CH Energy Group and Central Hudson Assets	$	18	$	-	$	18	$	14	$	-	$	4

(1)	Interest rate cap agreements are not shown in the above chart. As of December 31, 2021 and 2020, the fair value was $0

				Gross		Net Amount
				Amounts		of Liabilities		Gross Amounts Not Offset in the
		Gross		Offset in the		Presented in		Statement of Financial Position
		Amounts of		Statement		the Statement				Cash
		Recognized		of Financial		of Financial		Financial		Collateral		Net
Description		Liabilities		Position		Position		Instruments		Received		Amount
As of December 31, 2021(1)
Derivative Contracts:
	Central Hudson - electric	$	7,563	$	-	$	7,563	$	380	$	-	$	7,183
	Central Hudson - natural gas		-		-		-		-		-		-
	Total CH Energy Group and Central Hudson Liabilities	$	7,563	$	-	$	7,563	$	380	$	-	$	7,183
As of December 31, 2020(1)


Derivative Contracts:
	Central Hudson - electric	$	2,104	$	-	$	2,104	$	-	$	-	$	2,104
	Central Hudson - natural gas		49		-		49		14		-		35
	Total CH Energy Group and Central Hudson Liabilities	$	2,153	$	-	$	2,153	$	14	$	-	$	2,139

(1)	Interest rate cap agreements are not shown in the above chart. As of December 31, 2021 and 2020, the fair value was $0

Gross Fair Value of Derivative Instruments

Current accounting guidance related to fair value measurements establishes a fair value hierarchy to prioritize the inputs used in valuation techniques based on observable and unobservable data, but not the valuation techniques themselves. Observable inputs are inputs that reflect the assumptions market participants would use in pricing the asset or liability. Unobservable inputs are inputs that reflect the reporting entity’s own assumptions about the assumptions market participants would use in pricing an asset or a liability. Classification of inputs is determined based on the lowest level input that is significant to the overall valuation. The fair value hierarchy prioritizes the inputs to valuation techniques into the three categories described below:

Level 1 Inputs: Quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 Inputs: Directly or indirectly observable (market-based) information. This includes quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.

Level 3 Inputs: Unobservable inputs for the asset or liability for which there is either no market data, or for which asset and liability values are not correlated with market value.

Derivative contracts are measured at fair value on a recurring basis. As of December 31, 2021 and 2020, CH Energy Group's and Central Hudson's derivative assets and liabilities by category and hierarchy level are as follows (In Thousands):


						Quoted Prices in		Significant
						Active Markets		Other		Significant
						for Identical		Observable		Unobservable
						Assets		Inputs		Inputs
Asset or Liability Category				Fair Value		(Level 1)		(Level 2)		(Level 3)
As of December 31, 2021(1)			1
	Assets:		1
		Derivative Contracts:1	1
		Central Hudson - electric	1	$	1,604	$	-	$	1,604	$	-
		Central Hudson - natural gas	1		164		164		-		-
		Total CH Energy Group and Central Hudson Assets	1	$	1,768	$	164	$	1,604	$	-
	Liabilities:		1
		Derivative Contracts:	1
		Central Hudson - electric1	1	$	7,563	$	-	$	7,563	$	-


		Central Hudson - natural gas		1		-		-		-		-
			Total CH Energy Group and Central Hudson Liabilities	1	$	7,563	$	-	$	7,563	$	-
As of December 31, 2020(1)				1
	Assets:			1
		Derivative Contracts:		1
		Central Hudson - electric		1	$	-	$	-	$	-	$	-
		Central Hudson - natural gas		1		18		18		-		-
		Total CH Energy Group and Central Hudson Assets		1	$	18	$	18	$	-	$	-
	Liabilities:			1
		Derivative Contracts:		1
		Central Hudson - electric		1	$	2,104	$	-	$	2,104	$	-
		Central Hudson - natural gas		1		49		49		-		-
		Total CH Energy Group and Central Hudson Liabilities		1	$	2,153	$	49	$	2,104	$	-

(1)	Interest rate cap agreements are not shown in the above chart. These are classified as Level 2 in the fair value hierarchy using SIFMA Municipal Swap Curves and 3 month US Dollar Libor rate forward curves. As of December 31, 2021 and 2020, the fair value was $

The Effect of Derivative Instruments on the Statements of Income

Realized gains and losses on Central Hudson’s derivative instruments are returned to or recovered from customers through PSC authorized deferral accounting mechanisms, with no material impact on cash flows, results of operations or liquidity. Realized gains and losses on Central Hudson’s energy derivative instruments are reported as part of purchased natural gas, purchased electricity and fuel used in electric generation in CH Energy Group’s and Central Hudson’s Statements of Income as the corresponding amounts are either recovered from or returned to customers through fuel cost adjustment mechanisms in revenues. Additionally, unrealized gains and losses on Central Hudson’s derivative contracts have no impact on earnings since the energy contracts are subject to regulatory deferral.

For the years ended December 31, 2021, 2020 and 2019, neither CH Energy Group nor Central Hudson had derivatives designated as hedging instruments. The following table summarizes the effects of CH Energy Group’s and Central Hudson’s derivatives on the Statements of Income (In Thousands):


		Amount of Gain(Loss) Recognized as Increase/(Decrease) in the Statements of Income
		Year Ended
		December 31,
		2021		2020		2019		Location of Gain (Loss)
Central Hudson:
Electricity swap contracts		$	(1,687)	$	(14,379)	$	(15,145)	Deferred purchased electric costs(1)
Natural gas swap contracts			404		(866)		(23)	Deferred purchased natural gas costs(1)
	Total CH Energy Group and Central Hudson	$	(1,283)	$	(15,245)	$	(15,168)

(1)

Realized gains and losses on Central Hudson’s derivative instruments are returned to or recovered from customers through PSC authorized deferral accounting mechanisms with no net impact on results of operations.

Other Hedging Activities

Central Hudson – Electric

In November 2021, Central Hudson entered into an HDD costless collar weather option for the period December 1, 2021 through March 31, 2022, to hedge the effect of significant variances in weather conditions on electricity costs. For Central Hudson, this transaction will impact purchased electric expense and revenue, but will not have a net income impact due to the full deferral authority over commodity costs through its electric cost adjustment charge mechanisms. The aggregate limit on the contract is $5 million. This contract will be accounted for in accordance with guidance specific to accounting for weather derivatives. No premium was paid for the HDD costless collar weather option and all payouts will be recorded as a reduction to purchased electricity and all expenses incurred will be recorded as an increase to purchased electric costs in the Statements of Income. In December 2021, Central Hudson recorded $0.3 million of expense incurred to purchased electric cost.

In 2020 and 2019, Central Hudson entered into premium based weather options for the periods of December 1, 2020 through March 31, 2021 and December 1, 2019 through March 31, 2020, respectively, with an aggregate limit of $5 million per contract. Premiums paid were amortized to purchased electricity over the term of the agreements. The respective payouts earned of $0.6 million and $0.1 million on the 2020 and 2019 contracts were recorded as a reduction to purchased electricity in the Statements of Income in the periods earned.

Based on Central Hudson’s valuation models, the fair value of the costless collar weather option purchased for the December 1, 2021 through March 31, 2022 period, as of December 31, 2021 was approximately a net earned payout of $0.2 million. The fair value of the December 1, 2020 through March 31, 2021 weather option was approximately an earned payout of $0.5 million as of December 31, 2020. The valuations were based on significant unobservable inputs, including short term temperature forecast and historical temperature fluctuations in winter and, as such, would be a Level 3 valuation.

Central Hudson – Natural Gas

In November 2021, Central Hudson entered into an HDD costless collar weather option for the period December 1, 2021 through March 31, 2022, to hedge the effect of significant variances in weather conditions on natural gas costs. For Central Hudson, this transaction will impact purchased natural gas expense and revenue but will not have a net income impact due to the full deferral authority over commodity costs through its natural gas cost adjustment charge mechanisms. The aggregate limit on the contract is $5 million. This contract will be accounted for in accordance with guidance specific to accounting for weather derivatives. No premium was paid for the HDD costless collar weather option and all payouts will be recorded as a reduction to purchased natural gas and all expenses incurred will be recorded as an increase to purchased natural gas costs in the Statements of Income. In December 2021, Central Hudson recorded $0.3 million of expense incurred to purchased natural gas costs.

In 2020 and 2019, Central Hudson entered into premium based weather options for the periods of December 1, 2020 through March 31, 2021 and December 1, 2019 through March 31, 2020, respectively. The aggregate limit per contract was $5 million. Premiums paid were amortized to purchased natural gas over the term of the related agreement. The payout earned of $0.1 million on the 2020 contract was recorded as a reduction to purchased natural gas in the Statements of Income during the first quarter of 2021. There was no payout earned for the 2019 contract.

Based on Central Hudson’s valuation models, the fair value of the costless collar weather option purchased for the December 1, 2021 through March 31, 2022 period, as of December 31, 2021 was approximately a net earned payout of $0.2 million. The fair value of the December 1, 2020 through March 31, 2021 weather option was approximately an earned payout of $0.4 million as of December 31, 2020. The valuations were based on significant unobservable inputs, including short term temperature forecast and historical temperature fluctuations in winter and, as such, would be a Level 3 valuation.

NOTE 17 – Other Fair Value Measurements

Other Assets Recorded at Fair Value

In addition to the derivatives reported at fair value discussed in Note 16 – “Accounting for Derivative Instruments and Hedging Activities,” CH Energy Group and Central Hudson report certain other assets at fair value on the Balance Sheets. The following table summarizes the amounts reported at fair value related to these assets (In Thousands):


			Quoted Prices in		Significant		Significant
			Active Markets for		Observable		Unobservable
			Identical Assets		Inputs		Inputs
	Fair Value		(Level 1)		(Level 2)		(Level 3)
As of December 31, 2021:
Other Investments	$	21,624	$	21,624	$	-	$	-
As of December 31, 2020:
Other Investments	$	14,776	$	14,776	$	-	$	-

As of December 31, 2021 and 2020, a portion of the trust assets for the funding of the SERP and Deferred Compensation Plan were invested in mutual funds and money market accounts, which are measured at fair value on a recurring basis. These investments are valued at quoted market prices in active markets and, as such, are Level 1 investments as defined in the fair value hierarchy. These amounts are included in “Other investments” within the Deferred Charges and Other Assets section of the CH Energy Group’s and Central Hudson’s Balance Sheets.

The remaining amount reported in “Other investments” represents trust assets for the funding of the SERP and Deferred Compensation Plan held in trust-owned life insurance policies, which are recorded at cash surrender value. As of December 31, 2021 and 2020, the total cash surrender value of trust-owned life insurance held by these trusts was approximately $35.3 million and $33.1 million, respectively. The change in the cash surrender value is reported in “Other – net” income in the CH Energy Group’s and Central Hudson’s Income Statements.

Other Fair Value Disclosure

Financial instruments are recorded at carrying value in the financial statements, however, the fair value of these instruments are disclosed below in accordance with current accounting guidance related to financial instruments.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash and Cash Equivalents: Carrying amount.

Short-Term Borrowings: Carrying amount.

Due to the short-term nature (typically one month or less) of these borrowings, the carrying value is equivalent to the current fair market value.

Long-term Debt: Quoted market prices for the same or similar issues (Level 2).

Valuations were obtained for each issue using the observed Treasury market in conjunction with secondary market trading levels and recent new issuances of comparable companies.

The following tables summarize the long-term debt maturing or to be redeemed during the next five years and thereafter, as well as the estimated fair value of both CH Energy Group and Central Hudson’s long-term debt, including the current maturities (Dollars in Thousands):


CH Energy Group

		Fixed Rate				Variable Rate				Total Debt Outstanding
Expected Maturity Date		Amount		Estimated Effective Interest Rate		Amount		Estimated Effective Interest Rate		Amount		Estimated Effective Interest Rate
As of December 31, 2021:
	2022	$	25,364	3.7	%	$	-	-	%
	2023		2,100	6.95	%		-	-	%
	2024		2,245	6.95	%		30,000	1.22	%
	2025		22,401	3.43	%		-	-	%
	2026		50,000	3.73	%		-	-	%
	Thereafter		765,700	4.14	%		33,700	0.14	%
	Total	$	867,810	4.1	%	$	63,700	0.65	%	$	931,510	3.86	%

	Fair Value	$	1,012,654			$	63,700			$	1,076,354


As of December 31, 2020:
	2021	$	45,987	4.3	%	$	-	-	%
	2022		25,364	3.69	%		-	-	%
	2023		2,100	6.92	%		-	-	%
	2024		2,245	6.92	%		30,000	1.25	%
	2025		22,401	3.42	%		-	-	%
	Thereafter		685,700	4.27	%		33,700	0.16	%
	Total	$	783,797	4.24	%	$	63,700	0.68	%	$	847,497	3.98	%

	Fair Value	$	949,413			$	63,700			$	1,013,113


Central Hudson

		Fixed Rate				Variable Rate				Total Debt Outstanding
Expected Maturity Date		Amount		Estimated Effective Interest Rate		Amount		Estimated Effective Interest Rate		Amount	Estimated Effective Interest Rate
As of December 31, 2021:
	2022	$	23,400	3.42	%	$	-	-	%
	2023		-	-	%		-	-	%
	2024		-	-	%		30,000	1.22	%


	2025		20,000	3	%		-	-	%
	2026		50,000	3.73	%		-	-	%
	Thereafter		765,700	4.14	%		33,700	0.14	%
	Total	$	859,100	4.07	%	$	63,700	0.65	%	$	922,800	3.83	%

	Fair Value	$	1,003,268			$	63,700			$	1,066,968

As of December 31, 2020:
	2021	$	44,150	4.19	%	$	-	-	%
	2022		23,400	3.42	%		-	-	%
	2023		-	-	%		-	-	%
	2024		-	-	%		30,000	1.25	%
	2025		20,000	3	%		-	-	%
	Thereafter		685,700	4.27	%		33,700	0.16	%
	Total	$	773,250	4.21	%	$	63,700	0.68	%	$	836,950	3.94	%

	Fair Value	$	937,666			$	63,700			$	1,001,366

NOTE 18 – Related Party Transactions

Thompson Hine LLP serves as outside counsel to CH Energy Group and Central Hudson. One partner in that firm serves as each corporation’s General Counsel and Corporate Secretary. In addition, The Chazen Companies perform engineering services for Central Hudson, and a principal in the firm serves as a director of Central Hudson.

The following are fees paid by CH Energy Group and Central Hudson to Thompson Hine LLP and The Chazen Companies, respectively, as follows (In Thousands):



	Year Ended December 31,
		2021		2020		2019
CH Energy Group (Thompson Hine LLP)	$	2,031	$	2,264	$	2,096
Central Hudson (Thompson Hine LLP)	$	1,993	$	2,233	$	2,055
Central Hudson (The Chazen Companies)	$	786	$	710	$	829

CH Energy Group and Central Hudson may provide general and administrative services (“services”) to and receive services from each other, Fortis and other subsidiaries of Fortis. The costs of these services are reimbursed by the beneficiary company through accounts receivable and accounts payable, as necessary. CH Energy Group and Central Hudson may also incur charges from Fortis or each other for the recovery of general corporate expenses incurred by one another, Fortis or other affiliates. In addition, CH Energy Group and Central Hudson may also incur charges from Fortis for federal income taxes under their tax sharing agreement. These transactions are in the normal course of business and are recorded at the United States dollar amounts.

Related party transactions included in accounts receivable and accounts payable for CH Energy Group and Central Hudson are as follows (In Thousands):

December 31,

2021

2020

CH Energy Group(1)

Fortis


Accounts Receivable		$	1,390	$	1,350
Accounts Payable	1	$	-	$	-


		December 31,						December 31,
		2021						2020
					Other Affiliates						Other Affiliates
Central Hudson(1)		CHEG		Fortis				CHEG		Fortis
Accounts Receivable	$	36	$	7	$	-	$	157	$	25	$	9
Accounts Payable	$	823	$	-	$	1	$	931	$	-	$	-

(1) Fortis amounts include Fortis and all Fortis subsidiaries.

Related party transactions in operating expenses for CH Energy Group and Central Hudson are as follows (In Thousands):



		December 31,				December 31,				December 31,
		2021				2020				2019

		CHEG		Fortis(1)		CHEG		Fortis(1)		CHEG		Fortis(1)
CH Energy Group	$	-	$	4,055	$	-	$	3,692	$	-	$	3,121
Central Hudson	$	4,442	$	-	$	4,172	$	-	$	3,545	$	-

(1) Fortis amounts reported above include Fortis and all Fortis subsidiaries.

NOTE 19 – Subsequent Events

•On January 21, 2022, CH Energy Group’s Board of Directors approved the acceptance of a capital contribution in the amount of $29.3 million from its parent FortisUS to be received in the first quarter of 2022.

•On January 21 2022, Central Hudson’s Board of Directors approved the acceptance of a capital contribution in the amount of $21 million from its parent CH Energy Group to be received in the first quarter of 2022.

•On January 25, 2022, Standard and Poor’s (“S&P”) affirmed the rating of Central Hudson’s senior unsecured debt and changed their rating outlook from stable to negative. S&P indicated that the outlook reflects the potential for a one-notch downgrade over the next 12 months due to expected weaker financial measures for Central Hudson. In addition, S&P cited that the impact of Central Hudson’s 2021 Rate Order, and the Company’s elevated capital expenditures program as negative factors that could impact the Company’s financial ratios.

•On January 27, 2022, Central Hudson issued $110 million of Senior Notes in two separate tranches. Series W, 5-year Senior Notes have an interest rate of 2.37% per annum and a maturity date of January 27, 2027. Series X, 7-year Senior Notes have an interest rate of 2.59% per annum and a maturity date of January 27, 2029. Central Hudson expects to use the proceeds from the sale of the Senior Notes for the repayment of maturing debt and general corporate purposes.

•On January 28, 2022, Central Hudson made a contribution of $0.5 million to the 401(h) Plan to fund the management OPEB liabilities.

•On April 1, 2022, Central Hudson repaid $23.4 million of maturing 2011 Series G Senior Notes plus unpaid interest due at 3.378%. The Senior Notes were originally issued pursuant to a 2009 PSC Order approving the issuance by Central Hudson.

•On April 4, 2022, Central Hudson entered into a first amendment and increasing lender supplement to the Central Hudson credit agreement with five commercial banks. The amendment replaces the LIBO Rate with a benchmark replacement rate and increases the aggregate commitment by the lenders by $50 million making the aggregate amount of total commitments equal to $250 million. The credit agreement as amended has a five-year term, maturing in March 2025.

•On April 8,2022 Central Hudson received a response from the NYSDEC in regards to the November 2021 FRAA. Management is currently conducting a review of the comment letter and can make no determination at this time about any impacts to the range of potential costs disclosed in Note 14.

Management has evaluated the impact of events occurring after December 31, 2021 up to February 10, 2022, the date that Central Hudson’s U.S GAAP financial statements were issued and has updated such evaluation for disclosure purposes through April 15, 2022. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. Report data on a year-to-date basis.
Line No.	Item (a)	Unrealized Gains and Losses on Available-For-Sale Securities (b)	Minimum Pension Liability Adjustment (net amount) (c)	Foreign Currency Hedges (d)	Other Adjustments (e)	Other Cash Flow Hedges Interest Rate Swaps (f)	Other Cash Flow Hedges [Specify] (g)	Totals for each category of items recorded in Account 219 (h)	Net Income (Carried Forward from Page 116, Line 78) (i)	Total Comprehensive Income (j)
1	Balance of Account 219 at Beginning of Preceding Year				399,429			399,429
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income
3	Preceding Quarter/Year to Date Changes in Fair Value				238,235			238,235
4	Total (lines 2 and 3)				238,235			238,235	68,944,151	69,182,386
5	Balance of Account 219 at End of Preceding Quarter/Year				161,194			161,194
6	Balance of Account 219 at Beginning of Current Year				161,194			161,194
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income
8	Current Quarter/Year to Date Changes in Fair Value				179,845			179,845
9	Total (lines 7 and 8)				179,845			179,845	73,426,657	73,606,502
10	Balance of Account 219 at End of Current Quarter/Year				18,651			18,651

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.
Line No.	Classification (a)	Total Company For the Current Year/Quarter Ended (b)	Electric (c)	Gas (d)	Other (Specify) (e)	Other (Specify) (f)	Other (Specify) (g)	Common (h)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlantInServiceAbstract In Service
3	UtilityPlantInServiceClassified Plant in Service (Classified)	2,590,258,401	1,519,718,259	701,969,252				368,570,890
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	3,488,300			3,488,300
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	260,351,153	167,363,694	32,195,437				60,792,022
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	2,854,097,854	1,687,081,953	734,164,689	3,488,300			429,362,912
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	209,069	209,069
11	ConstructionWorkInProgress Construction Work in Progress	118,181,553	75,890,041	19,265,964				23,025,548
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	2,972,488,476	1,763,181,063	753,430,653	3,488,300			452,388,460
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	693,501,938	394,369,789	144,824,302				154,307,847
15	UtilityPlantNet Net Utility Plant (13 less 14)	2,278,986,538	1,368,811,274	608,606,351	3,488,300			298,080,613
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	624,383,702	393,696,717	144,824,302				85,862,683
19	AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService Amortization and Depletion of Producing Natural Gas Land and Land Rights
20	AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService Amortization of Underground Storage Land and Land Rights
21	AmortizationOfOtherUtilityPlantUtilityPlantInService Amortization of Other Utility Plant	69,118,236	673,072					68,445,164
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	693,501,938	394,369,789	144,824,302				154,307,847
23	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract Leased to Others
24	DepreciationUtilityPlantLeasedToOthers Depreciation
25	AmortizationAndDepletionUtilityPlantLeasedToOthers Amortization and Depletion
26	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers Total Leased to Others (24 & 25)
27	DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract Held for Future Use
28	DepreciationUtilityPlantHeldForFutureUse Depreciation
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	693,501,938	394,369,789	144,824,302				154,307,847

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

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

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Report below the original cost of electric plant in service according to the prescribed accounts. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included in column (c) are entries for reversals of tentative distributions of the prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent’s plant actually in service at end of year. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date.
Line No.	Account (a)	Balance Beginning of Year (b)	Additions (c)	Retirements (d)	Adjustments (e)	Transfers (f)	Balance at End of Year (g)
1	1. INTANGIBLE PLANT
2	(301) Organization
3	(302) Franchise and Consents	45,519					45,519
4	(303) Miscellaneous Intangible Plant	2,416,109					2,416,109
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	2,461,628					2,461,628
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights
9	(311) Structures and Improvements
10	(312) Boiler Plant Equipment
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units
13	(315) Accessory Electric Equipment
14	(316) Misc. Power Plant Equipment
15	(317) Asset Retirement Costs for Steam Production
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)
17	B. Nuclear Production Plant
18	(320) Land and Land Rights
19	(321) Structures and Improvements
20	(322) Reactor Plant Equipment
21	(323) Turbogenerator Units
22	(324) Accessory Electric Equipment
23	(325) Misc. Power Plant Equipment
24	(326) Asset Retirement Costs for Nuclear Production
25	TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26	C. Hydraulic Production Plant
27	(330) Land and Land Rights	417,164					417,164
28	(331) Structures and Improvements	3,386,746	135,811	24,770			3,497,787
29	(332) Reservoirs, Dams, and Waterways	22,456,084	223,465				22,679,549
30	(333) Water Wheels, Turbines, and Generators	10,671,463	496,918	186,029			10,982,352
31	(334) Accessory Electric Equipment	1,738,777	483				1,739,260
32	(335) Misc. Power Plant Equipment	139,931	81,280				221,211
33	(336) Roads, Railroads, and Bridges
34	(337) Asset Retirement Costs for Hydraulic Production
35	TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)	38,810,165	937,957	210,799			39,537,323
36	D. Other Production Plant
37	(340) Land and Land Rights	11,192					11,192
38	(341) Structures and Improvements	445,829					445,829
39	(342) Fuel Holders, Products, and Accessories	862,669					862,669
40	(343) Prime Movers	1,438,692					1,438,692
41	(344) Generators	872,355					872,355
42	(345) Accessory Electric Equipment	508,233		367			507,866
43	(346) Misc. Power Plant Equipment	42,756					42,756
44	(347) Asset Retirement Costs for Other Production
44.1	(348) Energy Storage Equipment - Production
45	TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)	4,181,726		367			4,181,359
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	42,991,891	937,957	211,166			43,718,682
47	3. Transmission Plant
48	(350) Land and Land Rights	29,524,499	344,540				29,869,039
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	16,024,615	52,571	1,186			16,076,000
50	(353) Station Equipment	140,270,321	8,259,489	321,495	74,625	77,786	148,205,154
51	(354) Towers and Fixtures	3,020,748	4,133	6,585			3,018,296
52	(355) Poles and Fixtures	156,319,020	6,396,356	1,200,832		819,971	160,694,573
53	(356) Overhead Conductors and Devices	81,621,959	995,208	410,188		111,814	82,095,165
54	(357) Underground Conduit	20,965					20,965
55	(358) Underground Conductors and Devices	9,053,355	21,853				9,075,208
56	(359) Roads and Trails
57	(359.1) Asset Retirement Costs for Transmission Plant	1,605,305	1,246,257	83,183			2,768,379
58	TOTAL Transmission Plant (Enter Total of lines 48 thru 57)	437,460,787	17,320,407	2,023,469	74,625	1,009,571	451,822,779
59	4. Distribution Plant
60	(360) Land and Land Rights	3,336,917	72,185				3,409,102
61	(361) Structures and Improvements	20,713,765	273,877	21,329			20,966,313
62	(362) Station Equipment	182,366,679	3,799,754	2,524,072	101,535	98,373	183,645,523
63	(363) Energy Storage Equipment – Distribution
64	(364) Poles, Towers, and Fixtures	301,297,944	29,081,778	4,133,304	72,789	72,789	326,246,418
65	(365) Overhead Conductors and Devices	248,072,868	12,464,082	1,996,699	15,269	15,269	258,540,251
66	(366) Underground Conduit	43,391,031	1,906,679	106,326			45,191,384
67	(367) Underground Conductors and Devices	73,169,550	1,008,789	29,998			74,148,341
68	(368) Line Transformers	139,772,008	6,041,148	2,560,569	7,007,331	7,007,331	143,252,587
69	(369) Services	53,149,476	1,653,548	184,961	2,917	2,917	54,618,063
70	(370) Meters	48,637,719	2,345,769	833,576			50,149,912
71	(371) Installations on Customer Premises	7,604,157	689,884	195,590			8,098,451
72	(372) Leased Property on Customer Premises	278,776					278,776
73	(373) Street Lighting and Signal Systems	16,544,365	421,229	670,662			16,294,932
74	(374) Asset Retirement Costs for Distribution Plant
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	1,138,335,255	59,758,722	13,257,086	7,199,841	7,196,679	1,184,840,053
76	5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77	(380) Land and Land Rights
78	(381) Structures and Improvements
79	(382) Computer Hardware
80	(383) Computer Software
81	(384) Communication Equipment
82	(385) Miscellaneous Regional Transmission and Market Operation Plant
83	(386) Asset Retirement Costs for Regional Transmission and Market Oper
84	TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85	6. General Plant
86	(389) Land and Land Rights	12,127					12,127
87	(390) Structures and Improvements	4,224,854	1,830				4,226,684
88	(391) Office Furniture and Equipment
89	(392) Transportation Equipment
90	(393) Stores Equipment
91	(394) Tools, Shop and Garage Equipment
92	(395) Laboratory Equipment
93	(396) Power Operated Equipment
94	(397) Communication Equipment
95	(398) Miscellaneous Equipment
96	SUBTOTAL (Enter Total of lines 86 thru 95)	4,236,981	1,830				4,238,811
97	(399) Other Tangible Property
98	(399.1) Asset Retirement Costs for General Plant
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	4,236,981	1,830				4,238,811
100	TOTAL (Accounts 101 and 106)	1,625,486,542	78,018,916	15,491,721	7,274,466	8,206,250	1,687,081,953
101	(102) Electric Plant Purchased (See Instr. 8)
102	(Less) (102) Electric Plant Sold (See Instr. 8)
103	(103) Experimental Plant Unclassified
104	TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)	1,625,486,542	78,018,916	15,491,721	7,274,466	8,206,250	1,687,081,953

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

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

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.	ElectricPlantHeldForFutureUseDescription Description and Location of Property (a)	ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate Date Originally Included in This Account (b)	ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate Date Expected to be used in Utility Service (c)	ElectricPlantHeldForFutureUse Balance at End of Year (d)
1	Land and Rights:
2	Acquired rights of way for future transmission line		12/31/2025	33,378
3	from Danskammer Point System Station to Manchester
4	Road Substation
5	Land aquired for future expansion of Ohioville sub		12/31/2025	12,835
6	Hopewell Junction substation land transferred to		12/31/2021	429
7	future use in 1996 for future expansion
8	Neversink Substation land transferred to future use		12/31/2025	162,427
21	Other Property:
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47	TOTAL			209,069

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Report below descriptions and balances at end of year of projects in process of construction (107). Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts). Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line No.	ConstructionWorkInProgressProjectDescription Description of Project (a)	ConstructionWorkInProgress Construction work in progress - Electric (Account 107) (b)
1	H-Line Rebuild	3,353,537
2	SB-Line Rebuild	2,988,610
3	TV Elec Transm Line Rebuild	9,992,533
4	KM Elec Transm Line Rebuild	1,174,194
5	Honk Falls 69kv Breaker Replacement	1,846,492
6	Coxsackie Substation Modernization	4,676,852
7	Hurley Ave 115kv Modernization	2,323,087
8	Kerhonkson Substation Expansion	2,967,718
9	Reconductor TV Line Underbuild	1,365,675
10	Knapps Corners Substation	13,188,835
11	MINOR PROJECTS (LESS THAN $1,000,000 EACH)	32,012,508
43	Total	75,890,041

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Explain in a footnote any important adjustments during year. Explain in a footnote any difference between the amount for book cost of plant retired, Line 12, column (c), and that reported for electric plant in service, page 204, column (d), excluding retirements of non-depreciable property. The provisions of Account 108 in the Uniform System of Accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Line No.	Item (a)	Total (c + d + e) (b)	Electric Plant in Service (c)	Electric Plant Held for Future Use (d)	Electric Plant Leased To Others (e)
Section A. Balances and Changes During Year
1	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance Beginning of Year	378,971,967	378,971,967
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	37,538,369	37,538,369
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs
5	ExpensesOfElectricPlantLeasedToOthers (413) Exp. of Elec. Plt. Leas. to Others
6	TransportationExpensesClearing Transportation Expenses-Clearing
7	OtherClearingAccounts Other Clearing Accounts	90,034	90,034
8	OtherAccounts Other Accounts (Specify, details in footnote):
9.1	Other Accounts (Specify, details in footnote):
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	37,628,403	37,628,403
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	15,408,538	15,408,538
13	CostOfRemovalOfPlant Cost of Removal	10,069,401	10,069,401
14	SalvageValueOfRetiredPlant Salvage (Credit)	1,162,650	1,162,650
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	24,315,289	24,315,289
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Other Debit or Cr. Items (Describe, details in footnote):	1,411,636	(a) 1,411,636
18	BookCostOfAssetRetirementCosts Book Cost or Asset Retirement Costs Retired
19	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)	393,696,717	393,696,717
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production
21	AccumulatedDepreciationNuclearProduction Nuclear Production
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional	17,859,253	17,859,253
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage
24	AccumulatedDepreciationOtherProduction Other Production	2,962,159	2,962,159
25	AccumulatedDepreciationTransmission Transmission	101,823,181	101,823,181
26	AccumulatedDepreciationDistribution Distribution	270,264,631	270,264,631
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	787,493	787,493
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	393,696,717	393,696,717

FOOTNOTE DATA

(a) Concept: OtherAdjustmentsToAccumulatedDepreciation


Page 219 Line 17.1 Column ( c ) Footnote 1

Description of Other Debit or Credit Items:			12/31/2021

Net Increase in Retirement Work In Progress			1,416,222
ARO Accumulated Depreciation			(4,586)


Total Other Debits or Credits			1,411,636

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Report below investments in Account 123.1, Investments in Subsidiary Companies. Provide a subheading for each company and list thereunder the information called for below. Sub-TOTAL by company and give a TOTAL in columns (e), (f), (g) and (h). (a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity, and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number. Report column (f) interest and dividend revenues from investments, including such revenues from securities disposed of during the year. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost) and the selling price thereof, not including interest adjustment includible in column (f). Report on Line 42, column (a) the TOTAL cost of Account 123.1.
Line No.	DescriptionOfInvestmentsInSubsidiaryCompanies Description of Investment (a)	DateOfAcquisitionInvestmentsInSubsidiaryCompanies Date Acquired (b)	DateOfMaturityInvestmentsInSubsidiaryCompanies Date of Maturity (c)	InvestmentInSubsidiaryCompanies Amount of Investment at Beginning of Year (d)	EquityInEarningsOfSubsidiaryCompanies Equity in Subsidiary Earnings of Year (e)	InterestAndDividendRevenueFromInvestments Revenues for Year (f)	InvestmentInSubsidiaryCompanies Amount of Investment at End of Year (g)	InvestmentGainLossOnDisplosal Gain or Loss from Investment Disposed of (h)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42	Total Cost of Account 123.1 $		Total

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

MATERIALS AND SUPPLIES
For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a); estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if applicable.
Line No.	Account (a)	Balance Beginning of Year (b)	Balance End of Year (c)	Department or Departments which Use Material (d)
1	Fuel Stock (Account 151)	372,604	490,486
2	Fuel Stock Expenses Undistributed (Account 152)
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	18,445,195	18,590,978
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	22,591	22,591
8	Transmission Plant (Estimated)
9	Distribution Plant (Estimated)
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)	4,836,134	5,010,922
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	23,303,920	23,624,491
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)
15	Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16	Stores Expense Undistributed (Account 163)	871	795
17
18
19
20	TOTAL Materials and Supplies	23,677,395	(a) 24,115,772

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: MaterialsAndOperatingSupplies

There were no major inventory adjustments resulting from periodic physical inventories, write-off or obsolete material for year ended 12/31/2021.

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	SO2 Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)
5	Returned by EPA
6
7
8	Purchases/Transfers:
9
10
11
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22
23
24
25
26
27
28	Total
29	Balance-End of Year
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)
34	Gains
35	Losses
	Allowances Withheld (Acct 158.2)
36	Balance-Beginning of Year
37	Add: Withheld by EPA
38	Deduct: Returned by EPA
39	Cost of Sales
40	Balance-End of Year
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	NOx Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)
5	Returned by EPA
6
7
8	Purchases/Transfers:
9
10
11
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22
23
24
25
26
27
28	Total
29	Balance-End of Year
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)
34	Gains
35	Losses
	Allowances Withheld (Acct 158.2)
36	Balance-Beginning of Year
37	Add: Withheld by EPA
38	Deduct: Returned by EPA
39	Cost of Sales
40	Balance-End of Year
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

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

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

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

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

Transmission Service and Generation Interconnection Study Costs
Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. List each study separately. In column (a) provide the name of the study. In column (b) report the cost incurred to perform the study at the end of period. In column (c) report the account charged with the cost of the study. In column (d) report the amounts received for reimbursement of the study costs at end of period. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.	DescriptionOfStudyPerformed Description (a)	StudyCostsIncurred Costs Incurred During Period (b)	StudyCostsAccountCharged Account Charged (c)	StudyCostsReimbursements Reimbursements Received During the Period (d)	StudyCostsAccountReimbursed Account Credited With Reimbursement (e)
1	Transmission Studies
2	AC Transmission Project	41,460	186.01
3	NRG Energy Inc NY Pathway Proj			500	186.01
20	Total	41,460		500
21	Generation Studies
22	Q967 KCE NY5 Ohioville	7,725	186.01	10,336	186.01
23	Green County Project	1,108	186.01	1,989	186.01
24	Sunset Hill Solar - SWA	4,780	186.01
25	Q597 Hecate 3 Solar on NC Line	3,654	186.01
26	Q577 Greene County Energy	12,319	186.01
27	Gedney Hill Solar	6,435	186.01	8,010	186.01
28	KCE NY 2 SWA	189	186.01	4,307	186.01
29	Magruder Solar SWA Q744	1,930	186.01	8,237	186.01
30	Danskammer Energy Q791			19,293	186.01
39	Total	38,140		52,172
40	Grand Total	79,600		52,672

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

OTHER REGULATORY ASSETS (Account 182.3)
Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Assets being amortized, show period of amortization.
				CREDITS
Line No.	DescriptionAndPurposeOfOtherRegulatoryAssets Description and Purpose of Other Regulatory Assets (a)	OtherRegulatoryAssets Balance at Beginning of Current Quarter/Year (b)	IncreaseDecreaseInOtherRegulatoryAssets Debits (c)	OtherRegulatoryAssetsWrittenOffAccountCharged Written off During Quarter/Year Account Charged (d)	OtherRegulatoryAssetsWrittenOffRecovered Written off During the Period Amount (e)	OtherRegulatoryAssets Balance at end of Current Quarter/Year (f)
1	18231-Variable Rate Notes - Interest - Elec	854,836			1,224,880	370,044
2	18232-Variable Rate Notes - Interest - Gas	313,707			472,064	158,357
3	18233-CC Def Interest (Variable)		51,000		51,000
4	18234-Rate Case Expense Deferral	834,198	4,001,528		3,653,418	1,182,308
5	18236-Pension Over/Undercollection	6,698,992	3,617,096		6,477,297	3,838,791
6	18238-Pension - FAS 87 Minimum Liability Adjustment	852,038	48,745		95,673,364	94,772,581
7	18239-CC Non-Pipe Alternative-Gas		22,796		22,796
8	18240-REV Demonstration Projects	122,003	222,874		358,583	13,706
9	18241-CC-REV Demonstration Projects		19,613		19,613
10	18242-Call Volume Overflow - E	1,678,332	1,716,360		2,394,692	1,000,000
11	18243-Call Volume Overflow - G		365,539		101,539	264,000
12	18244-Non-Pipe Alternative-Gas	325,835	135,884		934	460,785
13	18245-COVID Lost Revenue Deferral		8,904,213		8,904,213
14	18247-CC Storm Costs		1,728,143		1,728,143
15	18248-Deferred Property Taxes	108,794	16,149,075		15,755,008	502,861
16	18249-CC Deferred Property Taxes		405,933		405,933
17	18250-Cloud Computing Deferral	547,750	664,899		1,212,649
18	18251-Deferred Accretion	405,511	185,460		7,964	583,007
19	18252-CC - Call Volume Overflow		84,811		84,811
20	18253-CC Make Whole Provision		3,150		3,150
21	18254-Targeted Demand Mgmt Program	11,321,085	12,296,489		14,786,487	8,831,088
22	18255-CC-Targeted Demand Mgmt Program		557,668		557,668
23	18256-Management Audit Costs	239,525			98,825	140,700
24	18257-CC - Cloud Computing Deferral		20,986		20,986
25	18258-Federal Tax Cuts & Jobs Act-Unprotected	13,464,068	10,268,732			23,732,800
26	18259-Positive Revenue Adjustments		5,798,400		5,798,400
27	18260-Deferred Electric Energy Costs	3,469,901	71,672,926		57,823,418	17,319,408
28	18261-CC-Covid Deferral		199,114		199,114
29	18262-Deferred Unrealized Losses - FAS 133	2,134,951	6,083,871		2,259,716	5,959,106
30	18263-Distributed Energy Resources Projects	5,047	117,720		5,046	117,721
31	18264-CC-Distributed Energy Resources Projects	1,440	2,000		1,693	1,747
32	18265-CC-CDG Consolidated Billing	3	88		91
33	18266-Major Storm Reserve	19,901,783	48,408,417		54,568,326	13,741,873
34	18267-Actual MGP/SIR Costs & Recovery - Elec	5,426,837	8,359,809		12,373,268	1,413,378
35	18268-Actual MGP/SIR Costs & Recovery - Gas	4,039,706	2,073,110		3,147,490	2,965,326
36	18269-Accrued MGP and Other SIR Costs	74,903,000	2,117,247		5,367,247	71,653,001
37	18270-Electric RDM Deferral	21,883,752	71,580,017		49,480,342	215,923
38	18271-CC Electric RDM	189,520	442,613		384,707	131,614
39	18272-Gas RDM Deferral	3,746,820	10,358,555		11,194,559	2,910,816
40	18273-CC Gas RDM	31,588	114,230		114,077	31,741
41	18274-RY3 Delayed Increase Elec/Make Whole Provision	4,102,690	503,621		4,944,241	337,930
42	18275-Regulatory Adjustment Mechanism-Electric	13,866,393	29,046,956		27,655,380	15,257,969
43	18276-Regulatory Adjustment Mechanism-Gas	3,418,416	2,084,845		2,105,713	3,397,548
44	18277-CC-Rev Req Leak Prone Pipe		164,415		164,415
45	18278-Delayed Increase Gas	493,605	599,686		738,164	355,127
46	18279-Revenue Requirement Leak Prone Pipe	1,696,002	4,298,982		5,994,984
47	18280-Earnings Adjustment Mechanisms-Electric	3,409,914	3,804,062		3,644,257	3,569,719
48	18281-Earnings Adjustment Mechanisms-Gas	525,651	480,500		474,156	531,995
49	18282-EV-TOU Deferral	3,726	4,346		6,090	1,982
50	18283-Asbestos Litigation Costs Deferred	8,911	1,960,736		2,403,309	451,484
51	18284-Carrying Charge - Asbestos Litigation	21,244	12,173		33,417
52	18285-CDG Consolidated Billing	3,511	9,371		13,978	1,096
53	18286-Carrying Charges - MGP Costs & Recoveries		458,615		458,615
54	18287-Net Lost Rev - MFC Undercollection	1,294,231	1,361,119		1,703,195	952,155
55	18288-CC-MFC Undercollection	5,842	14,146		20,263	275
56	18289-Gas Costs Deferred - GSC	4,453,024	16,099,643		12,495,519	8,057,148
57	18291-Def Temp. Met Trans Bus. Tax Surcharge	1,542,609	3,024,518		2,705,964	1,861,163
58	18292-CC - RAM - Electric		59,037		59,037
59	18293-Deferred Vacation Pay Accrual	10,196,793	1,775,185		2,218,986	9,752,992
60	18294-EV Make Ready		586,240		24,957	561,283
61	18295-Pension Reserve - Carrying Charge	268,435	1,251,554		1,519,990
62	18296-CC - RAM - Gas		19,644		19,644
63	18297-Distribution System Implement Plan-DSIP		185,017		185,017
64	18298-CC-EV-Make Ready		12,450			12,450
65	18299-Deferred Income Taxes - FAS 109	26,968,200	304,923,700		296,108,400	35,783,500
44	TOTAL	201,615,853	661,539,672		722,431,201	140,724,324

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

MISCELLANEOUS DEFFERED DEBITS (Account 186)
Report below the particulars (details) called for concerning miscellaneous deferred debits. For any deferred debit being amortized, show period of amortization in column (a) Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by classes.
				CREDITS
Line No.	Description of Miscellaneous Deferred Debits (a)	Balance at Beginning of Year (b)	Debits (c)	Credits Account Charged (d)	Credits Amount (e)	Balance at End of Year (f)
1	Accrued Payroll	393,100	7,589,000		7,207,300	774,800
2	Minor Items(5)	3,162	9,796,989		9,797,940	4,113
47	Miscellaneous Work in Progress
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49	TOTAL	389,938				770,687

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Report the information called for below concerning the respondent’s accounting for deferred income taxes. At Other (Specify), include deferrals relating to other income and deductions.
Line No.	DescriptionOfAccumulatedDeferredIncomeTax Description and Location (a)	AccumulatedDeferredIncomeTaxes Balance at Beginning of Year (b)	AccumulatedDeferredIncomeTaxes Balance at End of Year (c)
1	Electric
2	Regulatory Liabilities	34,730,037	30,744,297
3	Federal and NY State Net Operating Losses	11,373,617	22,768,117
4	Pension & OPEBs	8,971,760	8,135,860
5	Tax Cuts & Jobs Act	36,403,800	35,894,000
7	Other
8	TOTAL Electric (Enter Total of lines 2 thru 7)	91,479,214	97,542,274
9	Gas
10	Regulatory Liabilities	9,652,523	9,602,663
11	Federal and State Net Operating Losses	2,169,200	6,530,500
12	Tax Cuts & Jobs Act	12,283,900	11,933,700
13	Pension & OPEBs	1,250,900	880,100
15	Other
16	TOTAL Gas (Enter Total of lines 10 thru 15)	25,356,523	28,946,963
17.1	Other (Specify) - Non Operating	12,259,100	(a) 13,840,900
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	129,094,837	140,330,137

Notes

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxes

FOOTNOTE DATA


	Balance at	Balance
Account Subdivisions	Beginning	End
	of Year	of Year
(a)	(b)	(c)
Directors and Officers Deferred Compensation Plan	3,885,900	4,496,100
Interest Variable Rate Notes	—
Carrying Charge-SBC/RPS/CEF - NYSERDA Electric	1,216,900	158,000
Sales Tax Provision	103,000	—
Carrying Charge Rate Moderator Gas	—	—
Carrying Charge Low Income Bill Discount	—	—
Carrying Charge - Bonus depreciation	—	—
Carrying Charge-Energy Efficiency Prog-Gas (INTERNAL)	5,900	7,200
Carrying Charge - OPEB Reserve	(477,900)	192,800
Carrying Charge - FAST CHARGING INF PRO	119,400	(92,300)
Carrying Charge - Stray Voltage	—	—
Carrying Charge - Energy Efficiency Programs	106,100	—
Carrying Charge - Deferral of Interest	(100)	—
DEF FIT-CC-SBC/RPS/CEF NYSE	5,200	6,800
Contra Elec NO		38,400
Contra Gas NO
FAS 109 Deferred Tax Asset - Current	2,764,600	2,977,300
FAS 109 Deferred Tax Asset - Long-term	2,409,800	3,499,500
FAS 109 Deferred SIT Asset - Current	915,200	985,600
FAS 109 Deferred SIT Asset - Long-term	1,204,600	1,564,700
Total Other - Nonoperating	12,259,100	13,840,900

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

CAPITAL STOCKS (Account 201 and 204)
Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year. Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative. State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purpose of pledge.
Line No.	Class and Series of Stock and Name of Stock Series (a)	Number of Shares Authorized by Charter (b)	Par or Stated Value per Share (c)	Call Price at End of Year (d)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Shares (e)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Amount (f)	Held by Respondent As Reacquired Stock (Acct 217) Shares (g)	Held by Respondent As Reacquired Stock (Acct 217) Cost (h)	Held by Respondent In Sinking and Other Funds Shares (i)	Held by Respondent In Sinking and Other Funds Amount (j)
1	Common Stock (Account 201)
2	Common Stock (1)	(a) 30,000,000	5	0	16,862,087	84,310,435	0	0	0	0
12	Total	30,000,000			16,862,087	84,310,435
13	Preferred Stock (Account 204)
14	Preferred Stock (Account 204)
15	Preferred Stock (2)	(b) 1	100	0	1	100	0	0	0	0
27	Total	1			1	100
1	Capital Stock (Accounts 201 and 204) - Data Conversion
2	Capital Stock (Accounts 201 and 204) - Data Conversion
3	Total

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: CommonStockSharesAuthorized

(1) All outstanding shares at December 31, 2021 are held by CH Energy Group, Inc (Parent of the respondent)

(b) Concept: PreferredStockSharesAuthorized

(2) Outstanding share at December 31, 2021 is held by GSS Holdings (Independent third party -non affiliate of respondent)

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2022-04-18

Year/Period of Report

End of:

2021

/

Q4

Other Paid-in Capital
1. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change. Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation. Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class and series of stock to which related. Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210) - Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related. Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts.
Line No.	Item (a)	Amount (b)
1	DonationsReceivedFromStockholdersAbstract Donations Received from Stockholders (Account 208)
2	DonationsReceivedFromStockholders Beginning Balance Amount
3.1	IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders Increases (Decreases) from Sales of Donations Received from Stockholders
4	DonationsReceivedFromStockholders Ending Balance Amount
5	ReductionInParOrStatedValueOfCapitalStockAbstract Reduction in Par or Stated Value of Capital Stock (Account 209)
6	ReductionInParOrStatedValueOfCapitalStock Beginning Balance Amount	209,370,014
7.1	IncreasesDecreasesDueToReductionsInParOrStatedValueOfCapitalStock Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
8	ReductionInParOrStatedValueOfCapitalStock Ending Balance Amount	209,370,014
9	GainOrResaleOrCancellationOfReacquiredCapitalStockAbstract Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
10	GainOnResaleOrCancellationOfReacquiredCapitalStock Beginning Balance Amount
11.1	IncreasesDecreasesFromGainOrResaleOrCancellationOfReacquiredCapitalStock Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12	GainOnResaleOrCancellationOfReacquiredCapitalStock Ending Balance Amount
13	MiscellaneousPaidInCapitalAbstract Miscellaneous Paid-In Capital (Account 211)
14	MiscellaneousPaidInCapital Beginning Balance Amount	1,241,508
15.1	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital	(a) 6,000,000
16	MiscellaneousPaidInCapital Ending Balance Amount	7,241,508
17	OtherPaidInCapitalAbstract Historical Data - Other Paid in Capital
18	OtherPaidInCapitalDetail Beginning Balance Amount
19.1	IncreasesDecreasesInOtherPaidInCapital Increases (Decreases) in Other Paid-In Capital
20	OtherPaidInCapitalDetail Ending Balance Amount
40	OtherPaidInCapital Total	216,611,522

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2022-04-18

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: IncreasesDecreasesDueToMiscellaneousPaidInCapital

Capital contribution from parent company of $6,000,000 in 2021

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

CAPITAL STOCK EXPENSE (Account 214)
Report the balance at end of the year of discount on capital stock for each class and series of capital stock. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line No.	NameOfClassAndSeriesOfStock Class and Series of Stock (a)	CapitalStockExpense Balance at End of Year (b)
1	Common Stock	4,632,842
22	TOTAL	4,632,842

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

LONG-TERM DEBT (Account 221, 222, 223 and 224)
Report by Balance Sheet Account the details concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other Long-Term Debt. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds, and in column (b) include the related account number. For Advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received, and in column (b) include the related account number. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued, and in column (b) include the related account number. In a supplemental statement, give explanatory details for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a)principal advanced during year (b) interest added to principal amount, and (c) principal repaid during year. Give Commission authorization numbers and dates. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (m). Explain in a footnote any difference between the total of column (m) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line No.	ClassAndSeriesOfObligationCouponRateDescription Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates) (a)	RelatedAccountNumber Related Account Number (b)	Principal Amount of Debt Issued (c)	LongTermDebtIssuanceExpensePremiumOrDiscount Total Expense, Premium or Discount (d)	LongTermDebtIssuanceExpenses Total Expense (e)	LongTermDebtPremium Total Premium (f)	LongTermDebtDiscount Total Discount (g)	NominalDateOfIssue Nominal Date of Issue (h)	DateOfMaturity Date of Maturity (i)	AmortizationPeriodStartDate AMORTIZATION PERIOD Date From (j)	AmortizationPeriodEndDate AMORTIZATION PERIOD Date To (k)	Outstanding (Total amount outstanding without reduction for amounts held by respondent) (l)	Interest for Year Amount (m)
1	Bonds (Account 221)
2
3
4
5	Subtotal
6	Reacquired Bonds (Account 222)
7
8
9
10	Subtotal
11	Advances from Associated Companies (Account 223)
12
13
14
15	Subtotal
16	Other Long Term Debt (Account 224)
17	Variable Rate - Series B, NYSERDA Due 2034, Issued 8-3-99, Com. Auth. #99-M-03493		33,700,000		610,693			08/03/1999	07/01/2034	12/01/1999	07/01/2034	33,700,000	38,746
18	Medium Term Notes - 5.84%, Series E, Due 12/5/35		24,000,000		299,289			12/05/2005	12/05/2035	12/05/2005	12/05/2035	24,000,000	1,401,600
19	Medium Term Notes - 5.76%, Series E, Due 11/17/31		27,000,000		437,572			11/17/2006	11/17/2031	11/17/2006	11/17/2031	27,000,000	1,556,280
20	Medium Term Notes - 5.80%, Series F, Due 3/23/37		33,000,000		407,364			03/23/2007	03/23/2037	03/23/2007	03/23/2037	33,000,000	1,915,320
21	Medium Term Notes - 5.80%, Series F, Due 11/1/39		24,000,000		325,098			09/30/2009	11/01/2039	09/30/2009	11/01/2039	24,000,000	1,392,000
22	Medium Term Notes - 4.15%, Series G, Due 4/1/21		44,150,000		517,563			12/07/2010	04/01/2021	12/07/2010	04/01/2021	0	458,055
23	Medium Term Notes - 5.716%, Series G, Due 4/1/41		30,000,000		350,682			12/07/2010	04/01/2041	12/07/2010	04/01/2041	30,000,000	1,714,800
24	Senior Notes - 5.64%, Series B, Due 9/21/40		24,000,000		150,058			09/21/2010	09/21/2040	09/21/2010	09/21/2040	24,000,000	1,353,600
25	Medium Term Notes - 3.378%, Series G, Due 4/1/22		23,400,000		282,489			09/30/2011	04/01/2022	09/30/2011	04/01/2022	23,400,000	790,452
26	Medium Term Notes - 4.707%, Series G, Due 4/1/42		10,000,000		121,507			09/30/2011	04/01/2042	09/30/2011	04/01/2042	10,000,000	470,700
27	Medium Term Notes - 4.776%, Series G, Due 4/1/42		48,000,000		606,562			03/30/2012	04/01/2042	03/30/2012	04/01/2042	48,000,000	2,292,480
28	Medium Term Notes - 4.065%, Series G, Due 10/1/42		24,000,000		358,955			10/20/2012	10/01/2042	10/20/2012	10/20/2042	24,000,000	975,600
29	Medium Term Notes - 4.09%, Series D, Due 12/2/28		16,700,000		156,952			12/02/2013	12/02/2028	12/02/2013	12/02/2028	16,700,000	683,030
30	Variable Rate Notes - Libor + 1%, Series E, Due 3/26/24		30,000,000		200,892			03/26/2014	03/26/2024	03/26/2014	03/26/2024	30,000,000	358,671
31	Senior Notes - 2.98%, Series F, Due 3/31/25		20,000,000		156,841			03/31/2015	03/31/2025	03/31/2015	03/31/2025	20,000,000	596,000
32	Senior Notes - 2.56%, Series H, Due 10/28/26, issued 10/28/16, Com. Auth # 15-M-0251		10,000,000		91,368			10/29/2016	10/28/2026	10/28/2016	10/28/2026	10,000,000	256,000
33	Senior Notes - 3.63%, Series I, Due 10/28/46, issued 10/28/16, Com. Auth # 15-M-0251		20,000,000		141,368			10/29/2016	10/28/2046	10/28/2016	10/28/2046	20,000,000	726,000
34	Senior Notes - 4.05%, Series J, Due 8/31/47, issued 8/31/17, Com. Auth # 15-M-0251		30,000,000		191,796			08/31/2017	08/31/2047	08/31/2017	08/31/2047	30,000,000	1,215,000
35	Senior Notes - 4.20%, Series K, Due 8/31/57, issued 8/31/17, Com. Auth # 15-M-0251		30,000,000		191,796			08/31/2017	08/31/2057	08/31/2017	08/31/2057	30,000,000	1,260,000
36	Senior Notes - 4.27%, Series L, Due 6/15/48, issued 6/15/18, Com. Auth # 15-M-0251		25,000,000		191,122			06/15/2018	06/15/2048	06/15/2018	06/15/2048	25,000,000	1,067,496
37	Senior Notes - 3.99%, Series M, Due 10/28/26, issued 10/29/18, Com. Auth # 15-M-0251		40,000,000		248,231			10/29/2018	10/28/2026	10/28/2018	10/28/2026	40,000,000	1,596,000
38	Senior Notes - 4.21%, Series N, Due 10/28/33, issued 10/29/18, Com. Auth # 15-M-0251		40,000,000		248,231			10/29/2018	10/28/2033	10/28/2018	10/28/2033	40,000,000	1,683,996
39	Senior Notes - 3.89%, Series O, Due 10/28/49, issued 10/28/19, Com. Auth # 18-M-0271		50,000,000		279,442			10/28/2019	10/28/2049	10/28/2019	10/28/2049	50,000,000	1,944,996
40	Senior Notes - 3.99%, Series P, Due 10/28/59, issued 10/28/19, Com. Auth # 18-M-0271		50,000,000		279,442			10/28/2019	10/28/2059	10/28/2019	10/28/2059	50,000,000	1,995,000
41	Senior Notes - 3.42%, Series Q, Due 5/14/50, issued 5/14/20, Com. Auth # 18-M-0271		30,000,000		175,230			05/14/2020	05/14/2050	05/14/2020	05/14/2050	30,000,000	1,026,000
42	Senior Notes - 3.62%, Series R, Due 7/14/60, issued 7/14/20, Com. Auth # 18-M-0271		30,000,000		175,580			07/14/2020	07/14/2060	07/14/2020	07/14/2060	30,000,000	1,086,000
43	Senior Notes - 2.03%, Series S, Due 9/28/30, issued 9/28/20, Com. Auth # 18-M-0271		40,000,000		219,263			09/28/2020	09/28/2030	09/28/2020	09/28/2030	40,000,000	811,980
44	Senior Notes - 2.03%, Series T, Due 11/17/30, issued 11/17/20, Com. Auth # 18-M-0271		30,000,000		176,671			11/17/2020	11/17/2030	11/17/2020	11/17/2030	30,000,000	609,000
45	Senior Notes - 3.29%, Series U, Due 3/16/51, issued 3/16/21, Com. Auth # 18-M-0271		75,000,000		416,302			03/16/2021	03/16/2051	03/16/2021	03/16/2051	75,000,000	1,960,293
46	Senior Notes - 3.22%, Series V, Due 10/30/51, issued 10/28/21, Com. Auth # 18-M-0271		55,000,000		306,348			10/28/2021	10/30/2051	10/30/2021	10/30/2051	55,000,000	314,852
47	Subtotal		966,950,000		8,314,707							922,800,000	33,549,947
33	TOTAL		966,950,000									922,800,000	33,549,947

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line No.	Particulars (Details) (a)	Amount (b)
1	Net Income for the Year (Page 117)	73,426,657
2	Reconciling Items for the Year
3
4	Taxable Income Not Reported on Books
5	See Schedule on footnote	(a) 11,224,300
9	Deductions Recorded on Books Not Deducted for Return
10	See Schedule on footnote1	(b) 40,630,667
11	See Schedule on footnote2	11,261,174
14	Income Recorded on Books Not Included in Return
15	See Schedule on footnote	10,733,200
19	Deductions on Return Not Charged Against Book Income
20	See Schedule on footnote	179,767,919
27	Federal Tax Net Income	53,958,321
28	Show Computation of Tax:
29	See Schedule on footnote	11,330,000

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: TaxableIncomeNotReportedOnBooks


Schedule Page: 261 Line No.: 5 Column: b


Taxable Income not Reported on Books:
Bonus Depreciation Deferral of Revenue	$	13,300
Unbilled Revenue	6,445,000
Contributions in Aid of Construction	1,665,000
Avoided Cost Interest Capitalized	3,101,000
Page 261 - Line 5	$	11,224,300

Deductions Reported on Books Not Deducted on Return:
New York State Deferred Income Taxes	$	4,777,767
Var Rate Poll Control Notes - Def/Amort	891,600
FAS 87 Pension Expense	1,895,900
Def Property Tax Overcollection	2,099,800
Major Storm reserve	6,160,000
MGP SIR Costs & Recovery	5,089,000
Deferred Directors Compensation	1,167,000
Service Quality Incentive	100
Deferred Shared Earning	3,414,000
Mortgage Bonds Redeemed - Amort/Def	112,000
Executive Performance Shares Plan	901,800
Deferred Pension and OPEB over/undercollection	1,686,500
Cloud Deferral	152,400
Asbestos Litigation	212,900
Low Income Bill Discount	1,746,400
Parking Space Disallowance per IRS	193,000
Lobbying Costs - IRC 162	91,000
Fast Charging Infrastructure Program	49,000
Gas Compliance	110,000
Attachment Rents	59,700
Credit Card Fee Deferral	73,200
Targeted Demand Mgmt Program	2,490,000
Nondeductible Penalties	20,000
MFC Overcollection	342,000
Management Audit Costs	91,900
REV Demonstration Projects	41,900
Operating Reserves - Net	1,033,400
RY3 Delayed Increase	4,632,600
Deferral of Interest	1,095,700
Research Credit	100
Page 261 - Line 10	$	40,630,667

Federal Income Tax:
Federal Income Tax - Operating - Account 409.1	476,000
Federal Income Tax - Non-operating - Account 409.2	(476,000)
Provision for Deferred Income Tax - Debits - Accounts 410.1 and 410.2	37,464,500
Provision for Deferred Income Tax - Credits - Accounts 411.1, 411.2, 411.3,411.4 ,411.5 and 411.6 (new for 2021)	(23,203,326)
Page 261 - Line 11	$	11,261,174

Income Recorded on Books Not Included on Return:
AFUDC	4,970,000

(b) Concept: DeductionsRecordedOnBooksNotDeductedForReturn


Schedule Page: 261 Line No.: 10 Column: b


FOOTNOTE DATA
Leak Prone Pipe Revenue Requirement	1,590,100
Gas Costs Deferred	3,604,000
Regulatory Adjustments Mechanism	569,100
Page 261 - Line 15	$	10,733,200

Deductions on Return Not Charged Against Book Income:
Repair Deduction	60,116,000
Tax Depreciation in Excess of Book Depreciation	16,239,000
Carrying Charges	1,092,800
OPEB Expense	6,608,900
Energy Efficiency Program (INTERNAL)	19,837,000
SBC/RPS/EEPS Costs Deferred	1,265,000
Stray Voltage Testing	120,100
Electric Vehicle - TOU	4,100
Economic Development	380,000
MTA Tax	318,000
Pension Expense	1,579,700
RDM Deferral	21,264,000
Distributed Energy Resources Proj	118,000
Interest Payable - Tax Reserve	7,700
Rate Case Expense Deferral	348,000
Federal Income Tax Rate Change Unprotected	200
Unrealized Gains/Losses Trust Earnings	1,632,000
Electric Fuel Costs Deferred	13,849,000
CDG Consolidated Billing	4,100
R & D Rev/Costs Deferred	679,300
Estimated Sales & Use Assessment	173,019
Prepaid Insurance	447,500
Cost of Removal	12,520,000
COVID 19 Lost Revenue	6,187,300
Property Taxes	841,000
Officer Life Insurance	533,000
Vacation Pay Accrual	40,000
Earnings Adj. Mechanism	166,000
Non-Pipe Alternative	135,000
ARO Accretion Expense	177,000
Rate Moderator	8,227,200
Deferred Payroll Taxes	2,603,300
SC8 Lighting Undercoll RDM	430,000
Call Volm Overflow	1,263,700
EV Make Ready-Electric	561,000
Page 261 - Line 20	$	179,767,919

Computation of Federal Income Tax:
Federal taxable income - Line 27 of Page 261	(53,958,321)

Computation of tax:
2021 Flat Rate at 21%	(11,331,248)







Regular federal income tax	(11,331,248)

Alternative minimum tax	—


FOOTNOTE DATA
	(11,331,248)
Rate difference and rounding adjustment	1,248

Federal income tax on taxable income - Line 29 of Page 261	(11,330,000)
Current Year NOL Carryforward	11,299,000
FIT Research Credit	(320,000)
R & D Credit Carryforward	320,000
	—
	—
Current year federal income tax	(31,000)

Adjustment of prior year federal income tax accruals	31,000

Total Federal Income Tax - Lines 2(d) of Page 262	$	—

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are known, show the amounts in a footnote and designate whether estimated or actual amounts. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (g) and (h). The balancing of this page is not affected by the inclusion of these taxes. Include in column (g) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (d). Enter all adjustments of the accrued and prepaid tax accounts in column (i) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. Report in columns (l) through (o) how the taxes were distributed. Report in column (o) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 409.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (o) the taxes charged to utility plant or other balance sheet accounts. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
					BALANCE AT BEGINNING OF YEAR					BALANCE AT END OF YEAR		DISTRIBUTION OF TAXES CHARGED
Line No.	DescriptionOfTaxesAccruedPrepaidAndCharged Kind of Tax (See Instruction 5) (a)	TypeOfTax Type of Tax (b)	TaxJurisdiction State (c)	TaxYear Tax Year (d)	TaxesAccrued Taxes Accrued (Account 236) (e)	PrepaidTaxes Prepaid Taxes (Include in Account 165) (f)	TaxesCharged Taxes Charged During Year (g)	TaxesPaid Taxes Paid During Year (h)	TaxAdjustments Adjustments (i)	TaxesAccrued Taxes Accrued (Account 236) (j)	PrepaidTaxes Prepaid Taxes (Included in Account 165) (k)	TaxesAccruedPrepaidAndCharged Electric (Account 408.1, 409.1) (l)	IncomeTaxesExtraordinaryItems Extraordinary Items (Account 409.3) (m)	AdjustmentsToRetainedEarnings Adjustment to Ret. Earnings (Account 439) (n)	TaxesIncurredOther Other (o)
1		Federal Tax	New York	2021	0	0				0	0	424,800			424,800
2					0	0				0	0
3	Subtotal Federal Tax				0	0				0	0	(a) 424,800			424,800
4	New York State Capital Base Tax	State Tax	New York	2021	0	0	1,672,000	1,698,000		26,000	0	1,461,300			210,700
5	Subtotal State Tax				0	0	1,672,000	1,698,000		26,000	0	1,461,300			210,700
6	Municipal Utility Service	Local Tax	New York	2021	346,910	0	1,695,503	1,275,187		767,226	0				1,695,503
7	Municipal Utility Service	Local Tax	New York	2020	0	0		346,910		346,910	0
8	Special Franchise Tax	Local Tax	New York	2021	0	9,216,155	29,864,613	30,626,308		0	9,977,850	17,842,697			12,021,916
9	Subtotal Local Tax				346,910	9,216,155	31,560,116	32,248,405		420,316	9,977,850	17,842,697			13,717,419
10	Subtotal Other Tax				0	0				0	0
11		Property Tax			0	0				0	0
12	Subtotal Property Tax				0	0				0	0
13	Real Estate Tax	Real Estate Tax	New York	2021	0	9,848,443	29,314,442	29,392,460			9,926,461	26,418,817			2,895,625
14	Subtotal Real Estate Tax				0	9,848,443	29,314,442	29,392,460		0	9,926,461	26,418,817			2,895,625
15	Federal Unemployment Tax	Unemployment Tax		2021	501	0	49,304	49,155		650	0	25,035			24,269
16	New York State Unemployment Tax	Unemployment Tax	New York	2021	851	0	290,464	287,784		3,531	0	147,600			142,864
17	Subtotal Unemployment Tax				1,352	0	339,768	336,939		4,181	0	172,635			167,133
18	Sales and Use Tax	Sales And Use Tax	New York	2021	2,724,272	0	8,172,356	9,859,851		1,036,777	0	2,757,365			5,414,989
19	Subtotal Sales And Use Tax				2,724,272	0	8,172,356	9,859,851		1,036,777	0	2,757,365			5,414,989
20	Subtotal Income Tax				0	0				0	0
21	Subtotal Excise Tax				0	0				0	0
22	Subtotal Fuel Tax				0	0				0	0
23	Subtotal Federal Insurance Tax				0	0				0	0
24	Subtotal Franchise Tax				0	0				0	0
25	Tax on Foreign Insurance Policies	Miscellaneous Other Tax	New York	2021	0	0		20,866		20,866	0
26	Subtotal Miscellaneous Other Tax				0	0		20,866		20,866	0
27	Hazardous Waste tax	Other Federal Tax		2021	0	0	524	524		0	0	419			105
28	Subtotal Other Federal Tax				0	0	524	524		0	0	419			105
29	MTA Surcharge	Other State Tax	New York	2021	16,496	0	1,403,909	1,396,866		23,539	0				1,403,909
30	MTA Surcharge	Other State Tax	New York	2020	0	0		14,220		14,220	0
31	Utility Service Tax	Other State Tax	New York	2020	0	0		156,704		156,704	0
32	Utility Service Tax	Other State Tax	New York	2021	155,907	0	6,880,206	6,747,209		288,904	0				6,880,206
33	Subtotal Other State Tax				172,403	0	8,284,115	8,314,999		141,519	0				8,284,115
34	Subtotal Other Property Tax				0	0				0	0
35	Subtotal Other Use Tax				0	0				0	0
36	Subtotal Other Advalorem Tax				0	0				0	0
37	Subtotal Other License And Fees Tax				0	0				0	0
38	FICA Contribution	Payroll Tax		2021	5,348,808	0	10,231,107	12,782,030		2,797,885	0	4,931,212			5,299,895
39	Subtotal Payroll Tax				5,348,808	0	10,231,107	12,782,030		2,797,885	0	4,931,212			5,299,895
40	Subtotal Advalorem Tax				0	0				0	0
41	Subtotal Other Allocated Tax				0	0				0	0
42	Subtotal Severance Tax				0	0				0	0
43	Subtotal Penalty Tax				0	0				0	0
44	Subtotal Other Taxes And Fees				0	0				0	0
40	TOTAL				8,593,745	19,064,598	89,574,428	94,654,074		4,353,812	19,904,311	54,009,245			35,565,181

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: TaxesAccruedPrepaidAndCharged


Line No.	Kind of Tax (See instruction 5)	Type of Tax	Other Income and	CWIP Accounts 107 & 118	Gas
			Deductions Account		(Account	Other	Total Other
			408.2, 409.2		408.1, 409.1)

1.1		Federal tax	(476,000)		51,200		(424,800)
2	Total Federal Tax		($476,000)	$0	$51,200		($424,800)
3.1	New York State Capital Base Tax	Income Tax	(157,000)		367,700		$210,700
4	Total State Tax		(157,000)	0	367,700		$210,700
5.1	Municipal Utility Service	Other State Tax				1,695,503	$1,695,503
5.2	Special Franchise Tax	Other State Tax			12,649,567	(627,651)	12,021,916
6	Total Local Tax		0	0	12,649,567	1,067,852	13,717,419
7.1	Real Estate Tax	Real Estate Tax	112,346		4,254,962	(1,471,683)	2,895,625
8	Total Real Estate Tax		112,346	0	4,254,962	(1,471,683)	2,895,625
9.1	Federal Unemployment Tax	Unemployment Tax		14,813	7,173	2,283	$24,269
9.2	New York State Unemployment Tax	Unemployment Tax		87,334	42,288	13,242	$142,864
10	Total Unemployment Tax		0	102,147	49,461	15,525	$167,133
11.1	Sales and Use Tax	Sales and Use Tax		2,859,036	632,889	1,923,064	$5,414,989
12	Total Sales and Use Tax		0	2,859,036	632,889	1,923,064	$5,414,989
13.1	Tax on Foreign Insurance Policies	Miscellaneous Other taxes
14	Total Miscellaneous Other Tax		0	0	0
15.1	Hazardous Waste tax	Other Federal Tax			105		105
16	Total Other Federal Tax		0	0	105	0	105
17.1	MTA Surcharge	Other State tax		55,875		1,348,034	1,403,909
17.2	Utility Service Tax	Other State tax				6,880,206	6,880,206
18	Total Other State Tax		0	55,875	0	8,228,240	$8,284,115
19.1	FICA Contribution	Payroll Tax		2,917,779	1,412,799	969,317	$5,299,895
20	Total Payroll Tax		0	2,917,779	1,412,799	969,317	$5,299,895
21	TOTAL		(520,654)	5,934,837	19,418,683	10,732,315	35,565,181

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g). Include in column (i) the average period over which the tax credits are amortized.
			Deferred for Year		Allocations to Current Year's Income
Line No.	Account Subdivisions (a)	Balance at Beginning of Year (b)	Account No. (c)	Amount (d)	Account No. (e)	Amount (f)	Adjustments (g)	Balance at End of Year (h)	Average Period of Allocation to Income (i)	ADJUSTMENT EXPLANATION (j)
1	Electric Utility
2	3%
3	4%
4	7%
5	10%
8	TOTAL Electric (Enter Total of lines 2 thru 7)
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10										`
47	OTHER TOTAL
48	GRAND TOTAL

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

OTHER DEFERRED CREDITS (Account 253)
Report below the particulars (details) called for concerning other deferred credits. For any deferred credit being amortized, show the period of amortization. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
			DEBITS
Line No.	Description and Other Deferred Credits (a)	Balance at Beginning of Year (b)	Contra Account (c)	Amount (d)	Credits (e)	Balance at End of Year (f)
1	Newburgh Gas Site Remediation	1,489,900	182	100,984	13,584	1,402,500
2	Other MGP Remediation	71,153,100	182	4,632,496	1,563,897	68,084,501
3	SIR Remediation	2,260,000	182	633,766	539,766	2,166,000
4	Def Revenue Attachment Rents	1,689,211	400	3,438,083	3,497,743	1,748,871
5	Executive Performance Share Plan	5,480,999	920	27,508,398	28,410,171	6,382,772
6	D&O Deferred Comp Plan	5,775,062	920/930.2	2,342,948	1,175,971	4,608,085
7	D&O Def Comp Plan Non Op	14,868,286	421.6	2,038,524	4,372,523	17,202,285
8	Solar Deposits	17,687,611	VARIOUS	5,578,649	0	12,108,962
9	R & D	124,002	400/930.2	0	124,002
10	Minor Items (3)	148,115		142,458	26,271	31,928
47	TOTAL	120,676,286		46,416,306	39,475,924	113,735,904

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)

Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property.
For other (Specify),include deferrals relating to other income and deductions.
Use footnotes as required.

CHANGES DURING YEAR

ADJUSTMENTS

Debits

Credits

Line No.

Account

(a)

Balance at Beginning of Year

(b)

Amounts Debited to Account 410.1

(c)

Amounts Credited to Account 411.1

(d)

Amounts Debited to Account 410.2

(e)

Amounts Credited to Account 411.2

(f)

Account Credited

(g)

Amount

(h)

Account Debited

(i)

Amount

(j)

Balance at End of Year

(k)

1

Accelerated Amortization (Account 281)

2

Electric

3

Defense Facilities

4

Pollution Control Facilities

5

Other

5.1

Other (provide details in footnote):

8

TOTAL Electric (Enter Total of lines 3 thru 7)

9

Gas

10

Defense Facilities

11

Pollution Control Facilities

12

Other

12.1

Other (provide details in footnote):

15

TOTAL Gas (Enter Total of lines 10 thru 14)

16

Other

16.1

Other

16.2

Other

17

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

18

Classification of TOTAL

19

Federal Income Tax

20

State Income Tax

21

Local Income Tax

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization. For other (Specify),include deferrals relating to other income and deductions. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 282
2	Electric	159,620,700	14,983,500	4,375,805			254	2,241,995	254, 282	74,900	167,911,500
3	Gas	65,127,500	5,767,321	768,121			253	237,300	253, 254	212,200	70,151,800
4	Other (Specify)	13,370,707					—	5,149,800	—		18,520,507
5	Total (Total of lines 2 thru 4)	238,118,907	20,750,821	5,143,926				3,145,105		287,100	256,583,807
6
7
8
9	TOTAL Account 282 (Total of Lines 5 thru 8)	238,118,907	20,750,821	5,143,926				3,145,105		287,100	256,583,807
10	Classification of TOTAL
11	Federal Income Tax	200,679,725	14,800,621	4,258,626			—	1,412,905	—	6,300	212,628,325
12	State Income Tax	37,439,182	5,950,200	885,300			—	1,732,200	—	280,800	43,955,482
13	Local Income Tax

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts recorded in Account 283. For other (Specify),include deferrals relating to other income and deductions. Provide in the space below explanations for Page 276. Include amounts relating to insignificant items listed under Other. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 283
2	Electric
3	(a) See Footnote	97,840,225	12,337,400	193,200	48,800	337,000		2,772,480		4,412,275	108,056,430
9	TOTAL Electric (Total of lines 3 thru 8)	97,840,225	12,337,400	193,200	48,800	337,000		2,772,480		4,412,275	108,056,430
10	Gas
11	(b) See Footnote	38,000,597	4,206,000	5,300		1,700		3,319,620		2,228,525	43,301,292
17	TOTAL Gas (Total of lines 11 thru 16)	38,000,597	4,206,000	5,300		1,700		3,319,620		2,228,525	43,301,292
18	TOTAL Other	(c) 13,540,400						158,600		3,887,800	17,269,600
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	149,381,222	16,543,400	187,900	48,800	338,700		5,933,500		2,753,000	168,627,322
20	Classification of TOTAL
21	Federal Income Tax	115,806,622	12,657,100	173,000	37,300	258,600		7,565,900		5,077,100	130,558,222
22	State Income Tax	33,574,600	3,886,300	14,900	11,500	80,100		2,295,000		1,603,300	38,069,100
23	Local Income Tax
NOTES

FOOTNOTE DATA

(a) Concept: DescriptionOfAccumulatedDeferredIncomeTaxOther


Schedule Page: 276 Line No.: 3 Column: a


Account Subdivisions	Balance at Beginning	Debited To Account	Credited To Account	Debited To Account	Credited To Account	Acct.	Amount	Acct	Amount	Balance at End of Year
	of Year	410.1	411.1	410.2	411.2	Cr.		Dr.
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)
Account 283
Electric
(182.76) DEF FIT REG ADJ MECH - ELEC	3,812,900	0	0	0	0		(382,900)		0	4,195,800
DEF FIT-ACCRETION EXPENSE	111,600	0	0	48,800	0		0		0	160,400
DEF FIT-CC-FEB 2010 STORM COSTS	0	0	0	0	0		0		0	0
(182.36) PENSION OVER/UNDER COLL-ELEC	1,553,900	(631,300)	0	0	0		0		0	922,600
(182.86) CC- ACT MGP SIR COSTS & RE	0	0	0	0	0		(80)		0	80
(182.83) DEFERRED ASBESTOS LITIGATION	99,800	(104,600)	0	0	0		0		0	(4,800)
(182.82) DEF FIT ELECTRIC VEHICLE T	1,000	(700)	0	0	0		0		0	300
(182.42) DEF FIT SC8 LIGHT UNDERCOL	461,500	(461,500)	0	0	0		0		0	0
(182.43) DEF FIT CC SC8 LIGHT UNDERCO	0	0	0	0	0		0		0	0
(182.34) DEF FIT- RATE CASE EXP DEF- ELEC	183,500	76,700	0	0	0		0		0	260,200
DEF FIT - ASBESTOS LITIGATION CC	5,800	0	0	0	0		0		(5,800)	0
FIT-SIT CONTRA - ELEC	(728,200)	(400)	0	0	0		0		0	(728,600)
(182.58) FIT TAX RATE CHANGE-NON OP	612,200	0	0	0	0		0		0	612,200
(182.58)FIT TAX RATE CHANGE-ELECT	2,847,500	0	0	0	0		(2,033,900)		0	4,881,400
COST OF REMOVAL-ELECTRIC	4,584,100	0	0	0	0		0		(4,384,200)	199,900
(182.63) DEF FIT DIST ENERGY RESOUR	1,400	31,000	0	0	0		0		0	32,400
(182.64) DEF FIT-CC-DIST ENERGY RES	400	0	0	0	0		(100)		0	500
REPAIR ALLOWANCE	4,315,300	0	222,300	0	0		0		0	4,093,000
DEF FIT - PREPAID INSURANCE - ELECTRIC	373,900	98,500	0	0	0		0		0	472,400
FIT-SIT CONTRA-N.O.	(39,300)	0	0	0	0		(6,200)		0	(33,100)
(182.70)DEF FIT ELECTRIC RDM	(6,018,100)	6,077,400	0	0	0		0		0	59,300
DEF FIT ELECTRIC RDM CC	(52,100)	0	0	0	0		(16,000)		0	(36,100)
(182.95) PEN ELEC RESERVE CARRY CHRG	(134,100)	0	0	0	0		(134,100)		0	0
(182.66)DEF FIT MAJOR STORM-ELECTRI	5,473,300	(1,694,400)	0	0	0		0		0	3,778,900


DEF FIT-CC-TARGETED DEMAND MGMT (18	0	0	0	0	0	0	0	0
DEF FIT - CC - VAR RATE INT - E	0	0	0	0	0	0	0	0
(128.30) NONDEDUCTBL PENS EXP-ELEC	(1,685,200)	339,600	0	0	0	0	0	(1,345,600)
(182.40) DEF FIT - REV DEMONSTRATION	33,600	(37,400)	0	0	0	0	0	(3,800)
(182.41) CC DEF FIT - REV DEMONSTRATION	0	0	0	0	0	0	0	0
(182.42) CALL VOLUME OVERFLOW E FIT	0	275,000	0	0	0	0	0	275,000
(182.85) ACT MGP SIR COSTS AND REC-ELEC	1,492,300	(1,103,600)	0	0	0	0	0	388,700
(182.59)DEF FIT - POSITIVE REV ADJ - ELECTRIC	0	0	0	0	0	0	0	0
DEF FIT-TARGETED DEMAND MGMT (182.54)	3,113,800	(686,800)	0	0	0	0	0	2,427,000
DEF FIT CC RAM ELECTRIC	0	0	0	0	0	0	0	0
DEF FIT MANAGEMENT AUDIT COSTS-ELECTRIC	50,900	(21,300)	0	0	0	0	0	29,600
(182.60) DEFERRED FUEL COSTS	954,500	3,808,200	0	0	0	0	0	4,762,700
CC-DEF FIT DEFERRED PROPERTY TAXES-ELEC	0	0	0	0	0	0	0	0
(182.91) TMTBTS - ELECTRIC	314,900	0	0	0	0	(43,900)	0	358,800
(182.50) DEF FIT CLOUD DEFERRAL - E	120,600	(120,600)	0	0	0	0	0	0
(182.80) DEF FIT Earnings Adj Mech	937,700	43,900	0	0	0	0	0	981,600
DEF FIT-18274-RY3 DELAYED IN-17-E-0	1,128,300	(1,221,300)	0	0	0	0	0	(93,000)
DEF FIT DEFERRED PROPERTY TAXES	(496,300)	145,600	0	0	0	0	0	(350,700)
(188.10) ELECTRIC R&D COSTS DEFERRED	$104,000	$0	($29,100)	$0	$0	$0	$0	$133,100
DEF FIT - VARIABLE RATE INT DEFERRAL	$235,200	$0	$0	$0	$337,000	$0	$0	($101,800)
(182.85) DEF FIT CDG CONSOL BILLING	$900	($1,100)	$0	$0	$0	$0	$0	($200)
DEF FIT REPAIR DEDUCTION-ELEC	$74,025,000	$7,526,500	$0	$0	$0	$0	$0	$81,551,500
(182.94) DEF FIT EV-MAKE READY ELEC	$0	$0	$0	$0	$0	($154,500)	$0	$154,500

(b) Concept: DescriptionOfAccumulatedDeferredIncomeTaxOther


Schedule Page: 276 Line No.: 11 Column: a


Account Subdivisions	Balance at Beginning	Debited To Account	Credited To Account	Debited To Account	Credited To Account	Acct.	Amount	Acct	Amount	Balance at End of Year
	of Year	410.1	411.1	410.2	411.2	Cr.		Dr.
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)

MTG RECORDING TAX/BOND RED & PREM*	43725	0	0	0	0		0		-22275	21450
TOTAL Electric	$97,840,225	$12,337,400	$193,200	$48,800	$337,000		($2,772,480)		($4,412,275)	$108,056,430
CC-NON-PIPE ALTERNATIVE	0	0	0	0	0		0		0	0
(182.76) DEF FIT REG ADJ MECH - GAS	940,300	0	0	0	0		0		(6,700)	933,600
DEF FIT-REV REQ-LEAK PRONE PIPE	466,600	(466,600)	0	0	0		0		0	0
(182.36) PENSION OVER/UNDER COLL-GAS	288,700	(155,500)	0	0	0		0		0	133,200
(182.86) CC- ACT MGP SIR COSTS & RE	0	0	0	0	0		(20)		0	20
(182.34) DEF FIT - RATE CASE EXP DEF- GAS	45,700	19,300	0	0	0		0		0	65,000
DEF FIT-CC-(182.57) CLOUD COMP DEF	0	0	0	0	0		0		0	0
(182.58) FIT TAX RATE CHANGE-NON OP	230,900	0	0	0	0		0		0	230,900
(182.58)FIT TAX RATE CHANGE-GAS	12,300	0	0	0	0		(789,700)		0	802,000
COST OF REMOVAL-GAS	657,500	0	0	0	0		0		(1,853,000)	(1,195,500)
DEF FIT - PREPAID INSURANCE - GAS	93,500	24,600	0	0	0		0		0	118,100
FIT-SIT CONTRA-GAS	(226,700)	80,200	0	0	0		0		0	(146,500)
DEF FIT GAS RDM	1,030,400	(229,900)	0	0	0		0		0	800,500
DEF FIT - GAS RDM CC	8,700	0	0	0	0		0		(600)	8,100
(182.95) PEN GAS RESERVE CARRY CHRGS	208,100	0	0	0	0		0		(208,100)	0
FIT-SIT CONTRA-N.O.	(27,100)	0	0	0	0		0		0	(27,100)
DEF FIT - CC - VARRATE INT - G	0	0	0	0	0		0		0	0
(128.30) NONDEDUCTBL PENS EXP-GAS	(1,932,500)	96,200	0	0	0		0		0	(1,836,300)
(182.44) Def FIT Non-Pipe Alternative	89,500	37,200	0	0	0		0		0	126,700
(182.85) ACT MGP SIR COSTS AND REC-GAS	1,110,900	(295,500)	0	0	0		0		0	815,400
(182.92) DEF FIT CC RAM GAS	0	0	0	0	0		0		0	0
DEF FIT MANAGEMENT AUDIT COSTS-GAS	14,900	(5,900)	0	0	0		0		0	9,000


(182.91) TMTBTS - GAS	108,900	0	0	0	0	(43,800)	0	152,700
DEF FIT CLOUD DEFERRAL - G	30,000	(7,100)	0	0	0	0	(22,900)	0
(182.81) -DEF FIT EARNINGS ADJ MECH	144,500	1,900	0	0	0	0	0	146,400
DEF FIT-18278-RY3 DELAYED IN-17-G-0	135,700	(38,000)	0	0	0	0	0	97,700
(182.89) GSC-CURRENT/PRIOR PERIOD	1,225,000	0	0	0	0	(990,800)	0	2,215,800
(188.20) GAS R&D COSTS DEFERRED	(26,400)	0	(5,300)	0	0	(16,500)	0	(4,600)
DEF FIT- CC - MFC OVER/UNDER	$1,600	$0	$0	$0	$1,700	$0	$0	($100)
DEF FIT - VARIABLE RATE INT DEFERRAL	$86,300	$0	$0	$0	$0	$0	($129,800)	($43,500)
DEF FIT - MFC OVER/UNDER	$355,800	($94,000)	$0	$0	$0	$0	$0	$261,800
(182.43) CALL VOLUME OVERFLOW G FIT	$0	$72,600	$0	$0	$0	$0	$0	$72,600
DEF FIT DEFERRED PROPERTY TAXES-GAS	$526,200	($37,200)	$0	$0	$0	$0	$0	$489,000
DEF FIT-PRA GAS SERVICE TERMINATION	$0	$0	$0	$0	$0	$0	$0	$0
DEF FIT REPAIR DEDUCTION-GAS	$23,222,400	$5,203,700	$0	$0	$0	$0	$0	$28,426,100
CC-DEF FIT DEFERRED PROPERTY TAXES-GAS	$0	$0	$0	$0	$0	$0	$0	$0
DEF FIT-CC-EMPIRE ZONE RATE-LOST RE	$0	$0	$0	$0	$0	($2,600)	$0	$2,600
(182.77)CC-DEF SIT LEAK PRONE PIPE-GAS	$0	$0	$0	$0	$0	$0	$0	$0
RESERVE FOR REPAIR DEDUCTION-FEDERAL	$9,164,322	$0	$0	$0	$0	($1,476,200)	$0	$10,640,522

(c) Concept: AccumulatedDeferredIncomeTaxesOther


Schedule Page: 276 Line No.: 18 Column: a


Account Subdivisions	Balance at Beginning	Debited To Account	Credited To Account	Debited To Account	Credited To Account	Acct.	Amount	Acct	Amount	Balance at End of Year
	of Year	410.1	411.1	410.2	411.2	Cr.		Dr.
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)
MTG RECORDING TAX/BOND RED & PREM*	14575	0	0	0	0		0		-7425	7150
TOTAL Gas	38000597	4206000	-5300	0	1700		-3319620		-2228525	43301292

Other

FAS 109 Def Tax Liability-Current	(131,300)	0	0	0	0		158,600		0	(289,900)
FAS 109 Def Tax Liability-Long term	13,671,700	0	0	0	0		0		3,887,800	17,559,500



TOTAL Other	13,540,400	0	0	0	0	158,600	3,887,800	17,269,600

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

OTHER REGULATORY LIABILITIES (Account 254)
Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Liabilities being amortized, show period of amortization.
			DEBITS
Line No.	Description and Purpose of Other Regulatory Liabilities (a)	Balance at Beginning of Current Quarter/Year (b)	Account Credited (c)	Amount (d)	Credits (e)	Balance at End of Current Quarter/Year (f)
1	25425- Credit Card Fee Deferral	475,921		944,169	428,478	39,770
2	25426-CC-Credit Card Fee Deferral			36,776	36,776
3	25432-Deferred Unbilled Revenues	5,081,531				5,081,531
4	25435-CC Def of Overcoll of Interest			55,288	55,288
5	25436-Def of Interest Overcollection	464,863		1,560,700	1,095,837
6	25437-Negative Revenue Adjustments	1,638,293		7,744,907	6,106,614
7	25438-CC Shared Earnings			15,476	15,476
8	25440-EV Fast Charge Incentive	4,668,379		12,099	60,632	4,716,912
9	25441-CC-EV Fast Charge Incentive	455,738		348	282,680	738,070
10	25442-CC - Economic Development - Elec			17,947	17,947
11	25443-CC - Economic Development - Gas			2,883	2,883
12	25444-Federal Income Tax Research Cr Elec	1,501,190		1,501,190
13	25445-Federal Income Tax Research Cr Gas	353,910		353,910
14	25451-Def Low Income Bill Disc-Elec	4,195,028		2,065,342	1,654,514	3,784,200
15	25452-Def Low Income Bill Disc-Gas	526,818		805,925	1,783,978	1,504,871
16	25456-CC-Low Income Bill Disc Prgm			369,784	369,784
17	25457-Bonus Depr Deferral	62,566		84,774	22,208
18	25458-CC Bonus Depr Deferral			3,688	3,688
19	25459-SBC/RPS/CEF-NYSERDA Electric	52,322,204		46,987,622	45,723,843	51,058,425
20	25460-CC-SBC/RPS/CEF-NYSERDA Electric	4,656,265		4,656,265	604,938	604,938
21	25461-SBC/RPS/CEF-NYSERDA Gas	895,317		830	12	894,499
22	25462-CC-SBC/RPS/CEF-NYSERDA Gas	19,546			6,612	26,158
23	25465-Deferred OPEB Costs-Over/Under Coll	199,519		2,650,789	2,778,827	71,481
24	25466-OPEB Reserve-Carrying Charge	1,828,440		714,799	2,543,239
25	25467-Def OPEB Liability Adj-SFAS 158	13,739,323		3,066,628	20,430,697	31,103,392
26	25468-Sales Tax Refund-Assessment			1,114,537	1,114,537
27	25469-CC-Sales Tax Refund-Assessments			11,114	11,114
28	25470-Economic Development Funding	877,010		866,079	419,588	430,518
29	25471-Accrued Sales Tax Audit Assessments			405,000		405,000
30	25472-CC Energy Efficiency Program - Gas	22,188		671	6,356	27,873
31	25473-CC Energy Efficiency Program - E	405,533		818,124	58,866	353,725
32	25475-Energy Efficiency Program - Gas	175,353		1,100,995	1,125,530	199,888
33	25476-Energy Efficiency Program - Elec	1,863,339		37,876,186	23,046,186	16,693,339
34	25477-FAS 133 Def. Unrealized Gain			13,855,143	14,019,303	164,160
35	25478-Other Regulatory Adjustments			1,013,860	1,013,860
36	25479-Net Plant Depreciation Target	10,193,000		13,719,000	3,526,000
37	25480-CC-Net Plant Depreciation Targets			273,328	273,328
38	25481-Economic Development - Gas			100,000	165,903	65,903
39	25483-Regulatory Debit			1,373,110	1,585,073	211,963
40	25485-CC-Regulatory Debit			11,302	37,602	26,300
41	25489-Federal Tax Cuts & Jobs Act-Protected	186,301,229		40,570,043	37,279,139	183,010,325
42	25490-FAS 109 Income Taxes	7,294,200		100,937,300	102,670,200	9,027,100
43	25491-Rate Moderator-Electric	15,785,998		46,426,475	50,011,778	19,371,300
44	25492-CC-Rate Moderator-Electric			946,056	946,056
45	25493-Rate Moderator-Gas	6,246,947		22,764,831	26,632,967	10,115,083
46	25494-CC-Rate Moderator-Gas			515,041	515,041
47	25496-Def Stray Voltage Overcollection	44,423		380,563	429,199	4,212
48	25497-CC Def Stray Volt-Over Collection			17,747	17,747
41	TOTAL	314,422,629		358,748,645	348,930,323	304,604,307

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

Electric Operating Revenues
The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The average number of customers means the average of twelve figures at the close of each month. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.	Title of Account (a)	Operating Revenues Year to Date Quarterly/Annual (b)	Operating Revenues Previous year (no Quarterly) (c)	MEGAWATT HOURS SOLD Year to Date Quarterly/Annual (d)	MEGAWATT HOURS SOLD Amount Previous year (no Quarterly) (e)	AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly) (f)	AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly) (g)
1	SalesOfElectricityHeadingAbstract Sales of Electricity
2	ResidentialSalesAbstract (440) Residential Sales	(a) 338,949,455	312,226,045	1,829,227	1,776,665	215,501	211,342
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	95,080,173	77,129,154	616,069	583,191	31,006	30,517
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	8,254,479	6,929,136	66,720	69,771	612	690
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	5,776,187	5,566,320	11,369	12,322	291	210
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities	17,723,598	14,840,817	141,345	141,222	2,044	2,184
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales	58,523	52,656	955	924	29	1
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	465,842,415	416,744,128	2,665,685	2,584,095	249,483	244,944
11	SalesForResaleAbstract (447) Sales for Resale	2,580,366	1,481,406	56,023	55,341	9	5
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	468,422,781	418,225,534	2,721,708	2,639,436	249,492	244,949
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	468,422,781	418,225,534	2,721,708	2,639,436	249,492	244,949
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	2,141	849,251
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	5,955	197,227
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	6,350,095	6,051,787
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(b) 133,912,465	121,089,541
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	15,081,661	5,374,386
23	RegionalTransmissionServiceRevenues (457.1) Regional Control Service Revenues
24	MiscellaneousRevenue (457.2) Miscellaneous Revenues
25	OtherMiscellaneousOperatingRevenues Other Miscellaneous Operating Revenues
26	OtherOperatingRevenues TOTAL Other Operating Revenues	155,348,035	133,562,192
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	623,770,816	551,787,726
Line12, column (b) includes $ 1,044,061 of unbilled revenues.
Line12, column (d) includes 41,634 MWH relating to unbilled revenues

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: ResidentialSales

There is additional residential revenue billed of $123,348,275 for the fuel adjustment clause.

(b) Concept: OtherElectricRevenue


FERC 456 Other Electric Revenues
			Year to date

Delivery Revenues Retail Access Customers 1			112,561,253
Alternative Revenue Programs (ARP) 2			25,207,930
Other Revenue Adjustments 3			(3,856,718)
Total Other Electric Revenues			133,912,465

1 In accordance with Case 94-00952, revenues earned for the distribution of electricity provided by Energy Service Companies "ESCOs" are recorded in accounts 456.

2 As established in Case 03-E-0640, et al., "Proceeding on Motion of the Commission to Investigate Potential Electric Delivery Rate Disincentives Against the Promotion of Energy Efficiency, Renewable Technologies and Distributed Generation, Order Requiring Proposals For Revenue Decoupling Mechanisms", issued April 20, 2007 and adopted by Central Hudson in Case 08-E-0887 is recorded in account 456 as well as several incentives earned when the company meets certain targets as prescribed in the Rate Orders.

3 Other revenue adjustments represents changes to regulatory deferral balances to reverse the impact of refunds/ (collections) of previously recognized deferrals and Negative Revenue Adjustments (“NRAs”) pursuant to PSC Orders.

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

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

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41	TOTAL Billed Residential Sales	1,807,174	339,501,467	215,501	8,386	0.1879
42	TOTAL Unbilled Rev. (See Instr. 6)	22,053	552,012			0.0250
43	TOTAL	1,829,227	(a) 338,949,455	215,501	8,488	0.1853

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: ResidentialSales

There is additional residential revenue billed of $123,348,275 for the fuel adjustment clause.

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41	TOTAL Billed Small or Commercial	596,488	93,484,100	31,006	19,238	0.1567
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)	19,581	1,596,073			0.0815
43	TOTAL Small or Commercial	616,069	95,080,173	31,006	19,869	0.1543

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41	TOTAL Billed Large (or Ind.) Sales	66,720	8,254,479	612	109,020	0.1237
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)
43	TOTAL Large (or Ind.)	66,720	8,254,479	612	109,020	0.1237

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41	TOTAL Billed Commercial and Industrial Sales
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41	TOTAL Billed Public Street and Highway Lighting	11,369	5,776,187	291	39,069	0.5081
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL	11,369	5,776,187	291	39,069	0.5081

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41	TOTAL Billed Other Sales to Public Authorities	141,345	17,723,598	2,044	69,151	0.1254
42	TOTAL Unbilled Rev. (See Instr. 6)	0	0
43	TOTAL	141,345	17,723,598	2,044	69,151	0.1254

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41	TOTAL Billed Interdepartmental Sales	955	58,523	29	32,931	0.0613
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL	955	58,523	29	32,931	0.0613

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
41	TOTAL Billed - All Accounts	2,624,051	464,798,354	249,483	10,518	0.1771
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts	41,634	1,044,061			0.0251
43	TOTAL - All Accounts	2,665,685	465,842,415	249,483	10,685	0.1748

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

SALES FOR RESALE (Account 447)
Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326). Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (g) through (k). In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,line 24. Footnote entries as required and provide explanations following all required data.
					ACTUAL DEMAND (MW)			REVENUE
Line No.	Name of Company or Public Authority (Footnote Affiliations) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Average Monthly Billing Demand (MW) (d)	Average Monthly NCP Demand (e)	Average Monthly CP Demand (f)	Megawatt Hours Sold (g)	Demand Charges ($) (h)	Energy Charges ($) (i)	Other Charges ($) (j)	Total ($) (h+i+j) (k)
1	New York State Electric and Gas- Bord	RQ	3				3,698	0	340,989		340,989
2	Orange and Rockland - Borderline	RQ	4				386	0	7,713		7,713
3	Orange and Rockland	RQ	32				0	0	0
4	New York State Electric & Gas	RQ					0	0	0
5	National Grid- Borderline	RQ	27				323	0	6,617		6,617
6	New York ISO	RQ					51,616	0	2,191,434		2,191,434
7	Power Authority State of New York	RQ	65						18,944		18,944
8	New York Power Authority	SF							14,669		14,669
15	Subtotal - RQ						56,023		2,565,697		2,565,697
16	Subtotal-Non-RQ								14,669		14,669
17	Total						56,023		2,580,366		2,580,366

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line No.	Account (a)	Amount for Current Year (b)	Amount for Previous Year (c) (c)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION EXPENSES
2	SteamPowerGenerationAbstract A. Steam Power Generation
3	SteamPowerGenerationOperationAbstract Operation
4	OperationSupervisionAndEngineeringSteamPowerGeneration (500) Operation Supervision and Engineering
5	FuelSteamPowerGeneration (501) Fuel
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses
11	RentsSteamPowerGeneration (507) Rents
12	Allowances (509) Allowances
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)
22	NuclearPowerGenerationAbstract B. Nuclear Power Generation
23	NuclearPowerGenerationOperationAbstract Operation
24	OperationSupervisionAndEngineeringNuclearPowerGeneration (517) Operation Supervision and Engineering
25	NuclearFuelExpense (518) Fuel
26	CoolantsAndWater (519) Coolants and Water
27	SteamExpensesNuclearPowerGeneration (520) Steam Expenses
28	SteamFromOtherSourcesNuclearPowerGeneration (521) Steam from Other Sources
29	SteamTransferredCreditNuclearPowerGeneration (Less) (522) Steam Transferred-Cr.
30	ElectricExpensesNuclearPowerGeneration (523) Electric Expenses
31	MiscellaneousNuclearPowerExpenses (524) Miscellaneous Nuclear Power Expenses
32	RentsNuclearPowerGeneration (525) Rents
33	NuclearPowerGenerationOperationsExpense TOTAL Operation (Enter Total of lines 24 thru 32)
34	NuclearPowerGenerationMaintenanceAbstract Maintenance
35	MaintenanceSupervisionAndEngineeringNuclearPowerGeneration (528) Maintenance Supervision and Engineering
36	MaintenanceOfStructuresNuclearPowerGeneration (529) Maintenance of Structures
37	MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration (530) Maintenance of Reactor Plant Equipment
38	MaintenanceOfElectricPlantNuclearPowerGeneration (531) Maintenance of Electric Plant
39	MaintenanceOfMiscellaneousNuclearPlant (532) Maintenance of Miscellaneous Nuclear Plant
40	NuclearPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 35 thru 39)
41	PowerProductionExpensesNuclearPower TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)
42	HydraulicPowerGenerationAbstract C. Hydraulic Power Generation
43	HydraulicPowerGenerationOperationAbstract Operation
44	OperationSupervisionAndEngineeringHydraulicPowerGeneration (535) Operation Supervision and Engineering
45	WaterForPower (536) Water for Power
46	HydraulicExpenses (537) Hydraulic Expenses		4,154
47	ElectricExpensesHydraulicPowerGeneration (538) Electric Expenses	139,105	115,250
48	MiscellaneousHydraulicPowerGenerationExpenses (539) Miscellaneous Hydraulic Power Generation Expenses	32,285	96,949
49	RentsHydraulicPowerGeneration (540) Rents
50	HydraulicPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 44 thru 49)	171,390	216,353
51	HydraulicPowerGenerationContinuedAbstract C. Hydraulic Power Generation (Continued)
52	HydraulicPowerGenerationMaintenanceAbstract Maintenance
53	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration (541) Mainentance Supervision and Engineering		236
54	MaintenanceOfStructuresHydraulicPowerGeneration (542) Maintenance of Structures	174,763	22,501
55	MaintenanceOfReservoirsDamsAndWaterways (543) Maintenance of Reservoirs, Dams, and Waterways	77,865	64,912
56	MaintenanceOfElectricPlantHydraulicPowerGeneration (544) Maintenance of Electric Plant	267,009	425,444
57	MaintenanceOfMiscellaneousHydraulicPlant (545) Maintenance of Miscellaneous Hydraulic Plant	174,092	138,869
58	HydraulicPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 53 thru 57)	693,729	651,962
59	PowerProductionExpensesHydraulicPower TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)	865,119	868,315
60	OtherPowerGenerationAbstract D. Other Power Generation
61	OtherPowerGenerationOperationAbstract Operation
62	OperationSupervisionAndEngineeringOtherPowerGeneration (546) Operation Supervision and Engineering		600
63	Fuel (547) Fuel	178,582	72,963
64	GenerationExpenses (548) Generation Expenses	28,822	22,300
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses	948	727
66	RentsOtherPowerGeneration (550) Rents
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	208,352	96,590
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering	37,140	37,637
70	MaintenanceOfStructures (552) Maintenance of Structures	877	1,873
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant	22,318	61,327
71.1	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration (553.1) Maintenance of Energy Storage Equipment
72	MaintenanceOfMiscellaneousOtherPowerGenerationPlant (554) Maintenance of Miscellaneous Other Power Generation Plant	53,435	52,376
73	OtherPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 69 thru 72)	113,770	153,213
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	322,122	249,803
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	176,425,221	133,918,411
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	0
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	3,470,211	3,583,773
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	11,522	16,140
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	179,906,954	137,518,324
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	181,094,195	138,636,442
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	839,309	930,656
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability	118,119	104,040
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	116
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development
90	TransmissionServiceStudies (561.6) Transmission Service Studies
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies	37,306	68,271
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services
93	StationExpensesTransmissionExpense (562) Station Expenses	730,307	742,561
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	382,745	398,119
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	2,191,404	2,192,074
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	1,037,402	1,023,600
98	RentsTransmissionElectricExpense (567) Rents	1,090,232	1,124,525
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	6,426,940	6,583,846
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	251,586	355,284
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	1,935	2,393
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	483,642	495,746
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	609,295	489,200
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	2,303,094	1,295,919
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	3,890,628	3,767,598
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	7,540,180	6,406,140
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	13,967,120	12,989,986
113	RegionalMarketExpensesAbstract 3. REGIONAL MARKET EXPENSES
114	RegionalMarketExpensesOperationAbstract Operation
115	OperationSupervision (575.1) Operation Supervision
116	DayAheadAndRealTimeMarketAdministration (575.2) Day-Ahead and Real-Time Market Facilitation
117	TransmissionRightsMarketAdministration (575.3) Transmission Rights Market Facilitation
118	CapacityMarketAdministration (575.4) Capacity Market Facilitation
119	AncillaryServicesMarketAdministration (575.5) Ancillary Services Market Facilitation
120	MarketMonitoringAndCompliance (575.6) Market Monitoring and Compliance
121	MarketFacilitationMonitoringAndComplianceServices (575.7) Market Facilitation, Monitoring and Compliance Services
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)
124	RegionalMarketExpensesMaintenanceAbstract Maintenance
125	MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses (576.1) Maintenance of Structures and Improvements
126	MaintenanceOfComputerHardware (576.2) Maintenance of Computer Hardware
127	MaintenanceOfComputerSoftware (576.3) Maintenance of Computer Software
128	MaintenanceOfCommunicationEquipmentRegionalMarketExpenses (576.4) Maintenance of Communication Equipment
129	MaintenanceOfMiscellaneousMarketOperationPlant (576.5) Maintenance of Miscellaneous Market Operation Plant
130	RegionalMarketMaintenanceExpense Total Maintenance (Lines 125 thru 129)
131	RegionalMarketExpenses TOTAL Regional Transmission and Market Operation Expenses (Enter Total of Lines 123 and 130)
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	2,893,940	2,662,502
135	LoadDispatching (581) Load Dispatching		2,733
136	StationExpensesDistribution (582) Station Expenses	321,029	316,651
137	OverheadLineExpenses (583) Overhead Line Expenses	21,976,062	19,766,401
138	UndergroundLineExpenses (584) Underground Line Expenses	1,275,290	1,020,367
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses
140	MeterExpenses (586) Meter Expenses	1,778,422	1,909,063
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	1,467,490	1,287,619
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	9,347,357	9,312,379
143	RentsDistributionExpense (589) Rents	553,707	504,218
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	39,613,297	36,776,467
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	1,881	25,081
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	607,414	985,076
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	39,709,443	37,364,892
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	1,177,150	973,203
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	515,826	431,626
153	MaintenanceOfMeters (597) Maintenance of Meters
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	2,104	2,943
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	42,013,818	39,782,821
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	81,627,115	76,559,288
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision
160	MeterReadingExpenses (902) Meter Reading Expenses	2,588,878	2,501,188
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	14,936,381	15,253,750
162	UncollectibleAccounts (904) Uncollectible Accounts	4,675,121	7,671,662
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	964,678	904,792
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	23,165,058	26,331,392
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	58,227,604	50,859,971
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses	244,984	181,924
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	1,532,720	1,318,862
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	60,005,308	52,360,757
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses		708
176	AdvertisingExpenses (913) Advertising Expenses
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)		708
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	26,895,102	26,351,241
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	7,095,144	7,844,590
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit
184	OutsideServicesEmployed (923) Outside Services Employed	6,591,415	3,712,085
185	PropertyInsurance (924) Property Insurance	879,864	675,929
186	InjuriesAndDamages (925) Injuries and Damages	3,003,852	3,500,088
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	4,373,121	5,889,017
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	1,747,704	1,843,663
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	14,568,916	15,192,244
193	RentsAdministrativeAndGeneralExpense (931) Rents	215,730	224,977
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	65,370,848	65,233,834
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	1,699,105	1,735,407
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	67,069,953	66,969,241
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	426,928,749	373,847,814

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

PURCHASED POWER (Account 555)
Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatthours shown on bills rendered to the respondent, excluding purchases for energy storage. Report in column (h) the megawatthours shown on bills rendered to the respondent for energy storage purchases. Report in columns (i) and (j) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. Report demand charges in column (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m). Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. The data in columns (g) through (n) must be totaled on the last line of the schedule. The total amount in columns (g) and (h) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13. Footnote entries as required and provide explanations following all required data.
					Actual Demand (MW)				POWER EXCHANGES		COST/SETTLEMENT OF POWER
Line No.	NameOfCompanyOrPublicAuthorityProvidingPurchasedPower Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	RateScheduleTariffNumber Ferc Rate Schedule or Tariff Number (c)	AverageMonthlyBillingDemand Average Monthly Billing Demand (MW) (d)	AverageMonthlyNonCoincidentPeakDemand Average Monthly NCP Demand (e)	AverageMonthlyCoincidentPeakDemand Average Monthly CP Demand (f)	MegawattHoursPurchasedOtherThanStorage MegaWatt Hours Purchased (Excluding for Energy Storage) (g)	MegawattHoursPurchasedForEnergyStorage MegaWatt Hours Purchased for Energy Storage (h)	EnergyReceivedThroughPowerExchanges MegaWatt Hours Received (i)	EnergyDeliveredThroughPowerExchanges MegaWatt Hours Delivered (j)	DemandChargesOfPurchasedPower Demand Charges ($) (k)	EnergyChargesOfPurchasedPower Energy Charges ($) (l)	OtherChargesOfPurchasedPower Other Charges ($) (m)	SettlementOfPower Total (k+l+m) of Settlement ($) (n)
1	Nonassociated Utilities:		(1)
2	NYSE&G Corp.	SF
3	NYSE&G Borderlines	RQ					3,272					285,833		285,833
4	Niagara Mohawk Power Corp.	SF
5	National Grid Borderlines	RQ					101					11,861		11,861
6	Orange & Rockland Util., Inc.	SF					11					1,965		1,965
7	Orange & Rockland Borderlines	RQ					5					182		182
8	Other Public Authorities:
9	Power Authority State of NY:	RQ
10	Gilboa	LF
11	Other-Rock Tavern	SF
12	MDA's	SF
13	Power Brokers:
14	Entergy Nuclear Fitzpatrick	OS
15	Cargill	OS
16	BP Energy	OS
17	CCI Caselton ICAP	OS										8,933,000		8,933,000
18	Constellation Power	OS
19	Danskammer Energy	OS
20	NRG	OS										456,000		456,000
21	Mirant/Southern Company	OS
22	Power Brokers (cont)
23	Noble Americas	OS
24	Citigroup Energy	OS
25	Constellation New Energy	OS
26	NYISO	OS					2,726,857					141,217,208		141,217,208
27	Axpo US	OS										775,486		775,486
28	PSEG	OS										1,028,163		1,028,163
29	CPV Valley LLC	OS										4,399,215		4,399,215
30	Shell Energy North America	OS										5,725,457		5,725,457
31	Exelon Icap	OS										1,238,866		1,238,866
32	Citadel Weather Options	OS										300,000		300,000
33	Consolidated Energy Service	OS
34	TFS Energy	OS										16,425		16,425
35	Brookfield Power	OS										170,000		170,000
36	Power Brokers (cont)	OS
37	GFI Brokers	OS
38	Hess	OS
39	Select Energy	OS
40	Trident Brokerage	OS
41	DB Energy Trading	OS
42	IDT Energy Inc	OS
43	Southwest Business Solutions	OS
44	Munich Re											547,500		547,500
45	Merrill Lynch	OS
46	JP Morgan	OS
47	BP Northamerica	OS
48	Mercuria	OS										6,670,000		6,670,000
49	IPP Net Metering	OS					50,239					5,184,095		5,184,095
50	Other Nonutilties (Cont'd)	OS
51	CCI Roseton	OS					42					2,529		2,529
52	Windsor Machinery	OS					8,021					481,249		481,249
53	Rivers Elec. (Mill Pond Hydro)	OS					1,974					120,219		120,219
54	Salisbury Hydro	OS					1,211					72,655		72,655
55	Montgomery Worsted Mills	OS
56	Hydro Tech	OS
57	Dutchess Co. Resourse Recovery	OS					40,310					2,418,616		2,418,616
58	Joshua Levine	OS
59	Zero Emissions											11,674,994		11,674,994
60	Renewable Energy Credits											2,367,922		2,367,922
61	Value Stack						84,974					6,110,629		6,110,629
62	Cost of Purch Elec Degerred-Net(2)												12,963,974	12,963,974
15	TOTAL						2,917,017					189,389,195	12,963,974	176,425,221

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

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

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

TRANSFER OF ENERGY

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

1

NYS Electric & Gas Corp.

LFP

26

Pleasant Valley

Woodbourne

2

"

LFP

22

Pleasant Valley

Fishkill Plains

478,265

50,829

3

"

LFP

49

Sugarloaf

Walden

88,553

98,328

4

"

LFP

26

Sugarloaf

Smithfield

12,497

13,747

5

New York Power Authority

"

New York Power Authority

LFP

51

Leeds

Sugarloaf (Gilboa)

75,240

6

NY ISO

New York ISO

LFP

51

Ashokan

Sugarloaf

14,843,517

35

TOTAL

579,315

15,081,661

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

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

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. Enter ""TOTAL"" in column (a) as the last line. Footnote entries and provide explanations following all required data.
			TRANSFER OF ENERGY		EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.	NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	TransmissionOfElectricityByOthersEnergyReceived MegaWatt Hours Received (c)	TransmissionOfElectricityByOthersEnergyDelivered MegaWatt Hours Delivered (d)	DemandChargesTransmissionOfElectricityByOthers Demand Charges ($) (e)	EnergyChargesTransmissionOfElectricityByOthers Energy Charges ($) (f)	OtherChargesTransmissionOfElectricityByOthers Other Charges ($) (g)	ChargesForTransmissionOfElectricityByOthers Total Cost of Transmission ($) (h)
1	Received Power from
2	Wheeler		0	0	0	0	0	0
3	NY State Electric & Gas	FNS	28,984	28,984	0	16,272	(a) 228	16,044
4	National Grid	OLF	0	0	0	2,175,360	0	2,175,360
	TOTAL		28,984	28,984	0	2,191,632	228	2,191,404

FOOTNOTE DATA

(a) Concept: OtherChargesTransmissionOfElectricityByOthers

(g) net accrual estimate vs actual

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.	Description (a)	Amount (b)
1	IndustryAssociationDues Industry Association Dues	140,997
2	NuclearPowerResearchExpenses Nuclear Power Research Expenses
3	OtherExperimentalAndGeneralResearchExpenses Other Experimental and General Research Expenses	1,519,102
4	PublicationAndDistributionExpensesForSecuritiesToStockholders Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities
5	OtherMiscellaneousGeneralExpenses Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
6	Dutchess County Local Development	12,000
7	Orange County Partnership	12,000
8	0
9	Other:
10	Civic Community Activities	167,855
11	MGP Site Rate Allowance	6,670,300
12	Training - Project Phoenix	888,041
13	Waiver of Reconnection Fee - Deferral - Electric	41,492
14	Def Over/Under Low Income Arrears Forgiveness & Bill Crd	486,291
15	News Media Information	25,845
16	Pollution Control Fees & Service Charges	17,977
17	Employee Awards	78,107
18	CEHG Directors' Fees	579,323
19	Administrative & General Costs Allocated - CHEG	2,848,824
20	Recruiting Expense	92,607
21	Pre-Employement Physicals	13,864
22	Employee Training Costs	240,726
23	Bank Trustee Fees	7,942
24	Rating Agency Fees	170,371
25	Other Debt Admin Costs	21,568
26	Bank Fees	140,838
27	Revolving Credit Agreement	292,010
28	Accrued Payroll Oper	62,000
29	EEI - Utility Solid Waste Act Group	7,377
30	Regulatory Permit Fees	16,224
31	Minor Items and Company Charges	15,235
46	MiscellaneousGeneralExpenses TOTAL	14,568,916

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403); (c) Depreciation Expense for Asset Retirement Costs (Account 403.1); (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405). Report in Section B the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year. Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used. In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used. For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification listed in column (a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type of mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related.
	A. Summary of Depreciation and Amortization Charges
Line No.	FunctionalClassificationAxis Functional Classification (a)	DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments Depreciation Expense (Account 403) (b)	DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	AmortizationOfLimitedTermPlantOrProperty Amortization of Limited Term Electric Plant (Account 404) (d)	AmortizationOfOtherElectricPlant Amortization of Other Electric Plant (Acc 405) (e)	DepreciationAndAmortization Total (f)
1	Intangible Plant	0	0	0	0
2	Steam Production Plant	0	0	0	0
3	Nuclear Production Plant	0	0	0	0
4	Hydraulic Production Plant-Conventional	689,707	0	0	0	689,707
5	Hydraulic Production Plant-Pumped Storage	0	0	0	0
6	Other Production Plant	111,364	0	0	0	111,364
7	Transmission Plant	10,129,963	0	69,031	0	10,198,994
8	Distribution Plant	26,464,717	0	0	0	26,464,717
9	Regional Transmission and Market Operation	0	0	0	0
10	General Plant	142,619	0	0	0	142,619
11	Common Plant-Electric	6,725,987	0	0	11,446,162	18,172,149
12	TOTAL	44,264,357		69,031	11,446,162	55,779,550

B. Basis for Amortization Charges

	C. Factors Used in Estimating Depreciation Charges
Line No.	AccountNumberFactorsUsedInEstimatingDepreciationCharges Account No. (a)	DepreciablePlantBase Depreciable Plant Base (in Thousands) (b)	UtilityPlantEstimatedAverageServiceLife Estimated Avg. Service Life (c)	UtilityPlantNetSalvageValuePercentage Net Salvage (Percent) (d)	UtilityPlantAppliedDepreciationRate Applied Depr. Rates (Percent) (e)	MortalityCurveType Mortality Curve Type (f)	UtilityPlantWeightedAverageRemainingLife Average Remaining Life (g)
12	331	3,442	95 years	50	2	R2	75 years, 6 months, 3 days
13	332	22,568	90 years	40	2	R3	66 years, 10 months, 28 days
14	333	10,827	80 years	60	2	R2.5	63 years, 7 months, 21 days
15	334	1,739	55 years	45	3	S0	11 years, 9 months, 25 days
16	335	181	50 years	20	2	S1.5	32 years, 22 days
17	341	446	55 years	15	2	R4	19 years, 2 months, 1 day
18	342	863	55 years	15	2	R5	32 years, 6 months, 18 days
19	343	1,439	25 years	10	4	R4	8 years, 9 months, 7 days
20	344	872	40 years	10	3	R2	11 years, 9 months, 25 days
21	345	508	35 years	20	3	R2.5	16 years
22	346	43	35 years		3	S2.5	14 years, 5 months, 16 days
23	Subtotal	42,928
24	352	16,050	80 years	15	1	R3	66 years, 2 months, 12 days
25	353-11	130,997	52 years	20	2	R1.5	38 years, 15 days
26	353-12	3,079	32 years	20	4	L1.5	18 years, 7 months, 10 days
27	353-20	8,012	40 years	20	3	S0	30 years, 3 months, 8 days
28	353-30	2,147	30 years	20	4	S2	21 years, 8 months, 16 days
29	361	20,840	80 years	20	2	R3	66 years, 4 months, 13 days
30	362-11	175,523	54 years	25	2	S0.5	41 years, 3 months, 19 days
31	362-12	3,095	30 years	25	4	S0.5	20 years, 5 months, 27 days
32	362-20	2,185	44 years	25	3	S1.5	28 years, 11 months, 1 day
33	362-30	2,205	30 years	25	4	S0	25 years
34	Subtotal	364,133
35	350-11-15	16,821	90 years		1	R4	69 years, 18 days
36	350-13	12	80 years		1	R4	0 years
37	354	3,020	80 years	30	2	R3	38 years, 4 months, 9 days
38	355-10-15	158,917	52 years	50	3	R2	45 years, 8 months, 9 days
39	356-10	74,260	70 years	35	2	R1.5	59 years, 3 months, 22 days
40	356-15	5,702	65 years	40	2	R2	42 years, 9 months, 18 days
41	356-20-25	1,952	70 years	40	2	R3	25 years, 11 months, 26 days
42	357	21	41 years		2	R0.5	13 years, 5 months, 23 days
43	358	9,064	55 years	5		R3	29 years, 5 months, 23 days
44	Subtotal	269,769
45	360-11-22	872	80 years	0	1.25	S4	33 years, 2 months, 23 days
46	360-13-23	6	70 years	0	1.43	S3	12 years, 4 months, 13 days
47	364	313,728	56 years	40	2.5	R0.5	48 years, 8 months, 12 days
48	365-10-20	253,307	70 years	40	2	R0.5	59 years, 8 months, 26 days
49	366-11-22	44,291	80 years	10	1.38	R4	58 years, 3 months, 19 days
50	367-22	73,659	75 years	15	1.53	R3	50 years, 11 months, 15 days
51	368-17	141,512	42 years	15	2.74	S0	30 years, 4 months, 20 days
52	369-10	39,776	65 years	65	2.54	R2	45 years, 8 months, 9 days
53	369-21-22	14,095	65 years	10	1.69	R2	48 years, 3 months, 22 days
54	370	49,394	33 years	0	3.03	L0.5	24 years, 4 months, 6 days
55	371-10-22	7,858	24 years	20	5	R0.5	16 years, 7 months, 21 days
56	372	279	8 years	0	12.5	L1.5	10 months, 28 days
57	373	16,420	30 years	10	3.67	O1	19 years, 3 months, 4 days
58	Subtotal	955,197
59	390	4,226	40 years	30	3.25	R0.5	34 years, 2 months, 5 days
60	Subtotal	4,226
61	(a) Total	1,636,253

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: AccountNumberFactorsUsedInEstimatingDepreciationCharges


Schedule Page: 336.1 Line No.: 61 Column: a


Central Hudson Gas & Electric Corporation

Plant included in Subaccounts
	353-11	Transmission Station Equipment - In Use
	353-12	Transmission Supervisory Equipment
	353-20	Transmission Station Equipment - Held for Re-Use
	362-11	Distribution Station Equipment - In Use
	362-12	Distribution Supervisory Equipment
	362-20	Distribution Station Equipment - Held for Re-Use
	350-11	Transmission Land and Land Rights - Other than 345KV Lines
	350-15	Transmission Land and Land Rights - 345KV Lines
	356-10	Transmission Overhead Conductors and Devices - Other than 345KV Lines
	356-15	Transmission Overhead Conductors and Devices - 345KV Lines
	356-20	Transmission Line Clearing - Other than 345KV Lines
	356-25	Transmission Line Clearing - 345KV Lines
	369-10	Distribution Services - Overhead
	369-20	Distribution Services - Underground

Note:	Depreciation Factors and Rates effective 7/1/22 in accordance with Rate Case 20-E-0428/G-0429

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

REGULATORY COMMISSION EXPENSES

Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years.
Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
List in columns (f), (g), and (h), expenses incurred during the year which were charged currently to income, plant, or other accounts.
Minor items (less than $25,000) may be grouped.

EXPENSES INCURRED DURING YEAR

AMORTIZED DURING YEAR

CURRENTLY CHARGED TO

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

1

New York Public Service Commission:

2

0

3

Costs of expense ofthe New York State Public

2,191,928

Electric

928

1,747,704

4

Service commission in accordance with

Gas

928

444,224

5

assessment as provided under Section 18A of

6

the Public Service Law

46

TOTAL

2,191,928

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D and D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts). Indicate in column (a) the applicable classification, as shown below: Classifications: Electric R, D and D Performed Internally: Generation hydroelectric Recreation fish and wildlife Other hydroelectric Fossil-fuel steam Internal combustion or gas turbine Nuclear Unconventional generation Siting and heat rejection Transmission Overhead Underground Distribution Regional Transmission and Market Operation Environment (other than equipment) Other (Classify and include items in excess of $50,000.) Total Cost Incurred Electric, R, D and D Performed Externally: Research Support to the electrical Research Council or the Electric Power Research Institute Research Support to Edison Electric Institute Research Support to Nuclear Power Groups Research Support to Others (Classify) Total Cost Incurred Include in column (c) all R, D and D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D and D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D and D activity. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e). Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year. If costs have not been segregated for R, D and D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by ""Est."" Report separately research and related testing facilities operated by the respondent.
					AMOUNTS CHARGED IN CURRENT YEAR
Line No.	ResearchDevelopmentAndDemonstrationClassification Classification (a)	ResearchDevelopmentAndDemonstrationDescription Description (b)	ResearchDevelopmentAndDemonstrationCostsIncurredInternally Costs Incurred Internally Current Year (c)	ResearchDevelopmentAndDemonstrationCostsIncurredExternally Costs Incurred Externally Current Year (d)	AccountNumberForResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Account (e)	ResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Amount (f)	ResearchDevelopmentAndDemonstrationExpenditures Unamortized Accumulation (g)
1	I. ELECTRIC UTILITY
2	A. R&D Performed Internally
3	1. System Planning
4		R&D Admin - Labor	38,288		920	38,288
5		R&D Admin - Supplies & Expense	5,791		921	5,791
6	2. Transmission
7		Smartwires Pilot	1,375		566	1,375
8		GIC Monitoring of the S1 Transformer	942		566	942
9		CEATI - Transmission Design Support	1,656		566	1,656
10	3. Distribution
11		A2V Network	459		588	459
12		PMI Voltage Sensors	850		588	850
13		Automated Interconnection Assessment	30,286		588	30,286
14		Mapping Modernization Transformation	3,208		588	3,208
15		Project Channel Tier 1 Network Strat Com	178		588	178
16		EPRI NY Load Mangment & Electricficatio	65,000		588	65,000
17		Cascade and Scada Analytics POC	262,448		588	262,448
18		EPRI DMs & Control Demonstration	110,789		588	110,789
19		EVAL DIST Automation Tech- Improv SCV Rel	26,558		588	26,558
20		UG SEC Network Comm	15,706		588	15,706
21		EPRI Low Carbon Research Intiative	100,000		588	100,000
22	5. Environment
23		EPRI CHGE ENV, Social and GOV PRI Assess	23,874		930	23,874
24	6. Other - Customer Service
25		DMR Pliot Porject	524		910	524
26		RPA Solutions	39,073		910	39,073
27		ChatBOT	530,802		910	530,802
28		IT Strategic Research	493,204		910	493,204
29	B. R&D Performed (Externally)
30	1. Research Support to Elec Pwr Research Insti			1,053,055	930	1,053,055
31		EPRI Advisory Committee Expense	17		921	17
32	4. Research Support to Others
33		Committees - Support (EPRI Advisory Comm. Labor)	28,572		920	28,572
34		New York State - ERDA (NYSERDA)	432,173		930	432,173
35		Membership Dues and Contributions	10,000		930	10,000
36		Deferred Balance			188		484,328
37	Miscellaneous
38		Expenses - Gen. Office Employees	15		921	15
39	TOTAL ELECTRIC UTILITY		2,210,206	1,053,055		3,263,261	484,328

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used.
Line No.	Classification (a)	Direct Payroll Distribution (b)	Allocation of Payroll Charged for Clearing Accounts (c)	Total (d)
1	SalariesAndWagesElectricAbstract Electric
2	SalariesAndWagesElectricOperationAbstract Operation
3	SalariesAndWagesElectricOperationProduction Production	166,619
4	SalariesAndWagesElectricOperationTransmission Transmission	2,466,075
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	17,222,957
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	6,453,700
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	764,836
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	29,513,412
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	56,587,599
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	3,470,086
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	2,014,526
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	10,813,804
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	600,295
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	16,898,711
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	3,636,705
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	4,480,601
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	28,036,761
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	6,453,700
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	764,836
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	30,113,707
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	73,486,310	3,082,418	76,568,728
29	SalariesAndWagesGasAbstract Gas
30	SalariesAndWagesGasOperationAbstract Operation
31	SalariesAndWagesGasOperationProductionManufacturedGas Production - Manufactured Gas	126
32	SalariesAndWagesGasOperationProductionNaturalGas Production-Nat. Gas (Including Expl. And Dev.)
33	SalariesAndWagesGasOperationOtherGasSupply Other Gas Supply	249,630
34	SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing Storage, LNG Terminaling and Processing
35	SalariesAndWagesGasOperationTransmission Transmission	961,812
36	SalariesAndWagesGasOperationDistribution Distribution	6,068,243
37	SalariesAndWagesGasCustomerAccounts Customer Accounts	1,603,620
38	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational	437,770
39	SalariesAndWagesGasSales Sales
40	SalariesAndWagesGasOperationAdministrativeAndGeneral Administrative and General	7,964,748
41	SalariesAndWagesGasOperation TOTAL Operation (Enter Total of lines 31 thru 40)	17,285,949
42	SalariesAndWagesGasMaintenanceAbstract Maintenance
43	SalariesAndWagesGasMaintenanceProductionManufacturedGas Production - Manufactured Gas	14,535
44	SalariesAndWagesGasMaintenanceProductionNaturalGas Production-Natural Gas (Including Exploration and Development)
45	SalariesAndWagesGasMaintenanceOtherGasSupply Other Gas Supply
46	SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing
47	SalariesAndWagesGasMaintenanceTransmission Transmission	241,685
48	SalariesAndWagesGasMaintenanceDistribution Distribution	3,336,370
49	SalariesAndWagesGasMaintenanceAdministrativeAndGeneral Administrative and General	149,146
50	SalariesAndWagesGasMaintenance TOTAL Maint. (Enter Total of lines 43 thru 49)	3,741,736
51	SalariesAndWagesGasOperationAndMaintenanceAbstract Total Operation and Maintenance
52	SalariesAndWagesGasProductionManufacturedGas Production-Manufactured Gas (Enter Total of lines 31 and 43)	14,661
53	SalariesAndWagesGasProductionNaturalGas Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54	SalariesAndWagesGasOtherGasSupply Other Gas Supply (Enter Total of lines 33 and 45)	249,630
55	SalariesAndWagesGasStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing (Total of lines 31 thru
56	SalariesAndWagesGasTransmission Transmission (Lines 35 and 47)	1,203,497
57	SalariesAndWagesGasDistribution Distribution (Lines 36 and 48)	9,404,613
58	SalariesAndWagesGasCustomerAccounts Customer Accounts (Line 37)	1,603,620
59	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational (Line 38)	437,770
60	SalariesAndWagesGasSales Sales (Line 39)
61	SalariesAndWagesGasAdministrativeAndGeneral Administrative and General (Lines 40 and 49)	8,113,894
62	SalariesAndWagesGasOperationAndMaintenance TOTAL Operation and Maint. (Total of lines 52 thru 61)	21,027,685	1,097,138	22,124,823
63	SalariesAndWagesOtherUtilityDepartmentsAbstract Other Utility Departments
64	SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance Operation and Maintenance
65	SalariesAndWagesOperationsAndMaintenance TOTAL All Utility Dept. (Total of lines 28, 62, and 64)	94,513,995	4,179,556	98,693,551
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	15,975,449	1,656,497	17,631,946
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant	3,946,685	441,991	4,388,676
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):	18,170,960	15,174	18,186,134
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	38,093,094	2,113,662	40,206,756
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	2,069,919	269	2,070,188
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant	265,719	230	265,949
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):	13,887		13,887
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	2,349,525	499	2,350,024
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription Other Accounts (Specify, provide details in footnote):
79	SalariesAndWagesOtherAccountsDescription Miscellaneous Work in Progress	7,490,158		7,490,158
80	SalariesAndWagesOtherAccountsDescription Lost Time	1,211,527		1,211,527
81	SalariesAndWagesOtherAccountsDescription Disability Insurance	44,224		44,224
82	SalariesAndWagesOtherAccountsDescription Miscellaneous Deferred	519,099		519,099
83	SalariesAndWagesOtherAccountsDescription
84	SalariesAndWagesOtherAccountsDescription
85	SalariesAndWagesOtherAccountsDescription
86	SalariesAndWagesOtherAccountsDescription
87	SalariesAndWagesOtherAccountsDescription
88	SalariesAndWagesOtherAccountsDescription
89	SalariesAndWagesOtherAccountsDescription
90	SalariesAndWagesOtherAccountsDescription
91	SalariesAndWagesOtherAccountsDescription
92	SalariesAndWagesOtherAccountsDescription
93	SalariesAndWagesOtherAccountsDescription
94	SalariesAndWagesOtherAccountsDescription
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	9,265,008		9,265,008
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	144,221,622	6,293,717	150,515,339

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

COMMON UTILITY PLANT AND EXPENSES

Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Electric Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used.
Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation.
Give date of approval by the Commission for use of the common utility plant classification and reference to the order of the Commission or other authorization.

COMMON UTILITY PLANT AND EXPENSES

The operations and maintenance expenses not assignable to a particular department and not closely related to any other expenses charged to a particular department were apportioned 80% to the Electric Department and 20% to the Gas Department.

Total Expenses Allocated to Electric & Gas Departments are summarized below:


Total Expenses Allocated to Utility Departments
Account Title	For Year	Electric	Gas

Depreciation & Amortization	16,443,631	13,154,905	3,288,726
Operation & Maintenance Exp.
901 Supervision	—	0	0
902 Meter Reading Expenses	2,816,117	2,252,847	563,270
903 Customer Rec & Collection Exp.	17,728,270	14,182,618	3,545,652
904 Uncollectible Accounts CECL	(132,247)	(105,798)	(26,449)
905 Misc. Customer Accounting Exp.	1,068,998	855,199	213,799

Total Customer Accounting Exp.	21,481,138	17,184,866	4,296,272

908 Customer Assistance Expenses	5,270,435	4,216,310	1,054,125
909 Informational Advertising Exp.	306,228	244,983	61,245
910 Misc. Customer Service Expenses	1,334,089	1,067,274	266,815
912 Demonstrating and Selling Expenses	—	—	—
916 Misc. Sales Promotion Expense	—	—	—

Total Sales & Services Expenses	6,910,752	5,528,567	1,382,185

920 Admin. & General Sales	27,386,775	21,909,219	5,477,556
921 Office Supplies & Expenses	5,602,163	4,481,723	1,120,440
923 Outside Services Employed	5,533,625	4,426,900	1,106,725
924 Property Insurance	4,247	3,398	849
925 Injuries & Damages	378,087	302,468	75,619
926 Employees Pensions & Benefits	2,867,111	2,293,673	573,438
928 Regulatory Commission Expenses	—	—	—
930.2 Miscellaneous General Expenses	6,524,840	5,219,849	1,304,991
931 Rents	283,783	227,027	56,756
932/935 Maintenance of General Plant	1,383,549	1,106,839	276,710

Total Administrative & General	49,964,180	39,971,096	9,993,084
Total Operation & Maintenance	78,356,070	62,684,529	15,671,541
Total Common Utility Expenses	94,799,701	75,839,434	18,960,267


Acct. No.	Item	Beginning Balance	Additions	Retirements	Transfers	Balance
301	Organization	89,000	247,210	—	—	336,210
302	Franchises & Consents	17,950	—	—	—	17,950
303	Miscellaneous Intangible Plant	97,205,873	55,096,753	—	—	152,302,626
	Total Intangible Plant	97,312,823	55,343,963	—	—	152,656,786

	Other (Specify)
	Total Other	0	0	0	0	0

389	Land & Land Rights	5,067,661	—	—	—	5,067,661
390	Structures & Improvements	83,158,495	22,102,113	(1,283,965)	—	103,976,643
391	Office Furniture & Equipment	23,839,457	5,035,625	(2,528,728)	—	26,346,354
392	Transportation Equipment	29,741,716	2,700,725	(2,162,432)	—	30,280,009
393	Stores Equipment	1,088,088	815,786	(408,299)	—	1,495,575
394	Tools, Shop & Garage Equip.	18,806,907	4,197,838	(332,684)	—	22,672,061
395	Laboratory Equip	1,447,355	318,667	(82,560)	—	1,683,462
396	Power Operated Equipment	47,926,308	3,156,564	(2,584,026)	—	48,498,846
397	Communication Equipment	33,882,824	2,551,692	(193,151)	—	36,241,365
398	Misc. Equipment	363,876	—	(3,549)	—	360,327
399	Other Tangible Property	83,823	—	—	—	83,823
	Total General Plant	245,406,510	40,879,010	(9,579,394)	—	276,706,126

	Total Common Utility Plant	342,719,333	96,222,973	(9,579,394)	—	429,362,912

	Depreciation Allocation of Common Items

Construction work in progress Common Utility Plant at December 31, 2021 amounted to $23,025,548 related to the following projects:



Training Academy - CTRL CTR			1,270,184
Training Academy - Development			7,409,005
DMS Phase IV			3,231,593
MINOR PROJECTS (LESS THAN $1,000,000 EACH)			11,114,766
			23,025,548

RESERVE DEPRECIATION OF COMMON UTILITY PLAN

Balance January 1, 2021			134,780,543
Depreciation and Amortization for year charged to:
Depreciation - Electric			6,731,699
Depreciation - Gas			1,682,925
Amortization - Electric			11,365,070
Amortization - Gas			2,841,268
Transportation - Clearing Account			6,170,190

Total Depreciation and Amortization Provisions			28,791,152

Net Charges for Plant Retired:
Book Cost of Plant Retired			9,593,178
Cost of Removal			783,186
Salvage (Credit)			(571,814)

Net Charges for Plant Retired			9,804,550

Other Debit or Credit Items:
Net decrease in Retirement Work in Progress			540,702
Department Transfers of Provision			—
ARO Accumulated Depreciation			—


Balance December 31, 2021			154,307,847

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line No.	Description of Item(s) (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1	Energy
2	Net Purchases (Account 555)	34,289,611	19,826,762	37,361,563	36,416,134
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)	2,007,623	1,369,785	1,986,270	1,054,542
4	Transmission Rights	1,047,878	298,938	92,303	655,054
5	Ancillary Services	1,366,356	791,679	602,626	1,030,755
6	Other Items (list separately)
7	NERC ERO Fees	32,630	40,919	31,206	41,273
8	ICAP Purchases	499,875	3,179,540	4,366,788	2,745,713
9	TCC Congestion Revenues	4,524,342	2,916,758	1,385,815	3,033,802
10	TCC Auction Revenues	90,138	1,290,938	31,572	3,425,804
11	Changes in Working Capital	0	0	0	5,000
12	0	0	0	0	0
46	TOTAL	30,614,247	18,560,357	39,050,829	33,379,781

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff. In columns for usage, report usage-related billing determinant and the unit of measure. On Line 1 columns (b), (c), (d), and (e) report the amount of ancillary services purchased and sold during the year. On Line 2 columns (b), (c), (d), and (e) report the amount of reactive supply and voltage control services purchased and sold during the year. On Line 3 columns (b), (c), (d), and (e) report the amount of regulation and frequency response services purchased and sold during the year. On Line 4 columns (b), (c), (d), and (e) report the amount of energy imbalance services purchased and sold during the year. On Lines 5 and 6, columns (b), (c), (d), and (e) report the amount of operating reserve spinning and supplement services purchased and sold during the period. On Line 7 columns (b), (c), (d), and (e) report the total amount of all other types ancillary services purchased or sold during the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
		Amount Purchased for the Year			Amount Sold for the Year
		Usage - Related Billing Determinant			Usage - Related Billing Determinant
Line No.	Type of Ancillary Service (a)	Number of Units (b)	Unit of Measure (c)	Dollar (d)	Number of Units (e)	Unit of Measure (f)	Dollars (g)
1	Scheduling, System Control and Dispatch		—	2,341,242		—
2	Reactive Supply and Voltage		—	1,337,892		—
3	Regulation and Frequency Response		—	321,236		—	17,216
4	Energy Imbalance		—			—
5	Operating Reserve - Spinning		—	1,637,917		—	171,412
6	Operating Reserve - Supplement		—			—
7	Other	2699231	MWH	(a) 1,875,754	51,514	MWH
8	Total (Lines 1 thru 7)	2,699,231		(b) 3,762,533	51,514		(c) 188,628

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: AncillaryServicesPurchasedAmount

The other amount is made up of NYISO-wide, Local Reliability, Incremental and Demand Response uplift, Residual Adjustments, Supplemental Event Charge and Financial Impact Credits, Local Reliability Black Start Service Charge & Black Start NYCA Component.

(b) Concept: AncillaryServicesPurchasedAmount

The total number of MWH's for ancillary services purchased in 2021 are 2,699,231.

(c) Concept: AncillaryServicesSoldAmount

The total number of MWH's for ancillary services sold in 2021 are 51,514.

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Firm Network Service for Self (e)	Firm Network Service for Others (f)	Long-Term Firm Point-to-point Reservations (g)	Other Long-Term Firm Service (h)	Short-Term Firm Point-to-point Reservation (i)	Other Service (j)
	NAME OF SYSTEM: 0
1	January	841	29	19	413	335		93
2	February	824	1	18	288	443		93
3	March	769	2	19	341	335		93
4	Total for Quarter 1				1,042	1,113	0	279		0
5	April	659	2	21	275	291		93
6	May	878	26	18	505	280		93
7	June	1,148	29	19	693	362		93
8	Total for Quarter 2				1,473	933	0	279		0
9	July	1,028	7	19	549	386		93
10	August	1,122	13	19	627	402		93
11	September	903	15	18	504	306		93
12	Total for Quarter 3				1,680	1,094	0	279		0
13	October	639	15	19	295	251	0	93
14	November	753	29	19	348	312	0	93
15	December	779	20	18	283	403	0	93
16	Total for Quarter 4				926	966	0	279		0
17	Total				5,121	4,106	0	1,116	0	0

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

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

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2022-04-18

Year/Period of Report

End of:

2021

/

Q4

ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line No.	Item (a)	MegaWatt Hours (b)	Line No.	Item (a)	MegaWatt Hours (b)
1	SOURCES OF ENERGY		21	DISPOSITION OF ENERGY
2	Generation (Excluding Station Use):		22	Sales to Ultimate Consumers (Including Interdepartmental Sales)	2,665,685
3	Steam		23	Requirements Sales for Resale (See instruction 4, page 311.)	56,023
4	Nuclear		24	Non-Requirements Sales for Resale (See instruction 4, page 311.)
5	Hydro-Conventional	74,487	25	Energy Furnished Without Charge
6	Hydro-Pumped Storage		26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)	9,876
7	Other	1,057	27	Total Energy Losses	260,977
8	Less Energy for Pumping		27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	75,544	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	2,992,561
10	Purchases (other than for Energy Storage)	2,917,017
10.1	Purchases for Energy Storage
11	Power Exchanges:
12	Received
13	Delivered
14	Net Exchanges (Line 12 minus line 13)	0
15	Transmission For Other (Wheeling)
16	Received	579,315
17	Delivered	579,315
18	Net Transmission for Other (Line 16 minus line 17)	0
19	Transmission By Others Losses
20	TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)	2,992,561

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

MONTHLY PEAKS AND OUTPUT
Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. Report in column (b) by month the system’s output in Megawatt hours for each month. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.	MonthAxis Month (a)	EnergyActivity Total Monthly Energy (b)	NonRequiredSalesForResaleEnergy Monthly Non-Requirement Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak - Megawatts (d)	DayOfMonthlyPeak Monthly Peak - Day of Month (e)	HourOfMonthlyPeak Monthly Peak - Hour (f)
	NAME OF SYSTEM: 0
29	January	249,406	0	841	29	19
30	February	297,543	0	824	1	18
31	March	249,252	0	769	2	19
32	April	209,311	0	659	2	21
33	May	208,250	0	878	26	18
34	June	260,296	0	1,148	29	19
35	July	286,870	0	1,028	7	19
36	August	299,330	0	1,122	13	19
37	September	220,332	0	903	15	18
38	October	186,881	0	639	15	19
39	November	224,894	0	753	29	19
40	December	300,196	0	779	20	18
41	Total	2,992,561	0

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

Steam Electric Generating Plant Statistics

1. Report data for plant in Service only.
2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.
3. Indicate by a footnote any plant leased or operated as a joint facility.
4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.
5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant.
6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.
7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.
8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
9. Items under Cost of Plant are based on USofA accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.
10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants.
11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.
12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.

Line No.	Item (a)	Plant Name: Coxsackie	Plant Name: South Cairo	Plant Name: —
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)	Gas Turbine	Gas Turbine	—
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)	Conventional	Conventional	—
3	YearPlantOriginallyConstructed Year Originally Constructed	1969	1974
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	1969	1974
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)	21.25	21.25
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)	25	23
7	PlantHoursConnectedToLoad Plant Hours Connected to Load	45	18
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)	25	23
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water	25	23
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water
11	PlantAverageNumberOfEmployees Average Number of Employees
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh	792,000	310,000
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights		11,192
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements	206,460	230,497
15	CostOfEquipmentSteamProduction Equipment Costs	1,803,373	1,920,945
16	AssetRetirementCostsSteamProduction Asset Retirement Costs
17	CostOfPlant Total cost (total 13 thru 20)	2,009,833	2,162,634
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including	94.5804	101.7710
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr
20	FuelSteamPowerGeneration Fuel	82,216	91,620
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)
22	SteamExpensesSteamPowerGeneration Steam Expenses
23	SteamFromOtherSources Steam From Other Sources
24	SteamTransferredCredit Steam Transferred (Cr)
25	ElectricExpensesSteamPowerGeneration Electric Expenses
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses
27	RentsSteamPowerGeneration Rents
28	Allowances Allowances
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant
34	PowerProductionExpensesSteamPower Total Production Expenses	82,216	91,620
35	ExpensesPerNetKilowattHour Expenses per Net kWh	0.1038	0.2955

35	FuelKindAxis Plant Name	Coxsackie	South Cairo	—
36	FuelKind Fuel Kind	Gas	Oil	—
37	FuelUnit Fuel Unit	Mcf	bbl	—
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned	9,530	772
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)	1	6
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year	8.627	118.672
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned	8.627	118.672
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	8.371	21.059
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen	0.140	0.296
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation	12,400.000	14,000

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

Hydroelectric Generating Plant Statistics

Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings).
If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number.
If net peak demand for 60 minutes is not available, give that which is available specifying period.
If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant.
The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.

Line No.	Item (a)	FERC Licensed Project No. — Plant Name:	FERC Licensed Project No. — Plant Name: —	FERC Licensed Project No. — Plant Name: Sturgeon Pool
1	PlantKind Kind of Plant (Run-of-River or Storage)	0	—	Storage
2	PlantConstructionType Plant Construction type (Conventional or Outdoor)	0	—	Conventional
3	YearPlantOriginallyConstructed Year Originally Constructed			1924
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed			1924
5	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)			14.4
6	NetPeakDemandOnPlant Net Peak Demand on Plant-Megawatts (60 minutes)			14
7	PlantHoursConnectedToLoad Plant Hours Connect to Load			11,035
8	NetPlantCapabilityAbstract Net Plant Capability (in megawatts)
9	NetPlantCapabilityUnderMostFavorableOperatingConditions (a) Under Most Favorable Oper Conditions			14
10	NetPlantCapabilityUnderMostAdverseOperatingConditions (b) Under the Most Adverse Oper Conditions
11	PlantAverageNumberOfEmployees Average Number of Employees
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh			56,988,000
13	CostOfPlantAbstract Cost of Plant
14	CostOfLandAndLandRightsHydroelectricProduction Land and Land Rights			369,382
15	CostOfStructuresAndImprovementsHydroelectricProduction Structures and Improvements			1,610,492
16	CostOfReservoirsDamsAndWaterwaysHydroelectricProduction Reservoirs, Dams, and Waterways			17,810,511
17	EquipmentCostsHydroelectricProduction Equipment Costs			6,156,153
18	CostOfRoadsRailroadsAndBridgesHydroelectricProduction Roads, Railroads, and Bridges
19	AssetRetirementCostsHydroelectricProduction Asset Retirement Costs
20	CostOfPlant Total cost (total 13 thru 20)			25,946,538
21	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 20 / 5)			1,801.8429
22	ProductionExpensesAbstract Production Expenses
23	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering
24	WaterForPower Water for Power
25	HydraulicExpenses Hydraulic Expenses
26	ElectricExpensesHydraulicPowerGeneration Electric Expenses
27	MiscellaneousHydraulicPowerGenerationExpenses Misc Hydraulic Power Generation Expenses
28	RentsHydraulicPowerGeneration Rents
29	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration Maintenance Supervision and Engineering
30	MaintenanceOfStructuresHydraulicPowerGeneration Maintenance of Structures
31	MaintenanceOfReservoirsDamsAndWaterways Maintenance of Reservoirs, Dams, and Waterways
32	MaintenanceOfElectricPlantHydraulicPowerGeneration Maintenance of Electric Plant
33	MaintenanceOfMiscellaneousHydraulicPlant Maintenance of Misc Hydraulic Plant
34	PowerProductionExpensesHydraulicPower Total Production Expenses (total 23 thru 33)
35	ExpensesPerNetKilowattHour Expenses per net kWh

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

Pumped Storage Generating Plant Statistics
Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings). If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number. If net peak demand for 60 minutes is not available, give that which is available, specifying period. If a group of employees attends more than one generating plant, report on Line 8 the approximate average number of employees assignable to each plant. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses." Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
Line No.	Item (a)	FERC Licensed Project No. 0 Plant Name: 0
1	PlantConstructionType Type of Plant Construction (Conventional or Outdoor)
2	YearPlantOriginallyConstructed Year Originally Constructed
3	YearLastUnitOfPlantInstalled Year Last Unit was Installed
4	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)
5	NetPeakDemandOnPlant Net Peak Demaind on Plant-Megawatts (60 minutes)
6	PlantHoursConnectedToLoad Plant Hours Connect to Load While Generating
7	NetContinuousPlantCapability Net Plant Capability (in megawatts)
8	PlantAverageNumberOfEmployees Average Number of Employees
9	NetGenerationExcludingPlantUse Generation, Exclusive of Plant Use - kWh
10	EnergyUsedForPumping Energy Used for Pumping
11	NetOutputForLoad Net Output for Load (line 9 - line 10) - Kwh	0
12	CostOfPlantAbstract Cost of Plant
13	CostOfLandAndLandRightsPumpedStoragePlant Land and Land Rights
14	CostOfStructuresAndImprovementsPumpedStoragePlant Structures and Improvements
15	CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant Reservoirs, Dams, and Waterways
16	CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant Water Wheels, Turbines, and Generators
17	CostOfAccessoryElectricEquipmentPumpedStoragePlant Accessory Electric Equipment
18	CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant Miscellaneous Powerplant Equipment
19	CostOfRoadsRailroadsAndBridgesPumpedStoragePlant Roads, Railroads, and Bridges
20	AssetRetirementCostsPumpedStoragePlant Asset Retirement Costs
21	CostOfPlant Total cost (total 13 thru 20)
22	CostPerKilowattOfInstalledCapacity Cost per KW of installed cap (line 21 / 4)
23	ProductionExpensesAbstract Production Expenses
24	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering
25	WaterForPower Water for Power
26	PumpedStorageExpenses Pumped Storage Expenses
27	ElectricExpensesPumpedStoragePlant Electric Expenses
28	MiscellaneousPumpedStoragePowerGenerationExpenses Misc Pumped Storage Power generation Expenses
29	RentsPumpedStoragePlant Rents
30	MaintenanceSupervisionAndEngineeringPumpedStoragePlant Maintenance Supervision and Engineering
31	MaintenanceOfStructuresPumpedStoragePlant Maintenance of Structures
32	MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant Maintenance of Reservoirs, Dams, and Waterways
33	MaintenanceOfElectricPlantPumpedStoragePlant Maintenance of Electric Plant
34	MaintenanceOfMiscellaneousPumpedStoragePlant Maintenance of Misc Pumped Storage Plant
35	PowerProductionExpenseBeforePumpingExpenses Production Exp Before Pumping Exp (24 thru 34)
36	PumpingExpenses Pumping Expenses
37	PowerProductionExpensesPumpedStoragePlant Total Production Exp (total 35 and 36)
38	ExpensesPerNetKilowattHour Expenses per kWh (line 37 / 9)
39	ExpensesPerNetKilowattHourGenerationAndPumping Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

GENERATING PLANT STATISTICS (Small Plants)

Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped storage plants of less than 10,000 Kw installed capacity (name plate rating).
Designate any plant leased from others, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give project number in footnote.
List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 402.
If net peak demand for 60 minutes is not available, give the which is available, specifying period.
If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.

Production Expenses

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

1

Dashville Hydro

1920

5

18,837,000

6,882,062

2

High Falls

1986

3

6,071,000

6,708,723

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

ENERGY STORAGE OPERATIONS (Large Plants)
Large Plants are plants of 10,000 Kw or more. In columns (a) (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location. In column (d), report Megawatt hours (MWH) purchased, generated, or received in exchange transactions for storage. In columns (e), (f) and (g) report MWHs delivered to the grid to support production, transmission and distribution. The amount reported in column (d) should include MWHs delivered/provided to a generator’s own load requirements or used for the provision of ancillary services. In columns (h), (i), and (j) report MWHs lost during conversion, storage and discharge of energy. In column (k) report the MWHs sold. In column (l), report revenues from energy storage operations. In a footnote, disclose the revenue accounts and revenue amounts related to the income generating activity. In column (m), report the cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. In columns (n) and (o), report fuel costs for storage operations associated with self-generated power included in Account 501 and other costs associated with self-generated power. In columns (q), (r) and (s) report the total project plant costs including but not exclusive of land and land rights, structures and improvements, energy storage equipment, turbines, compressors, generators, switching and conversion equipment, lines and equipment whose primary purpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property accounts listed.
Line No.	Name of the Energy Storage Project (a)	Functional Classification (b)	Location of the Project (c)	MWHs (d)	MWHs delivered to the grid to support Production (e)	MWHs delivered to the grid to support Transmission (f)	MWHs delivered to the grid to support Distribution (g)	MWHs Lost During Conversion, Storage and Discharge of Energy Production (h)	MWHs Lost During Conversion, Storage and Discharge of Energy Transmission (i)	MWHs Lost During Conversion, Storage and Discharge of Energy Distribution (j)	MWHs Sold (k)	Revenues from Energy Storage Operations (l)	Power Purchased for Storage Operations (555.1) (Dollars) (m)	Fuel Costs from associated fuel accounts for Storage Operations Associated with Self- Generated Power (Dollars) (n)	Other Costs Associated with Self-Generated Power (Dollars) (o)	Project Costs included in (p)	Production (Dollars) (q)	Transmission (Dollars) (r)	Distribution (Dollars) (s)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSMISSION LINE STATISTICS
Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. If required by a State commission to report individual lines for all voltages, do so but do not group totals for each voltage under 132 kilovolts. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g). Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
	DESIGNATION		VOLTAGE (KV) - (Indicate where other than 60 cycle, 3 phase)			LENGTH (Pole miles) - (In the case of underground lines report circuit miles)				COST OF LINE (Include in column (j) Land, Land rights, and clearing right-of-way)			EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	OperatingVoltageOfTransmissionLine Operating	DesignedVoltageOfTransmissionLine Designated	SupportingStructureOfTransmissionLineType Type of Supporting Structure	LengthForStandAloneTransmissionLines On Structure of Line Designated	LengthForTransmissionLinesAggregatedWithOtherStructures On Structures of Another Line	NumberOfTransmissionCircuits Number of Circuits	SizeOfConductorAndMaterial Size of Conductor and Material	CostOfLandAndLandRightsTransmissionLines Land	ConstructionAndOtherCostsTransmissionLines Construction Costs	OverallCostOfTransmissionLine Total Costs	OperatingExpensesOfTransmissionLine Operation Expenses	MaintenanceExpensesOfTransmissionLine Maintenance Expenses	RentExpensesOfTransmissionLine Rents	OverallExpensesOfTransmissionLine Total Expenses
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)
1	Roseton	Rock Tavern	345.00	0.00	H Frame -W	17.17	0.00	0	1033.5 ACSR	1,604,584	6,598,745	8,203,329
2	Roseton	Hurley Avenue	345.00	0.00	H Frame -W	30.31	0.00	0	1033.5 ACSR	2,117,296	13,897,716	16,015,012
3	Hurley Avenue	Leeds	345.00	0.00	H Frame -W	28.62	0.00	0	1033.5 ACSR	2,496,825	12,599,766	15,096,591
4	115 KV Lines		115.00	0.00	Several	216.05	0.00	0	Several	7,233,533	102,307,405	109,540,938
5	69 KV Lines		69.00	0.00	Several	266.89	20.88	0	Several	17,577,229	118,538,286	136,115,515
6	Segregation of Expenses by	Line is not available											4,606,402	5,237,086	1,090,232	10,933,720
36	TOTAL					559.04	20.88	0		31,029,467	253,941,918	284,971,385	4,606,402	5,237,086	1,090,232	10,933,720

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSMISSION LINES ADDED DURING YEAR

Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines.
Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic.

LINE DESIGNATION

SUPPORTING STRUCTURE

CIRCUITS PER STRUCTURE

CONDUCTORS

LINE COST

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

(o)

(p)

(q)

1

Line Altered:

44

TOTAL

0.00

0

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

SUBSTATIONS
Report below the information called for concerning substations of the respondent as of the end of the year. Substations which serve only one industrial or street railway customer should not be listed below. Substations with capacities of Less than 10 MVA except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
		Character of Substation		VOLTAGE (In MVa)						Conversion Apparatus and Special Equipment
Line No.	SubstationNameAndLocation Name and Location of Substation (a)	SubstationCharacterDescription Transmission or Distribution (b)	SubstationCharacterAttendedOrUnattended Attended or Unattended (b-1)	PrimaryVoltageLevel Primary Voltage (In MVa) (c)	SecondaryVoltageLevel Secondary Voltage (In MVa) (d)	TertiaryVoltageLevel Tertiary Voltage (In MVa) (e)	SubstationInServiceCapacity Capacity of Substation (In Service) (In MVa) (f)	NumberOfTransformersInService Number of Transformers In Service (g)	Number of Spare Transformers (h)	ConversionApparatusAndSpecialEquipmentType Type of Equipment (i)	NumberOfConversionApparatusAndSpecialEquipmentUnits Number of Units (j)	CapacityOfConversionApparatusAndSpecialEquipment Total Capacity (In MVa) (k)
1	Bethlehem Road Tn. Of New Windsor	Distribution	Unattd	115.00	13.80		70.00	2	0
2	Boulevard Tn. Of Ulster	Distribution	Unattd	69.00	13.80		45.00	2	1
3	Coldenham Tn. Of Montgomery	Distribution	Unattd	115.00	13.80		75.00	2	0
4	Coxsackie Vl. Of Coxsackie	Distribution	Unattd	69.00	13.80		13.00	1	0
5	East Fishkill Tn. Of East Fishkill	Transmission	Unattd	345.00	115.00		746.00	2	0
6	East Kingston City of Kingston	Distribution	Unattd	115.00	13.80		75.00	2	0
7	East Park Tn. Of Hyde Park	Distribution	Unattd	69.00	13.80		20.00	1	0
8	East Walden Tn. Of Montgomery	(a) Transmission	Unattd	115.00	69.00	13.80	84.00	2	1
9	Fishkill Plains Tn. Of East Fishkill	Distribution	Unattd	115.00	13.80		74.00	2	0
10	Forgebrook Tn. Of Fishkill	Distribution	Unattd	115.00	13.80		64.00	2	0
11	Freehold Tn. Of Greenville	Distribution	Unattd	69.00	13.80		14.00	1	0
12	Galeville Tn Of Gardner	Distribution	Unattd	69.00	13.80		45.00	2	0
13	Greenfield Road Tn. Of Wawarsing	Distribution	Unattd	69.00	13.80	4.16	12.00	5	0
14	Hibernia Tn. Of Clinton	Distribution	Unattd	69.00	13.80		14.00	1	0
15	High Falls Tn. Of Marbletown	Distribution	Unattd	69.00	13.80		40.00	2	0
16	Highland Tn. Of Lloyd	Distribution	Unattd	115.00	13.80		42.00	2	0
17	Honk Falls Tn. Of Wawarsing	Distribution	Unattd	69.00	13.80		12.00	1	0
18	Hunter Vl. Of Hunter	Distribution	Unattd	34.50	13.80		19.00	2	0
19	Hurley Ave. Tn. Of Ulster	(b) Transmission	Unattd	345.00	115.00	69.00	470.00	6	1
20	Inwood Ave. Tn. Of Poughkeepsie	Distribution	Unattd	115.00	13.80		70.00	2	0
21	Kerhonkson Tn. Of Wawarsing	Distribution	Unattd	69.00	13.80		45.00	4	0
22	Knapps Corners Tn. Of Poughkeepsie	(c) Transmission	Unattd	115.00	69.00	13.80	93.00	6	0
23	Lawrenceville Tn. Of Catskill	Distribution	Unattd	69.00	34.50		12.00	3	1
24	Lincoln Park Tn. Of Ulster	Distribution	Unattd	115.00	13.80		100.00	3	0
25	Manchester Tn. Of Poughkeepsie	Distribution	Unattd	115.00	13.80		70.00	2	0
26	Marlboro Tn. Of Marlboro	Distribution	Unattd	115.00	13.80		40.00	2	0
27	Maybrook Vl. Of Maybrook/Tn. Of Montgomery	Distribution	Unattd	69.00	13.80		25.00	2	1
28	Merritt Park Vl. Of Fishkill	Distribution	Unattd	115.00	13.80		74.00	2	0
29	Milan Tn. Of Milan	Distribution	Unattd	115.00	13.80		20.00	1	0
30	Modena Tn. Of Plattekill	(d) Transmission	Unattd	115.00	69.00	13.80	46.00	4	1
31	Montgomery Tn. Of Montgomery	(e) Transmission	Unattd	115.00	69.00		22.00	2	0
32	Montgomery St. City of Newburgh	Distribution	Unattd	13.80	4.16		18.00	0	0
33	Myers Corners Tn. Of Wappingers Falls	Distribution	Unattd	69.00	13.80		40.00	2	0
34	New Baltimore Tn. Of New Baltimore	Distribution	Unattd	69.00	13.80		22.00	1	0
35	North Catskill Tn. Of Catskill	(f) Transmission	Unattd	115.00	69.00	13.80	152.00	4	0
36	North Chelsea Tn. Of Wappingers Falls	(g) Transmission	Unattd	115.00	69.00	13.80	131.00	3	0
37	Ohioville Tn. Of New Paltz	(h) Transmission	Unattd	115.00	69.00	13.80	40.00	2	0
38	Pleasant Valley Tn. Of Pleasant Valley	(i) Transmission	(m) Unattd	345.00	115.00		468.00	3	1
39	Pulvers Corners Tn. Of Pine Plains	(j) Transmission	Unattd	69.00	34.50	13.80	17.00	2	0
40	Reynolds Hill City of Poughkeepsie	Distribution	Unattd	115.00	13.80	4.16	75.00	0	0
41	Rhinebeck Tn. Of Rhinebeck	(k) Transmission	Unattd	115.00	69.00	13.80	164.00	3	0
42	Rock Tavern Tn. Of New Windsor	Transmission	Unattd	345.00	115.00		706.00	2	0
43	Rock Tavern Tn. Of New Windsor	Transmission	Unattd	115.00	69.00		40.00	1	0
44	Sand Dock Tn. Of Poughkeepsie	Distribution	Unattd	115.00	13.80		22.00	1	0
45	Saugerties Tn. Of Saugerties	Distribution	Unattd	69.00	13.80	4.16	75.00	0	0
46	Shenandoah Tn. Of East Fishkill	Distribution	Unattd	115.00	13.80		33.00	1	0
47	South Cairo Tn. Of Cairo	Distribution	Unattd	69.00	13.80		20.00	1	0
48	Spackenkill Tn Of Poughkeepsie	Distribution	Unattd	115.00	13.80		75.00	2	0
49	Staatsburg Tn. Of Hyde Park	Distribution	Unattd	69.00	13.80		20.00	1	0
50	Stanfordville Tn. Of Stanford	Distribution	Unattd	69.00	13.80		14.00	1	0
51	Sturgeon Pool Tn. Of Rosendale	(l) Transmission	Unattd	6.60	69.00	4.16	90.00	5	0
52	Tinkertown Tn. Of Pleasant Valley	Distribution	Unattd	69.00	13.80		25.00	2	0
53	Tioronda Tn. Of Fishkill	Distribution	Unattd	115.00	13.80		20.00	1	0
54	Todd Hill Tn. Of LaGrange	Distribution	Unattd	115.00	69.00	13.80	131.00	3	0
55	Union Ave. Tn. Of New Windsor	Distribution	Unattd	115.00	13.80		101.00	3	0
56	Vinegar Hill Tn. Of Lexington	Distribution	Unattd	115.00	34.50		12.00	1	0
57	West Balmville Tn. Of Newburgh	Distribution	Unattd	115.00	13.80		66.00	2	0
58	Westerlo Tn. Of Westerlo	Distribution	Unattd	69.00	13.80		20.00	1	0
59	Woodstock Tn. Of Woodstock	Distribution	Unattd	69.00	13.80		25.00	2	0
60	18 Substations Under 10 MVA	Distribution	Unattd				59.00	14	1
61	TotalDistributionSubstationMember						2,405
62	TotalGenerationSubstationMember						0
63	TotalTransmissionSubstationMember						2,827
64	Total						5,232	137	8			0

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: SubstationCharacterDescription


Schedule Page: 426 Line No.: XX Column: b


Page 426 Column (b) lines 8, 19, 22, 30, 31, 35, 36, 37, 39, 40.01 and 40.11

The substations listed on the above chart in the lines noted as Transmission also have a Distribution component.

(b) Concept: SubstationCharacterDescription


Schedule Page: 426 Line No.: XX Column: b


Page 426 Column (b) lines 8, 19, 22, 30, 31, 35, 36, 37, 39, 40.01 and 40.11

The substations listed on the above chart in the lines noted as Transmission also have a Distribution component.

(c) Concept: SubstationCharacterDescription


Schedule Page: 426 Line No.: XX Column: b


Page 426 Column (b) lines 8, 19, 22, 30, 31, 35, 36, 37, 39, 40.01 and 40.11

The substations listed on the above chart in the lines noted as Transmission also have a Distribution component.

(d) Concept: SubstationCharacterDescription


Schedule Page: 426 Line No.: XX Column: b


Page 426 Column (b) lines 8, 19, 22, 30, 31, 35, 36, 37, 39, 40.01 and 40.11

The substations listed on the above chart in the lines noted as Transmission also have a Distribution component.

(e) Concept: SubstationCharacterDescription


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(f) Concept: SubstationCharacterDescription


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(g) Concept: SubstationCharacterDescription


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(h) Concept: SubstationCharacterDescription


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The substations listed on the above chart in the lines noted as Transmission also have a Distribution component.

(i) Concept: SubstationCharacterDescription


Schedule Page: 426 Line No.: 38 Column: b


Central Hudson Gas & Electric Corporation		December 31, 2021

	Substations

Instruction - Item #6

• The 345KV section of the Pleasant Valley Substation is not owned by Central Hudson; however, the transformer and capacity is owned by Central Hudson

(j) Concept: SubstationCharacterDescription


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The substations listed on the above chart in the lines noted as Transmission also have a Distribution component.

(k) Concept: SubstationCharacterDescription


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The substations listed on the above chart in the lines noted as Transmission also have a Distribution component.

(l) Concept: SubstationCharacterDescription


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The substations listed on the above chart in the lines noted as Transmission also have a Distribution component.

(m) Concept: SubstationCharacterAttendedOrUnattended


Page 426 Column (c) (d) and (e)

Central Hudson Gas & Electric Corporation

	Substations	December 31, 2021

Columns (c) (d) & (e) Voltage is reported as KV, not MVa.

Name of Respondent:

CENTRAL HUDSON GAS & ELECTRIC CORPORATION

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/18/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not attempt to include or aggregate amounts in a nonspecific category such as "general". Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Line No.	Description of the Good or Service (a)	Name of Associated/Affiliated Company (b)	Account(s) Charged or Credited (c)	Amount Charged or Credited (d)
1	Non-power Goods or Services Provided by Affiliated
2	Insurance	CH Energy Group, Inc.	165.20	223,644
3	License - Misc	CH Energy Group, Inc.	165.90	50,222
4	Director's Fees	CH Energy Group, Inc.	930.20	416,653
5	Accrued Exp - Auditing	CH Energy Group, Inc.	242.41	85,155
6	Special Services	CH Energy Group, Inc.	923.00	15,497
7	Office Expenses	CH Energy Group, Inc.	921.00	10,510
8	Management Costs	CH Energy Group, Inc.	930.20	3,561,030
9	OneSource Software	CH Energy Group, Inc.	921.00	1,898
10	Non mainframe Software/License	CH Energy Group, Inc.	903.00	65,203
11	Non mainframe Software &/or Licenses	CH Energy Group, Inc.	923.00	2,989
12	Common Utility Plant	CH Energy Group, Inc.	118.42	9,600
13		.
19
20	Non-power Goods or Services Provided for Affiliated
21	Mutual Aid	Fortis, Inc.	186.65	7,859
22	Medical Insurance	Fortis Ontario	186.65	10,333
23	Pension & OPEB	FortisAlberta	186.65	206,208
24	Monthly Payroll and Related Costs	CH Energy Group, Inc.	186.62	4,216,677
25	Professional Fees & Consulting and Other	CH Energy Group, Inc.	186.62	48,058
26	Monthly Payroll and Related Costs	CH Enterprises, Inc.	186.60	60,097
27	Bank Fees	CH Enterprises, Inc.	186.60	2,350
28	Monthly Payroll and Related Costs	CH Electric Transmission, Inc.	186.61	19,388
29	Bank Fees	CH Electric Transmission, Inc.	186.61	2,916
42

FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

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

GENERAL INFORMATION

Purpose

Who Must Submit

What and Where to Submit

When to Submit

Where to Send Comments on Public Reporting Burden.

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report