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 Maine Power Company

Year/Period of Report

End of:

2023

/

Q2

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

GENERAL INFORMATION

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

What and Where to Submit

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

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

The CPA Certification Statement should:

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

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

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

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

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

GENERAL INSTRUCTIONS

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

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

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

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

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

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

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

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

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

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

DEFINITIONS

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

EXCERPTS FROM THE LAW

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

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

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

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

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

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

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

"Sec. 304.

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

"Sec. 309.

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

GENERAL PENALTIES

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

FERC FORM NO.

1/3-Q

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

Identification

01 Exact Legal Name of Respondent

Central Maine Power Company

02 Year/ Period of Report

End of:

2023

/

Q2

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)

83 Edison Drive, Augusta, ME 04336

05 Name of Contact Person

Jack E. Jessop

06 Title of Contact Person

Director, Networks Accounting

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

One City Center, 5th Floor, Portland, ME 04101

08 Telephone of Contact Person, Including Area Code

(207) 458-3119

09 This Report is An Original / A Resubmission

(1)

☑ An Original

(2)

☐ A Resubmission

10 Date of Report (Mo, Da, Yr)

08/29/2023

Quarterly Corporate Officer Certification

The undersigned officer certifies that:

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

01 Name

Andrea M Vanluling

02 Title

Controller and Treasurer

03 Signature

Andrea M Vanluling

04 Date Signed (Mo, Da, Yr)

08/29/2023

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

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

List of Schedules
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line No.	Title of Schedule (a)	Reference Page No. (b)	Remarks (c)
	ScheduleIdentificationAbstract Identification	1
	ScheduleListOfSchedulesAbstract List of Schedules (Electric Utility)	2
1	ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Quarter	108
2	ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet	110
3	ScheduleStatementOfIncomeAbstract Statement of Income for the Quarter	114
4	ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Quarter	118
5	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120
6	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122
7	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Comp Income, Comp Income, and Hedging Activities	122a
8	ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep	200
9	ScheduleElectricPlantInServiceAndAccumulatedProvisionForDepreciationByFunctionAbstract Electric Plant In Service and Accum Provision For Depr by Function	208
10	ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract Transmission Service and Generation Interconnection Study Costs	231
11	ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets	232
12	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278
13	ScheduleElectricOperatingRevenuesAbstract Elec Operating Revenues (Individual Schedule Lines 300-301)	300
14	ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1)	302	None
15	ScheduleElectricProductionOtherPowerTransmissionRegionalExpensesAbstract Electric Prod, Other Power Supply Exp, Trans and Distrib Exp	324
16	ScheduleElectricCustomerAccountServiceSalesAdministrativeAndGeneralExpensesAbstract Electric Customer Accts, Service, Sales, Admin and General Expenses	325
17	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
18	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331	Not Applicable
19	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
20	ScheduleDepreciationDepletionAndAmortizationsAbstract Deprec, Depl and Amort of Elec Plant (403,403.1,404,and 405) (except Amortization of Acquisition Adjustments)	338
21	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts Included in ISO/RTO Settlement Statements	397
22	ScheduleMonthlyPeaksAndOutputAbstract Monthly Peak Loads and Energy Output	399
23	ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load	400
24	ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load	400a	None

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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.

None.
None.
None.
None.
None.
CMP had $184.5 million short-term debt outstanding at June 30, 2023 and $46.0 million at December 31, 2022. CMP funds short-term liquidity needs through an agreement among Avangrid’s regulated utility subsidiaries (the “Virtual Money Pool Agreement”), a bi-lateral intercompany credit agreement with Avangrid (the “Bi-Lateral Intercompany Facility”) and a bank provided credit facility to which CMP is a party (the “AGR Credit Facility”), each of which are described below. The Virtual Money Pool Agreement is an agreement among the investment grade-rated, regulated utility subsidiaries of Avangrid under which the parties to this agreement may lend to or borrow from each other. This Agreement allows Avangrid to optimize cash resources within the regulated utility companies which are prohibited by regulation from lending to unregulated affiliates. The interest rate on transactions under this agreement is the A2/P2 non-financial 30-day commercial paper rate published by the Federal Reserve. CMP has a lending/borrowing limit of $100 million under this agreement. CMP had no debt outstanding at June 30, 2023 and $7.0 million outstanding at December 31, 2022. The Bi-Lateral Intercompany Facility provides for borrowing of up to $500 million from Avangrid at the A2/P2 non-financial 30-day commercial paper rate published by the Federal Reserve. CMP had $184.5 million outstanding under this agreement at June 30, 2023 and $39.0 million outstanding at December 31, 2022. On November 23, 2021, Avangrid and its investment-grade rated utility subsidiaries (New York State Electric & Gas Corporation (“NYSEG”), Rochester Gas and Electric Corporation (“RG&E”), CMP, The United Illuminating Company (“UI”), Connecticut Natural Gas Corporation (“CNG”), The Southern Connecticut Gas Company ("SCG") and The Berkshire Gas Company (“BGC”)) executed a new credit facility with an aggregate limit of $3,575 million and a termination date of November 23, 2026. Under the terms of the AGR Credit Facility, each borrower has a maximum borrowing entitlement, or sublimit, which can be periodically adjusted to address specific short-term capital funding needs, subject to the maximum limit contained in the agreement. NYSEG has a maximum sublimit of $700 million, RG&E has $300 million, CMP has $200 million, UI has $250 million, CNG and SCG have maximum sublimits of $150 million and BGC has a maximum sublimit of $50 million. Effective on November 23, 2021, the AGR Credit Facility was amended to increase Avangrid’s maximum sublimit to $2,500 million and to establish minimum sublimits of $500 million for NYSEG, $200 million for RG&E, $100 million for CMP, $150 million for UI, $50 million for CNG and SCG and $25 million for BGC. Under the AGR Credit Facility, each of the borrowers are charged a facility fee that is dependent on their credit rating. The facility fees range from 10 to 22.5 basis points. CMP had no borrowings outstanding under this agreement at June 30, 2023 and December 31, 2022. In the AGR Credit Facility we covenant not to permit, without the consent of the lender, our ratio of total indebtedness to total capitalization to exceed 0.65 to 1.00 at any time. For purposes of calculating the maximum ratio of indebtedness to total capitalization, the facility excludes from net worth the balance of accumulated other comprehensive loss as it appears on the balance sheet. The facility contains various other covenants, including a restriction on the amount of secured indebtedness we may maintain. Continued un-remedied failure to comply with those covenants for five business days after written notice of such failure from the lender constitutes an event of default and would result in acceleration of maturity. Our ratio of indebtedness to total capitalization pursuant to the revolving credit facility was 0.4 to 1.00 at June 30, 2023. We are not in default as of June 30, 2023. The short-term financing arrangements discussed above are authorized in FERC Docket No. ES17-34-000 and by the State of Maine Public Utilities Commission in Docket No. 2016-00029.
None
None
Electricity Distribution The Maine distribution rate stipulation and the FERC Transmission Return on Equity (ROE) case are some of the most important specific regulatory processes that currently affect CMP. The revenues of CMP are regulated, being based on tariffs established in accordance with administrative procedures set by the various regulatory bodies. The tariffs applied to regulated activities in the U.S. are approved by the regulatory commissions and are based on the cost of providing service. The revenues of each regulated utility are set to be sufficient to cover all its operating costs, including finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable ROE. Generally, tariff reviews cover various years and provide for a reasonable ROE and full reconciliation of exceptional costs as identified in CMP's rate plan. Energy costs that are set on the New England wholesale markets are passed on to consumers by Competitive Energy Providers, licensed by the MPUC. Under Maine Law, transmission and distribution utilities are prohibited from providing retail energy supply. Default retail supply is provided by Standard Offer Providers periodically selected by the MPUC through a competitive procurement process. Transmission - FERC ROE and Other FERC Matters CMP’s transmission rates are determined by a tariff regulated by the FERC and administered by ISO New England, Inc. (ISO-NE). Transmission rates are set annually pursuant to a FERC authorized formula that allows for recovery of direct and allocated transmission operating and maintenance expenses, and for a return of and on investment in assets. On September 30, 2011, the Massachusetts Attorney General, Massachusetts Department of Public Utilities, Connecticut Public Utilities Regulatory Authority, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a joint complaint with the FERC, pursuant to sections 206 and 306 of the Federal Power Act, against several New England Transmission Owners (NETOs) claiming that the approved base ROE of 11.14% used by NETOs in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) was not just and reasonable and seeking a reduction of the base ROE with refunds to customers for the 15-month refund periods beginning October 1, 2011 (Complaint I), December 27, 2012 (Complaint II), July 31, 2014 (Complaint III) and April 29, 2016 (Complaint IV). On October 16, 2014, the FERC issued its final decision in Complaint I, setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 - December 2012 period as well as prospectively from October 16, 2014. On March 3, 2015, the FERC upheld its decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner's total transmission return. The complaints were consolidated and the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, (1) for the fifteen month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the fifteen month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The initial decision in Complaints II and III is the administrative law judge’s recommendation to the FERC Commissioners. CMP reserved for refunds for Complaints I, II and III consistent with the FERC’s Mach 3, 2015 decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP total reserve associated with Complaints II and III is $28.9 million as of June 30, 2023, which has not changed since December 31, 2022, except for the accrual of carrying costs. If adopted as final by the FERC, the impact of the initial decision by the FERC administrative law judge would be an additional aggregate reserve for Complaints II and III of $12.8 million, which is based upon currently available information for these proceedings. Following various intermediate hearings, orders and appellate decisions, on October 16, 2018, the FERC issued an order directing briefs and proposing a new methodology to calculate the NETOs ROE that is contained in NETOs' transmission formula rate on file at the FERC (the October 2018 Order). Pursuant to the October 2018 Order, the NETOs filed initial briefs on the proposed methodology in all four Complaints on January 11, 2019, and replied to the initial briefs on March 8, 2019. On November 21, 2019, the FERC issued rulings on two complaints challenging the base return on equity for Midcontinent Independent System Operator, or MISO transmission owners. These rulings established a new zone of reasonableness based on equal weighting of the DCF and capital-asset pricing model for establishing the base return on equity. This resulted in a base return on equity of 9.88% as the midpoint of the zone of reasonableness. Various parties have requested rehearing on this decision, which was granted. On May 21, 2020, the FERC issued a ruling, which, among other things, adjusted the methodology to determine the MISO transmission owners’ ROE, resulting in an increase in ROE from 9.88% to 10.02% by utilizing the risk premium model, or RPM, in addition to the DCF model and capital-asset pricing model under both prongs of Section 206 of the FPA, and calculated the zone of reasonableness into equal thirds rather than employing the quartile approach. Parties to these orders affecting the MISO transmission owners' base ROE petitioned for their review at the D.C. Circuit Court of Appeals in January 2021. The NETO's submitted an amici curia brief in support of the MISO transmission owners on March 17, 2021. On August 9, 2022, the D.C. Circuit Court vacated FERC's orders and remanded the matter back to FERC. The D.C. Circuit Court held that FERC failed to offer a reasoned explanation for its decision to reintroduce the RPM after initially, and forcefully, rejecting it and that because the FERC adopted that significant portion of its model in an arbitrary and capricious fashion, the new ROE produced by that model cannot stand. We cannot predict the potential impact the MISO transmission owners' ROE proceeding may have in establishing a precedent for the NETO's pending four Complaints. On April 15, 2021, the FERC issued a supplemental Notice of Proposed Rulemaking (Supplemental NOPR) that proposes to eliminate the 50 basis-point ROE incentive for utilities who join Regional Transmission Organizations after three years of membership. The NETOs submitted initial comments in opposition to the Supplemental NOPR on June 25, 2021 and reply comments on July 26, 2021. If the elimination of the 50 basis-point ROE incentive adder becomes final, we estimate we would have an approximately $1 million reduction in earnings per year. We cannot predict the outcome of this proceeding. CMP Distribution Rate Stipulation and New Renewable Source Generation In an order issued on February 19, 2020, the MPUC authorized an increase in CMP's distribution revenue requirement of $17.4 million, or approximately 6.9%, based on an allowed ROE of 9.25% and a 50.00% equity ratio. The rate increase was effective March 1, 2020. Commencing on March 1, 2020, the MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017 which would be removed after demonstrating satisfactory customer service performance. In September 2021, CMP met the 18-month required rolling average satisfactory customer service benchmarks and filed with the MPUC a request for removal of the management efficiency adjustment, which was approved by the MPUC effective as of its February 18, 2022 order. The Order provided additional funding for staffing increases, vegetation management programs and storm restoration costs, while retaining the basic tiered structure for storm cost recovery implemented in the 2014 stipulation. The MPUC Order also retained the RDM implemented in 2014. The Order denied CMP’s request to increase rates for higher costs associated with services provided by its affiliates and ordered the initiation of a management audit to evaluate whether CMP's current management structure, and the management and other services from its affiliates, are appropriate and in the interest of Maine customers. The management audit was commenced in July 2020 by the MPUC's consultants and culminated with a report issued by the MPUC’s consultants in July 2021. On February 18, 2022, the MPUC opened a narrowly tailored follow-on investigation examining how CMP and its customers are affected by decisions made at the CMP corporate parent level about earnings, capital budgeting, and planning. In this context, the investigation will also examine regulatory approaches and structures including ratemaking and performance mechanisms. In an order dated February 7, 2023, the MPUC closed this investigation after consolidating its records with CMP's pending rate case. In accordance with Chapter 120 of MPUC Rules, on May 26, 2022, CMP filed a nonbinding notice of intent to file a distribution rate case on or after sixty days from the issuance of the letter. In the notice, CMP signaled its intent to propose a three-year rate plan, which includes a multi-year capital investment plan to fund investments needed to improve reliability and resiliency, as well as to continue to improve the customer experience and cost-effectively advance clean energy transformation. CMP’s notice estimated a revenue change in the range of $45 to $50 million in the first year of the rate plan followed by increases in the range of $25 to $30 million in the second year and $20 to $25 million in the third year. We cannot predict the outcome of this matter. On August 11, 2022, CMP filed a three-year rate plan, with adjustments to the distribution revenue requirement in each year. In its filing, CMP has set the three rate years as August 1, 2023 to July 31, 2024 (“Rate Year 1”); August 1, 2024 to July 31, 2025 (“Rate Year 2”); and August 1, 2025 to July 31, 2026 (“Rate Year 3”). The requested Rate Year revenue requirement increases for the rate years are $48 million, $28 million and $23 million, respectively. The revenue requirement adjustments are based on a test year ending December 31, 2021. The requested revenue changes for each rate year of the proposal are subject to a number of adjustment mechanisms most significantly including: (1) an annual review of plant additions with potential downward reconciliation in the event of an underspend, (2) a capital adjustment mechanism for certain incremental pole replacements, broadband work, electric vehicle work, energy storage projects, and metering system upgrades, (3) a symmetrical inflation reconciliation adjustment, and (4) symmetrical reconciliation of the Company's tax basis repair deduction. Other parties filed direct testimony in this proceeding on December 2, 2022 and CMP filed rebuttal testimony on February 7, 2023. Settlement discussions are on-going and technical conferences are scheduled for mid-May 2023. New rates are expected to take effect on or around August 2023. We cannot predict the outcome of this matter. Pursuant to Maine law, the MPUC is authorized to conduct periodic requests for proposals seeking long-term supplies of energy, capacity or Renewable Energy Certificates, or RECs, from qualifying resources. The MPUC is further authorized to order Maine Transmission and Distribution Utilities to enter into contracts with sellers selected from the MPUC’s competitive solicitation process. Pursuant to a MPUC Order dated October 8, 2009, CMP entered into a 20-year agreement with Evergreen Wind Power III, LLC, on March 31, 2010, to purchase capacity and energy from Evergreen’s 60 MW Rollins wind farm in Penobscot County, Maine. CMP’s purchase obligations under the Rollins contract are approximately $9 million per year. Pursuant to a MPUC Order dated December 18, 2017, CMP entered into a 20-year agreement with Dirigo Solar, LLC on September 10, 2018, to purchase capacity and energy from multiple Dirigo solar facilities throughout CMP's service territory. CMP's purchase obligations under the Dirigo contract will increase as additional solar facilities are brought on line, eventually reaching a level of approximately $2.5 million per year. Pursuant to a MPUC Order dated November 6, 2019, CMP entered into a 20-year agreement with Maine Aqua Ventus I GP LLC on December 9, 2019, to purchase capacity and energy from an off-shore wind farm under development near Monhegan Island, Maine. CMP's purchase obligations under the Maine Aqua Ventus contract will be approximately $12 million per year once the facility begins commercial operation. On September 11, 2020 the project was assigned to New England Aqua Ventus, LLC. Pursuant to Maine law, the MPUC conducted two competitive solicitation processes to procure, in the aggregate, an amount of energy or RECs from Class 1A resources that is equal to 14% of retail electricity sales in the State during calendar year 2018, or 1.715 Million MWh. Of that 14% total, the MPUC must acquire at least 7%, but not more than 10%. Through contracts approved in December 2020 (Tranche 1), CMP was ordered to execute 13 contracts, 2 contracts terminated in 2022 prior to achieving Commercial Operations. In October 2021 CMP executed contracts with 6 additional facilities (Tranche 2), 1 contract terminated in 2023 prior to achieving Commercial Operations. Each of the Tranche 1 and Tranche 2 are for 20-year terms. In accordance with MPUC orders, CMP either sells the purchased energy, or in one case the RECs, from these facilities in the ISO New England markets, through periodically auctioning the purchased output to wholesale buyers in the New England regional market, or through a sale to a third party for the RECs. Under Maine law, CMP is assured recovery of any differences between power purchase costs and achieved market revenues through a reconcilable component of its retail distribution rates. Although the MPUC has conducted multiple requests for proposals under Maine law, and has tentatively accepted term sheet proposals for long-term contracts from other sellers, these selections have not yet resulted in additional currently effective contracts with CMP. Summary Investigation into Security Limits Litigation On December 13, 2021, the MPUC issued a Notice initiating a summary investigation of certain allegations with respect to the recovery of capital expenditure costs contained in the lawsuit filed by Security Limits, Inc. and Paul Silva against the Company, Networks and Iberdrola, S.A. and several other entities and individuals in the United States District Court Southern District of New York. CMP filed a report describing any costs described in the complaint that are currently being recovered or will be recovered in rates on January 18, 2022 as directed by the Notice of Summary Investigation. In the report, CMP noted that the plaintiffs’ had not yet served the complaint upon Networks or the Company. The MPUC directed CMP to submit notification to the MPUC when the Complaint has been served or when the procedural deadline for serving the Complaint has passed. On February 9, 2022, Security Limits, Inc. and Paul Silva dismissed their complaint. On February 10, 2022, CMP notified the MPUC of the dismissal and requested that the proceeding be closed. Subsequently on March 8, 2022, the MPUC issued an Order closing the investigation. Minimum Equity Requirements for Regulated Subsidiaries CMP is subject to a minimum equity ratio requirement that is tied to the capital structure assumed in establishing revenue requirements. Pursuant to these requirements CMP must maintain a minimum equity ratio equal to the ratio in its currently effective rate plan or decision measured using a trailing 13-month average. On a monthly basis CMP must maintain a minimum equity ratio of no less than 300 basis points below the equity ratio used to set rates. The minimum equity ratio requirement has the effect of limiting the amount of dividends that may be paid and may, under certain circumstances, require that the parent contribute equity capital. CMP is prohibited by regulation from lending to unregulated affiliates. CMP has also agreed to minimum equity ratio requirements in certain short-term borrowing agreements. These requirements are lower than the regulatory requirements. We are in compliance with these requirements.
None.
None.
None.
None.

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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	5,420,565,311	5,335,090,441
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	246,283,873	233,663,593
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		5,666,849,184	5,568,754,034
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	1,468,829,215	1,412,281,757
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		4,198,019,969	4,156,472,277
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)		4,198,019,969	4,156,472,277
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		25,324,575	25,330,437
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		1,372,834	1,371,631
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	136,497,764	130,274,544
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228
24	OtherInvestments Other Investments (124)
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)
29	SpecialFunds Special Funds (Non Major Only) (129)
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		160,449,505	154,233,350
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)			348,607
36	SpecialDeposits Special Deposits (132-134)		205,430	205,430
37	WorkingFunds Working Fund (135)		5,180	5,180
38	TemporaryCashInvestments Temporary Cash Investments (136)		1,007	1,007
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		150,767,245	147,294,599
41	OtherAccountsReceivable Other Accounts Receivable (143)		94,469,359	94,516,947
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		16,410,019	16,935,894
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		59,182,539	63,900,315
45	FuelStock Fuel Stock (151)	227
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	(a) 50,919,600	(b) 39,512,255
49	Merchandise Merchandise (155)	227
50	OtherMaterialsAndSupplies Other Materials and Supplies (156)	227
51	NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157)	202/227
52	AllowanceInventoryAndWithheld Allowances (158.1 and 158.2)	228
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227
55	GasStoredCurrent Gas Stored Underground - Current (164.1)
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57	Prepayments Prepayments (165)		9,965,020	27,016,463
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)			27,933
60	RentsReceivable Rents Receivable (172)
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		41,763,644	45,781,353
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)
65	DerivativeInstrumentAssetsHedges Derivative Instrument Assets - Hedges (176)
66	DerivativeInstrumentAssetsHedgesLongTerm (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
67	CurrentAndAccruedAssets Total Current and Accrued Assets (Lines 34 through 66)		390,869,005	401,674,195
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		4,754,216	4,993,380
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	572,321,897	461,888,925
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		18,157,597	18,115,813
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)		5,093,261	3,487,535
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	80,050,370	80,177,378
79	DeferredLossesFromDispositionOfUtilityPlant Def. Losses from Disposition of Utility Plt. (187)
80	ResearchDevelopmentAndDemonstrationExpenditures Research, Devel. and Demonstration Expend. (188)	352
81	UnamortizedLossOnReacquiredDebt Unamortized Loss on Reaquired Debt (189)		121,612	165,500
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	147,939,966	158,378,813
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		828,438,919	727,207,344
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		5,577,777,398	5,439,587,166

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

FOOTNOTE DATA

(a) Concept: PlantMaterialsAndOperatingSupplies

Functional Allocation of Account 154, Plant Materials and Operating Supplies (Estimated):


Balance End of Quarter:
Transmission:			29,439,252
Distribution:			21,480,348
			50,919,600

* Allocation based upon the relationship of Transmission and Distribution investment as of 3/31/2023 per page 208 lines 7 and 8.

(b) Concept: PlantMaterialsAndOperatingSupplies

Functional Allocation of Account 154, Plant Materials and Operating Supplies (Estimated):


Balance End of Year:
Transmission:			16,439,337
Distribution:			23,072,918
			39,512,255

* Allocation based upon the relationship of Transmission and Distribution investment as of 12/31/2022 per pages 204-207 lines 58 and 75.

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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	156,057,355	156,057,355
3	PreferredStockIssued Preferred Stock Issued (204)	250	571,300	571,300
4	CapitalStockSubscribed Capital Stock Subscribed (202, 205)
5	StockLiabilityForConversion Stock Liability for Conversion (203, 206)
6	PremiumOnCapitalStock Premium on Capital Stock (207)		269,813,541	269,813,541
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	756,307,601	756,307,601
8	InstallmentsReceivedOnCapitalStock Installments Received on Capital Stock (212)	252
9	DiscountOnCapitalStock (Less) Discount on Capital Stock (213)	254
10	CapitalStockExpense (Less) Capital Stock Expense (214)	254b
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	967,752,749	919,423,547
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	63,029,985	56,806,765
13	ReacquiredCapitalStock (Less) Reacquired Capital Stock (217)	250
14	NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218)
15	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	122(a)(b)	3,115,422	3,215,795
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		2,210,417,109	2,155,764,314
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	1,150,000,000	1,150,000,000
19	ReacquiredBonds (Less) Reacquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256	140,000,000	140,000,000
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)		1,290,000,000	1,290,000,000
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		15,090,892	15,376,180
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		1,540,525	885,990
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		55,900,956	59,461,488
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)		5,221,900	5,093,400
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)		161,724,216	160,670,899
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)		971,934	971,934
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		240,450,423	242,459,891
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)
38	AccountsPayable Accounts Payable (232)		189,096,488	262,396,791
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		184,500,000	46,000,000
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		19,039,633	40,520,348
41	CustomerDeposits Customer Deposits (235)		19,102,600	21,243,537
42	TaxesAccrued Taxes Accrued (236)	262	9,257,036	623,101
43	InterestAccrued Interest Accrued (237)		18,795,098	18,393,469
44	DividendsDeclared Dividends Declared (238)			8,570
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		1,674,663	2,277,194
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		46,873,374	48,071,823
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		1,534,577	1,083,477
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities
52	DerivativeInstrumentLiabilitiesHedges Derivative Instrument Liabilities - Hedges (245)
53	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54	CurrentAndAccruedLiabilities Total Current and Accrued Liabilities (lines 37 through 53)		489,873,469	440,618,310
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)		63,394,606	60,783,469
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	28,750,069	8,518,277
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	386,044,737	390,846,523
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reacquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		717,895,905	711,865,829
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		150,951,080	138,730,553
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		1,347,036,397	1,310,744,651
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		5,577,777,398	5,439,587,166

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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	507,864,657	488,865,541	259,988,211	238,074,589	507,864,657	488,865,541
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	239,554,602	230,249,296	118,812,887	110,716,615	239,554,602	230,249,296
5	MaintenanceExpense Maintenance Expenses (402)	320	86,436,404	62,583,219	42,038,794	30,162,138	86,436,404	62,583,219
6	DepreciationExpense Depreciation Expense (403)	336	62,446,272	58,897,054	31,400,313	29,629,541	62,446,272	58,897,054
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	4,349,887	4,751,687	2,040,413	2,438,971	4,349,887	4,751,687
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)
13	RegulatoryCredits (Less) Regulatory Credits (407.4)
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	34,103,815	33,257,098	17,165,917	17,001,867	34,103,815	33,257,098
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	4,780,167	23,718,398	998,386	12,613,510	4,780,167	23,718,398
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	1,166,383	7,715,334	6,588,193	4,833,360	1,166,383	7,715,334
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	100,423,439	72,333,232	47,026,792	35,647,735	100,423,439	72,333,232
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	90,606,422	97,464,193	53,519,255	52,348,313	90,606,422	97,464,193
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)		430,761,447	396,041,125	212,552,440	190,695,424	430,761,447	396,041,125
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		77,103,210	92,824,416	47,435,771	47,379,165	77,103,210	92,824,416
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)		1,204	1,204	606	606
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	6,223,220	5,486,169	3,231,314	2,917,607
37	InterestAndDividendIncome Interest and Dividend Income (419)		102,979	161,719	102,715	147,740
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		5,332,756	5,686,372	2,905,185	3,052,160
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		6,018,347	1,370,643	3,114,253	322,280
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		166,153	34,546	89,903	34,546
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		17,842,251	12,738,245	9,442,764	6,473,727
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		12,083	13,766	2,510	13,766
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		571,879	681,000	205,254	195,555
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)		42,022	29,500	26,522	17,000
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		312,475	339,210	172,236	231,430
49	OtherDeductions Other Deductions (426.5)		862,398	1,257,759	469,057	193,581
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		1,800,857	2,321,235	875,579	651,332
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	177,914	174,768	89,089	89,428
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	2,077,634	551,732	1,652,310	448,156
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	970,121	257,623	771,522	209,260
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	930,585	1,144,673	795,887	786,130
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272
57	InvestmentTaxCreditAdjustmentsNonutilityOperations Investment Tax Credit Adj.-Net (411.5)
58	InvestmentTaxCredits (Less) Investment Tax Credits (420)
59	TaxesOnOtherIncomeAndDeductions TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)		4,156,254	2,128,796	3,308,808	1,532,974
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		11,885,140	8,288,214	5,258,377	4,289,421
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		25,775,761	25,005,994	12,732,486	12,417,719
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		256,949	265,034	127,731	130,103
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		43,889	46,321	20,728	23,160
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)		3,484,148	43,995	2,326,624	43,995
68	OtherInterestExpense Other Interest Expense (431)		7,042,206	319,666	4,381,702	494,043
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		2,184,164	1,700,330	1,202,313	912,126
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		34,418,789	23,980,680	18,386,958	11,208,808
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		54,569,561	77,131,950	34,307,190	40,459,778
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)		54,569,561	77,131,950	34,307,190	40,459,778

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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		919,423,547	1,004,567,530
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		48,346,341	71,645,781
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)
23.1	DividendsDeclaredPreferredStock		17,139	17,139
29	DividendsDeclaredPreferredStock TOTAL Dividends Declared-Preferred Stock (Acct. 437)		17,139	17,139
30	DividendsDeclaredCommonStockAbstract Dividends Declared-Common Stock (Account 438)
30.1	DividendsDeclaredCommonStock			50,000,000
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)			50,000,000
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)		967,752,749	1,026,196,172
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)		967,752,749	1,026,196,172
	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 Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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)	54,569,561	77,131,950
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	62,446,272	58,897,054
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Regulatory Assets and Liabilities	26,715,790	926,387
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization and Depletion of Utility Plant	4,349,887	4,751,687
5.3	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Other Assets and Liabilities	282,596	424,431
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	10,747,602	23,986,288
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	4,812,483	31,295,695
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	11,388,421	1,905,459
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	60,101,017	2,161,832
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	149,227,220	14,899,353
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	10,310,169	49,761,667
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	5,332,756	5,686,372
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies	6,223,220	5,486,169
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other (provide details in footnote):	(a) 36,415,956	(c) 13,412,379
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Pension Expense	1,325,563	2,144,456
18.3	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Carrying Cost of Regulatory Assets and Liabilities	251,390	1,161,567
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	22,696,491	189,907,416
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)	121,460,991	118,190,801
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	5,332,756	5,686,372
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	116,128,235	112,504,429
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)
39	InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Investments in and Advances to Assoc. and Subsidiary Companies
40	ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies Contributions and Advances from Assoc. and Subsidiary Companies
41	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract Disposition of Investments in (and Advances to)
42	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
44	PurchaseOfInvestmentSecurities Purchase of Investment Securities (a)
45	ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a)
46	LoansMadeOrPurchased Loans Made or Purchased
47	CollectionsOnLoans Collections on Loans
49	NetIncreaseDecreaseInReceivablesInvestingActivities Net (Increase) Decrease in Receivables
50	NetIncreaseDecreaseInInventoryInvestingActivities Net (Increase) Decrease in Inventory
51	NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities Net (Increase) Decrease in Allowances Held for Speculation
52	NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities Net Increase (Decrease) in Payables and Accrued Expenses
53	OtherAdjustmentsToCashFlowsFromInvestmentActivities Other (provide details in footnote):
53.1	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Notes Receivable from Associated Companies
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Investment in Subsidiary Company		1,152,420
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	116,128,235	113,656,849
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
64.1	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Equity Infusion to Subsidiary		51,152,420
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Repayment of Short Term Debt Affiliates	138,500,000	42,500,000
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	138,500,000	93,652,420
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)		125,000,000
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Obligations Under Capital Leases	6,742
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock	17,139	17,139
81	DividendsOnCommonStock Dividends on Common Stock		50,000,000
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	138,476,119	81,364,719
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)	348,607	5,114,152
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	560,224	9,216,550
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	(b) 211,617	(d) 4,102,398

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

FOOTNOTE DATA

(a) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities


Other Net Utility Plant			(931,073)
Misc Deferred Debits			83,575
Provisions for Injuries and Damages			654,535
Other Post Retirement Benefits			(3,560,531)
Environmental Provision			128,500
Customer Advances for Construction			2,611,137
Other Deferred Credits			20,231,791
Accumulated Other Comprehensive Income			139,513

Prepayments			17,051,443

Other			7,066
			36,415,956

(b) Concept: CashAndCashEquivalents

Cash and Cash Equivalents at the end of the period consisted of:



Special Deposits (132-134)			205,430
Working Funds (135)			5,180
Temporary Cash Investments (136)			1,007
			211,617

(c) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities


Other Net Utility Plant			1,623,016
Misc. Deferred Debits			78,114
Provisions for Injuries and Damages			10,789,839
Other Post Retirement Benefits			(33,951,333)
Environmental Provision			5,200
Customer Advances for Construction			4,478,089

Other Deferred Credits			2,616,500
Accumulated Other Comprehensive Income			325,038

Prepayments			621,953

Other			1,205
			(13,412,379)

(d) Concept: CashAndCashEquivalents

Cash and Cash Equivalents at the end of the period consisted of:


Cash (131)			3,890,781
Special Deposits (132-134)			205,430
Working Funds (135)			5,180
Temporary Cash Investments (136)			1,007
			4,102,398

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

NOTES TO FINANCIAL STATEMENTS

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

As permitted by the FERC, for the 2023 FERC Form 3Q, the Notes to Financial Statements set forth below are principally from the Respondent's unaudited June 30, 2023 GAAP Financial Statements, which were filed with the New York Independent System Operator (NYISO), Pennsylvania Jersey Maryland Independent System Operator (PJM), and ISO New England, and with its lenders of its Revolving Credit Agreement and its other debt obligation indentures.

Financial statements: The accompanying financial statements were prepared in accordance with the

accounting requirements of the Federal Energy Regulatory Commission (FERC) as set forth in its applicable Uniform System of Accounts and published accounting releases, which constitutes a comprehensive basis of accounting other than principles generally accepted in the United States of America. As required by the FERC, the Respondent accounts for investments in majority-owned subsidiaries on the equity method.

The primary differences consist of the following:

a.Intercompany accounts are presented on a gross basis for FERC reporting but are netted together by counterparty for U.S. GAAP reporting.

b.For FERC reporting, regulatory assets and liabilities are presented on a gross basis and are classified as non-current. For U.S. GAAP reporting, regulatory assets and liabilities are presented on a net basis where appropriate and are classified as current or long-term as applicable.

c.The accumulated amounts collected in rates for cost of removal over spending are included within accumulated depreciation for FERC reporting, but are presented as a regulatory liability for U.S. GAAP reporting.

d.All debt is classified as long-term in the balance sheet for FERC reporting. Under U.S. GAAP, the presentation reflects current and long-term debt separately.

e.For FERC reporting, the debt issuance costs related to term loans are presented in the balance sheets within deferred charges and other assets. Under U.S. GAAP, this is presented in the balance sheets as a direct deduction from the carrying value of debt.

f.For FERC reporting, the liability for uncertain tax positions related to temporary differences is not recognized pursuant to FERC guidance and deferred taxes are recognized based on the difference between positions taken in filed tax returns and amounts reported in the financial statements. For U.S. GAAP reporting, the liability for uncertain tax positions related to temporary differences is recognized and deferred taxes are recognized based on the difference between the positions taken in filed tax returns adjusted for uncertain tax positions related to temporary differences and amounts reported in the financial statements.

g.For FERC reporting, deferred tax assets and liabilities are presented on a gross basis. For U.S. GAAP reporting, deferred tax assets and liabilities are presented on a net basis.

h.For FERC reporting, net periodic benefit cost for non-service component is presented in operations expense account 926 employee pensions and benefits. For U.S. GAAP reporting the non-service component is presented in other income and deductions.

Note 1. Significant Accounting Policies

Background and nature of operations: Central Maine Power Company and subsidiaries (CMP, the company, we, our, us) conduct regulated electricity transmission and distribution operations in Maine serving approximately 663,800 customers as of June 30, 2023, in a service territory of approximately 11,000 square miles with a population of approximately one million people. The service territory is

located in the southern and central areas of Maine and contains most of Maine’s industrial and commercial centers, including the city of Portland and the Lewiston-Auburn, Augusta-Waterville, Saco-Biddeford and Bath-Brunswick areas. We operate under the authority of the Maine Public Utilities Commission (MPUC) and are also subject to regulation by the Federal Energy Regulatory Commission (FERC).

CMP consists of the following subsidiaries: Maine Electric Power Company, Inc. (MEPCO) is a 78.3% owned subsidiary of CMP with the remaining 21.7% owned by Versant Power (Versant). Versant is wholly-owned by ENMAX Corp. Chester SVC Partnership (the Partnership or Chester) is a general partnership between NORVARCO, a wholly-owned subsidiary of CMP, which owns 50% interest in the Partnership and Bangor Var Co., Inc., a wholly-owned subsidiary of Versant, which owns the remaining 50% interest organized on October 9, 1990, under the Maine Uniform Partnership Act.

CMP is the principal operating utility of CMP Group, Inc. (CMP Group), a wholly-owned subsidiary of Avangrid Networks, Inc. (Networks), which is a wholly-owned subsidiary of Avangrid, Inc. (AGR), which is a 81.6% owned subsidiary of Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain.

Basis of presentation: The accompanying condensed financial statements should be read in conjunction with the annual financial statements in the FERC Form No. 1 for the fiscal year ended December 31, 2022.

The accompanying unaudited condensed financial statements for the interim periods have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) for interim financial information and with the instructions to FERC Form No. 3-Q. Accordingly, the interim condensed financial statements do not include all the information and note disclosures required by U.S. GAAP for complete financial statements.

In the opinion of management, the accompanying condensed financial statements contain all adjustments necessary to present fairly our condensed financial statements for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three months ended June 30, 2023, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2023.

Significant Accounting Policies and New Accounting Pronouncements: The new accounting pronouncements we have adopted as of January 1, 2023, and reflected in our condensed financial statements are described below. There have been no other material changes to the significant accounting policies described in our financial statements and FERC Form No. 1 for the fiscal year ended December 31, 2022, except for the those described below resulting from the adoption of new authoritative accounting guidance issued by Financial Accounting Standards Board (FASB).

Adoption of New Accounting Pronouncements

Although we are not a public business entity, our parent company is a public business entity; therefore, we adopt new accounting standards based on the effective date for public entities as permitted. There were no significant new accounting pronouncements adopted since January 1, 2023.

Accounting Pronouncements Issued But Not Yet Adopted

There are no new accounting pronouncements not yet adopted, including those issued since December 31, 2022, that will materially affect our condensed financial statements.

Note 2. Industry Regulation

Our revenues are regulated, being based on tariffs established in accordance with administrative procedures set by the various regulatory bodies. Distribution rates are established by the Maine Public Utilities Commission (MPUC) and transmission rates are established by the Federal Energy Regulatory Commission (FERC). The tariffs are applied based on the cost of providing service.

Electricity Distribution

The Maine distribution rate stipulation and the FERC Transmission Return on Equity (ROE) case are some of the most important specific regulatory processes that currently affect CMP.

The revenues of CMP are regulated, being based on tariffs established in accordance with administrative procedures set by the various regulatory bodies. The tariffs applied to regulated activities in the U.S. are approved by the regulatory commissions and are based on the cost of providing service. The revenues of each regulated utility are set to be sufficient to cover all its operating costs, including finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable ROE. Generally, tariff reviews cover various years and provide for a reasonable ROE and full reconciliation of exceptional costs as identified in CMP's rate plan.

Energy costs that are set on the New England wholesale markets are passed on to consumers by Competitive Energy Providers, licensed by the MPUC. Under Maine Law, transmission and distribution utilities are prohibited from providing retail energy supply. Default retail supply is provided by Standard Offer Providers periodically selected by the MPUC through a competitive procurement process.

Transmission - FERC ROE and Other FERC Matters

CMP’s transmission rates are determined by a tariff regulated by the FERC and administered by ISO New England, Inc. (ISO-NE). Transmission rates are set annually pursuant to a FERC authorized formula that allows for recovery of direct and allocated transmission operating and maintenance expenses, and for a return of and on investment in assets.

On September 30, 2011, the Massachusetts Attorney General, Massachusetts Department of Public Utilities, Connecticut Public Utilities Regulatory Authority, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a joint complaint with the FERC, pursuant to sections 206 and 306 of the Federal Power Act, against several New England Transmission Owners (NETOs) claiming that the approved base ROE of 11.14% used by NETOs in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) was not just and reasonable and seeking a reduction of the base ROE with refunds to customers for the 15-month refund periods beginning October 1, 2011 (Complaint I), December 27, 2012 (Complaint II), July 31, 2014 (Complaint III) and April 29, 2016 (Complaint IV).

On October 16, 2014, the FERC issued its final decision in Complaint I, setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 - December 2012 period as well as prospectively from October 16, 2014. On March 3, 2015, the FERC upheld its decision and further clarified that the 11.74% ROE cap will be applied on a project specific

basis and not on a transmission owner's total transmission return. The complaints were consolidated and the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, (1) for the fifteen month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the fifteen month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The initial decision in Complaints II and III is the administrative law judge’s recommendation to the FERC Commissioners.

CMP reserved for refunds for Complaints I, II and III consistent with the FERC’s Mach 3, 2015 decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP total reserve associated with Complaints II and III is $28.9 million as of June 30, 2023, which has not changed since December 31, 2022, except for the accrual of carrying costs. If adopted as final by the FERC, the impact of the initial decision by the FERC administrative law judge would be an additional aggregate reserve for Complaints II and III of $12.8 million, which is based upon currently available information for these proceedings.

Following various intermediate hearings, orders and appellate decisions, on October 16, 2018, the FERC issued an order directing briefs and proposing a new methodology to calculate the NETOs ROE that is contained in NETOs' transmission formula rate on file at the FERC (the October 2018 Order). Pursuant to the October 2018 Order, the NETOs filed initial briefs on the proposed methodology in all four Complaints on January 11, 2019, and replied to the initial briefs on March 8, 2019.

On November 21, 2019, the FERC issued rulings on two complaints challenging the base return on equity for Midcontinent Independent System Operator, or MISO transmission owners. These rulings established a new zone of reasonableness based on equal weighting of the DCF and capital-asset pricing model for establishing the base return on equity. This resulted in a base return on equity of 9.88% as the midpoint of the zone of reasonableness. Various parties have requested rehearing on this decision, which was granted. On May 21, 2020, the FERC issued a ruling, which, among other things, adjusted the methodology to determine the MISO transmission owners’ ROE, resulting in an increase in ROE from 9.88% to 10.02% by utilizing the risk premium model, or RPM, in addition to the DCF model and capital-asset pricing model under both prongs of Section 206 of the FPA, and calculated the zone of reasonableness into equal thirds rather than employing the quartile approach. Parties to these orders affecting the MISO transmission owners' base ROE petitioned for their review at the D.C. Circuit Court of Appeals in January 2021. The NETO's submitted an amici curia brief in support of the MISO transmission owners on March 17, 2021. On August 9, 2022, the D.C. Circuit Court vacated FERC's orders and remanded the matter back to FERC. The D.C. Circuit Court held that FERC failed to offer a reasoned explanation for its decision to reintroduce the RPM after initially, and forcefully, rejecting it and that because the FERC adopted that significant portion of its model in an arbitrary and capricious fashion, the new ROE produced by that model cannot stand. We cannot predict the potential impact the MISO transmission owners' ROE proceeding may have in establishing a precedent for the NETO's pending four Complaints.

On April 15, 2021, the FERC issued a supplemental Notice of Proposed Rulemaking (Supplemental NOPR) that proposes to eliminate the 50 basis-point ROE incentive for utilities who join Regional Transmission Organizations after three years of membership. The NETOs submitted initial comments in opposition to the Supplemental NOPR on June 25, 2021 and reply comments on July 26, 2021. If the elimination of the 50 basis-point ROE incentive adder becomes final, we estimate we would have an approximately $1 million reduction in earnings per year. We cannot predict the outcome of this proceeding.

CMP Distribution Rate Stipulation and New Renewable Source Generation

In an order issued on February 19, 2020, the MPUC authorized an increase in CMP's distribution revenue requirement of $17.4 million, or approximately 6.9%, based on an allowed ROE of 9.25% and a 50.00% equity ratio. The rate increase was effective March 1, 2020. Commencing on March 1, 2020, the MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017 which would be removed after demonstrating satisfactory customer service performance. In September 2021, CMP met the 18-month required rolling average satisfactory customer service benchmarks and filed with the MPUC a request for removal of the management efficiency adjustment, which was approved by the MPUC effective as of its February 18, 2022 order.

The Order provided additional funding for staffing increases, vegetation management programs and storm restoration costs, while retaining the basic tiered structure for storm cost recovery implemented in the 2014 stipulation. The MPUC Order also retained the RDM implemented in 2014. The Order denied CMP’s request to increase rates for higher costs associated with services provided by its affiliates and ordered the initiation of a management audit to evaluate whether CMP's current management structure, and the management and other services from its affiliates, are appropriate and in the interest of Maine customers. The management audit was commenced in July 2020 by the MPUC's consultants and culminated with a report issued by the MPUC’s consultants in July 2021. On February 18, 2022, the MPUC opened a narrowly tailored follow-on investigation examining how CMP and its customers are affected by decisions made at the CMP corporate parent level about earnings, capital budgeting, and planning. In this context, the investigation will also examine regulatory approaches and structures including ratemaking and performance mechanisms. In an order dated February 7, 2023, the MPUC closed this investigation after consolidating its records with CMP's pending rate case.

In accordance with Chapter 120 of MPUC Rules, on May 26, 2022, CMP filed a nonbinding notice of intent to file a distribution rate case on or after sixty days from the issuance of the letter. In the notice, CMP signaled its intent to propose a three-year rate plan, which includes a multi-year capital investment plan to fund investments needed to improve reliability and resiliency, as well as to continue to improve the customer experience and cost-effectively advance clean energy transformation. CMP’s notice estimated a revenue change in the range of $45 to $50 million in the first year of the rate plan followed by increases in the range of $25 to $30 million in the second year and $20 to $25 million in the third year. We cannot predict the outcome of this matter.

On August 11, 2022, CMP filed a three-year rate plan, with adjustments to the distribution revenue requirement in each year. In its filing, CMP has set the three rate years as August 1, 2023 to July 31, 2024 (“Rate Year 1”); August 1, 2024 to July 31, 2025 (“Rate Year 2”); and August 1, 2025 to July 31, 2026 (“Rate Year 3”). The requested Rate Year revenue requirement increases for the rate years are $48 million, $28 million and $23 million, respectively. The revenue requirement adjustments are based on a test year ending December 31, 2021. The requested revenue changes for each rate year of the proposal are subject to a number of adjustment mechanisms most significantly including: (1) an annual review of plant additions with potential downward reconciliation in the event of an underspend, (2) a capital adjustment mechanism for certain incremental pole replacements, broadband work, electric vehicle work, energy storage projects, and metering system upgrades, (3) a symmetrical inflation reconciliation adjustment, and (4) symmetrical reconciliation of the Company's tax basis repair deduction. Other parties filed direct testimony in this proceeding on December 2, 2022 and CMP filed rebuttal testimony on February 7, 2023. Settlement discussions are on-going and technical conferences are scheduled for mid-May 2023. New rates are expected to take effect on or around August 2023. We cannot predict the outcome of this matter.

Pursuant to Maine law, the MPUC is authorized to conduct periodic requests for proposals seeking long-term supplies of energy, capacity or Renewable Energy Certificates, or RECs, from qualifying resources. The MPUC is further authorized to order Maine Transmission and Distribution Utilities to enter into contracts with sellers selected from the MPUC’s competitive solicitation process. Pursuant to a MPUC Order dated October 8, 2009, CMP entered into a 20-year agreement with Evergreen Wind Power III, LLC, on March 31, 2010, to purchase capacity and energy from Evergreen’s 60 MW Rollins wind farm in Penobscot County, Maine. CMP’s purchase obligations under the Rollins contract are approximately $9 million per year. Pursuant to a MPUC Order dated December 18, 2017, CMP entered into a 20-year agreement with Dirigo Solar, LLC on September 10, 2018, to purchase capacity and energy from multiple Dirigo solar facilities throughout CMP's service territory. CMP's purchase obligations under the Dirigo contract will increase as additional solar facilities are brought on line, eventually reaching a level of approximately $2.5 million per year. Pursuant to a MPUC Order dated November 6, 2019, CMP entered into a 20-year agreement with Maine Aqua Ventus I GP LLC on December 9, 2019, to purchase capacity and energy from an off-shore wind farm under development near Monhegan Island, Maine. CMP's purchase obligations under the Maine Aqua Ventus contract will be approximately $12 million per year once the facility begins commercial operation. On September 11, 2020 the project was assigned to New England Aqua Ventus, LLC. Pursuant to Maine law, the MPUC conducted two competitive solicitation processes to procure, in the aggregate, an amount of energy or RECs from Class 1A resources that is equal to 14% of retail electricity sales in the State during calendar year 2018, or 1.715 Million MWh. Of that 14% total, the MPUC must acquire at least 7%, but not more than 10%. Through contracts approved in December 2020 (Tranche 1), CMP was ordered to execute 13 contracts, 2 contracts terminated in 2022 prior to achieving Commercial Operations. In October 2021 CMP executed contracts with 6 additional facilities (Tranche 2), 1 contract terminated in 2023 prior to achieving Commercial Operations. Each of the Tranche 1 and Tranche 2 are for 20-year terms. In accordance with MPUC orders, CMP either sells the purchased energy, or in one case the RECs, from these facilities in the ISO New England markets, through periodically auctioning the purchased output to wholesale buyers in the New England regional market, or through a sale to a third party for the RECs. Under Maine law, CMP is assured recovery of any differences between power purchase costs and achieved market revenues through a reconcilable component of its retail distribution rates. Although the MPUC has conducted multiple requests for proposals under Maine law, and has tentatively accepted term sheet proposals for long-term contracts from other sellers, these selections have not yet resulted in additional currently effective contracts with CMP.

Summary Investigation into Security Limits Litigation

On December 13, 2021, the MPUC issued a Notice initiating a summary investigation of certain allegations with respect to the recovery of capital expenditure costs contained in the lawsuit filed by Security Limits, Inc. and Paul Silva against the Company, Networks and Iberdrola, S.A. and several other entities and individuals in the United States District Court Southern District of New York. CMP filed a report describing any costs described in the complaint that are currently being recovered or will be recovered in rates on January 18, 2022 as directed by the Notice of Summary Investigation. In the report, CMP noted that the plaintiffs’ had not yet served the complaint upon Networks or the Company. The MPUC directed CMP to submit notification to the MPUC when the Complaint has been served or when the procedural deadline for serving the Complaint has passed. On February 9, 2022, Security Limits, Inc. and Paul Silva dismissed their complaint. On February 10, 2022, CMP notified the MPUC of the dismissal and requested that the proceeding be closed. Subsequently on March 8, 2022, the MPUC issued an Order closing the investigation.

Minimum Equity Requirements for Regulated Subsidiaries

CMP is subject to a minimum equity ratio requirement that is tied to the capital structure assumed in establishing revenue requirements. Pursuant to these requirements CMP must maintain a minimum equity ratio equal to the ratio in its currently effective rate plan or decision measured using a trailing 13-month average. On a monthly basis CMP must maintain a minimum equity ratio of no less than 300 basis points below the equity ratio used to set rates. The minimum equity ratio requirement has the effect of limiting the amount of dividends that may be paid and may, under certain circumstances, require that the parent contribute equity capital. CMP is prohibited by regulation from lending to unregulated affiliates. CMP has also agreed to minimum equity ratio requirements in certain short-term borrowing agreements. These requirements are lower than the regulatory requirements. We are in compliance with these requirements.

Note 3. Regulatory Assets and Liabilities

Pursuant to the requirements concerning accounting for regulated operations we capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific order, we use regulatory precedent to determine if recovery is probable. We also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. Of the total regulatory assets net of regulatory liabilities, approximately $225.7 million represents the offset of accrued liabilities for which funds have not been expended. The remainder is either included in rate base or accruing carrying costs.

Details of other regulatory assets and other regulatory liabilities are shown in the tables below. They result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment.

Regulatory assets as of June 30, 2023 and December 31, 2022 consisted of:


	June 30,		December 31,
As of	2023		2022
(Thousands)
Asset retirement obligation	$	965	$	965
Deferred meter replacement costs	20,122		21,043
Environmental remediation costs	455		318
Federal tax depreciation normalization adjustment	12,869		13,087
Non-bypassable charges (stranded costs)	74,145		14,497
Pension and other post retirement benefits	79,154		79,154
Pension and other post retirement benefits cost deferrals	11,753		11,753
Storm costs	166,261		121,388
Transmission revenue reconciliation mechanism	5,218		10,890
Unamortized losses on reacquired debt	122		166
Unfunded future income taxes	201,894		189,008
Other	3,406		2,713
Total regulatory assets	576,364		464,982
Less: current portion	83,921		60,653
Total non-current regulatory assets	$	492,443	$	404,329

Asset retirement obligations represent the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability.

Deferred meter replacement costs represent the deferral of the net book value of retired meters which were replaced by advanced metering infrastructure meters. This amount is being amortized at the related existing depreciation amounts.

Environmental remediation costs include spending that has occurred and is eligible for future recovery in customer rates. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs.

Federal tax depreciation normalization adjustment represents the deferral of the normalization of change impacts in book lives and the pass back of theoretical reserves associated with Power Tax deferred income tax.

Non-bypassable charges (stranded costs) represents costs that resulted from government-mandated long term Purchased Power Agreement (PPA) contracts between CMP and power producers at prices above current market rates which must be resold to the market at the current going rate. These costs and assets became stranded as CMP was prohibited from owning power and was therefore forced to sell the power back at the market rate, significantly lower than the PPA price. The monthly stranded cost over/under expense compared to revenue is recorded to be recovered in future years.

Pension and other postretirement benefits represent the actuarial losses on the pension and other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. Because no funds have yet been expended for this regulatory asset, it does not accrue carrying costs and is not included within the rate base.

Pension and other postretirement benefits cost deferrals represent the distribution related portion of lump-sum pension settlement expense to be amortized in future rates.

Storm costs are allowed in rates based on an estimate of the routine costs of service restoration. CMP is also allowed to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. CMP’s total deferral, including carrying costs, was $166.3 million at June 30, 2023 and $121.4 million at December 31, 2022.

Transmission revenue reconciliation mechanism reflects any differences in actual costs in the rate year from those used to set rates. The ATU (Annual Transmission True Up) portion is recovered over the subsequent January to December period. When the ATU is known we record it as a regulatory asset (regulatory liability), with an offset to revenues, and amortize it over the twelve-month period as the related revenues are collected (refunded).

Unamortized losses on reacquired debt represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt.

Unfunded future income taxes represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates.

Other includes various items subject to reconciliation such as CRM&B (Billing System Costs), OPA Assessment for Non-Wire Alternatives, 100 BP Recovery, Rate Case Expenses and Electric Lifeline Program (ELP).

Regulatory liabilities as of June 30, 2023 and December 31, 2022 consisted of:


	June 30,		December 31,
As of	2023		2022
(Thousands)
Accrued removal obligations	$	31,398	$	32,434
Environmental remediation costs	1,462		1,228
Rate refund - FERC ROE proceeding	28,911		27,852
Revenue decoupling mechanism	8,913		13,314
Tax Act - remeasurement	269,685		274,691
Transmission revenue reconciliation mechanism	69,754		63,775
Other	1,223		1,723
Total regulatory liabilities	411,346		415,017
Less: current portion	91,366		86,937
Total non-current regulatory liabilities	$	319,980	$	328,080

Accrued removal obligations represent the differences between asset removal costs incurred and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant.

Rate refund - FERC ROE proceedings: see Note 2.

Revenue Decoupling Mechanism represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales.

Tax Act – re-measurement represents the impact from re-measurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates from 35% to 21% under the provisions of the Tax Act will result in amounts previously collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates.

Transmission revenue reconciliation mechanism reflects any differences in actual costs in the rate year from those used to set rates. The ATU is recovered over the subsequent January to December period. When the ATU is known we record it as a regulatory asset (regulatory liability), with an offset to revenues, and amortize it over the twelve-month period as the related revenues are collected (refunded).

Other includes various items subject to reconciliation such as ELP, Demand Side Management and Vegetation Management.

Note 4. Revenue

We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of ASC 606, such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any material significant payment terms because we receive payment at or shortly after the point of sale.

The following describes the principal activities from which we generate revenue.

CMP derives its revenue primarily from tariff-based sales of electricity service to customers in the Maine area with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity.

Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. Maine state law prohibits the utility from providing the electricity commodity to customers. For customers that receive their commodity from another supplier, the utility acts as an agent and delivers the electricity provided by that supplier. Revenue in those cases is only for providing the service of delivery of the commodity.

Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to FERC regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts.

The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as CMP delivers or sells the electricity or provides the transmission service.

CMP records revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. CMP ARPs include revenue decoupling mechanisms, other ratemaking mechanisms, annual revenue requirement reconciliations, and other demand side management programs.

CMP also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property, and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, ARPs, or other activities.

Revenues disaggregated by major source for the periods ended June 30, 2023 and 2022 are as follows:



Three Months Ended June 30,	2023		2022
(Thousands)
Regulated operations – electricity	$	149,597	$	225,728
Other(a)	8,098		13,306
Revenue from contracts with customers	157,695		239,034
Leasing revenue	757		394
Alternative revenue programs	6,470		1,025.00
Other revenue	3,741		15,569
Total operating revenues	$	168,663	$	256,022


Six Months Ended June 30,	2023		2022
(Thousands)
Regulated operations – electricity	$	400,657	$	470,303
Other(a)	4,759		20,545
Revenue from contracts with customers	405,416		490,848
Leasing revenue	1,139		801
Alternative revenue programs	9,335		1,025.00
Other revenue	7,723		19,600
Total operating revenues	$	423,613	$	512,274

(a)Primarily includes certain intra-month trading activities, billing, collection, and administrative charges, sundry billings, and other miscellaneous revenue.

As of June 30, 2023 and December 31, 2022, nearly all of the accounts receivable balances included in “Accounts receivable and unbilled revenues, net” on our condensed balance sheets are related to contracts with customers and include unbilled revenues of $38.6 million and $41.0 million, respectively.

.

Note 5. Income Taxes

The effective tax rate for the six months ended June 30, 2023 was 16.3%, which was lower than the 21% statutory federal income tax rate due predominately to excess ADIT amortization and property related flow through, partially offset by state taxes. The effective tax rate for the six months ended June 30, 2022 was 12.1%, which was lower than the 21% statutory federal income tax rate due predominately to excess ADIT amortization and property related flow through, partially offset by state taxes.

Note 6. Bank Loans and Other Borrowings

CMP had $184.5 million short-term debt outstanding at June 30, 2023 and $46.0 million at December 31, 2022. CMP funds short-term liquidity needs through an agreement among Avangrid’s regulated utility subsidiaries (the “Virtual Money Pool Agreement”), a bi-lateral intercompany credit agreement with Avangrid (the “Bi-Lateral Intercompany Facility”) and a bank provided credit facility to which CMP is a party (the “AGR Credit Facility”), each of which are described below.

The Virtual Money Pool Agreement is an agreement among the investment grade-rated, regulated utility subsidiaries of Avangrid under which the parties to this agreement may lend to or borrow from each other. This Agreement allows Avangrid to optimize cash resources within the regulated utility companies which are prohibited by regulation from lending to unregulated affiliates. The interest rate on transactions under this agreement is the A2/P2 non-financial 30-day commercial paper rate published by the Federal Reserve. CMP has a lending/borrowing limit of $100 million under this agreement. CMP had no debt outstanding at June 30, 2023 and $7.0 million outstanding at December 31, 2022.

The Bi-Lateral Intercompany Facility provides for borrowing of up to $500 million from Avangrid at the A2/P2 non-financial 30-day commercial paper rate published by the Federal Reserve. CMP had $184.5 million outstanding under this agreement at June 30, 2023 and $39.0 million outstanding at December 31, 2022.

On November 23, 2021, Avangrid and its investment-grade rated utility subsidiaries (New York State Electric & Gas Corporation (“NYSEG”), Rochester Gas and Electric Corporation (“RG&E”), CMP, The United Illuminating Company (“UI”), Connecticut Natural Gas Corporation (“CNG”), The Southern Connecticut Gas Company ("SCG") and The Berkshire Gas Company (“BGC”)) executed a new credit facility with an aggregate limit of $3,575 million and a termination date of November 23, 2026. Under the terms of the AGR Credit Facility, each borrower has a maximum borrowing entitlement, or sublimit, which can be periodically adjusted to address specific short-term capital funding needs, subject to the maximum limit contained in the agreement. NYSEG has a maximum sublimit of $700 million, RG&E has $300 million, CMP has $200 million, UI has $250 million, CNG and SCG have maximum sublimits of $150 million and BGC has a maximum sublimit of $50 million. Effective on November 23, 2021, the AGR Credit Facility was amended to increase Avangrid’s maximum sublimit to $2,500 million and to establish minimum sublimits of $500 million for NYSEG, $200 million for RG&E, $100 million for CMP, $150 million for UI, $50 million for CNG and SCG and $25 million for BGC. Under the AGR Credit Facility, each of the borrowers are charged a facility fee that is dependent on their credit rating. The facility fees range from 10 to 22.5 basis points. CMP had no borrowings outstanding under this agreement at June 30, 2023 and December 31, 2022.

In the AGR Credit Facility we covenant not to permit, without the consent of the lender, our ratio of total indebtedness to total capitalization to exceed 0.65 to 1.00 at any time. For purposes of calculating the maximum ratio of indebtedness to total capitalization, the facility excludes from net worth the balance of

accumulated other comprehensive loss as it appears on the balance sheet. The facility contains various other covenants, including a restriction on the amount of secured indebtedness we may maintain. Continued un-remedied failure to comply with those covenants for five business days after written notice of such failure from the lender constitutes an event of default and would result in acceleration of maturity. Our ratio of indebtedness to total capitalization pursuant to the revolving credit facility was 0.4 to 1.00 at June 30, 2023. We are not in default as of June 30, 2023.

Note 7. Redeemable Preferred Stock

We have redeemable preferred stock that contains a feature that could lead to potential redemption-triggering events that are not solely within our control.

At March 31, 2023 and December 31, 2022, our redeemable preferred stock was:


					Amount
					(Thousands)
Series	Par Value per Share		Redemption Price per Share	Shares Authorized and Outstanding(1)	2023		2022
CMP, 6% Noncallable	$	100	—	5,713	$	571	$	571
Total					$	571	$	571

(1) At March 31, 2023 and December 31, 2022 CMP had 2,300,000 shares of $100 par value preferred stock authorized but unissued.

CMP Group owns 3,792 shares of the 5,713 shares outstanding.

Note 8. Environmental Liability

From time to time environmental laws, regulations and compliance programs may require changes in our operations and facilities and may increase the cost of electric service.

Waste sites

The Environmental Protection Agency (EPA) and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at five waste sites. The five sites do not include sites where coal gas was manufactured in the past, which are discussed below. With respect to the five sites, two sites are included in Maine's Uncontrolled Sites Program (MUSP), one is subject to Maine's Waste Management Programs and one is included on the Massachusetts Non-Priority Confirmed Disposal Site list. Two of the sites are also included on the National Priorities list. Any liability may be joint and several for certain of those sites. We have recorded an estimated liability of $1.5 million related to the five sites at June 30, 2023.

We have recorded an estimated liability of $3.4 million at June 30, 2023, related to three additional sites where we believe it is probable that we will incur remediation costs and/or monitoring costs as a result of being regulated under State Resource Conservation and Recovery Act (RCRA) program. It is reasonably possible the ultimate cost to remediate the sites may be significantly more than the accrued amount. Our estimate for costs to remediate the nine total sites ranges from $4.2 million to $10.5 million as of June 30, 2023. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the portion attributed to us. We recorded a

corresponding regulatory asset, net of insurance recoveries, because we expect to recover the net costs in rates.

Manufactured gas plants

We have a program to investigate and perform necessary remediation and/or monitoring at our three sites where coal gas was manufactured in the past. The three sites are in Maine's Voluntary Response Action Program, Brownfield Cleanup Program or MUSP.

Our estimate for costs related to investigation, remediation and/or monitoring of the sites ranges from $0.1 million to $0.2 million at June 30, 2023. The estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action, changes in technology relating to remedial alternatives, changes due to property use and changes to current laws and regulations.

The liability to investigate and perform remediation, as necessary, at the known inactive coal gas manufacturing sites was $0.2 million at June 30, 2023 and $0.2 million at December 31, 2022. We recorded a corresponding regulatory asset because we expect to recover the net costs in rates.

Our environmental liabilities are recorded on an undiscounted basis.

Note 9. Accounting for Derivative Instruments and Hedging Activities

We are exposed to certain risks relating to our ongoing business operations. The primary risk we manage by using derivative instruments is commodity price risk. In accordance with the accounting requirements concerning derivative instruments and hedging activities, we recognize all derivative instruments as either assets or liabilities at fair value on our balance sheet. For financial statement presentation, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement.

The financial instruments we hold or issue are not for trading or speculative purposes.

Cash flow hedging: Our fleet fuel hedges are designated as cash flow hedging instruments. We record changes in the fair value of the cash flow hedging instruments in other comprehensive income (OCI), to the extent they are considered effective, and reclassify those gains or losses into earnings in the same period or periods during which the hedged transactions affect earnings.

We did not have any derivatives designated as hedging instruments as of June 30, 2023 and December 31, 2022.

The effect of hedging instruments on OCI and income was:



Three Months Ended June 30,	Gain Recognized in OCI on Derivatives		Location of Gain (Loss) Reclassified From Accumulated OCI into Income	(Loss) Gain Reclassified From Accumulated OCI into Income		Total Amount per Income Statement
(Thousands)
2023
Interest rate contracts	$	—	Interest expense	$	(45)	$	18,394

Total	$	—		$	(45)

2022
Interest rate contracts	$	—	Interest expense	$	(45)	$	11,202
Commodity contracts: Other	302		Operations and maintenance	366		$	134,067
Total	$	302		$	321


Six Months Ended June 30,	Gain Recognized in OCI on Derivatives		Location of (Loss) Gain Reclassified From Accumulated OCI into Income	(Loss) Gain Reclassified From Accumulated OCI into Income		Total Amount per Income Statement
(Thousands)
2023
Interest rate contracts	$	—	Interest expense	$	(91)	$	34,611

Total	$	—		$	(91)

2022
Interest rate contracts	$	—	Interest expense	$	(91)	$	23,970
Commodity contracts: Other	764		Operations and maintenance	530		$	275,170
Total	$	764		$	439

The amount in AOCI related to previously settled interest rate hedging contracts at June 30, 2023 is a net loss of $2.0 million as compared to a net loss of $2.1 million at December 31, 2022. For the six month period ended June 30, 2023, we recorded $0.1 million in net derivative losses related to discontinued cash flow hedges. We will amortize approximately $0.1 million of discontinued cash flow hedges for the remainder of 2023.

Note 10. Fair Value of Financial Instruments and Fair Value Measurements

The estimated fair value of debt amounted to $1,181 million as of June 30, 2023 and $1,182 million as of December 31, 2022. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rate curve used to make these calculations takes into account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value hierarchy for the fair value of debt is considered as Level 2.

Assets and liabilities measured at fair value on a recurring basis

There were no financial instruments measured at fair value as of June 30, 2023 and December 31, 2022.

We had no transfers to or from Level 1 and 2 at June 30, 2023 and December 31, 2022. Our policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that causes a transfer, if any.

Valuation techniques: We measure the fair value of our noncurrent investments available for sale using quoted market prices in active markets for identical assets and include the measurements in Level 1. The investments primarily consist of money market funds.

We entered into fuel derivative contracts to hedge our unleaded and diesel fuel requirements for our fleet vehicles. Exchange based forward market prices were used but because a basis adjustment is added to the forward prices, we included the fair value measurement for these contracts in Level 3. As of December 31, 2022, the fleet fuel program was discontinued.

Instruments measured at fair value on a recurring basis using significant unobservable inputs



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
		Derivatives, Net
Three Months Ended June 30,		2023		2022
(Thousands)
Beginning balance		$	—	$	336
Total (losses) gains (realized/unrealized)
Included in earnings		—		(366)
Included in other comprehensive income		—		302
Ending balance		$	—	$	272


	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
		Derivatives, Net
Six Months Ended June 30,		2023		2022
(Thousands)
Beginning balance		$	—	$	38
Total (losses) gains (realized/unrealized)
Included in earnings		—		(530)
Included in other comprehensive income		—		764
Ending balance		$	—	$	272

The amounts of realized and unrealized gain and loss included in earnings for the period (above) are reported in Operations and maintenance of the consolidated statements of income.

Note 11. Accumulated Other Comprehensive Loss


	As of December 31, 2021		2022 Change		As of June 30, 2022		As of December 31, 2022		2023 Change		As of June 30, 2023
(Thousands)
Amortization of pension cost for nonqualified plans and current year actuarial gain, net of income tax	$	(1,896)	$	—	$	(1,896)	$	(1,672)	$	35	$	(1,637)
Unrealized gain (loss) on derivatives qualified as hedges:
Unrealized gain during period on derivatives qualified as hedges, net of income tax expense of $214 for 2022			550						—
Reclassification adjustment for loss included in net income, net of income tax (benefit) of $(149) for 2022			(381)						—
Reclassification adjustment for loss on settled cash flow treasury hedges, net of income tax expense of $26 for 2022 and $25 for 2023			65						66
Net unrealized gain (loss) on derivatives qualified as hedges	(1,647)		234		(1,413)		(1,544)		66		(1,478)
Accumulated Other Comprehensive Loss	$	(3,543)	$	234	$	(3,309)	$	(3,216)	$	101	$	(3,115)

Note 12. Post-retirement and Similar Obligations

The components of net periodic benefit cost for pension and postretirement benefits for the periods ended June 30, 2023 and 2022, respectively, consisted of:



	Pension Benefits				Postretirement Benefits
Three Months Ended June 30,	2023		2022		2023		2022
(Thousands)
Net periodic benefit cost
Service cost	$	426	$	1,130	$	75	$	134
Interest cost	3,422		3,155		745		623
Expected return on plan assets	(4,510)		(4,674)		(252)		(331)
Amortization of prior service (credit)	—		—		—		(159)
Amortization of net loss	—		1,106		—		330
Net periodic benefit cost	$	(662)	$	717	$	568	$	597


	Pension Benefits				Postretirement Benefits
Six Months Ended June 30,	2023		2022		2023		2022
(Thousands)
Net periodic benefit cost
Service cost	$	852	$	2,413	$	149	$	268
Interest cost	6,843		6,138		1,490		1,246
Expected return on plan assets	(9,021)		(10,135)		(504)		(661)
Amortization of prior service (credit)	—		—		—		(319)
Amortization of net loss	—		3,728		—		661
Net periodic benefit cost	$	(1,326)	$	2,144	$	1,135	$	1,195

Note 13. Other Income and Other Deductions



Three Months Ended June 30,	2023		2022
(Thousands)

Interest and dividends income	$	2,712	$	970
Allowance for funds used during construction	2,904		3,059
Carrying costs on regulatory assets	482		(609)
Equity earnings	15		14
Miscellaneous	490		147
Total other income	$	6,603	$	3,581
Pension non-service components	$	588	$	(17)
Miscellaneous	(660)		(652)
Total other deductions	$	(72)	$	(669)

Note 14. Related Party Transactions

Certain Networks subsidiaries, including CMP, borrow from AGR, the parent of Networks, through intercompany revolving credit agreements. For CMP, the intercompany revolving credit agreements provide access to supplemental liquidity. See Note 6 for further detail on the credit facility with AGR.

AGR, through its affiliates, provides administrative and management services to Networks operating utilities, including CMP, pursuant to service agreements. The cost of those services is allocated in accordance with methodologies set forth in the service agreements. The cost allocation methodologies vary depending on the type of service provided. Management believes such allocations are reasonable. The charge for operating and capital services provided to CMP by AGR and its affiliates for the six months ended June 30, 2023 and 2022 was $23.6 million and $22.0 million. The charge for services provided by CMP to AGR and its subsidiaries were approximately $2.7 million and $2.5 million for the six months ended June 30, 2023 and 2022. All of the charges associated with services provided are recorded as revenues to offset other operating expenses on the financial statements.

The balance in accounts payable to affiliates of $19.3 million at June 30, 2023 and $40.9 million at December 31, 2022 is mostly payable to Avangrid Service Company. The balance in accounts receivable from affiliates of $2.1 million at June 30, 2023 and $6.9 million at December 31, 2022 is mostly receivable from New England Clean Energy Connect.

The balance in notes receivable from affiliates was $0.2 million at June 30, 2023 and December 31, 2022. Notes receivable from affiliates relate to the Virtual Money Pool Agreement as discussed in Note 6 of these financial statements. The balance in notes payable to affiliates of $184.5 million and $46.0 million at June 30, 2023 and December 31, 2022 is payable to Avangrid. Notes payable to affiliates relate to the Virtual Money Pool Agreement and the Bi-Lateral Intercompany Facility as discussed in Note 6 of these financial statements.

.

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. Report data on a year-to-date basis.
Line No.	Item (a)	Unrealized Gains and Losses on Available-For-Sale Securities (b)	Minimum Pension Liability Adjustment (net amount) (c)	Foreign Currency Hedges (d)	Other Adjustments (e)	Other Cash Flow Hedges Interest Rate Swaps (f)	Other Cash Flow Hedges [Specify] (g)	Totals for each category of items recorded in Account 219 (h)	Net Income (Carried Forward from Page 116, Line 78) (i)	Total Comprehensive Income (j)
1	Balance of Account 219 at Beginning of Preceding Year		1,811,344			1,760,128	28,677	3,542,795
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income					52,520	409,664	357,144
3	Preceding Quarter/Year to Date Changes in Fair Value						590,993	590,993
4	Total (lines 2 and 3)					52,520	181,329	233,849	77,131,950	77,365,799
5	Balance of Account 219 at End of Preceding Quarter/Year		1,811,344			1,707,608	210,006	3,308,946
6	Balance of Account 219 at Beginning of Current Year		1,587,827			1,627,968		3,215,795
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income					65,236		65,236
8	Current Quarter/Year to Date Changes in Fair Value		35,137					35,137
9	Total (lines 7 and 8)		35,137			65,236		100,373	54,569,561	54,669,934
10	Balance of Account 219 at End of Current Quarter/Year		1,552,690			1,562,732		3,115,422

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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)	4,514,938,329	4,514,938,329
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	(a) 18,310,812	18,310,812
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	551,811,189	551,811,189
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	5,085,060,330	5,085,060,330
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	3,528,884	3,528,884
11	ConstructionWorkInProgress Construction Work in Progress	246,283,873	246,283,873
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	331,976,097	331,976,097
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	5,666,849,184	5,666,849,184
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	1,468,829,215	1,468,829,215
15	UtilityPlantNet Net Utility Plant (13 less 14)	4,198,019,969	4,198,019,969
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	1,331,883,520	1,331,883,520
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	125,570,132	125,570,132
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	1,457,453,652	1,457,453,652
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	2,338	2,338
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)	2,338	2,338
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	11,373,225	11,373,225
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	1,468,829,215	1,468,829,215

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

FOOTNOTE DATA

(a) Concept: UtilityPlantInServicePropertyUnderCapitalLeases


Capital			3,618,888
Operating			14,691,924
Property Under Capital Leases			18,310,812

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

Electric Plant In Service and Accum Provision For Depr by Function
Report below the original cost of plant in service by function. In addition to Account 101, include Account 102, and Account 106. Report in column (b) the original cost of plant in service and in column(c) the accumulated provision for depreciation and amortization by function.
Line No.	Item (a)	Plant in Service Balance at End of Quarter (b)	Accumulated Depreciation And Amortization Balance at End of Quarter (c)
1	Intangible Plant	163,227,233	125,570,132
2	Steam Production Plant
3	Nuclear Production Plant
4	Hydraulic Production - Conventional
5	Hydraulic Production - Pumped Storage
6	Other Production
7	Transmission	2,565,662,643	631,771,409
8	Distribution	1,872,035,521	518,381,455
9	Regional Transmission and Market Operation
10	General	465,824,121	181,730,655
11	TOTAL (Total of lines 1 through 10)	5,066,749,518	1,457,453,651

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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	Detroit Projects	144,198	561.6		—
3	Kimball Projects	131,603	561.6		—
4	Augusta Projects	125,847	561.6		—
5	CMP Projects Interconnect	124,988	561.6		—
6	Greater Projects	119,160	561.6		—
7	Sanford Projects	113,974	561.6		—
8	Louden Projects	112,515	561.6		—
9	Winslow Projects	103,340	561.6		—
10	Midcoast Projects	101,348	561.6		—
11	Fairfield Solar	100,635	561.6		—
12	Wyman Projects	87,799	561.6		—
13	Green Apple Solar Power	34,193	561.6		—
14	Sturtev Projects	33,065	561.6		—
15	Raymond Projects	30,731	561.6		—
16	Roxbury Projects	26,715	561.6		—
17	Other	65,480	561.6		—
18	0		—		—
20	Total	1,455,591
21	Generation Studies
22	0		—		—
23	Electric transmission - Generator interconnection	256,589	561.7		—
39	Total	256,589
40	Grand Total	1,712,180

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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	Advanced Meter Infrastructure - Carrying Cost; Docket Nos. 2007-215, 2008-111 ,2010-051 (II) (Amortization period ending 06/2033)	7,414,925		456	180,881	7,234,044
2	One Month Lag for Distribution Level Customers; Docket No. RT04-2, ER09-938 (Amortization period ending 12/2023)	9,018,552		456	2,921,982	6,096,570
3	Advanced Meter Infrastructure - O&M Cost; Docket Nos. 2007-215, 2008-111, 2010-051(II) (Amortization period ending 06/2033)	6,779,744		905	165,480	6,614,264
4	Non-Wire Alternative Docket 2022-00041 (Amortization period ending 06/2023)	1,019,011	104,669	456	178,386	945,294
5	Advanced Meter Infrastructure - Cost Savings; Docket Nos. 2007-215, 2008-111, 2010-051(II) (Amortization period ending 06/2033)	3,111,793		456	75,358	3,036,435
6	Pension Cost Deferral Docket 2013-168, ASC 715	11,752,633		—		11,752,633
7	Advanced Meter Infrastructure - Early Retirement of Legacy Meter Tax Impact; Docket Nos. 2007-215, 2008-111, 2010-051(II) (Amortization period ending 06/2033)	4,382,674		456	106,895	4,275,779
8	Public Advocate Cost Recovery			—
9	Advanced Meter Infrastructure - AMI Meter Depreciation Deferral; Docket Nos. 2007-215, 2008-111, 2010-051(II) (Amortization period ending 06/2033)	5,399,310		403/404	131,690	5,267,620
10	SFAS 143 - Asset Retirement Obligation; Docket 97-580	965,261		—		965,261
11	Advanced Meter Infrastructure - Legacy Meter Grant Carrying Costs; Docket Nos. 2007-215, 2008-111, 2010-051(II) (Amortization period ending 06/2033)	543,741		456	13,262	530,479
12	SFAS No. 109 - Deferred Income Taxes; Docket No. 93-140	190,551,578	9,200,335	—		199,751,913
13	Advanced Meter Infrastructure - Opt-Out Program; Docket Nos. 2022-00041 (Amortization period ending 06/2023)	127,099	39,610	456	4,615	171,324
14	SFAS No. 158 - Postretirement Benefits Other Than Pension; Docket No. 2007-215	2,789,189		926		2,789,189
15	Advanced Meter Infrastructure - Legal & Health Cost; Docket Nos. 2010-051(II), 2013-168, 2018-069	2,823		—		2,823
16	SFAS No. 158 - Pension Benefits; Docket No. 2007-215	81,943,827		926		81,943,827
17	Advanced Meter Infrastructure - PUC Audit Cost; Docket No. 2010-051(II)	123,231		—		123,231
18	Storm Costs; Docket Nos. 2022-00041 (Amortization period ending 06/2023)	177,977,388	3,699,741	923/905	15,416,381	166,260,748
19	100 Basis Points Recovery; Docket 2022-00041 (Amortization period ending 06/2023)	612,597		456	612,597
20	Stranded LGS-ST and T			—
21	Arrears Forgiveness Program Costs; Docket No. 2022-00041 (Amortization period ending 06/2023)	58,178	16,263	903	13,856	60,585
22	Stranded Cost Revenue Reconciliation Over/Under; Docket No. 2022-00042 (Amortization period ending 06/2023)	46,123,325	28,220,952	456	199,502	74,144,775
23	Customer Relationship Management and Billing System (CRM&B); Docket No. 2015-040, 2018-069 (Amortization period ending 06/2032)	142,482	3,262	923	7,113	138,631
24	Transmission credits for distribution customers Docket Nos. RT04-2, ER09-938	3,178,445	80,348	456		3,098,097
25	Delay of Rate Implementation Docket No. 2014-056			—
26	Transmission Annual True-up & Trans Rev Forecast; Docket Nos. RT04-2, ER09-938 (Amortization period ending 12/2023)		2,121,613	456	2,121,613
27	Energy Efficiency Programs (DSM) Customers			—
28	Vegetation Management Docket 2018-00194, 2021-00036			—
29	Environmental Clean-Up; Docket Nos. 97-580	380,600	74,140	923		454,740
30	Yankee Department of Energy Phase IV proceeds; Docket ER13, 2019-00310			—
31	Environmental Clean-Up Costs at F. O'Connor Site; Docket Nos. 2022-00041 (Amortization period ending 06/2023)	3,539		923	3,539
32	Electric Lifeline Program (ELP) Over/Under Collection to Customers; Dockets 2022-00041 (Amortization period ending 06/2023)	319,444	780,238	456		1,099,682
33	Electric Thermal Storage (ETS) Costs; Docket No. 2012-325	158,514	2,844	—		155,670
34	Rate Case Expenses; Docket 2022-152		1,008,000	456		1,008,000
35	Funded Deferred Income Tax - Power-tax Normalization; Docket 2013-168,2016-035,2020-065 (Amortization period ending 12/2051)	12,977,817		456	108,999	12,868,818
36	Low-Income Bill Credit; Docket 2022-00043, 2022-00041 (Amortization period ending 06/2023)	1,186		456	1,186
37	Management Audit; Docket 2018-00194			—
38	Net Energy Billing			—
39	Large General Service Transmission and Sub-Trans; Docket Nos. RT04-2, ER09-938	570,174	130,309	—		439,865
44	TOTAL	549,182,744	45,216,018		22,076,865	572,321,897

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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	CMP Improper Notices; Docket 2020-00017		—
2	Congestion Revenue Reconciliation; Docket No. 99-185	1,341,477	—		390,165	951,312
3	Cost of Removal; Docket No. 2007-215 (Amortization period ending 03/2040)	38,166,833	403	562,750		37,604,083
4	Customer Relationship Management & Billing Cost (CRMB); Docket No. 2018-069 (Amortization period ending 06/2031)		905	3,262	3,262
5	Electric Lifeline Program (ELP) Over/Under Collection to Customers; Dockets 2022-00041 (Amortization period ending 06/2023)		456	198,495	198,495
6	Environmental Cost Reserve for PCB/MGP; Docket Nos. 2007-215, 2008-111 & 2013-168	1,311,014	—		151,257	1,462,271
7	Revenue Decoupling Mechanism (RDM); Docket Nos. 2022-00041 (Amortization period ending 06/2023)	8,207,072	456	2,332,715	3,038,577	8,912,934
8	Stranded Cost Revenue Reconciliation Over/Under; Docket No. 2022-00042 (Amortization period ending 06/2023)		456	526,522	526,522
9	Stranded LGS-ST and T		—
10	Transmission Revenue True Up & Trans Exp; Docket Nos. RT04-2, ER09-938 (Amortization period ending 12/2023)	72,320,259	456	2,887,790	630,020	68,802,449
11	Transmission Credits for Distribution Customers; Docket Nos. RT04-2, ER09-938 (Amortization period ending 12/2023)		456	546,832	546,832
12	Vegetation Management; Docket 2022-00041 (Amortization period ending 06/2023)	600,937	456	45,134	65,274	621,077
13	Yankee Department of Energy Phase IV; Dockets ER13		—
14	2018 Tax Reform Impact Public Law No. 115-97 "Tax Cuts & Jobs Act"-Dist; Docket No. 2018-069, 2022-00041 Distribution (Amortization period ending 02/2030, 06/2023)	58,983,905	410	806,652		58,177,253
15	2018 Tax Reform Impact Public Law No. 115-97 "Tax Cuts & Jobs Act"-Trans; Docket Nos. RT04-2, ER09-938 Transmission, 2018-00194 (Amortization period ending 02/2030)	210,598,307	410	1,688,033		208,910,274
16	2019 One Time Adjustments Collected in July 2020		—
17	Energy Efficiency Programs (DSM) Customers Docket No. 2022-00041 (Amortization period ending 06/2023)	2,583,599	456	239,995	1,740,520	603,084
41	TOTAL	394,113,403		9,838,180	1,769,514	386,044,737

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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	129,447,300		73		579,793
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	32,761,446		101		71,712
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	2,942,805				2,745
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	1,559,788				558
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales	344,149
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	167,055,488		174		654,808
11	SalesForResaleAbstract (447) Sales for Resale	11,473,372		417,354
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	178,528,860		417,528		654,808
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	178,528,860		417,528		654,808
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	1,719,142
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(a) 2,271,350
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	8,379,714
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(b) 66,518,153
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	250,447,438
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	329,335,797
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	507,864,657
Line12, column (b) includes $ of unbilled revenues.
Line12, column (d) includes MWH relating to unbilled revenues

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

FOOTNOTE DATA

(a) Concept: MiscellaneousServiceRevenues

This amount represent charges for:


Establishment of Services			678,556
AMI Opt Out Charges			430,878
Line Extension			39,080
Electric Revenue - Miscellaneous (CIAC)			1,121,710
Electric Revenue - Miscellaneous			1,126
Total			2,271,350

(b) Concept: OtherElectricRevenue


Regulatory Assets & Liabilities Amortizations:

Advanced Meter Infrastructure IFRS/GAAP			(389,078)
Demand Side Energy Management Program IFRS/GAAP			479,989
Electric Lifeline Program Over/Under Collection IFRS/GAAP			396,990
Stranded Costs IFRS/GAAP			647,189
Power Tax IFRS/GAAP			(217,998)
OPA Non-Wire Alternative			(356,772)
Yankee DOE Phase I & Phase II IFRS/GAAP			—
Supply Credit - IFRS			(2,373)
Public Advocate			—
Net Energy Billing			—
Remove 100 Basis Point ROE Reduction			(1,225,195)
Other Items Less than $250K IFRS/GAAP			90,269

Regulatory Assets & Liabilities Deferrals:

Demand Side Energy Management Program IFRS/GAAP			778,756
Electric Lifeline Program Over/Under Collection IFRS/GAAP			491,731
Net Energy Billing IFRS/GAAP			—
Vegetation Management (D) IFRS/GAAP			(614,288)
Non-Wire Alternative IFRS/GAAP			209,339
Stranded Costs IFRS/GAAP			58,585,641
Customer Supply Credit			—
Rate Case Expenses IFRS			1,008,000
Other Items Less than $250K IFRS/GAAP			51,461



Mechanisms:


Electric Lifeline Program re: Maine State Housing Assoc			(3,087,954)
Revenue Decoupling Mechanism IFRS/GAAP			4,597,588

Other Distribution Revenue >$250K:


Billing and Collection Charges			1,041,059
Field Survey Billings			307,320
Net Energy Billing Capacity			172,137
Renewable Energy Certificate Sales			451,410
ISO NE ICAP HQ			1,838,213
Interconnection CIAC			454,159
LT Contract Reallocation			(5,524,702)
Misc Electric Ops			482,624
Interconnection fees			693,703
Mutual Aid - Nova Scotia			—
MGS Rate Relief LD			—
Energy Supply Relief Credit			—
NEB Capacity Buyout			(366,028)
Other Services to Third Party			165,972
Other Items Less than $250K			61,221

Other Transmission Revenue >$250K:


Interconnection Support Charge Sched 14-			1,524,985
Interconnection Fees			3,272,153
Misc Project Billing			196,553
Other Items Less than $250K			304,079
TOTAL			66,518,153

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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	None
46	TOTAL

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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

Report Electric production, other power supply expenses, transmission, regional market, and distribution expenses through the reporting period.
Line No.	Account (a)	Year to Date Quarter (b)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION AND OTHER SUPPLY EXPENSES
2	SteamPowerGenerationOperationsExpense Steam Power Generation - Operation (500-509)
3	SteamPowerGenerationMaintenanceExpense Steam Power Generation – Maintenance (510-515)
4	PowerProductionExpensesSteamPower Total Power Production Expenses - Steam Power
5	NuclearPowerGenerationOperationsExpense Nuclear Power Generation – Operation (517-525)
6	NuclearPowerGenerationMaintenanceExpense Nuclear Power Generation – Maintenance (528-532)
7	PowerProductionExpensesNuclearPower Total Power Production Expenses - Nuclear Power
8	HydraulicPowerGenerationOperationsExpense Hydraulic Power Generation – Operation (535-540.1)
9	HydraulicPowerGenerationMaintenanceExpense Hydraulic Power Generation – Maintenance (541-545.1)
10	PowerProductionExpensesHydraulicPower Total Power Production Expenses - Hydraulic Power
11	RentsOtherPowerGeneration Other Power Generation – Operation (546-550.1)
12	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration Other Power Generation – Maintenance (551-554.1)
13	MaintenanceOfMiscellaneousOtherPowerGenerationPlant Total Power Production Expenses - Other Power
14	OtherPowerSuplyExpensesAbstract Other Power Supply Expenses
15	PurchasedPower (555) Purchased Power	41,981,869
15.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations
16	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	551,263
17	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	1,265,870
18	OtherPowerSupplyExpense Total Other Power Supply Expenses (line 15-17)	41,267,262
19	PowerProductionExpenses Total Power Production Expenses (Total of lines 4, 7, 10, 13 and 18)	41,267,262
20	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
21	TransmissionExpensesOperationAbstract Transmission Operation Expenses
22	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	1,196,050
24	LoadDispatchReliability (561.1) Load Dispatch-Reliability	12,219
25	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	1,705,243
26	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling
27	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services
28	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development
29	TransmissionServiceStudies (561.6) Transmission Service Studies	1,455,591
30	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies	256,589
31	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services	85,304
32	StationExpensesTransmissionExpense (562) Station Expenses	1,043,255
32.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
33	OverheadLineExpense (563) Overhead Lines Expenses	180,629
34	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses
35	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	102,046,575
36	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	742,881
37	RentsTransmissionElectricExpense (567) Rents	89,058
38	OperationSuppliesAndExpensesTransmissionExpense (567.1) Operation Supplies and Expenses (Non-Major)
39	TransmissionOperationExpense TOTAL Transmission Operation Expenses (Lines 22 - 38)	108,813,394
40	TransmissionMaintenanceAbstract Transmission Maintenance Expenses
41	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	1,357,668
42	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	438,330
43	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware
44	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software
45	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment
46	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
47	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	1,561,091
47.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
48	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	4,872,300
49	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	22,123
50	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	76,665
51	MaintenanceOfTransmissionPlant (574) Maintenance of Transmission Plant
52	TransmissionMaintenanceExpenseElectric TOTAL Transmission Maintenance Expenses (Lines 41 – 51)	8,328,177
53	TransmissionExpenses Total Transmission Expenses (Lines 39 and 52)	117,141,571
54	RegionalMarketExpensesAbstract 3. REGIONAL MARKET EXPENSES
55	RegionalMarketExpensesOperationAbstract Regional Market Operation Expenses
56	OperationSupervision (575.1) Operation Supervision
57	DayAheadAndRealTimeMarketAdministration (575.2) Day-Ahead and Real-Time Market Facilitation
58	TransmissionRightsMarketAdministration (575.3) Transmission Rights Market Facilitation
59	CapacityMarketAdministration (575.4) Capacity Market Facilitation
60	AncillaryServicesMarketAdministration (575.5) Ancillary Services Market Facilitation
61	MarketMonitoringAndCompliance (575.6) Market Monitoring and Compliance
62	MarketFacilitationMonitoringAndComplianceServices (575.7) Market Facilitation, Monitoring and Compliance Services
63	RegionalMarketOperationExpense Regional Market Operation Expenses (Lines 55 - 62)
64	RegionalMarketExpensesMaintenanceAbstract Regional Market Maintenance Expenses
65	MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses (576.1) Maintenance of Structures and Improvements
66	MaintenanceOfComputerHardware (576.2) Maintenance of Computer Hardware
67	MaintenanceOfComputerSoftware (576.3) Maintenance of Computer Software
68	MaintenanceOfCommunicationEquipmentRegionalMarketExpenses (576.4) Maintenance of Communication Equipment
69	MaintenanceOfMiscellaneousMarketOperationPlant (576.5) Maintenance of Miscellaneous Market Operation Plant
70	RegionalMarketMaintenanceExpense Regional Market Maintenance Expenses (Lines 65-69)
71	RegionalMarketExpenses TOTAL Regional Control and Market Operation Expenses (Lines 63,70)
72	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
73	DistributionOperationExpensesElectric Distribution Operation Expenses (580-589)	19,415,885
74	DistributionMaintenanceExpenseElectric Distribution Maintenance Expenses (590-598)	72,717,956
75	DistributionExpenses Total Distribution Expenses (Lines 73 and 74)	92,133,841

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

Electric Customer Accts, Service, Sales, Admin and General Expenses
Report the amount of expenses for customer accounts, service, sales, and administrative and general expenses year to date.
Line No.	Account (a)	Year to Date Quarter (b)
-	CustomerAccountsExpensesOperationsAbstract Operation
1	CustomerAccountExpenses (901-905) Customer Accounts Expenses	20,926,806
2	CustomerServiceAndInformationExpenses (907-910) Customer Service and Information Expenses	19,199,874
3	SalesExpenses (911-917) Sales Expenses	35,483
4	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
5	AdministrativeAndGeneralExpensesOperationAbstract Operation
6	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	3,659,480
7	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	2,930,421
8	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit
9	OutsideServicesEmployed (923) Outside Services Employed	13,530,147
10	PropertyInsurance (924) Property Insurance	713,556
11	InjuriesAndDamages (925) Injuries and Damages	1,567,789
12	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	1,104,796
13	FranchiseRequirements (927) Franchise Requirements
14	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	4,097,918
15	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.	3,145,815
16	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	615,783
17	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	518,059
18	RentsAdministrativeAndGeneralExpense (931) Rents	221,726
19	AdministrativeAndGeneralOperationExpense TOTAL Operation (Total of lines 6 thru 18)	29,895,898
20	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
21	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	5,390,271
22	AdministrativeAndGeneralExpenses TOTAL Administrative and General Expenses (Total of lines 19 and 21)	35,286,169

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c). Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c). In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain. Report in column (i) and (j) the total megawatthours received and delivered. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (0) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively. Footnote entries and provide explanations following all required data.
									TRANSFER OF ENERGY		REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Line No.	PaymentByCompanyOrPublicAuthority Payment By (Company of Public Authority) (Footnote Affiliation) (a)	TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName Energy Received From (Company of Public Authority) (Footnote Affiliation) (b)	TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName Energy Delivered To (Company of Public Authority) (Footnote Affiliation) (c)	StatisticalClassificationCode Statistical Classification (d)	RateScheduleTariffNumber Ferc Rate Schedule of Tariff Number (e)	TransmissionPointOfReceipt Point of Receipt (Substation or Other Designation) (f)	TransmissionPointOfDelivery Point of Delivery (Substation or Other Designation) (g)	BillingDemand Billing Demand (MW) (h)	TransmissionOfElectricityForOthersEnergyReceived Megawatt Hours Received (i)	TransmissionOfElectricityForOthersEnergyDelivered Megawatt Hours Delivered (j)	Demand Charges ($) (k)	Energy Charges ($) (l)	Other Charges ($) (m)	RevenuesFromTransmissionOfElectricityForOthers Total Revenues ($) (k+l+m) (n)
1	Brookfield Energy Marketing, LP Non-Jurisdictional Sales	Not Available	Not Available	LFP	(a) —	New England/HVDC	HQ Phase I or II	85
2	HQ Energy Services US, Inc.	Not Available	Not Available	LFP	(b) —	New England/HVDC	HQ Phase I or II	93	183,770	183,770	829,916			829,916
3	HQ Energy Services US, Inc.	Not Available	Not Available	NF	(c) —	New England/HVDC	HQ Phase I or II	57	110,237	110,237			(i) 704,172	704,172
4	VITOL	Not Available	Not Available	LFP	(d) —	New England/HVDC	HQ Phase I or II	1	2,184	2,184	12,575			12,575
5	VITOL	Not Available	Not Available	NF	(e) —	New England/HVDC	HQ Phase I or II		2,160	2,160			(j) 12,575	12,575
6	MAG	Not Available	Not Available	NF	(f) —	New England/HVDC	HQ Phase I or II		133	133
7	Nalcor	Not Available	Not Available	NF	—	New England/HVDC	HQ Phase I or II
8	ISO New England, Inc. Non-Jurisdictional Sales	ISO New England Participants	ISO New England Participants	OS	—	ISO New England, Inc	ISO New England, Inc						(k) 46,993,620	46,993,620
9	Jurisdictional Sales:	—	—	OS	—	—	—		(g) 4,559,906	(h) 4,559,906
10	Residential Transmission Sales	3	—	OS	—	—	—						35,521,099	35,521,099
11	Commercial Transmission Sales	—	—	OS	—	—	—						27,334,217	27,334,217
12	Industrial Transmission Sales	—	—	OS	—	—	—						13,834,477	13,834,477
13	Lighting Transmission Sales	—	—	OS	—	—	—						130,830	130,830
14	Wholesale Transmission Sales	—	—	OS	—	—	—						567,461	567,461
15	Regulatory Transmission Revenues	—	—	OS	—	—	—						(l) 3,693,319	3,693,319
35	TOTAL							236	4,858,390	4,858,390	842,491		128,791,770	129,634,261

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

FOOTNOTE DATA

(a) Concept: RateScheduleTariffNumber

Pursuant to Part II of the ISO-NE Transmission, Markets and Services Tariff, Schedule 20A-CMP filed with the Commission on March 31, 2005 in Docket No. ER05-754-000.

(b) Concept: RateScheduleTariffNumber

Pursuant to Part II of the ISO-NE Transmission, Markets and Services Tariff, Schedule 20A-CMP filed with the Commission on March 31, 2005 in Docket No. ER05-754-000.

(c) Concept: RateScheduleTariffNumber

Pursuant to Part II of the ISO-NE Transmission, Markets and Services Tariff, Schedule 20A-CMP filed with the Commission on March 31, 2005 in Docket No. ER05-754-000

(d) Concept: RateScheduleTariffNumber

Pursuant to Part II of the ISO-NE Transmission, Markets and Services Tariff, Schedule 20A-CMP filed with the Commission on March 31, 2005 in Docket No. ER05-754-000.

(e) Concept: RateScheduleTariffNumber

Pursuant to Part II of the ISO-NE Transmission, Markets and Service Tariff, Schedule 20A-CMP filed with

the Commission on March 31, 2005 in Docket No. ER05-754-000.

(f) Concept: RateScheduleTariffNumber

ISO-NE FERC Electric Tariff Number 3.

(g) Concept: TransmissionOfElectricityForOthersEnergyReceived

The energy received is from suppliers who serve the Respondent's customers. The energy is delivered to these customers by the Respondent. The MWHs reported are the net tie flow on an hourly basis needed to serve the Respondent's customer load.

(h) Concept: TransmissionOfElectricityForOthersEnergyDelivered

Respondent provides Local Network Transmission Service to Wholesale and Retail Customers pursuant to Part II of the ISO-NE Transmission, Markets and Services Tariff - Schedule 21-CMP filed with the Commission on December 22, 2004 in Docket Nos. ER05-374-000 and ER05-374-001. The Jurisdictional Sales revenues include unbilled transmission revenues.

(i) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Non-Firm Transmission Charge.

(j) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Schedule Page: 328 Line No.: 6 Column: m

Non-Firm Transmission Charge.

(k) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Payment to Respondent was made pursuant to the Rate Design and Funds Disbursement Agreement filed with the Commission on October 1, 2004 in Docket No. RTO04-2-000 et al. and Part II of the ISO-NE Transmission, Markets and Services Tariff ("ISO Tariff") filed with the Commission on December 22, 2004 in Docket Nos. ER05-374-000 and ER05-374-001.

This amount represents transmission service charges for:


ISO Tariff - Part II:

Regional Network Service			45,101,762
Schedule 1			789,693
Through or Out Revenues			1,102,165

Total			46,993,620

(l) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers


Regulatory Assets/Liabilities Amortizations:

Transmission Revenue True Up			766,177
One Month Billing Lag			(2,921,982)
Distribution Level Share - RNS Credits			546,832

Regulatory Assets/Liabilities Deferrals:

Unfunded Deferred Income Tax Adjustment			—
Transmission Revenue True Up			5,513,014
One Month Billing Lag			—
Distribution Level Share - RNS Credits			(447,605)
LGS-ST-TOU & LGS-T-TOU Credit Deferral			(130,309)

Mechanisms:
Congestion			367,190

Total:			3,693,319

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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	Not Applicable
40	TOTAL

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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	Public Service Company of New Hampshire	LFP	66,098	66,098	10,900			10,900
2	Emera Maine	LFP	8,840	8,840	41,397			41,397
3	ISO New England	OS					(a) 46,594,534	46,594,534
4	Boston Electric (AC)	OS					(b) 5,574	5,574
5	New England HQ (AC)	OS					(c) 13,281	13,281
6	New England HQ (DC)	OS					(d) 217,834	217,834
7	NHH (DC)	OS					(e) 185,236	185,236
8	New England Elect Transm (DC)	OS					(f) 12,946	12,946
9	New England Power (NEP AC)	OS					(g) 69,277	69,277
10	Vermont Electric (VETCO DC)	OS					(h) 16,493	16,493
	TOTAL		74,938	74,938	52,297	0	47,115,175	47,167,472

FOOTNOTE DATA

(a) Concept: OtherChargesTransmissionOfElectricityByOthers


Regional Network Services			44,020,185
Schedule 1			569,770
Schedule 2 Expense			366,030
Schedule 2 RNS Expense			55,068
Schedule 3 RNS Expense			2,643
Schedule 16 Blackstart			804,856
Congestion Uplift			—
Schedule 2 Var Support			(3,870)
Load Response			—
OATT SCH 17 IROL-CIP			12,551
ISO NE ICAP HQ REVENUE			(5,073)

ISO Tariff Part IV:

Schedule 1			742,789
Schedule 5 - NESCO			29,587

Total			46,594,536

(b) Concept: OtherChargesTransmissionOfElectricityByOthers

Central Maine Power Company 7.1205% AC Supporter Share Payments for Hydro Quebec Phase II

(c) Concept: OtherChargesTransmissionOfElectricityByOthers

Central Maine Power Company 7.1205% DC Supporter Share Payments for Hydro Quebec Phase II

(d) Concept: OtherChargesTransmissionOfElectricityByOthers

Central Maine Power Company 7.1205% DC Supporter Share Payments for Hydro Quebec Phase II

(e) Concept: OtherChargesTransmissionOfElectricityByOthers

Central Maine Power Company 7.1205% DC Supporter Share Payments for Hydro Quebec Phase II

(f) Concept: OtherChargesTransmissionOfElectricityByOthers

Central Maine Power Company 6.9935% DC Supporter Share Payments for Hydro Quebec Phase I

(g) Concept: OtherChargesTransmissionOfElectricityByOthers

Central Maine Power Company 7.1205% DC Supporter Share Payments for Hydro Quebec Phase II

(h) Concept: OtherChargesTransmissionOfElectricityByOthers

Central Maine Power Company 6.9935% DC Supporter Share Payments for Hydro Quebec Phase I

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

Deprec, Depl and Amort of Elec Plant (403,403.1,404,and 405) (except Amortization of Acquisition Adjustments)
Report the year to date amounts of depreciation expense, asset retirement cost depreciation, depletion and amortization, except amortization of acquisition adjustments for the accounts indicated and classified according to the plant functional groups described.
Line No.	FunctionalClassificationAxis Functional Classification (a)	DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments Depreciation Expense (Account 403) (b)	DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	AmortizationOfLimitedTermPlantOrProperty Amortization of Limited Term Electric Plant (Account 404) (d)	AmortizationOfOtherElectricPlant Amortization of Other Electric Plant (Acc 405) (e)	DepreciationAndAmortization Total (f)
1	Intangible Plant			4,275,060		4,275,060
2	Steam Production Plant
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant
7	Transmission Plant	32,186,229				32,186,229
8	Distribution Plant	20,137,957		57,297		20,195,254
9	General Plant	10,122,086		17,529		10,139,615
10	Common Plant-Electric
11	TOTAL	62,446,272		4,349,887		66,796,159

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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)
2.1	Net Purchases (Account 555.1)	3,862	59,516
3	Net Sales (Account 447)	5,964,138	5,509,235
4	Transmission Rights
5	Ancillary Services
6	Other Items (list separately)
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46	TOTAL	5,968,000	5,568,751

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

Monthly Peak Loads and Energy Output
Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. Report in column (b) by month the system’s output in Megawatt hours for each month. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.	MonthAxis Month (a)	Total Monthly Energy (MWH) (b)	Monthly Non-Requirements Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak Megawatts (See Instr. 4) (d)	DayOfMonthlyPeak Monthly Peak Day of Month (e)	HourOfMonthlyPeak Monthly Peak Hour (f)
	NAME OF SYSTEM: 0
1	January	53,736	54,908	1,437	31	19
2	February	53,425	56,998	1,608	4	18
3	March	78,743	66,662	1,334	1	8
4	Total for Quarter 1	185,904	178,568
5	April	69,121	74,987	1,251	5	19
6	May	84,703	96,055	1,178	3	18
7	June	84,977	67,745	1,284	25	18
8	Total for Quarter 2	238,801	238,787
9	July
10	August
11	September
12	Total for Quarter 3	0	0
41	Total

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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	1,437	31	19	1,437
2	February	1,608	4	18	1,608
3	March	1,334	1	8	1,334
4	Total for Quarter 1				4,380	0	0			0
5	April	1,251	5	19	1,251
6	May	1,178	3	18	1,178
7	June	1,284	25	18	1,284
8	Total for Quarter 2				3,712	0	0			0
9	July
10	August
11	September
12	Total for Quarter 3				0	0	0			0
13	October
14	November
15	December
16	Total for Quarter 4				0	0	0			0
17	Total				8,092	0	0	0	0	0

Name of Respondent:

Central Maine Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/29/2023

Year/Period of Report

End of:

2023

/

Q2

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

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