EAL Appendix 1 Exhibit 3 Docket No. 18-037-TF Page 2 of 17 ...

ARKANSAS PUBLIC SERVICE COMMISSION

Original Sheet No. TC-1 Schedule Sheet 1 of 6

Replacing: Sheet No.

Entergy Arkansas, LLC Name of Company

Kind of Service: Electric Class of Service: All Docket No.: 18-073-TF Order No.: 2 Effective: 2/1/19

TABLE OF CONTENTS PSC File Mark Only

THIS SPACE FOR PSC USE ONLY

Part I. General Information

Class of Service Schedule No. and Name Sheet Number

All 1. Utility Information GIS-1 All 2. Tariff Format GIS-2

EAL Appendix 1 Exhibit 3Docket No. 18-037-TF

Page 2 of 17

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APSC FILED Time: 3/1/2019 2:03:54 PM: Recvd 3/1/2019 2:03:24 PM: Docket 18-037-TF-Doc. 71

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1st Revised Sheet No. TC-2 Schedule Sheet 2 of 6

Replacing: Original Sheet No. TC-2


Kind of Service: Electric Class of Service: All Docket No.: 16-060-U Order No.: Effective:



Part II. Exemptions

Class of Service Exemption Schedule No. and Name Sheet Number All 1. Schedule of Exemptions from General Service Rules ES-1 All 2. Schedule of Exemptions from Rules for Conservation

and Energy Efficiency ProgramsES-2

All 3. Schedule of Exemptions from Special Rules - Electric ES-3

EAL Compliance Exhibit GDH-2Docket No. 16-060-U

Page 1 of 2

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APSC FILED Time: 1/30/2020 12:19:17 PM: Recvd 1/30/2020 12:18:43 PM: Docket 16-060-U-Doc. 126

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Part III. Rate Schedules

Class of Service Rate Schedule No. and Title Sheet Number

Residential 1. General Purpose Residential Service (RS) 1.1

Residential 2. Optional Residential Time-Of-Use (RT) 2.1

3. RESERVED FOR FUTURE USE 3.1

Commercial/Industrial 4. Small General Service (SGS) 4.1

Industrial 5. General Farm Service (GFS) 5.1

Commercial/Industrial 6. Large General Service (LGS) 6.1

Commercial/Industrial 7. Large General Service Time-Of-Use (GST) 7.1

Commercial/Industrial 8. Large Power Service (LPS) 8.1

Commercial/Industrial 9. Large Power Service Time-Of-Use (PST) 9.1

Lighting 10. Municipal Street Lighting Service (L1) 10.1

Lighting 11. Traffic Signal Service (TSS) 11.1

All 12. All Night Outdoor Lighting Service (L4) 12.1

Governmental Agencies 13. Municipal Pumping Service (MP) 13.1

Industrial 14. Agricultural Water Pumping Service (AP) 14.1

Industrial 15. Cotton Ginning Service (CGS) 15.1

Commercial 16. Community Antenna TV Amplifier Service (CTV) 16.1

All 17. Table of Riders Applicable to Rate Schedules 17.1

Commercial/Industrial 18. Voltage Adjustment Rider (VAR) 18.1

All 19. Collective Billing Rider (CBR) 19.1

All 20. Standby Service Rider (SSR) 20.1


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Lighting 21. Municipal Shielded Street Lighting Service (L1SH) 21.1

Commercial/Industrial 22. Fire And Flood Loads Rider (FFLR) 22.1

Commercial/Industrial 23. Highly Fluctuating Loads Rider (HFLR) 23.1

Industrial 24. Short Term, Temporary & Intermittent Service Rider (STIR) 24.1

Commercial/Industrial 25. Seasonal Service Rider (SESR) 25.1

Commercial/Industrial 26. Additional Facilities Charge Rider (AFCR) 26.1

Commercial 27. Modification of General Service Minimum Rider (GSMR) 27.1

Commercial/Industrial 28. Separately Metered Commercial Space & Water HeatingRider (SMWHR)

28.1

As Applicable 29. Charges Related To Customer Activity (CAC) 29.1

Residential 30. Optional Apartment Service Rider (OASR) 30.1

Commercial 31. Commercial Space Heating Rider (CSHR) 31.1

As Applicable 32. Economic Development Rider (EDR) 32.1

Residential 33. Residential Energy Management Time-Of-Use (REMT) 33.1

All 34. Small Cogeneration Rider (SCR) 34.1

All 35. Large Cogeneration Rider (LCR) 35.1


All 37. ANO Decommissioning Cost Rider (NDCR) 37.1

All 38. Energy Cost Recovery Rider (ECR) 38.1

All 39. Municipal Franchise Adjustment Rider (MFA) 39.1

All 40. Energy Efficiency Cost Rate Rider (EECR) 40.1

Industrial 41. Optional Interruptible Service Rider (OISR) 41.1


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5th Revised Sheet No. TC-5 Schedule Sheet 5 of 6

Replacing: 4th Revised Sheet No. TC-5

Entergy Arkansas, LLCName of Company

Kind of Service: Electric Class of Service: All Docket No.: 10-008-UOrder No.: 8Effective: 4/30/21




All 42. Grand Gulf Rider (GGR) 42.1

All 43. Federal Litigation Consulting Fee Rider (FLCF) 43.1

All 44. Formula Rate Plan Rider (FRP) 44.1


All 46. Internal Restructuring Credit Rider (IRCR) 46.1

All 47. Capacity Cost Recovery Rider (CCR) 47.1

All 48. Production Cost Allocation Rider (PCA) 48.1

49. RESERVED FOR FUTURE USE


All 51. Government Mandated Expenditure Surcharge Rider (GMES) 51.1

As Applicable 52. Net-Metering Service (N-M) 52.1

Governmental Agencies 53. Additional Facilities Charge Rider – Governmental (AFCRG) 53.1

All 54. MISO Rider (MISO) 54.1


All 56. Economic Redevelopment Rider (ERDR) 56.1

Residential 58. Peak Time Rebate Rider (PTR) Pilot 58.1

As Applicable 60. Extension Of Facilities (EOFP) 60.1

As Applicable 61. Tariff Governing the Installation of Electric UndergroundResidential Distribution Systems and Underground ServiceConnections (UGP)

61.1

All 62. Solar Energy Purchase Option (SEPO) 62.1


5th Revised

Replacing: 4th Revised

Entergy Arkansas, LLC

Sheet No. TC-5 Schedule Sheet 5 of 6

Sheet No. TC-5

Name of Company

Kind of Service: Electric Class of Service: fl Docket No.: 10-008-UOrder No.: 8

TABLE OF CONTENTS . P50 File Mark Only

Class of Service

All

All

All

All

All

All

AM

As Applicable

Governmental Agencies

All

All

Residential

As Applicable

As Applicable

All

42.

43.

44.

45.

46.

47.

48.

49.

50.

51.

52.

53.

54.

55.

56.

58.

60.

61.

62.

Rate Schedule No. and Title

Grand Gulf Rider (GGR)

Federal Litigation Consulting Fee Rider (FLCF)

Formula Rate Plan Rider (FRP)

RESERVED FOR FUTURE USE

Internal Restructuring Credit Rider (IRCR)

Capacity Cost Recovery Rider (CCR)

Production Cost Allocation Rider (PCA)



Government Mandated Expenditure Surcharge Rider (GMES)

Net-Metering Service (N-M)

Additional Facilities Charge Rider — Governmental (AFCRG)

MISO Rider (MISO)


Economic Redevelopment Rider (ERDR)

Peak Time Rebate Rider (PTR) Pilot

Extension Of Facilities (EOFP)

Tariff Governing the Installation of Electric UndergroundResidential Distribution Systems and Underground ServiceConnections (UGP)

Solar Energy Purchase Option (SEPO)

Effective: 4/30/21

SheetNumber

42.1

44.1

45.1

46.1

47.1

48.1

50.1

51.1

52.1

53.1

54.1

55.1

56.1

58.1

60.1

61.1

62.1



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PART IV. POLICY SCHEDULES

Class of Service Policy Schedule No. and Title Sheet Number

All 1. Pick A Date Plan (PADP) (Extended Due Date) P1.1 As Applicable 2. Budget Billing Plan (BBP) (Levelized/Equal Pay) P2.1 Residential 3. Extended Absence Payment Plan (EAPP) P3.1 Residential 4. Provisions for Landlord and Tenants (LTP) P4.1 All 5. Standard Nominal Voltages (SNVP) P5.1 Does Not Apply 6. Voltage Verification Plan (VVP) P6.1 Lighting 7. All Night Outdoor Lighting Maintenance Policy (OLMP) P7.1 All 8. Quick Pay Center Payment (QPCP) P8.1 All 9. Service Regulations (SRP) P9.1 All 10. Contingency Emergency Power Conservation And Curtailment

Plan (EPCP) P10.1 Does Not Apply 11. Transformer Company No., Location No. & Birthmark P11.1 All 12. Meter Testing Program (MTP) P12.1 All 13. Contract Forms P13.0.1


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Original Sheet No. GIS-1 Schedule Sheet 1 of 1



Kind of Service: Electric Class of Service: All Docket No.: 18-073-TF Order No.:

Part I. General Information Schedule No. 1 Effective: 2/1/19

Title: Utility Information PSC File Mark Only


1. UTILITY INFORMATION

Utility Official: David Palmer Director - Regulatory Affairs

Telephone Number: (501) 377-3571

Mailing Address: Entergy Arkansas, LLC 425 West Capitol, P. O. Box 551 Little Rock, AR 72203-0551

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Original Sheet No. GIS-2.1 Schedule Sheet 1 of 1




Part I. General Information Schedule No. 2 Effective: 2/1/19

Title: Tariff Format PSC File Mark Only


2.0. TARIFF FORMAT

2.1. SHEET NUMBERING

Sheet numbers appear in the upper left corner of the sheet. The Table of Contents sheets are numbered sequentially beginning with TC-1. All other sheets are numbered sequentially in the format xx.y, where xx is the schedule number and y is the page number within the schedule. For example, Sheet No. 12.2 would be the second page of Rate Schedule No. 12.

2.2. SHEET REVISIONS

Sheet revisions appear in the upper left corner of the sheet and are used to determine the most current sheet version on file with the Arkansas Public Service Commission. For example, the 3rd Revised Sheet No. 16 Replacing 2nd Revised Sheet No. 16.

2.3. PARAGRAPH NUMBERING SEQUENCE

There are seven levels of paragraph numbering.

2. 2.1. 2.1.1. 2.1.1.1. 2.1.1.1.A. 2.1.1.1.A.(1) 2.1.1.1.A.(1)a.

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Original Sheet No. ES 1.1 Schedule Sheet 1 of 8



Kind of Service: Electric Class of Service: As Applicable Docket No.: 18-073-TF Order No.:

Part II. Exemption Schedule No. 1 Effective: 2/1/19

Title: Schedule of Exemptions from General Service Rules PSC File Mark Only


1.0. SCHEDULE OF EXEMPTIONS FROM GENERAL SERVICE RULES (GSR)

1.1. General Service Rule 3.03.B.(5) Extension of Service Agreement

Entergy Arkansas, LLC (EAL) is currently exempted from GSR 3.03.B.(5). by the addition of the following exception:

Exception: A sketch is not required when: (1) a customer requests that an adequate overhead service be replaced

with an underground service, or (2) a developer, builder or customer requests the installation of a new

service in a subdivision where the customers are to be served from the Company’s existing underground circuit facilities.

1.2. General Service Rule 4.01. Deposits From Applicants

Entergy Arkansas, LLC (EAL) is currently exempted from GSR 4.01.A. See rate Schedule No. 29, Charges Related To Customer Activity (CAC), § 29.6.1.3.

Entergy Arkansas, LLC (EAL) is currently exempted from GSR 4.01.C. See Rate Schedule No. 29, Charges Related To Customer Activity (CAC), § 29.6.3.1.

1.3. General Service Rule 4.02.A Deposits From Customers - Conditions

EAL is currently exempted from GSR 4.02.A. See Rate Schedule No. 29, Charges Related To Customer Activity (CAC), § 29.7.1.1 and § 29.7.2.1.

1.4. General Service Rule 4.02.D. Deposits From Customers - Payment Procedures

EAL is currently exempted from GSR 4.02.D. See Rate Schedule No. 29, Charges Related To Customer Activity (CAC), § 29.7.1.2.

1.5. General Service Rule 4.03.B. For Inadequate Billing History

EAL is currently exempted from GSR 4.03.B. See Rate Schedule No. 29, Charges Related To Customer Activity (CAC), § 29.8.

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1.6. General Service Rule 4.04.D Guaranty Agreement Form

EAL is currently exempted from GSR 4.04.D. by replacing the Guaranty Agreement in that Rule with the following Third Party Guarantor Agreement.

THIRD PARTY GUARANTOR AGREEMENT

In consideration of Entergy Arkansas, LLC, providing service to the below named person(s), I agree to be liable for an amount not to exceed $_______________ in lieu of a deposit for the following person(s):

NAME:____________________________________________________________

ADDRESS:_________________________________________________________

ACCOUNT #:_______________________________________________________

I also understand that Entergy Arkansas, LLC, may transfer up to the above amount to my active account if the above-named person does not pay all of the final bill after the account has been closed. I understand I will be responsible for the lesser of the deposit or the amount the above-named person actually owes Entergy Arkansas, LLC This guaranty will transfer to my account (at other locations) should I change my service address. The guaranty on a residential account shall expire under the same conditions as would result in the refund of a deposit. I understand that utilities are not required to refund deposits on business or commercial accounts until the account is closed. I understand that I cannot terminate this guaranty before that time unless my account is closed. The amount of the guaranty is limited to the amount required for a deposit when the guaranty is made.

The Third Party Guaranty Agreement MUST BE NOTARIZED AND ORIGINAL (no facsimile or copy accepted) RETURNED TO:

Entergy c/o Credit & Collections P.O. Box 2431 Baton Rouge, LA 70821

THIRD PARTY GUARANTOR:

Name:____________________________________________________________

Address:__________________________________________________________

State: ____________________________________________________________

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Zip Code: __________________________________________________________

Account #:__________________________________________________________

Signed:____________________________________________________________ Guarantor

Date:______________________________________________________________

Notary Public:_______________________________________________________

Expires:____________________________________________________________

1.7. General Service Rule 5.01. Information on Bill

1.7.1 The Company is exempted from Rule 5.01.F which requires display on the customer’s bill “the amount of any ‘late payment charge’ “. The “Account Summary” area of the bill clearly displays the amounts due by, and after, the due date enabling the customer to calculate the late payment charge.

1.7.2. The Collective Billing Service Rider (CBR), Rate Schedule No. 19 of EAL is currently exempted from the Commission's General Service Rule 5.01. The exemption allows EAL to offer, and qualifying customers to elect, a Collective Billing option that complies in most but not all respects with § 5.01.B. and 5.01.I. The optional bill format will be considered as meeting the requirements of GSR 5.01., when elected by such qualifying customers.

1.7.3. The Community Antenna TV Amplifier Service (CTV), Rate Schedule No. 16 of EAL is exempted from Rule 5.01 allowing EAL to bill CTV customers under the Collective Billing procedure. The exemption allows EAL to render Collective Bills that comply in most but not all respects with § 5.01.B. and 5.01.I. The bill format will be considered as meeting the requirements of GSR 5.01.

1.7.4. EAL is currently exempted from the requirements of GSR 5.01 with regard to Electronic Data Interchange (EDI) billing for commercial and industrial customers who contract for the service. The number of days in the billing period, required by the Rule, is calculated by the recipient from reading dates electronically transmitted by EAL. The bill date of an EDI bill is the electronic mail date.

1.8. General Service Rule 5.05. Due Dates

The Collective Billing Service Rider (CBR), Rate Schedule No. 19 and the Community Antenna TV Amplifier Service (CTV), Rate Schedule No. 16 of EAL are currently exempted from the Commission's General Service Rule 5.05. The exemption allows the Company to require a fourteen (14) day due date for all accounts included on one Collective Bill.

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1.9. General Service Rule 5.08. Estimated Usage for Billing

EAL is currently exempted from GSR 5.08. with regard to the Company’s bill estimating procedure.

When it is not possible to obtain a customer’s meter reading for any reason the Company will employ an appropriate computer estimation procedure described below instead of the manual method described in GSR 5.08.

The first step in the estimation process is to determine a valid representative period from which to estimate. If available and appropriate, the same period of the previous year is used as the base period. If not available or logically determined by the Company to be inappropriate, the system will use the previous month as the basis of estimation. If neither is available or appropriate, such as with new service, a default value based on class profiles will be used.

Once an available and appropriate base period is determined for the customer, then the system adjusts that consumption amount as described below.

The system applies a weighting factor to the representative period to determine the kWh consumption for billing. Linear Weighting is used for commercial accounts and Degree-Day Weighting is used for residential accounts. In using Linear Weighting, each day is given the same weighting to calculate the expected consumption for the current period. The consumption for the representative period is divided by the number of days in that period to determine the average daily usage. The representative average daily usage is then multiplied by the number of days in the current period to determine the consumption for the current period.

In using Degree-Day Weighting, the expected consumption calculated by the system is varied by factors that are directly related to the difference between the daily average temperatures in the representative period and base temperatures in the period for which the consumption is being estimated. The basis for the Heating Degree-Day calculation is 60° F; that is, there is one half of a Heating Degree-Day for each degree that the average of the high and low temperatures for the day is below 60° F. Similarly the basis for the Cooling Degree-Day calculation is 70° F and there is one Cooling Degree-Day for each degree that the average of the high and low temperatures for the day is above 70° F. The weighting factors contain a base amount to reflect that some consumption is not weather related and therefore should not be adjusted. Similarly, Heating Degree-Days are reduced to reflect that the majority of customers do not have electric heat.

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1.10. General Service Rule 5.09. Extended Due Date Policy

EAL is currently exempted from GSR 5.09.C. by making Extended Due Date available to more customers than the Rule requires. See Policy Schedule No. 1, Pick A Date Plan, § 1.2, Availability for the types of customers who are not eligible for the Plan.

1.11. General Service Rule 5.21. Transferring Past Due Balances to Other Accounts

EAL is currently exempted from GSR 5.21. by the addition of the following paragraph.

“C. An account of any customer, of any class, when the Company receives a written request to have a balance transferred to the requesting Customer’s account and when the following information is stated in the letter of request:

(1) Name and account number of the customer requesting that a balance is to be transferred to their account;

(2) Name and account number of the customer whose balance is to be transferred;

(3) A statement that the requesting customer understands that their own service may be terminated for non-payment if the transferred balance is not paid in full in accordance with any agreed upon payment arrangements.”

1.12. General Service Rule 6.08.B. Payment Requirements to Prevent Suspension

EAL is currently exempted from GSR 6.08.B. by a replacement of the word “collection” with the word “trip”. As revised GSR 6.08.B reads as follows for EAL:

B. The utility may require the customer to pay any applicable approved trip fee or late charge to prevent suspension.

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1.13. General Service Rule 6.09.B.(1) Suspension Procedures at the Premises

EAL is currently exempted from GSR 6.09.B.(1) by replacement of the second paragraph in its entirety with the following language:

“The utility employee may refuse a customer’s offer of payment of any kind if the customer is given 24 hours to make payment at an authorized payment location. The utility employee shall honor a receipt from the utility or a canceled check showing that the customer paid the bill.”

1.14. General Service Rule 6.09.B.(2) e. Suspension Procedures at the Premises

EAL is currently exempted from GSR 6.09.B.(2) e. by a replacement of the words “collection charge” with the words “trip fee”. GSR 6.09.B.(2) e., as revised, reads as follows for EAL:

e. any approved trip fee; and,

1.15. General Service Rule 6.11 Collection Fees

EAL is currently exempted from GSR 6.11 by the removal of all references to collections at the customer’s premises, replacement of the words “collection charge” with the words “trip fee” and the revision of GSR 6.11 to read as follows for EAL:

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Rule 6.11 Trip Fees

A utility may charge a Commission-approved trip fee under the following conditions:

A. The last day to pay, as printed on the shut-off notice, has passed; and,

B. A utility employee is dispatched to the customer’s premises to terminate service and service is not terminated for either of the following reasons:

1. because receipt of payment at the premises was refused by the Companyemployee and the customer was allowed 24 hours to pay at an authorizedpayment location; or,

2. because the customer’s normally accessible meter was inaccessible and thecustomer or other adult was not at the premises or did not respond.

The employee must leave a notice as described in Rule 6.09.B. (2) if the customer or other adult is not at the premises or does not respond.

1.16. General Service Rule 6.15 Cold Weather Rule

EAL is currently exempted from GSR 6.15 by replacing the words “National Weather Service” with the words “national weather service reporting company to which it subscribes” in the Rule. GSR 6.15, as revised, reads as follows for EAL:

Electric and gas utilities may not suspend residential service on a day when the national weather service reporting company to which it subscribes forecasts that a temperature of 32 degrees Fahrenheit or lower will occur at any time during the following 24 hour period. The utility must obtain the most recent forecast for the customer's weather zone from the national weather service reporting company to which it subscribes on the morning of the day that the customer's shut-off is scheduled.

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Part II. Exemption Schedule No.: 1 Effective: 2/1/19



1.17. General Service Rule 6.17.D. Medical Need For Utility Service Physician’s Certificate

EAL is currently exempted from GSR 6.17.D. by the insertion of the bold italicized language in the following two passages below:

“To: . (Name of Utility) Account Number Date”

“I certify that loss of utility service would give rise to a substantial risk of death or gravely impair the health of who lives at

. DATE OF BIRTH: ”.

This exemption also includes the insertion of the following passage immediately above the Physician’s signature line:

“List electrical medical equipment in use . .

Is any of the above listed equipment utilized 24 hours continuously? YES . NO .”

1.18 General Service Rule 6.18.E Hot Weather Protection

EAL is currently exempted from GSR 6.18.E by replacing the words “National Weather Service” with the words “national weather service reporting company to which it subscribes” in the Rule. GSR 6.18.E, as revised, reads as follows for EAL:

(1) An electric or gas utility shall not suspend residential service to an elderly customer or customer who is an individual with disabilities on a day when the national weather service reporting company to which it subscribes forecasts that a temperature of 95 degrees Fahrenheit or higher will occur at any time during the following 24-hour period. For gas utilities, hot weather protection shall be limited to elderly or individuals with disabilities air conditioning customers only.

(2) The utility must obtain the forecast for the customer's weather zone from the national weather service reporting company to which it subscribes on the morning of the day that the customer's shut-off is scheduled.

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Title: Schedule of Exemptions from Rules for Conservation and Energy Efficiency Programs

PSC File Mark Only


2.0. SCHEDULE OF EXEMPTIONS FROM RULES FOR CONSERVATION AND ENERGY EFFICIENCY PROGRAMS (RCEEP)

2.1. Rules For Conservation And Energy Efficiency Programs § 7.D Cost Recovery

Entergy Arkansas, LLC (EAL) is currently exempted from RCEEP § 7.D. by the addition of the italicized passage below to the Section:

D. Demand response programs that involve rates (e.g., interruptible service, curtailment, off-peak service, time-of-use rates) shall not be included in any surcharge or rider. The rates for those mechanisms will be established through utility-specific rate or tariff proceedings. The Arkansas Public Service Commission has granted Entergy Arkansas, LLC a waiver of the rule with respect to the costs associated with the Company’s Irrigation Load Control Program by allowing the recovery of such costs through the Company’s Energy Efficiency Cost Recovery Rider (EECR).

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ARKANSAS PUBLIC SERVICE COMMISSION Original Sheet No. ES 3.1 Schedule Sheet 1 of 1 Replacing: Sheet No. Entergy Arkansas, LLC Name of Company Kind of Service: Electric Class of Service: As Applicable Docket No.: 16-060-U Order No.: Part II. Exemption Schedule No. 3 Effective: Title: Schedule of Exemptions from Special Rules –

Electric PSC File Mark Only


3.0. SCHEDULE OF EXEMPTIONS FROM SPECIAL RULES – ELECTRIC 3.1. Meter Testing Programs and Filing Requirements § 7.08.B

Meter Test Programs for In-Service Meters

Entergy Arkansas, LLC is exempted from complying with in-service meter testing of SRE § 7.08.B. during the Company’s Advanced Metering Infrastructure (“AMI”) deployment. In-service meter testing will resume following the completion of the deployment of AMI.


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Original Sheet No. 1.1 Schedule Sheet 1 of 3



Kind of Service: Electric Class of Service: Residential Docket No.: 18-073-TF Order No.:

Part III. Rate Schedule No. 1 Effective: 2/1/19

Title: General Purpose Residential Service (RS) PSC File Mark Only


1.0. GENERAL PURPOSE RESIDENTIAL SERVICE

1.1. REGULATORY AUTHORITY

The Arkansas Legislature has delegated authority to the Arkansas Public Service Commission (“APSC” or the “Commission”) to regulate public utilities in the State of Arkansas, including Entergy Arkansas, LLC (“EAL” or the “Company”). The APSC’s regulatory authority over the provision of electric service applies not only in the Distribution Service area allocated to EAL by the APSC but also extends to service to customers who have been released to EAL by other electric distribution utilities, when such release for service has been approved by the Commission pursuant to Rule 6.07(b) or (c) of the Commission's Rules of Practice and Procedure. Similarly, the Tennessee Regulatory Authority exercises such authority delegated to it by the Tennessee legislature in areas of the State of Tennessee served by EAL.

1.2. AVAILABILITY

For residential service to single family residences or individual family apartments supplied through one meter, including incidental family use, on the appurtenant premises. This Rate Schedule is not applicable to commercial type use on the appurtenant premises such as chicken brooding and grain drying. Where a portion of the residence premises (not separately metered) is used for nonresidential purposes, the predominant use of the service, as determined by the Company, shall determine the Rate Schedule applicable to all service. Service is for the use of the customer and may not be shared and may not be resold to others. Not applicable to standby or supplementary service.

1.3. CHARACTER OF SERVICE

Service will normally be single-phase, 60 cycles, at approximately 120/240 Volts or at such other voltages as may be adopted by the Company and approved by the APSC. Three-phase service may be made available pursuant to § 1.4.5 of this rate schedule.

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1.4. NET MONTHLY RATE

1.4.1. Rate

Billing Item Rate Customer Charge: $8.40

Energy Charge per kWh: June - September: 1st 1,500 kWh $0.07392

All additional kWh $0.09593 October - May: 1st 1,000 kWh $0.06990

All additional kWh $0.05154

1.4.2. LOW/LEVEL USE PROVISION

Any customer who has at least 12 consecutive months billing record at the same residence for the 12 billing months ending with the current billing month, and

(a) whose annual consumption was not greater than 6,000 kWh, and

(b) whose maximum monthly consumption billed in the months of June through September did not exceed 1.2 times the maximum monthly consumption billed in the months of October through May,

will be billed according to the rates in the following table.

1.4.2.1. Low/Level Use Rate

Billing Item Rate Customer Charge $8.40

Energy Charge per kWh: June - September: 1st 1500 kWh $0.06991

All additional kWh $0.08987 October - May: 1st 1000 kWh $0.06392

All additional kWh $0.04707

1.4.3. Minimum

The greater of (1) the Net Monthly Rate Customer Charge shown above as adjusted by § 1.4.6, if applicable, or (2) an amount that may be required under the Company’s Rate Schedule No. 60, Extension of Facilities.

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1.4.4 Billing Amount

The Billing Amount will be the greater of the amounts calculated in the applicable Net Monthly Rate, §§ 1.4.1, 1.4.2.1, and 1.4.3 above, plus the Energy Cost Recovery Factor times the billed energy, plus all other Adjustments required by § 1.4.6 below.

1.4.5. Three-Phase Service

When three-phase service is supplied, a monthly charge will be added to the Net Monthly Rate Customer Charge applicable to single-phase service as follows:

Billing Item Rate Charge per Month $3.31

In the event a primary line extension is necessary, customer will reimburse Company for the estimated construction cost of the three-phase primary extension in excess of the estimated cost of a single-phase extension, in advance of construction.

1.4.6. Adjustments

Applicable Riders which adjust this Rate Schedule are listed in Rate Schedule No. 17, Table of Riders Applicable to Rate Schedules.

1.5. PAYMENT

The monthly bill shall be computed in accordance with the Net Monthly Rate, other provisions of the rate schedule and all applicable riders. Payment shall be made in accordance with Rate Schedule No. 29, Charges Related to Customer Activity (CAC), § 29.19.1.

1.6. CONTRACT PERIOD

Month to month or as required by Rate Schedule No. 60, Extension of Facilities.

1.7. SERVICE REGULATIONS

Service under this schedule is subject to Policy Schedule No. 9, Service Regulations, of the Company as it is now on file, and as it may in the future be filed, with the APSC and the rules of the Commission.

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Title: Optional Residential Time-Of-Use (RT) PSC File Mark Only


2.0. OPTIONAL RESIDENTIAL TIME-OF-USE

NOT AVAILABLE TO NEW APPLICATIONS AFTER JUNE 30, 2010



2.2. AVAILABILITY

For residential service to single family residences or individual family apartments supplied through one meter, including incidental family use, on the appurtenant premises. This Rate Schedule is not applicable to commercial type use on the appurtenant premises such as chicken brooding and grain drying. Where a portion of the residence premises (not separately metered) is used for nonresidential purposes, the predominant use of the service, as determined by the Company, shall determine the Rate Schedule applicable to all service. Service is for the use of the customer and may not be shared and may not be resold to others. Not applicable to standby or supplementary service.




2.4.1 Rate Billing Item Rate

Customer Charge: $13.81 Energy Charge per kWh:

On-Peak Hours Use: $ 0.15451 Off-Peak Hours Use: $ 0.03050

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2.4.2. On-Peak Hours

Summer Period (June – September) Other Period (October – May) 1:00 p.m. - 8:00 p.m. Monday - Friday 7:00 a.m. - 6:00 p.m. Monday - Friday

2.4.3. Off-Peak Hours

All hours not designated as on-peak hours.

2.4.4. Minimum

The greater of (1) the Net Monthly Rate Customer Charge shown above as adjusted by § 2.4.6, if applicable, or (2) an amount that may be required under the Company’s Rate Schedule No. 60, Extension of Facilities.


The Billing Amount will be the greater of the amounts calculated in §§ 2.4.1 and 2.4.4 above, plus the Energy Cost Recovery Factor times the billed energy, plus all other Adjustments required by § 2.4.7 below.



Billing Item Rate Charge per Month: $3.31

In the event a primary line extension is necessary, customer will reimburse Company for the estimated construction cost of the three-phase primary extension in excess of the estimated cost of a single-phase extension in advance of construction.

2.4.7. Adjustments


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2.5. PAYMENT



Not less than one year nor less than required by Rate Schedule No. 60, Extension of Facilities.



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1st Revised Sheet No. 4.1 Schedule Sheet 1 of 4

Replacing: Original Sheet No. 4.1


Kind of Service: Electric Class of Service: Commercial/Industrial Docket No.: 21-058-TF Order No.:


Title: Small General Service (SGS) PSC File Mark Only


4.0. SMALL GENERAL SERVICE


The Arkansas Legislature has delegated authority to the Arkansas Public Service Commission (“APSC” or the “Commission”) to regulate public utilities in the State of Arkansas, including Entergy Arkansas, LLC (“EAL” or the “Company”). The APSC’s regulatory authority over the provision of electric service applies not only in the Distribution Service area allocated to EAL by the APSC but also extends to service to customers who have been released to EAL by other electric distribution utilities, when such release for service has been approved by the Commission pursuant to Rule 6.07(b) or (c) of the Commission's Rules of Practice and Procedure. Similarly, the Tennessee Regulatory Authority exercises such authority delegated to it by the Tennessee legislature in areas of the State of Tennessee served by EAL. Notwithstanding, the Arkansas General Assembly also has provided that for a public utility’s nonresidential classes of customers that have rates with a demand component other than the class of customers with the highest level of consumption per customer that has rates with a demand component, the public utility may establish and the Commission shall approve a maximum level of consumption or demand to be eligible for service as part of those classes that is lower than the minimum level of consumption or demand to be eligible for the class of customers with the highest level of consumption per customer that has rates with a demand component.

4.2. AVAILABILITY

To electric service for any non-residential customer for whom no specific schedule is provided, supplied at one point of delivery and measured through one kilowatt-hour meter.

SGS is available only to customers whose historical highest monthly demand is less than 100 kW. For a customer initiating new service with EAL, the anticipated highest monthly demand must be less than 100 kW, and in the event the customer’s actual monthly demand actually exceeds 100 kW, the customer will be removed from SGS the month following EAL’s notice to the customer. For customers taking service under SGS prior to the effective date of this schedule, EAL will review customer billings to determine whether a customer’s monthly demand exceeds the eligibility thresholds for enrollment in this schedule in which case the customer’s eligibility under SGS will be evaluated for removal from SGS during the Company’s next base rate case following the effective date of this schedule.

Service under this schedule is also available to supply power to street lighting systems not owned or maintained by the Company in unincorporated communities having a property owner’s association duly authorized to contract on behalf of the residents of such community for such service.

EAL Direct Exhibit CRM-1Docket No. 21-058-TF

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Service under this Schedule is also available to customers that would be served under Rate Schedule No. 16, Community Antenna TV Power Supply (CTV), if the customer prefers metered service. Such service will be non-demand metered and will be provided only pursuant to Rate Schedule No. 16, § 16.2.

Service pursuant to new municipally owned Interstate or other controlled access highway system lighting contracts executed on and after this Schedule’s effective date will be metered and billed pursuant to this schedule.

Not applicable to resale or shared service.


Single- or three-phase, 60 cycles and at one standard delivery voltage required by customer and available at customer's service location where service is delivered and metered at voltages less than 13,800Y/7,960. For service delivered and/or metered at other voltages, see Rate Schedule No. 18 for the appropriate adjustments to the Net Monthly Rate.


4.4.1. Rate


Demand Charge per kW: All kW over 6.0 kW $ 4.43

Energy Charge per kWh: 1st 900 kWh plus 150 kWh per kW over 6.0 kW $ 0.05637 All additional kWh $ 0.03972

4.4.2. Minimum

The Minimum shall be the greater of the following: Billing Item Rate

Customer Charge: Plus

$24.25

Demand Charge per kW: Highest kW over 6.0 kW established in the twelve months ending with the current month;

or, $ 2.95

An amount that may be required by Rate Schedule No. 60, Extension of Facilities.


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1st Revision Sheet No. 4.3 Schedule Sheet 3 of 4







4.4.3. Billing Amount

The Billing Amount will be the greater of the amounts calculated in § 4.4.1 or § 4.4.2 above, plus the Energy Cost Recovery factor times the billed energy, plus all other Adjustments required by § 4.4.4 below. When a minimum bill is rendered pursuant to § 4.4.2, the Adjustments will apply to the kW that would have been billed absent the ratchet in the minimum.

4.4.4. Adjustments


4.5. DEMAND

The kW or kVA, if kVA metered, as shown by or computed from the readings of the Company's demand meter, for the 15-minute period of greatest use during the month, subject to the table below. The Company may install kW or kVA demand metering if in Company’s opinion demand metering is warranted or low power factor is suspected. The Billing kW below may be further adjusted by the application of optional riders to this Rate Schedule.

1. If account is not demand metered and energy consumption for the month is equal toor greater than 1,800 kWh: Billing kW = kWh/300.

2. If kVA metered: Billing kW = Metered kVA x 0.9.

3. If kW metered: Billing kW = Metered kW.

4. In any case the Billing kW will not be less than 6 kW.

4.6. PAYMENT



Month to month except as otherwise required by Company's Rate Schedule No. 60, Extension of Facilities.


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1st Revision Sheet No. 4.4 Schedule Sheet 4 of 4










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Kind of Service: Electric Class of Service: Industrial Docket No.: 18-073-TF Order No.:


Title: General Farm Service (GFS) PSC File Mark Only


5.0. GENERAL FARM SERVICE



5.2. AVAILABILITY

For all uses of electric service, for which no specific rate schedule is provided, required on a farm for the growing, harvesting and processing of farm products, all of such uses at the service location being supplied through one meter. Rate Schedule GFS is available only for general farming purposes where there is no domestic or residential use. Not applicable to standby or supplementary service or to industrial or commercial establishments on or off the farm. Service is for the use of the customer and may not be shared or resold to others.


Service will normally be single-phase, 60 cycles, at approximately 120/240 Volts or at such other voltages as may be adopted by the Company and approved by the APSC. Three-phase service may be made available pursuant to § 5.4.4., of this rate schedule.


5.4.1. Rate

Billing Item Rate Customer Charge: $20.20 Demand Charge per kW:

All kW over 6.0 kW $ 3.94 Energy Charge per kWh:

All kWh $ 0.04192

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5.4.2. Minimum

The greater of:

Billing Item Rate A. Demand Charge per kVA or fraction thereof of

transformer capacity installed to serve the customer; or,

B. Such other amount as may be required under Company’s Rate Schedule No. 60, Extension of Facilities.

$1.52


The Billing Amount will be the greater of the amounts calculated in § 5.4.1, as adjusted by § 5.4.4 if required, or § 5.4.2 above. In either case, the Energy Cost Recovery factor times the billed energy, plus all other Adjustments required by § 5.4.5 below, will also be added.


When three-phase service is supplied, a monthly charge will be added to the Net Monthly Rate Customer Charge and to the minimum bill requirements for single-phase service as follows:

Billing Item Rate Charge per Month $2.98

In the event a primary line extension is necessary, customer will reimburse Company for the estimated construction cost of the three-phase primary extension in excess of the estimated cost of a single-phase extension. in advance of construction.

5.4.5. Adjustments


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5.5. DEMAND

The kW or kVA, if kVA metered, as shown by or computed from the readings of the Company's demand meter, for the 15-minute period of greatest use during the month, subject to the table below. The Company may install kW or kVA demand metering if in Company’s opinion demand metering is warranted or low power factor is suspected. The Billing kW below may be further adjusted by the application of optional riders to this Rate Schedule.

1. If account is not demand metered and energy consumption for the month is equal toor greater than 1,800 kWh Billing kW = kWh/300.



4. In any case the Billing kW will not be less than 6 kW.

5.6. PAYMENT



Month to month except as otherwise required by Company's Rate Schedule No. 60, Extension of Facilities



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Title: Large General Service (LGS) PSC File Mark Only


6.0. LARGE GENERAL SERVICE



6.2. AVAILABILITY

To all electric service required by customer on the premises, when supplied at one point of delivery and measured through one meter. Applicable to standby or supplementary service and to interruptible service only in conjunction with the applicable Rider for such service. Not applicable to resale or shared service.



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NET MONTHLY RATE

6.4.1. Rate


All Summer Period kW* $13.85 All Other Period kW $11.74

Energy Charge per kWh: All Summer Period kWh* $ 0.02709 All Other Period kWh $ 0.01927

*Summer Period is defined as the billing months of June, July, August and September. Allother billing months are defined as "Other Period."

6.4.2. Minimum

The greater of:


Highest kW established in the twelve months ending with the current month:

$ 4.68

Or, such other amount required by Rate Schedule No. 60 Extension of Facilities.


The Billing Amount will be the greater of the amounts calculated in § 6.4.1 or § 6.4.2 above plus the Energy Cost Recovery factor times the billed energy, plus all other Adjustments required by § 6.4.4 below. When a demand based minimum bill is rendered pursuant to § 6.4.2, the Adjustments will apply to the kW that would have been billed absent the ratchet.

6.4.4. Adjustments


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6.5. DEMAND

The kW or kVA, if kVA metered, as shown by or computed from the readings of the Company's demand meter, for the 15-minute period of greatest use during the month, subject to the table below. The Company may install kVA demand metering if low power factor is suspected. The Billing kW below may be further adjusted by the application of optional riders to this Rate Schedule.

1. If kVA metered: Billing kW = Metered kVA x 0.9

2. If kW metered: Billing kW = Metered kW

3. In either case the Billing kW will not be less than 100 kW

6.6. PAYMENT



Not less than one year nor less than required by Rate Schedule No. 60 Extension of Facilities.

No term contract will be required for customer who, through Federal Statute, rule or regulation, is prohibited from entering into Company's standard Agreement for Electric Service and who meets the Company's requirements for advancing the cost of connection facilities.



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Original Sheet No.: 7.1 Schedule Sheet 1 of 4

Replacing: Sheet No.:



Part III. Rate Schedule No.: 7 Effective: 2/1/19

Title: Large General Service - Time-Of-Use (GST) PSC File Mark Only


7.0. LARGE GENERAL SERVICE - TIME-OF-USE



7.2. AVAILABILITY

To all electric service required by any Customer with maximum demand of less than 1,000 kW on the premises, when supplied at one point of delivery and measured through one meter. Applicable to standby or supplementary service and to interruptible service only in conjunction with the applicable Rider for such service. Not applicable to resale or shared service.


Single- or three-phase, 60 cycles and at one standard delivery voltage required by Customer and available at Customer's service location where service is delivered and metered at voltages less than 13,800Y/7,960. For service delivered and/or metered at other voltages, see Rate Schedule No. 18 for the appropriate adjustments to the Net Monthly Rate.

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7.4.1. Rate


Demand Charge per kW: Summer Period*

All On-Peak kW $18.62 All Excess kW $ 5.49

Other Period* All On-Peak kW $15.70 All Excess kW $ 4.76

Energy Charge per kWh: Summer Period*

All On-Peak kWh $ 0.01975 All Off-Peak kWh $ 0.01409

Other Period* All On-Peak kWh $ 0.01086 All Off-Peak kWh $ 0.00931



Summer Period: Other Period:

1:00 p.m. - 8:00 p.m. 7:00 a.m. - 6:00 p.m. Monday - Friday Monday - Friday



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7.4.4. Minimum

The greater of:


Demand Charge per kW: Highest kW established in the twelve months ending with the current month:

$ 4.68

Or such other amount required by Rate Schedule No. 60, Extension of Facilities.


The Billing Amount will be the greater of the amounts calculated in § 7.4.1 or § 7.4.4 above plus the Energy Cost Recovery factor times the billed energy, plus all other Adjustments required by § 7.4.6 below. When a demand based minimum bill is rendered pursuant to § 7.4.4, the Adjustments applying to demand will apply to the kW that would have been billed absent the ratchet in the minimum.

7.4.6. Adjustments


7.5. DEMAND

The kW or kVA, if kVA metered, as shown by or computed from the readings of the Company's demand meter, for the 15-minute period of greatest use during the month, subject to the following:



3. In either case the Billing kW will not be less than 100 kW of on-peak demand.

Excess Demand is the amount by which the Off-Peak Demand exceeds the On-Peak Demand.

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7.6. PAYMENT




No term contract will be required for Customer who, through Federal Statute, rule or regulation, is prohibited from entering into Company's standard Agreement for Electric Service and who meets the Company's requirements for advancing the cost of connection facilities.



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Title: Large Power Service (LPS) PSC File Mark Only


8.0. LARGE POWER SERVICE



8.2. AVAILABILITY

To all electric service required by customer on the premises, when supplied at one point of delivery and measured through one meter. Applicable to standby or supplementary service and to interruptible service only in conjunction with the applicable Rider for such service. Not applicable to resale or shared service.



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8.4.1. Rate


All Summer Period kW * $ 13.42 All Other Period kW * $ 11.28

Energy Charge per kWh: All Summer Period kWh * $ 0.02709 All Other Period kWh * $ 0.01927


8.4.2. Minimum

The greater of:


Highest kW established in the twelve months ending with the current month: $ 4.68



The Billing Amount will be the greater of the amounts calculated in § 8.4.1 or § 8.4.2 above plus the Energy Cost Recovery factor times the billed energy, plus all other Adjustments required by § 8.4.4 below. When a demand based minimum bill is rendered pursuant to § 8.4.2, the Adjustments will apply to the kW that would have been billed absent the ratchet.

8.4.4. Adjustments


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8.5. DEMAND

The kW or kVA, if kVA metered, as shown by or computed from the readings of the Company's demand meter, for the 15-minute period of greatest use during the month, subject to the table below. The Company may install kVA demand metering if low power factor is suspected. The Billing kW below may be further adjusted by the application of optional riders to this Rate Schedule.



3. In either case the Billing kW will not be less than 1000 kW.

8.6. PAYMENT



Not less than five years.

No term contract will be required for customer who, through Federal Statute, rule or regulation, is prohibited from entering into Company's standard Agreement for Electric Service and who meets the Company's requirements for advancing the cost of connection facilities.



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Title: Large Power Service - Time-Of-Use (PST) PSC File Mark Only


9.0. LARGE POWER SERVICE - TIME-OF-USE



9.2. AVAILABILITY

To all electric service required by any Customer with maximum demand of 1,000 kW or greater on the premises, when supplied at one point of delivery and measured through one meter. Applicable to standby or supplementary service and to interruptible service only in conjunction with the applicable Rider for such service. Not applicable to resale or shared service.


Single- or three-phase, 60 cycles and at one standard delivery voltage required by Customer and available at Customer's service location where service is delivered and metered at voltages less than 13,800Y/7,960. For service delivered and/or metered at other voltages, see Rate Schedule No. 18 for the appropriate adjustments to the Net Monthly Rate.

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9.4.1. Rate


Demand Charge per kW: Summer Period*

All On-Peak kW $ 18.18 All Excess kW $ 5.33

Other Period* All On-Peak kW $ 15.31 All Excess kW $ 4.63

Energy Charge per kWh: Summer Period*

All On-Peak kWh $ 0.01973 All Off-Peak kWh $ 0.01408

Other Period* All On-Peak kWh $ 0.01086 All Off-Peak kWh $ 0.00930



Summer Period: Other Period

1:00 p.m. - 8:00 p.m. 7:00 a.m. - 6:00 p.m. Monday - Friday Monday - Friday



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9.4.4. Minimum

The greater of:


Demand Charge per kW: Highest kW established in the twelve months ending with the current month:

$ 4.68



The Billing Amount will be the greater of the amounts calculated in § 9.4.1 or § 9.4.4 above plus the Energy Cost Recovery factor times the billed energy, plus all other Adjustments required by § 9.4.6 below. When a demand based minimum bill is rendered pursuant to § 9.4.4, the Adjustments applying to demand will apply to the kW that would have been billed absent the ratchet in the minimum.

9.4.6. Adjustments


9.5. DEMAND

The kW or kVA, if kVA metered, as shown by or computed from the readings of the Company's demand meter, for the 15-minute period of greatest use during the month, subject to the following:


2. If kW metered: Billing kW = Metered kW

3. In either case the Billing kW will not be less than 1,000 kW of on-peak demand

Excess Demand is the amount by which Off-Peak Demand exceeds On-Peak Demand.

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9.6. PAYMENT

The monthly bill shall be computed in accordance with the Net Monthly Rate, other provisions of the rate schedule and all applicable riders. Payment shall be made in accordance with Rate Schedule No. 29, Charges Related to Customer Activity (CAC), paragraph 29.19.1.



No term contract will be required for Customer who, through Federal Statute, rule or regulation, is prohibited from entering into Company's standard Agreement for Electric Service and who meets the Company's requirements for advancing the cost of connection facilities.



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Kind of Service: Electric Class of Service: Lighting Docket No.: 18-073-TF Order No.:


Title: Municipal Street Lighting Service (L1) PSC File Mark Only


10.0. MUNICIPAL STREET LIGHTING SERVICE



10.2. AVAILABILITY

This Schedule is available for lighting service required by any Municipality contracting for street lighting service for streets, alleys and other public ways that may lawfully install unshielded street lights pursuant to the terms of the Shielded Outdoor Lighting Act, Ark. Code Ann § 8-14-101 et seq. (the Act). This Rate Schedule is not applicable to temporary, resale, shared, or seasonal service. In the context of this Rate Schedule only, the term “municipality” shall mean any incorporated city or town served by EAL, or any unincorporated community where EAL serves more than 500 customers and where an incorporated property owners association or Board, as a part of its ordinary function, furnishes street lighting and other services normally provided by incorporated cities to, or for, residents of the unincorporated community. This service is available for street-lighting purposes only and is not available for parking facilities, temporary, resale, shared or seasonal service. Availability and installation will be consistent with the Company’s Customer Installation Standards.

In accordance with the Act, municipalities currently taking service for the fixtures listed in § 10.4.1, that no longer qualify for unshielded street lighting service, will continue to bebilled at the Net Monthly Rates in § 10.4.1 or comparable sections of superseding rate schedules until the light fails for any reason other than the failure of a lamp, photocell or starter. The customer will then be given the opportunity to choose a replacement fixture from the Company’s Rate Schedule No. 21, Municipal Shielded Street Lighting Service (L1SH) at the then current rate for the replacement.


Service will normally be single-phase, 60 cycles, at approximately 120/240 Volts, however, the service voltage and type of service will be at the Company's option. Lighting service under this Schedule will be furnished from dusk until dawn.

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10.4.1. Company Owned Facilities

The following net monthly rate is applicable when the Company owns the entire street lighting facility, consisting of the Company's standard luminaire fixture on a wood pole, overhead circuits, controls, and all other related equipment. Company will operate and maintain such facility at its expense including the cost of material required for replacing broken outer globes and for the total cost of replacing or repairing broken or damaged poles used primarily for street lighting. If Company provides change-outs or removals of functioning lighting equipment at the request of the municipality, the municipality will be responsible for the costs of such change-outs or removals. Such change-outs and removals will be scheduled reflecting the Company’s available normal resources. If the quantity of change-outs or removals cannot be completed by the Company with normal resources in the time frame requested by the municipality, the Company may utilize additional resources to meet the requested time frame with the consent of the municipality or the municipality may accept the timeline proposed by the Company. In such case, municipality will be responsible for any Company costs associated with the change-outs or removals and the cost of the additional resources.

Billing Item

Rate Keys and Description First Unit/Pole Each Excess

Unit/Pole A. Incandescent Lighting (NA)

L1A 100 Watt Unenclosed (NA) $1.89 - L1B 150 Watt Unenclosed (NA) $2.71 -

B. Mercury Vapor Lighting L1C 100 Watt (NA) $2.89 - L1D / L1DE 175 Watt (NA) $4.02 $1.48 L1E / L1EE 250 Watt (NA) $4.95 $2.01 L1F / L1FE 400 Watt (NA) $4.95 $3.21 L1G / L1GE 1,000 Watt (NA) $7.91 $4.64

C. High Pressure Sodium Lighting L1H / L1HE 150 Watt $5.75 $4.53 L1I / L1IE 250 Watt $6.95 $5.50 L1J / L1JE 360 Watt (NA) $7.12 $5.17 L1K / L1KE 400 Watt $7.39 $6.27

D. Metal Halide Lighting L1Y / L1YE 150 Watt Contempo Post-top $21.28 $18.67 L1Z / L1ZE 320 Watt Open $24.62 $20.33 L1AZ / L1AZE 320 Watt Cobra $23.75 $19.47

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10.4.1. Company Owned Facilities (continued) Billing Item


Unit/Pole E. LED Lighting

SL1A / SL1AE 60 Watt Open (NA) $10.29 $ 6.01 SL1B / SL1BE 87 Watt Open (NA) $10.97 $ 6.69 SL1C / SL1CE 110 Watt Open (NA) $11.50 $ 7.22 SL1D / SL1DE 67 Watt Cobra (NA) $10.97 $ 6.69 SL1E / SL1EE 110 Watt Cobra (NA) $11.73 $ 7.45 SL1F / SL1FE 140 Watt Cobra (NA) $13.19 $ 8.91 SL1G / SL1GE 213 Watt Cobra (NA) $15.17 $10.88 SL1H / SL1HE 96 Watt Acorn Post-top (NA) $16.04 $11.31 SL1I / SL1IE 140 Watt Shoebox (NA) $18.29 $ 9.29 SL1J / SL1JE 213 Watt Shoebox (NA) $20.27 $11.26 SL1K / SL1KE 280 Watt Shoebox (NA) $22.14 $13.14

HPS Equivalent

SL1L / SL1LE 4,800 Lumen NEMA 100W HPS $12.09 $ 7.69 SL1M / SL1ME 6,900 Lumen NEMA 150W HPS $12.89 $ 8.16 SL1N / SL1NE 12,300 Lumen Flood 320W HPS $14.43 $ 9.70 SL1O / SL1OE 5,400 Lumen Cobra 100W HPS $13.18 $ 8.86 SL1P / SL1PE 9,100 Lumen Cobra 150W HPS $14.50 $ 9.86 SL1Q / SL1QE 12,300 Lumen Cobra 250W HPS $16.00 $11.36 SL1R / SL1RE 21,000 Lumen Cobra 400W HPS $19.94 $15.30 SL1S / SL1SE 12,200 Lumen Shoebox 250W HPS $21.09 $11.94 SL1T / SL1TE 22,400 Lumen Shoebox 400W HPS $23.54 $14.39 SL1U / SL1UE 24,800 Lumen Shoebox 1,000W HPS $26.25 $17.09 SL1V / SL1VE 8,400 Lumen Acorn 150W HPS $19.57 $14.77

The first unit/pole rate indicates the rate for a single light on the company owned pole. Each excess unit/pole rate indicates the rate for any additional light beyond the initial light on the same pole.

F. Steel Poles - Additional monthly charges will be made for each of Company's standard steel poles as follows. This provision is not applicable when a nonrefundable contribution is made to cover the additional installed cost of steel poles. L1V For Poles of 30 Feet or Less Mounting Height: $1.83 L1W For Poles of 35 Feet Mounting Height: $2.81 These charges do not include or cover costs for painting steel poles. Any painting service requested by the municipality will be scheduled by the Company utilizing additional resources, and the Company shall recover the cost of acquiring the additional resources from the requesting municipality. The requesting municipality will be informed of such costs prior to the start of any requested painting service.

NA - Not available to new installations after the effective date of this sheet, however, maintenance of the photocell and lamp of existing lights will continue. When any other failure occurs, or lamps are no longer available the light will be removed and the customer may choose a replacement at the then current monthly rate of the replacement. Customer and Company may develop a City-specific plan for such replacements. 471


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G. Underground and Other Nonstandard Facilities - If the Company provides underground circuits or equipment other than the standard equipment described above or rearranges existing facilities at the request of the customer, customer may choose to pay (1) a non-refundable cash contribution in aid of construction equal to the additional cost of the non-standard equipment and/or the cost of rearranging existing facilities or (2) an additional monthly facilities charge calculated by multiplying the monthly facilities charge rate in Rate Schedule No. 26, § 26.3 times the additional cost of the non-standard equipment and/or rearrangement costs for existing facilities. Non-salvageable components of facilities installed or provided by the Company for underground service shall not be considered as Additional Facilities but shall be paid through a contribution in aid of construction. Street lighting facilities provided in accordance with Company's Tariff Governing the Installation of Residential Underground Electric Distribution Systems and Underground Service Connections, Rate Schedule No. 61, will not be subject to such additional monthly facilities charge.

10.4.2. Municipally Owned Facilities

The following Net Monthly Rates are applicable when the Municipality owns the entire street lighting facility, including the fixture, pole, circuit, controls, and all other related equipment on the load side of the Company's point of delivery; or when such facility is provided by any other public agency and Municipality is obligated to operate and maintain such facility. Company will operate and maintain such facilities at its option, based on the availability of resources. Municipality will reimburse Company for the total material and labor cost of all maintenance, except Entergy’s standard lamp replacements. Municipality will supply poles, fixtures and non-standard lamps and will reimburse Company for the total labor and equipment cost of replacing or repairing broken or damaged poles and fixtures. After the effective date of this Schedule the Company will continue re-lamping Mercury Vapor fixtures as standard lamp replacements until such lamps are unavailable to the Company. On and after the effective date of this Schedule, Company will not provide service under this § 10.4.2 to new applications requiring lamps other than Entergy’s standard lamps. Provision of service under contracts in effect on this Schedule’s effective date will continue until termination of the contract.

This Schedule is not available to new applications for lighting Interstate or other controlled access highway systems. Service to such systems for contracts executed on and after this Schedule’s effective date will be metered and billed pursuant to Rate Schedule No.4, Small General Service for energy consumed. Municipality will be responsible for all maintenance of its facilities. Service to such lighting systems will continue under this Schedule provided such service is in effect on the Schedule’s effective date.

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10.4.2. Municipally Owned Facilities (continued)

Billing Item


Unit/Pole A. Mercury Vapor Lighting

L1M 100 Watt $1.50 - L1N 175 Watt $1.14 - L1O 250 Watt $1.74 - L1P / L1PE 400 Watt $2.70 $1.91 L1Q 1,000 Watt $4.27 -

B. High Pressure Sodium Lighting L1R / L1RE 150 Watt $3.79 $2.94 L1S / L1SE 250 Watt $4.30 $3.34 L1T / L1TE 400 Watt $4.40 $3.40 L1U / L1UE 1,000 Watt $9.16 $6.67

C. Metal Halide Lighting L1BZ / L1BZE 150 Watt $15.07 $4.17 L1CZ / L1CZE 320 Watt $15.87 $5.64

10.4.3. Municipally Owned and Maintained LED Facilities

This service is only applicable for Light Emitting Diode (LED) street lighting facilities where the facilities are customer owned and maintained. The following Net Monthly Rates are applicable when the Municipality owns the entire street lighting facility, including the fixture, pole, circuit, controls, and all other related equipment on the load side of the Company's point of delivery; or when such facility is provided by any other public agency and Municipality is obligated to operate and maintain such facility. Company’s service is limited only to the supply of energy for street lighting and verification of voltage at the point of connection to the Municipality’s equipment when requested. Customer’s lighting facilities must be equipped with photocells that permit only dusk-to-dawn operation.

Net Monthly Bill

A. Customer Charge $1.09 per fixture

B. Energy Charge $0.034585 per kWh for all kWh

1. At the time Customer contracts for service under this Schedule, Customer shallprovide Company with a written inventory of all unmetered lighting fixtures for whichcustomer requests service under this Schedule. This inventory shall include thelocation, type and wattage rating for each fixture. The monthly billing kWh will bedetermined by the Company based on 4,000 annual burning hours and the type,rating, and quantity of lighting equipment from the inventory provided by customer.

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2. Customer will update its inventory of lighting fixtures by informing the Company inwriting of changes in type, rating, location, and quantity of lighting fixtures as suchchanges occur and billings will be adjusted accordingly.

3. Company reserves the right to inspect the equipment at each location and makeprospective adjustments in billing as indicated by such inspections; however,Company shall be under no obligation to conduct such inspections for the purpose ofdetermining accuracy of billing or otherwise. Company's decision not to conductsuch inspections shall not release Customer from the obligation to provide toCompany, and to update, an accurate inventory of the types, ratings, and quantitiesof lighting equipment upon which billing is based.

4. As this service is unmetered, Customer agrees to pay amounts billed in accordancewith the current inventory, regardless of whether any of the installations ofCustomer’s equipment were electrically operable during the period in question andregardless of the cause of any such equipment’s failure to operate.

10.4.4. Adjustments

Applicable Riders which adjust this Rate Schedule are listed in Rate Schedule No. 17, Table of Riders Applicable to Rate Schedules. The kWh consumption to which the adjustments apply is the average monthly kWh based on 4,000 burning hours per year.

10.5. PAYMENT

The monthly bill shall be computed in accordance with the Net Monthly Rate, other provisions of the Rate Schedule and all applicable riders. Payment shall be made in accordance with Rate Schedule No. 29, Charges Related to Customer Activity (CAC), § 29.19.1.


The contract period is as covered by any existing contract now in effect with the Municipality. All new contracts shall be for a period of one year.

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In the event the customer ceases to take electric service from the Company or wishes to change the nature of the service now being delivered within the initial term of the contract, the Company reserves the right to consent to such cancellation or change provided customer pays the lesser of the following:

1. The applicable monthly charge for the remaining months of the Contract.

2 The amount computed under the following formula; provided, however, suchamount shall never be less than zero:[A + B - C] X D

Where:

A = Original installed cost of the facilitiesB = Cost of removing facilitiesC = Salvage value to Company of equipment and material removedD = 1.12 less .01 times the number of months which have expired since the

facilities were installed


Service under this Schedule is subject to Policy Schedule No. 9, Service Regulations, of the Company as it is now on file, and as it may in the future be filed, with the APSC and the rules of the Commission.

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Title: Traffic Signal Service (TSS) PSC File Mark Only


11.0. TRAFFIC SIGNAL SERVICE



11.2. AVAILABILITY

To un-metered traffic control signals, flashing or warning signals and safety surveillance video equipment of a municipality, a county, the States of Arkansas or Tennessee, or an agency thereof for the control of traffic on public streets or highways. Where a traffic signal installation contains a street light, the street light must be served under § 10.4.2, Municipally Owned Facilities of the Municipal Street Lighting Service Rate Schedule No. 10. Not applicable to temporary service.


Single-phase, approximately 60 cycles, at approximately 120/240 Volts.


11.4.1. Traffic Control Signals

Billing Item Rate Each direction of traffic controlled at each intersection, or point of control, including three lenses per direction controlled: $3.93

Each lens in excess of three per direction of traffic controlled at each intersection, or point of control: $1.19

If average lamp rating at each intersection, or point of control exceeds 85 Watts, the number of lenses will be determined by dividing the sum of the lamp ratings, in Watts, by eighty-five (85) and rounding to nearest whole number (major fractions will be rounded to one).

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Each 50 Watts, or fraction thereof, of power requirement of signal controlling and/or traffic counting devices at each intersection or point of control will be counted as one additional lens.

11.4.2. Flashing or Warning Signals and Safety Surveillance Video Equipment

Billing Item Rate First 100 or less lamp Watts per signal: $3.93

Each additional 25 or major fraction thereof lamp Watts per signal: $0.60

Monthly minimum charge per signal: $3.93

11.4.3. Adjustments

Applicable Riders which adjust this Rate Schedule are listed in Rate Schedule No. 17, Table of Riders Applicable to Rate Schedules. The kWh consumption to which the adjustments apply will be determined by multiplying the wattage of lights by 0.30 and the wattage of controls by 0.73. Where light emitting diodes have been installed as the lighting source and the customer has given the Company proper notice, the Company’s billing will reflect the appropriate wattage for the color of each signal in the calculation of energy for the application of Adjustments applying to energy.

11.5. BILLING

The minimum billing period for service to any installation is one month and no monthly bill will be prorated because service is connected or disconnected during a billing cycle.

11.6. OTHER PROVISIONS

If additional facilities are necessary or if it is necessary to rearrange existing facilities, customer will pay to Company the cost of such additional facilities or rearrangement of existing facilities.

Customer agrees not to change the connected load or the character of its facilities at each installation without notifying Company in writing of its intention to do so.

Company reserves the right to test and/or inspect customer's installation from time to time and to adjust the wattage ratings for billing purposes to conform to the findings of such tests or inspections.

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11.7. PAYMENT



Month to month.



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Title: All Night Outdoor Lighting Service (L4) PSC File Mark Only


12.0. ALL NIGHT OUTDOOR LIGHTING SERVICE



12.2. GENERAL

This schedule is presented in two parts, § 12.3 applies where All Night Outdoor Lighting Service is provided by Company owned and maintained lighting facilities and § 12.4 applies where the Company’s service is limited only to the supply of energy for use in subdivision-owned outdoor lighting facilities.

12.3. COMPANY OWNED AND MAINTAINED LIGHTING FACILITIES

12.3.1. AVAILABILITY

Available to un-metered automatically controlled outdoor lighting service burning all night. Company will install, own, operate, and maintain Nightwatcher or Floodlight, including any necessary lamp replacements. Availability and installation will be consistent with the Company’s Customer Installation Standards.

All necessary normal service, maintenance and lamp replacements will be furnished at Company's expense within three (3) business days after notice is given by customer to Company’s Customer Service Center at 1-800-ENTERGY or any superseding telephone number. The cost of unusual maintenance resulting from negligent or purposeful physical damage or vandalism shall be the responsibility of and billed to customer. If payment for such unusual maintenance is not made within the time period allowed in the Payment provision of this Rate Schedule the Agreement For All Night Outdoor Lighting Service shall be terminated and Company's facilities will be removed in accordance with Company's Policy Schedule No. 7, All Night Outdoor Lighting Maintenance Policy, as filed with the APSC and as provided to customer with customer's copy of the Agreement For All Night Outdoor Lighting Service.

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Not applicable for seasonal service. Applicable to temporary service when the customer pays in advance of construction the estimated gross cost of providing, installing and removing the temporary facilities required to provide service less the estimated salvage value of such facilities upon removal.

12.3.2. NET MONTHLY RATE

12.3.2.1. Nightwatchers

Billing Item Rate Key Watts / Type Rate

A. Incandescent Unshielded L4H 300 Not available for new installations after 3/8/90 $ 5.74

B. Mercury Vapor Unshielded L4A 100 / Open (NA) $ 4.94 L4B 175 / Open (NA) $ 5.08 L4C 250 / Open (NA) $ 5.41 L4D 400 / Open (NA) $ 6.63 L4S 400 / Shoebox (NA) $10.03

C. High Pressure Sodium Unshielded N4A 100 / Open (NA) $ 8.40 L4E 150 / Open $ 6.32 L4F 250 / Open $ 7.45 N4B 250 / Cobra $10.53 N4U 250 / Traditionaire $14.52 L4G 400 / Open $ 8.71 N4C 400 / Cobra $11.89 N4E 150 / Colonial $10.22 N4F 150 / Acorn $11.83 L4T 400 / Shoebox $13.22 N4G 400 / Square (NA) $16.11 N4H 1,000 / Shoebox $22.37

D. High Pressure Sodium Shielded N4PS 150 / Cobra $ 8.81 N4QS 250 / Cobra $11.64 N4RS 400 / Cobra $12.91 N4SS 150 / Colonial Post Top $ 8.91

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E. Metal Halide Unshielded N4J 175 / Acorn (NA) $15.39 N4P 150 / Acorn $13.35 L4N 400 / Open (NA) $ 9.08 N4Q 320 / Open $ 9.80 L4U 400 / Shoebox (NA) $14.35 N4D 400 / Cobra (NA) $15.59 N4R 320 / Cobra $15.67 N4V 320 / Shoebox $21.23 N4K 400 / Square (NA) $19.11 N4L 1,000 / Shoebox $25.84 N4M 1,000 / Square (NA) $28.11

F. Light Emitting Diode (LED) HPS Equivalent N4LED1 2,150 Lumen Traditional 75W HPS $ 9.90 N4LED2 4,500 Lumen Traditional 100W HPS $10.34 N4LED3 6,200 Lumen Traditional 150W HPS $10.78 N4LED4 5,200 Lumen Granville 100W HPS $15.15 N4LED5 7,700 Lumen Granville 150W HPS $15.71 N4LED6 5,200 Lumen Acorn 100W HPS $14.07 N4LED7 8,400 Lumen Acorn 150W HPS $14.77 N4LED8 12,200 Lumen Shoebox 250W HPS $11.94 N4LED9 22,400 Lumen Shoebox 400W HPS $14.39 N4LED10 24,800 Lumen Shoebox 1,000W HPS $17.09 N4LED11 4,800 Lumen NEMA 100W HPS $ 7.69 N4LED12 6,900 Lumen NEMA 150W HPS $ 8.16

12.3.2.2. Floodlights

Billing Item Rate Key Watts / Type Rate

A. Mercury Vapor Unshielded L4J 400 / Flood (NA) $ 8.35 L4K 1,000 / Flood (NA) $13.12

B. High Pressure Sodium Unshielded N4N 100 / Flood (NA) $ 9.49 L4L 250 / Flood $10.71 L4M 400 / Flood $11.51 L4P 1,000 / Flood $15.09

C. Metal Halide Unshielded N4O 250 / Flood (NA) $14.57 L4Q 400 / Flood (NA) $12.69 N4S 320 / Flood $12.72 L4R 1,000 / Flood $17.22

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NA - Not available for new installations after the effective date of this Sheet. Existing installations will be maintained until the fixture fails, or lamps are no longer available. Customer may then choose a replacement at the then current monthly rate of the replacement. Photocell or lamp failure will not be considered a fixture failure.

12.3.3. Additional Facilities

The rates in § 12.3.2.1 and § 12.3.2.2 are applicable only when a standard Nightwatcher or Floodlight is installed on an existing pole and connected to an existing secondary circuit.

When a Nightwatcher or Floodlight is not installed on existing facilities, the customer may request a compatible pole listed in § 12.3.4 and the associated monthly pole rate will apply. If the customer requests a different available pole, or any other additions to or rearrangement of existing facilities, a monthly Additional Facilities Charge will apply. Such monthly charge will be calculated by multiplying the monthly facilities charge rate in Rate Schedule No. 26, § 26.3 times the estimated cost of such other additions to, or rearrangement of, existing facilities.

If the Company installs non-standard equipment at the request of the customer, customer will pay a non-refundable cash contribution-in-aid of construction equal to the additional cost of the non-standard equipment or an additional monthly facilities charge calculated by multiplying the additional cost of such non-standard equipment by the rate previously cited in this § 12.3.3.

The 30 foot Wood Pole (P4A) and 35 foot Wood Pole (P4B) are not available as additional facilities after March 9, 2001 but are available at the monthly Rates shown in § 12.3.4.

D. Light Emitting Diode (LED) HPS Equivalent F4LED1 5,500 Lumen Flood 100W HPS $10.55 F4LED2 7,600 Lumen Flood 150W HPS $11.05 F4LED3 11,500 Lumen Flood 250W HPS $12.27 F4LED4 22,400 Lumen Flood 400W HPS $14.49 F4LED5 32,300 Lumen Flood 1,000W HPS $17.58

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12.3.4. Poles/Pole Equipment

If there is no existing pole, customer may choose from those listed below to the extent compatible with customer's selection of fixture.

Billing Item Rate Key / Description of Pole or Pole Equipment Rate P4A / 30 foot Wood Pole (including supply line) $ 3.26 P4B / 35 foot Wood Pole (including supply line) $ 3.99 P4C / 30 foot Steel-5” Square Pole (excluding supply line) (1) (2) $ 8.46 P4D / 28 foot Concrete Octagon Pole (excluding supply line) (1) (2) $ 5.41 P4E / 18 foot Fiberglass Round Pole (excluding supply line) (1) (2) $ 2.66 P4F / 39 foot Steel Round Tapered Pole (excluding supply line) (1) (2) $11.97 P4G / Plugged 4-way Adapter (1) $ 1.93 (1) Available for new applications only as Additional Facilities on and after the effective

date of this sheet. (2) Includes internal 12/2 Romex or equivalent to connect fixture to underground

secondary.

12.3.5. Minimum

The Net Monthly Rate plus the Energy Cost Recovery factor times the energy consumed, plus all other Adjustments required by § 12.3.6 below.

12.3.6. Adjustments


12.4. ENERGY RATE FOR SUBDIVISION OWNED LIGHTING FACILITIES

This service is available only from Company’s existing underground secondary voltage facilities and only where such facilities and transformation are adequate to accommodate the additional load. If additional facilities, including transformation, must be installed to accommodate the additional load, then the customer must pay the installed cost of such additional facilities. This service is available only where outdoor lighting is provided by customer owned and maintained facilities and the Company’s service is limited only to the supply of energy for outdoor lighting. Customer’s lighting facilities must be equipped with photocells to permit only dusk-to-dawn operation.

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This service is available to platted and recorded subdivisions within a municipality where the municipality will not provide street lighting service or in platted and recorded subdivisions outside municipal corporate limits. Such subdivision must have an incorporated property owners association or board that, as a part of its ordinary function, furnishes street lighting and other similar services to the subdivision. Such subdivision must have at least fifty (50) lots and require no less than ten (10) outdoor lighting units. This service is not available to individual customer owned outdoor lighting.

12.4.1. CHARACTER OF SERVICE

Service will normally be single-phase, 60 cycles, at approximately 120/240 Volts.

12.4.2. NET MONTHLY RATE

12.4.2.1. Rate

Billing Item Rate Rate Key

All determined kWh: $0.02819 L4V

12.4.2.2. Minimum Monthly Bill

The amount calculated under the Net Monthly Rate plus all adjustments pursuant to § 12.4.2.3 based on the estimated kWh for the account.

12.4.2.3. Adjustments


12.4.2.4. Determination of Energy Requirements

At the time customer contracts for service under this Schedule, customer shall provide Company with a written inventory of all unmetered lighting at each point of delivery for which customer requests service under this Schedule, which inventory shall include the type and wattage rating for each fixture. The demand and energy for each point of service will be determined by the Company based on the type, rating, and quantity of lighting equipment from the inventory provided by customer. Determination of the monthly kWh for a lighting device shall be based on 4,000 annual burning hours.

Customer shall update its inventory by informing the Company in writing of changes in type, rating, and/or quantity of lighting equipment as such changes occur but not less than annually, and billings will be adjusted accordingly pursuant to APSC GSR 5.19.

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Company may, at its discretion, test meter the load of various types and ratings of customer's lighting equipment to the extent necessary to verify the estimated demand and energy used for billing purposes and, where dictated by such test metering, Company will make prospective adjustments in estimated usage for subsequent billing purposes. However, Company shall be under no obligation to test meter the load of customer's lighting equipment and Company's decision not to test meter the load of customer's equipment shall not release customer from the obligation to initially provide its inventory to Company, and to update such inventory by informing the Company in writing of changes in type, rating, and/or quantity of lighting equipment, upon which billing is based, as such changes occur but not less than annually.

Upon Company's request, customer shall provide an updated inventory of all lighting equipment at each point of service.

Company reserves the right to periodically inspect customer’s lighting equipment at each point of service and make adjustments in billing pursuant to APSC GSR 5.19 as indicated by such inspections; however, Company shall be under no obligation to conduct such inspections for the purpose of determining accuracy of billing or otherwise. Company's decision not to conduct such inspections shall not release customer from the obligation to initially provide to Company, and to update its inventory by informing the Company in writing of changes in type, rating, and/or quantity of lighting equipment, upon which billing is based, as such changes occur but not less than annually. Because this service is unmetered, customer agrees to pay amounts billed in accordance with the current inventory, regardless of whether any of the installations of customer’s lighting were electrically operable during the period in question and regardless of the cause of such equipment’s failure to operate.

12.4.4. Disconnection of Service

Service may be disconnected at the point(s) of delivery to a delinquent account pursuant to Commission Rules.

12.4.5. Reconnection of Disconnected Service

If service is disconnected for non-pay, customer will be required to pay a reconnection fee for the reconnection of each point of delivery to Company’s secondary voltage facilities before service is restored. Such fee shall be as provided in Rate Schedule No. 29, Charges Related to Customer Activity (CAC), § 29.14.

12.4.6. Fusing / Maintenance of Customer Owned Facilities

The customer shall provide fusing that disconnects the customer’s facilities from those of the Company. Customer shall disconnect customer facilities from those of the Company prior to and during all maintenance except lamp replacements.

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12.4.7. Identification of Customer-Owned Facilities

Customer owned facilities shall be identified as not being the facilities of the Company through a Company supplied insignia that shall be attached to the facilities of the customer at points designated by the Company.

12.4.8. Indemnity

In the event of injury or death to any person as a result of contact with said customer owned facilities, the customer shall defend, indemnify and hold the Company harmless from any and all claims, actions, causes of action and demands arising therefrom. Said obligation to defend, indemnify and hold harmless includes, but is not limited to, payment of judgment, settlements or claims and litigation and preparation expense in connection therewith for discovery, expert witness fees, reasonable attorney's fees, and other such expenses to the extent permissible by law.

12.4.9. Inspection / Maintenance of Customer Owned Facilities

The Company has no duty to inspect, repair, or replace lamps or otherwise maintain the lighting facilities of customer to which this energy only service is provided pursuant to § 12.4 of this rate schedule, or to disconnect Company’s service from customer’s facilities for customer’s inspection, repair, lamp replacement or maintenance of customer’s facilities.

12.5. Contract Period

The contract period for service under § 12.3 is month to month unless Company provides service under § 12.3.3 or § 12.3.4 or special conditions exist, in which case a written Agreement for All Night Outdoor Lighting Service will be required with a contract period not less than one year. The form of the Agreement is shown in § 13.4.1 of Policy Schedule No. 13.

The contract period for service under § 12.4, Energy Rate for Subdivision Owned Lighting Facilities, shall be not less than two years. The form of the Agreement is shown in § 13.4.2 of Policy Schedule No. 13.

12.6. PAYMENT


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Kind of Service: Electric Class of Service: Governmental Agencies Docket No.: 18-073-TF Order No.:


Title: Municipal Pumping Service (MP) PSC File Mark Only


13.0. MUNICIPAL PUMPING SERVICE



13.2. AVAILABILITY

For power service to municipalities or other public agencies for the operation of residential sludge grinder pumps only. Not applicable to temporary, breakdown, resale, shared service, standby or supplementary service.


Single- or three-phase, 60 cycles and at one standard delivery voltage required by customer and available at customer's service location.


13.4.1. Rate

Billing Item Rate Charge per installed horsepower: $ 1.01

13.4.2. Minimum

Billing Item Rate Charge per month: $32.96

The minimum billing period for any single installation is one month and no monthly bill will be prorated because a grinder pump is connected or disconnected during a billing cycle.

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The Billing Amount will be the greater of the amounts calculated in § 13.4.1 or § 13.4.2 above plus the Energy Cost Recovery factor times the billed energy, plus all other Adjustments required by § 13.4.4. When a minimum bill is rendered pursuant to § 13.4.2, the Adjustments will apply to the calculated kWh pursuant to § 13.4.4 below.

13.4.4. Adjustments

Applicable Riders which adjust this Rate Schedule are listed in Rate Schedule No. 17, Table of Riders Applicable to Rate Schedules. The kWh consumption to which the adjustments apply will be determined by multiplying the installed horsepower by 16.0.


Customer will provide all wiring and equipment needed for connection to Company's existing distribution system, including a suitable device to disconnect and protect his service near the point of connection. Customer shall keep the switch enclosure locked.

If additional facilities are necessary or if it is necessary to rearrange existing facilities, customer will pay to Company the cost of such additional facilities or rearrangement.


Company reserves the right to test customer's installation from time to time and to adjust the horsepower rating for billing purposes to be in conformance with the results of such tests.


Not less than one year.

13.7. PAYMENT


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Title: Agricultural Water Pumping Service (AP) PSC File Mark Only


14.0. AGRICULTURAL WATER PUMPING SERVICE



14.2. AVAILABILITY

To electric service for agricultural water pumping for the irrigation of crops, fish farming, and other agricultural purposes which require large quantities of water. The season is defined as that period commencing with the billing month of March and ending with the billing month of February of the following year. Not applicable to standby, breakdown, supplementary, resale, or shared service.


Single- or three-phase, approximately 60 cycles, at any one standard voltage required by customer and available at customer's service location. Customer will not install a single-phase motor of greater than 10 HP without prior Company approval.

14.4. SEASONAL RATE (A)

14.4.1. Rate

Billing Item Rate

Energy Charge per kWh: 1st 268 kWh/kW of Billing Load $0.08246 All additional kWh $0.05647

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14.4.2. Minimum

Billing Item Rate Demand Charge per kW of cumulative Billing

Load per season: $10.42


The Billing Amount will be the greater of the amounts calculated in § 14.4.1 or § 14.4.2 above. In either case, the Energy Cost Recovery factor times the billed energy, plus all other Adjustments required by § 14.4.6 below will be added.

14.4.4. Billing Load

For those customers in billing cycles 9 through 21, the Billing Load for a season is defined as three times the maximum monthly kW load required for operation of customer's pumping plant for the peak billing months of June, July and August. For those customers in billing cycles 1 through 8, the Billing Load for a season is defined as three times the maximum monthly kW load required for the operation of customer's pumping plant for the peak billing months of July, August and September, provided, however, customer's Billing Load for the season shall be based on three peak billing months even though service is not used during all of such peak billing months.

The maximum monthly kW load will be the maximum kW supplied during the 15-minute period of customer's greatest use but not less than 11 kW.

14.4.5. Billing Procedure

Pre-peak billing season: Energy billed during a season prior to the customer’s initial peak billing month will be billed at the rates applicable to the initial step of the Energy Charge per kWh in § 14.4.1.

Peak billing season: The bill for the current month will be the amount determined by applying the Seasonal Rate (including Minimum) to the cumulative Billing Load (1, 2 or 3 times the highest kW) and the cumulative kWh consumption for the current season to date and subtracting the cumulative billing previously rendered during the current season.

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In any peak billing month where the customer is billed a minimum demand billing, the customer will be charged applicable Adjustments for all energy consumed during the month pursuant to § 14.4.6 plus the minimum demand billing.

Post-peak billing season: The billing for the season will not be less than the charge per kW in § 14.4.2 times the Billing Load before application of Adjustments. If at the end of the customer’s Peak-billing season the cumulative amount billed was the result of a demand minimum billing, any kWh paid for through such minimum demand billing but not consumed will be credited against billings for kWh consumed during subsequent months of the same season.

14.4.6. Adjustments


14.5. OPTIONAL MONTHLY RATE (B)

Customer may elect to be billed under the following Monthly Rate at the beginning of a season or when service is connected each season. After such election, the billing during the season will be on the rate so elected and the basis for billing will not be changed from the Optional Monthly Rate (B) to the Seasonal Rate (A) (or vice versa) during any one season.

14.5.1. Rate

Billing Item Rate Energy Charge per kWh:

1st 402 kWh/kW of Billing Load $0.07979 All additional kWh $0.05647

14.5.2. Minimum

Billing Item Rate Demand Charge per kW:

All kW of Billing Load $6.12



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The Billing Load (kW) for each month is the maximum kW supplied during the 15-minute period of customer's greatest use during the month but not less than 11 kW.

14.5.5. Adjustments

See § 14.4.6 above.


Month to month.

14.7. PAYMENT




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Title: Cotton Ginning Service (CGS) PSC File Mark Only


15.0. COTTON GINNING SERVICE



15.2. AVAILABILITY

To electric power service, including incidental lighting where customer furnishes and maintains necessary equipment to reduce service voltage to lighting voltage, supplied through one meter at one point of delivery for the ginning of cotton during the year beginning March 16.

The ginning season shall begin September 15 each year, unless an earlier date of beginning is agreed to by the Company, and shall end on March 15 of the following year. The Company reserves the right to disconnect all service provided under this rate schedule from customer's premises at the conclusion of the ginning season and agrees to reconnect such service at the beginning of the next ginning season upon reasonable advance notice from customer.

Service under this schedule shall not be resold, submetered, used for standby or shared with others. Electric service used for other purposes on the same premises shall be separately served, metered and billed in accordance with the applicable rate schedule for such other service.


Three-phase, 60 cycles and at one standard delivery voltage required by customer and available at customer's service location.

15.4. NON-SEASONAL USE

Any customer who uses energy during the annual period beginning March 16 for other than incidental purposes such as motor testing during the non-ginning season shall be separately metered and billed on the appropriate General Service schedule.

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15.5. SEASONAL RATE

Applicable to customers who restrict their usage to the ginning season.

15.5.1. Rate


1st 268 kWh per kW of Billing Load $ 0.09419 All additional kWh $ 0.06461

15.5.2. Minimum

The greater of:

Billing Item Rate Demand Charge per kW of Billing Load:

October $ 4.35 November $ 8.69 December $13.04

Or an annual amount required by Rate Schedule No. 60 distributed equally in the months of the ginning season.




The Billing Load (kW) is defined as the maximum monthly kW supplied during the 15-minute period of customer's greatest use during the season but not less than 19 kW.

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The bill for the current month will be the amount determined by applying the Seasonal Rate (including Minimum) to the Billing Load and the cumulative kWh consumption for the current season to date and subtracting the cumulative billing previously rendered during the current season. Energy billed during a season prior to the initial peak billing month will be billed at the rates applicable to the initial step of the Energy Charge per kWh in § 15.5.1 above. The cumulative billing in each month of the season will not be less than the Demand Charge in § 15.5.2 above applied to the Billing Load in each of the three months of the ginning season. Any kWh paid for but not consumed will be credited against billings for kWh consumed during subsequent months of the same season.

15.5.6. Adjustments



Not less than one ginning season.

15.7. PAYMENT




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Kind of Service: Electric Class of Service: Commercial Docket No.: 18-073-TF Order No.:


Title: Community Antenna TV Power Supply (CTV) PSC File Mark Only


16.0. COMMUNITY ANTENNA TV POWER SUPPLY SERVICE



16.2. AVAILABILITY

Available for un-metered electric service to community antenna television power supplies. Customers preferring metered service may be served under Rate Schedule No. 4, Small General Service when the customer provides and installs a meter base and meter loop either on customer’s free-standing pole, or free-standing power supply unit all to Company’s specifications. Not applicable to temporary, standby, supplementary, breakdown, resale or shared service.


Single-phase, 60 cycles at approximately 120/240 Volts.


16.4.1. The kWh consumption to which provisions of this Net Monthly Rate apply will be determined by multiplying the nameplate rating of the power supply in watts by 0.73.

16.4.2. Rate

Billing Item: Rate

Energy Charge per kWh:

All kWh $0.07557

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16.4.3. Minimum

Billing Item Rate

Charge per installation: $1.70


The Billing Amount will be the greater of the amounts calculated in § 16.4.2 and § 16.4.3 above plus the Energy Cost Recovery factor times the energy consumed as determined in § 16.4.1 plus all other Adjustments required by § 16.4.6 below.


One bill will be rendered monthly to the customer for each power supply. The minimum billing period for any single installation is one month and no monthly bill will be prorated because an amplifier or power supply is connected or disconnected during a billing cycle. Collective Billing may be made available to CTV customers pursuant to Rate Schedule No. 19, Collective Billing Rider (CBR).

16.4.6. Adjustments



If additional facilities are necessary or if it is necessary to rearrange existing facilities, customer will pay to Company the cost of such additional facilities or rearrangement.


Company reserves the right to test customer's installation from time to time and to adjust the wattage rating for billing purposes to conform with the results of such tests.

16.6. PAYMENT


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2nd Revised Sheet No. 17.1 Schedule Sheet 1 of 2

Replacing: 1st Revised Sheet No.


Kind of Service: Electric Class of Service: As Applicable Docket No.: 10-008-UOrder No.: 8


Title: Table of Riders Applicable to Rate Schedules PSC File Mark Only


17.0. TABLE OF RIDERS APPLICABLE TO RATE SCHEDULES

17.1. MANDATORY APPLICATION

The Rate Schedules listed in Group 1 below are mandatory pursuant to the Adjustment provision of each Rate Schedule and shall be applied, as applicable, to each Rate Schedule listed in Group 2 below. Group 1 Rate Schedule No. / Name

29. Charges Related To Customer Activity (CAC)37. ANO Decommissioning Cost Rider (NDCR)38. Energy Cost Recovery Rider (ECR)39. Municipal Franchise Adjustment Rider (MFA)40. Energy Efficiency Cost Rate Rider (EECR)42. Grand Gulf Rider (GGR)43. Federal Litigation Consulting Fee Rider (FLCF)44. Formula Rate Plan Rider (FRP)46. Internal Restructuring Credit Rider (IRCR)47.Capacity Cost Recovery Rider (CCR) 48. Production Cost Allocation Rider (PCA)49. Capacity Acquisition Rider (CA)51. Government Mandated Expenditure Surcharge Rider (GMES)54. MISO Rider (MISO)

Group 2 Rate Schedule No. / Name

1. General Purpose Residential Service (RS)2. Optional Residential Time-Of-Use (RT)*4. Small General Service (SGS)5. Nonresidential General Farm Service (GFS)6. Large General Service (LGS)7. Large General Service Time-Of-Use (GST)8. Large Power Service (LPS)9. Large Power Service Time-Of-Use (PST)10. Municipal Street Lighting Service (L1)11. Traffic Signal Service (TSS)12. All Night Outdoor Lighting Service (L4)13. Municipal Pumping Service (MP)14. Agricultural Water Pumping Service (AP)15. Cotton Ginning Service (CGS)16. Community Antenna TV Amplifier Service (CTV)20. Standby Service Rider (SSR)21. Municipal Shielded Street Lighting Service (L1SH)28. Separately Metered Commercial Space & Water Heating Rider (SMWHR)*33. Residential Energy Management Time-Of-Use Service (REMT)*Not Available for New Applications


2nd Revised Sheet No. 17.1 Schedule Sheet 1 of2

Replacing: 1St Revised Sheet No.


Kind of Service: Electric Class of Service: As Applicable Docket No.: 10-008-UOrder No.: 8


Title: Table of Riders Applicable to Rate Schedules . PSC ”'5 Markon'y

17.0.

17.1.

TABLE OF RIDERS APPLICABLE TO RATE SCHEDULES

MANDATORY APPLICATION

The Rate Schedules listed in Group 1 below are mandatory pursuant to the Adjustmentprovision of each Rate Schedule and shall be applied, as applicable, to each RateSchedule listed in Group 2 below.Group 1Rate Schedule No. / Name

29. Charges Related To Customer Activity (CAC)37. ANO Decommissioning Cost Rider (NDCR)38. Energy Cost Recovery Rider (ECR)39. Municipal Franchise Adjustment Rider (MFA)40. Energy Efficiency Cost Rate Rider (EECR)42. Grand Gulf Rider (GGR)43. Federal Litigation Consulting Fee Rider (FLCF)44. Formula Rate Plan Rider (FRP)46. Internal Restructuring Credit Rider (IRCR)47.Capacity Cost Recovery Rider (CCR)48. Production Cost Allocation Rider (PCA)49. Capacity Acquisition Rider (CA)51. Government Mandated Expenditure Surcharge Rider (GMES)54. MISO Rider (MISO)

Group 2Rate Schedule No. / Name

1. General Purpose Residential Service (RS)2. Optional Residential Time-Of—Use (RT)*4. Small General Service (SGS)5. Nonresidential General Farm Service (GFS)6. Large General Service (LGS)7. Large General Service Time-Of—Use (GST)8. Large Power Service (LPS)9. Large Power Service Time-Of—Use (PST)10. Municipal Street Lighting Service (L1)11. Traffic Signal Service (T88)12. All Night Outdoor Lighting Service (L4)13. Municipal Pumping Service (MP)14. Agricultural Water Pumping Service (AP)15. Cotton Ginning Service (CGS)16. Community Antenna TV Amplifier Service (CTV)20. Standby Service Rider (SSR)21. Municipal Shielded Street Lighting Service (L1SH)28. Separately Metered Commercial Space & Water Heating Rider (SMWHR)*33. Residential Energy Management Time-Of—Use Service (REMT)

*Not Available for New Applications



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Title: Table of Riders Applicable to Rate Schedules PSC File Mark Only


17.2. APPLICATION AT CUSTOMER'S OPTION

The Rate Schedules or Rate Schedule Riders listed below are available as applicable at the customer’s option pursuant to the Availability provision of the Rider.

Rate Schedule No. / Name

18. Voltage Adjustment Rider (VAR)19. Collective Billing Rider (CBR)20. Standby Service Rider (SSR)22. Fire and Flood Loads Rider (FFLR)23. Highly Fluctuating Loads Rider (HFLR)24. Short Term, Temporary & Intermittent Service Rider (STIR)*25. Seasonal Service Rider (SESR)26. Additional Facilities Charge Rider (AFCR)27. Modification of General Service Minimum Rider (GSMR)28. Separately Metered Commercial Space & Water Heating Rider (SMWHR)*30. Optional Apartment Service Rider (OASR)31. Commercial Space Heating Rider (CSHR)32. Economic Development Rider (EDR)34. Small Cogeneration Rider (SCR)35. Large Cogeneration Rider (LCR)41. Optional Interruptible Service Rider (OISR)53. Additional Facilities Charge Rider – Governmental (AFCRG)56. Economic Redevelopment Rider (ERDR)60. Extension Of Facilities (EOFP)61. Tariff Governing the Installation of Electric Underground Residential

Distribution Systems and Underground Service Connections (UGP)

Policy Schedule No. / Name

P1. Pick A Date Plan (PADP) (Extended Due Date Plan) P2. Budget Billing Plan (BBP)(Levelized Billing Plan) P3. Extended Absence Payment Plan (EAPP) P8. Quick Pay Center Payment (QPCP)

*Not Available for New Applications

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Part IV. Rate Schedule No. 18 Effective: 2/1/19

Title: Voltage Adjustment Rider (VAR) PSC File Mark Only


18.0. VOLTAGE ADJUSTMENT RIDER

18.1. AVAILABILITY

Available at the option of the Company to a customer receiving electric service under Rate Schedules No. 4, Small General Service, No. 6, Large General Service, No. 7, Large General Service Time-of-Use, No. 8, Large Power Service, No. 9, Large Power Service Time-of-Use, or No. 20, Standby Service Rider where such service is delivered and/or metered at voltages of 13,800Y/7,960 or greater.

18.2. ADJUSTMENT TO NET MONTHLY RATE

The Demand, Energy and the highest kW Demand, or ratchet Demand, in the Minimum provision of the service schedule are reduced by the percentage reductions below but the demand charge in the Minimum provision of the service schedule is not reduced by the $/kW reduction. The minimum Demand defined in the Demand provision of the service schedule is not reduced by the percentage reductions below.

In this schedule secondary voltages are those less than 13,800Y/7,960 Volts, primary voltages are those 13,800Y/7,960 Volts or greater but less than 69,000 Volts and transmission voltages are those 69,000 Volts or greater.

18.2.1. Service is delivered and metered at secondary voltage.

Billing Item Rate No reductions: 0.0%

18.2.2. Service is delivered at secondary voltage but metered at primary voltage.

Billing Item Rate Reduce Demand and Energy for losses by: 1.0%

18.2.3. Service is delivered at primary voltage but metered at secondary voltage and customer owns and maintains all transformation facilities.

Billing Item Rate Reduce Monthly Demand Charge per kW by: $1.61 Reduce Daily Demand Charge per kW by: $0.0531

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Title: Voltage Adjustment Rider (VAR) PSC File Mark Only


18.2.4. Service is delivered and metered at primary voltage and customer owns and maintains all transformation facilities.

Billing Item Rate Reduce Demand and Energy for losses by: 1.0% Reduce Monthly Demand Charge per kW by: $1.61 Reduce Daily Demand Charge per kW by: $0.0531

18.2.5. Service is delivered at transmission voltage but metered at primary voltage.

18.2.6. Service is delivered and metered at transmission voltage.



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Title: Collective Billing Rider (CBR) PSC File Mark Only


19.0. COLLECTIVE BILLING RIDER

19.1. AVAILABILITY

Available to any eligible customer receiving year-round, full requirements electric service under any of Entergy Arkansas, LLC (“EAL” or the “Company”) Rate Schedules and who enters into an agreement which is in substantially the same form as the Agreement For Collective Billing shown in Policy Schedule No. 13, § 13.5. Eligibility is determined by the Company. Customers having and maintaining a credit rating of BBB- or higher from the S&P Rating Group, BBB- or higher from Fitch Ratings or Baa3 or higher from Moody’s Investor Service, or their successors, may be considered eligible. The Company may also consider, among other things, the number of accounts customer is requesting to be summarized, the type of metering on the account and customer’s payment record. Individually metered apartment accounts that are automatically transferred upon vacancy to the “complex account” rather than being disconnected may not be included in a Collective Bill for the apartment complex.


There will be no additional charge for the service initially. However, Company reserves the right to implement a charge for the service upon appropriate regulatory approval and thirty (30) days written notice to customer.

19.3. PROCEDURE

Company will monthly render a Collective Bill, summarizing the bills for the customer’s individual accounts for which the customer has requested such service.

19.4. PAYMENT

The amount shown as owed on each Collective Bill will be due upon receipt. Payment shall be made in accordance with Rate Schedule No. 29, Charges Related to customer Activity (CAC), § 29.19.2. Payment will be considered delinquent if not received by the Company, either (a) via physical delivery by mail or courier or (b) via electronic funds transfer, within the period specified in Rate Schedule No. 29, § 29.19.2. If the payment becomes delinquent, Company may exercise the rights and privileges afforded it by the Arkansas Public Service Commission (“APSC” or the “Commission”) General Service Rules, or successor thereto, with regard to delinquent accounts, and all accounts on that Collective Bill will be subject to service interruption. Collective Bill accounts that become delinquent may be deemed ineligible for this Collective Billing Rider at the Company’s sole option and be removed from Collective Billing. When applicable holidays occur from the date of mailing through the date by which the bill must be paid to avoid delinquency, the due date will be extended by one day per applicable holiday. The following is a list of the applicable holidays:

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Title: Collective Billing Rider (CBR) PSC File Mark Only


1. New Year’s Day 4. Memorial Day 7. Thanksgiving Day2. M. L. King, Jr. Day 5. Fourth of July 8. Christmas Eve Day3. President’s Day 6. Labor Day 9. Christmas Day


The contract period is month to month. Either party may cancel upon thirty (30) days written notice to the other.

19.6. OTHER PROVISION

Except as modified herein to provide for Collective Billing and waiver of General Service Rules 5.01.B., 5.01.I., and 5.05.A., all provisions of the applicable Rate Schedules and the General Service Rules will apply.

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Title: Standby Service Rider (SSR) PSC File Mark Only


20.0. STANDBY SERVICE RIDER



20.2. AVAILABILITY

This schedule is applicable to customers who have their own generating equipment and who contract for Standby Service from the Company. Standby Service is composed of Reserved Service, Maintenance Service, Backup Service, and Non-Reserved Service as defined below. The Company is not obligated to provide Maintenance or Backup Service in excess of a customer’s Reserved Service.

Standby Service shall be restricted to a total number of kW, which number shall not exceed the nameplate rating of the customer’s generating equipment which may be operated in parallel with the Company’s system.

The customer shall not resell or share any power purchased under this schedule, except in cases of Qualified Facilities (QF) sales, resale and sharing among facilities treated as a single QF under PURPA as interpreted by the Federal Energy Regulatory Commission and applicable case law.

Service under this Rider is available only under the Agreement for Electric Service contained in Policy Schedule No. 13, Contract Forms.


Single- or three-phase, 60 cycles and at one standard delivery voltage required by customer and available at customer’s service location where service is delivered and metered at voltages less than 13,800Y/7,960. For service delivered and/or metered at other voltages, see Rate Schedule No. 18 for the appropriate adjustments to the Net Monthly Rate.

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20.4. MODIFICATION OF REGULAR RATE SCHEDULE

Service taken under this schedule may be in addition to other service provided by the Company. Service necessary to supply the customer’s other load requirements shall be billed on the applicable rate schedule(s) of the Company, and the other rate schedules in such case, if applicable, will be modified by the application of § 20.5 and § 20.7 of this Schedule.

20.5. TYPES OF SERVICE AND BILLING DETERMINANTS

20.5.1. Reserved Service

Reserved Service is the electric energy and capacity the Company stands ready to supply during a scheduled or unscheduled outage of the customer’s on-site generation equipment. The Reserved Service Billing Demand in a month shall be equal to the greater of: (1) the amount of Contracted kW, (2) the maximum Daily Maintenance Service Billing Demand established during the term of service of the contract, (3) the maximum Daily Backup Service Billing Demand established during the term of service of the contract, or (4) the maximum Reserved Service Billing Demand established during the prior contract with the customer, unless it was established from use of Contracted kW, unless customer has changed the rated capacity of its self-generation unit or unless customer has provided verifiable evidence of a non-temporary change in operation that results in reduced self-generation consumption needs. Should the customer’s demand during a Maintenance period be established such that Backup Service is supplied in addition to the requested Maintenance Service, the sum of such Backup Service and the requested Maintenance Service shall establish the customer’s Reserved Service Billing Demand.

20.5.2. Maintenance Service

Maintenance Service is electric energy and capacity supplied by the Company during a scheduled outage of the customer’s generating equipment. Maintenance Service will be available during the service months of October through May, and during the off-peak hours (as defined in § 20.8) of the service months of June through September. During the service months of June through September, Maintenance Service will not be scheduled for a continuous period of less than one day. Customers must notify the Company no less than seven (7) days in advance of the intent to take Maintenance Service. Arrangements for and scheduling of Maintenance Service (the “Maintenance Period”) will be agreed in writing in advance of use, or confirmed in writing if arranged verbally. Maintenance Service will be scheduled only during such times, in such manner and at such locations that, in the Company’s reasonably exercised opinion, will not result in affecting adversely or jeopardizing firm service to other customers, prior commitments for Maintenance Service to other customers, or commitments to other utilities.

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The Company is not obligated to furnish Maintenance Service in excess of that which is scheduled by the customer. If customer takes service in excess of the scheduled Maintenance Service and such excess has not been approved pursuant to a request for Non-Reserved Service, such excess shall be treated as Backup Service. Where there are applications from more than one customer, or applications are for more capacity than Company has available, Company shall schedule available service on a first come, first accepted basis.

The Daily Maintenance Service Billing Demand for each calendar day of the Maintenance Period shall be the lesser of (1) the maximum measured 15-minute demand established during such day less, in the case where a customer purchases power from the Company under other rate schedule(s), contract power as established under such other rate schedule(s) or (2) the scheduled maintenance kW. During a Maintenance Period for which Non-Reserved Service has been approved, the customer may schedule only his Reserved Service Billing Demand as the maintenance kW. In no event shall the Daily Maintenance Service Billing Demand be less than zero. Measurement of the customer’s maximum 15-minute demand is subject to relevant metering practices, power factor adjustments, and other provisions described herein.

Notwithstanding the above, where Maintenance Service stands requested, agreed and scheduled, but not taken, the Daily Maintenance Service Billing Demand will be the scheduled maintenance kW under the following conditions: (a) the Company has refused to supply some other customer similar service in order to limit total Maintenance Service to that which the Company considers available or, (b) if in anticipation of providing such Maintenance Service the Company has incurred costs that would not otherwise have been incurred. The Company shall undertake all reasonable efforts in order to avoid or mitigate the loss of revenue or occurrence of cost.

20.5.3. Non-Reserved Service

Non-Reserved Service is electric energy and capacity the Company may supply during a scheduled outage of the customer’s on-site generation equipment during the service months of October through May. Customers must request this service no less than twenty (20) days in advance of their anticipated need for this power and energy, stating in such request the amount of Non-Reserved Service demand (kW) to be scheduled and the expected period for which the service will be taken. The Company, in its sole discretion, may approve or deny any request for Non-Reserved Service. Arrangements for and scheduling of Non-Reserved Service will be agreed and confirmed in writing in advance of use. The Company is not obligated to furnish Non-Reserved Service in excess of that which is scheduled by the customer. Non-Reserved Service may be provided one time per calendar year for a period not to exceed thirty (30) days.

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The Monthly Non-Reserved Service Billing Demand for each month during which Non-Reserved Service is approved shall be the maximum measured 15-minute demand established during the Non-Reserved Service Period of such month less (1) in the case where a customer purchases power from the Company under other rate schedule(s), contract power as established under such other rate schedule(s) and (2) the scheduled Maintenance kW. Non-Reserved Service Billing demand shall not be less than zero (0) nor shall it exceed the amount of demand that was requested and agreed. Measurement of the customer’s maximum 15-minute demand is subject to relevant metering practices, power factor adjustments, and other provisions described herein. Usage and charges shall not be prorated. Demand usage shall not establish demands for future minimum billing purposes of supplemental usage tariff application. If the requested amount of Non-Reserved Service results in the need for new or additional facilities and/or equipment, customer shall pay the net cost for installation and removal of such facilities.

20.5.4. Backup Service

Backup Service is the electric energy and capacity supplied by the Company during an unscheduled outage of the customer’s generating equipment and electric energy and capacity supplied by the Company during a scheduled outage that exceeds the sum of scheduled Maintenance Service and any scheduled Non-Reserved Service. The customer is required to notify the Company of the time periods when Backup Service is being taken (the “Backup Period”) within 24 hours of the beginning and end of usage to avoid increasing the customer’s contract or ratcheted demand under other rate schedules.

The Daily Backup Service Billing Demand for each calendar day during which Backup Service is taken shall be the customer’s maximum measured 15-minute demand during such day, less: (1) the sum of any scheduled kW of Maintenance Service and any scheduled Non-Reserved Service during such day and (2) in the case where the customer purchases power from the Company under other rate schedules, contract power as established under such other rate schedule(s). In no event shall the Daily Backup Service Billing Demand be less than zero. Measurement of the customer’s maximum 15-minute demand is subject to relevant metering practices, power factor adjustments, and other provisions described herein.

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20.5.5. Energy Associated with Maintenance Service

The energy associated with the Maintenance Service during a scheduled Maintenance Period shall be as metered by Company’s meters during the Maintenance Period less, for customers who purchase energy from the Company under other rate schedule(s), the energy used under such other rate schedule(s) in each hour of the Maintenance Period, measured as the average energy used under such other rate schedule(s) for the five hours prior to the beginning of the Maintenance Period. Maintenance Service energy in any hour may not exceed the scheduled Maintenance kW, and in no event shall the energy associated with the taking of Maintenance Service be less than zero.

20.5.6. Energy Associated with Non-Reserved Service

The energy associated with the Non-Reserved Service taken shall be as metered by Company’s meters during the Non-Reserved Service Period less, (1) for customers who purchase energy from the Company under other rate schedule(s), the energy used under such other rate schedule(s) in each hour of the Period, measured as the average energy used under such other rate schedule(s) for the five hours prior to the beginning of the Period, and (2) the energy associated with scheduled Maintenance Service. In no event shall the energy (kWh) in any given hour associated with the taking of Non-Reserved Service be less than zero nor greater than the requested and agreed level of demand (kW) of such service.

20.5.7. Energy Associated with Backup Service

The energy associated with Backup Service shall be as metered by Company’s meters during the Backup Period, less, (1) for customers who purchase energy from the Company under other rate schedule(s), the energy used under such other rate schedule(s) in each hour of the Maintenance Period or Backup Period, measured as the average energy used under such other rate schedule(s) for the five hours prior to the beginning of the Backup Period, and (2) the sum of any Maintenance Service energy and any Non-Reserved Service energy during each hour of the period. In no event shall the energy associated with the taking of Backup Service be less than zero.

20.5.8. Voltage Adjustment Rider (VAR) Applicability

The metered Billing Determinants (kW and kWh) defined in this Section 20.5 and Demand Charges in Section 20.7 will be adjusted by Rate Schedule No. 18, Voltage Adjustment Rider (VAR), as applicable, before application of the Net Monthly Rate.

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20.6. DAILY DEMAND

The kW or kVA, if kVA metered, as shown by or computed from the readings of the Company’s demand meter, for the 15-minute period of greatest use during the day, subject to the following:

1. If kVA metered: Billing kW = Metered kVA x 0.92. If kW metered: Billing kW = Metered kW.


20.7.1. Customer Charge

Billing Item Rate Charge per month: $468.60

If a customer is taking electric service under another Company Rate Schedule, pursuant to § 20.4, the customer charge applicable to such other Rate Schedule will be zero.

20.7.2. Reservation Charges

Billing Item Rate Rate per kW of Reserved Service Billing Demand: $ 3.73

20.7.3. Maintenance Demand Charges

For each calendar day the customer takes Maintenance Service within a billing month, the Maintenance Demand Rate to be applied to such day’s Daily Maintenance Service Billing Demand shall be the applicable daily demand rate shown below:

Billing Item Rate Demand Charge:

Summer Period $/kW/Day: $ 0.1748 Other Period $/kW/Day: $ 0.1524

The combined result for all days within the billing month is the Maintenance Demand Charge.

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20.7.4. Backup Demand Charges

For each calendar day the customer utilizes Backup Service within a billing month, the Backup Demand Rate to be applied to such day’s Daily Backup Service Billing Demand shall be the applicable daily demand rate shown below:

Billing Item Rate Demand Charge:

Summer Period $/kW/Day: $0.4400 Other Period $/kW/Day: $0.3714

The combined result for all days within the billing month is the Backup Demand Charge.

20.7.5. Non-Reserved Service Demand Charges

For each month during which the customer utilizes Non-Reserved Service, the Non-Reserved Service Demand Rate to be applied to such month’s Non-Reserved Service Billing Demand shall be the rate for demand applicable under the customer’s rate schedule for supplemental service taken in conjunction with this Standby Service Rider. Should the customer take only Standby Service and no supplemental service rate schedule applies, the demand rate from the currently effective Large Power Service rate schedule shall apply to all Non-Reserved Service demand.

20.7.6. Maintenance Energy Charges

The Monthly Energy Rate to be applied to the energy associated with Maintenance Service as determined in § 20.5.5 shall be as follows:

Billing Item Rate Energy Charge per kWh: Summer Period: $0.02709

Other Period: $0.01927

The result is the Maintenance Energy Charge.

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20.7.7. Backup Energy Charges

The Monthly Energy Rates to be applied to the energy associated with Backup Service as determined in § 20.5.6 shall be as follows:


Summer Period: $0.02709 Other Period: $0.01927

The result is the Backup Energy Charge.

20.7.8. Non-Reserved Service Energy Charge

The Monthly Energy Rate to be applied to the energy associated with Non-Reserved Service as determined in § 20.5.7 shall be the rate for energy applicable under the customer’s rate schedule for supplemental service taken in conjunction with this Standby Service Rider. Should the customer take only Standby Service and no supplemental service rate schedule applies, the energy rate from the currently effective Large Power Service rate schedule shall apply to all Non-Reserved Service energy. A monthly Avoided Cost adder shall also apply to all Non-Reserved Service energy. This Adder shall be defined as the currently effective Rider SCR Avoided Cost Annual Average rate for the customer’s service voltage less the current Energy Cost Recovery Rider (ECR) factor.

20.7.9. Minimum Charge

The monthly Customer Charge plus the Reservation Charge shall represent the monthly minimum charge. Where the installation of excessive new facilities is required or where there are special conditions affecting the service, the Company may require in the contract a higher minimum charge and/or additional facilities charge arrangements to compensate for additional costs.

20.7.10.Maximum Charge

The monthly maximum charge shall be the sum of (1) the greater of (a) the Reservation Charge or (b) the sum of the Maintenance Demand Charge, the Backup Demand Charge, the Maintenance Energy Charge, and the Backup Energy Charge, for that month plus (2) the Customer Charge plus (3) the Energy Cost Recovery charge plus (4) the Non-Reserved Service Demand Charge plus (5) the Non-Reserved Service Energy Charge plus (6) any other applicable charges described in this tariff.

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20.7.11.Adjustments

Applicable Riders which adjust this Rate Schedule are listed in Rate Schedule No. 17, Table of Riders Applicable to Rate Schedules. The Rate Adjustment for Large General Service Rate Class applications as defined by the currently effective ANO Decommissioning Cost Rider (NDCR), Rate Schedule No. 37, the currently effective Grand Gulf Rider (GGR), Rate Schedule No. 42, the currently effective MISO Rider, Rate Schedule No. 54, and the currently effective Capacity Cost Recovery Rider (CCR), Rate Schedule No. 47 shall be converted to daily rates for application to Daily Maintenance Service Billing Demands and Daily Backup Service Billing Demands in § 20.7.3 and § 20.7.4 respectively by multiplying such Rates by a factor of 0.03288 and rounding to four (4) places.

20.8. DEFINITION OF SUMMER PERIOD, OTHER PERIODS, AND ON-PEAK AND OFF-PEAK HOURS

20.8.1. Summer Period

The Summer Period is defined as the billing months of June, July, August, and September. All other billing months are defined as “Other Period.”


The Company’s On-Peak hours are:

Summer Period: Other Periods:

1:00 p.m. to 8:00 p.m. 7:00 a.m. to 6:00 p.m. Monday - Friday Monday - Friday


The Company’s Off-peak hours, for purposes of this schedule, are all hours of the year not specified as On-Peak hours.

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20.9.1. The customer shall pay to the Company the initial and continuing cost of any additional facilities including special metering facilities which are made necessary by interconnection with customer’s generating facilities. Continuing costs are considered to be the operation and maintenance, taxes and replacement costs, associated with any additional facilities. The monthly charge pursuant to this § 20.9.1, will be determined by multiplying the then current “Monthly % Post-Recovery Term” percentage found in § 26.4 of Rate Schedule No. 26, Additional Facilities Charge Rider (AFCR) or § 53.4 of Rate Schedule No. 53, Additional Facilities Charge Rider – Governmental (AFCRG) if applicable, times the initial cost as modified to include costs associated subsequent capital modifications or additions to such facilities and in the case of replacement, the excess of the cost of replacement over the original installed cost of the replaced facilities.

20.9.2. Protective Devices

Unless provision is made for complete shutdown of customer’s electrical power production equipment and disconnection and/or isolation from other sources of power supply during periods when service is being taken from Company, customer will install and maintain at his own expense:

A. Protective devices necessary for the protection of his personnel and equipment; B. Protective devices necessary in the Company’s judgment for the protection of

Company’s personnel, equipment, and service.

These protective devices are subject to inspection by the Company’s authorized representatives at all reasonable times.

These protective devices shall include but are not limited to the following functions:

A. To automatically disconnect customer facilities when Company’s service is interrupted;

B. To prevent interconnection with Company’s system when Company’s supply line is de-energized;

C. To protect equipment and personnel during synchronization and interconnection with Company’s system;

D. To isolate and protect customer’s equipment when his generating equipment is not running.

20.9.3. The customer shall hold harmless the Company from any loss due to damage or loss to customer’s equipment, personnel or property arising from or in connection with interconnection with Company’s system. The customer shall indemnify and keep indemnified the Company from and against all loss, damage and expense which the Company may sustain by reason of or in connection with the interconnection.

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The term of service shall be such as may be agreed upon in the contract, but not less than one year.

20.11. PAYMENT

The monthly bill shall be computed in accordance with § 20.7, Net Monthly Rate, other provisions of the rate schedule, and all applicable riders. Payment shall be made in accordance with Rate Schedule No. 29, Charges Related to Customer Activity (CAC), § 29.19.1.

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Title: Municipal Shielded Street Lighting Service (L1SH) PSC File Mark Only


21.0. MUNICIPAL SHIELDED STREET LIGHTING SERVICE



21.2. AVAILABILITY

This Schedule is available for lighting service required by any Municipality contracting for street lighting service for streets, alleys and other public ways. In the context of this Rate Schedule only, the term “municipality” shall mean any incorporated city or town served by EAL, or any unincorporated community where EAL serves more than 500 customers and where an incorporated property owners association or Board, as a part of its ordinary function, furnishes street lighting and other services normally provided by incorporated cities to, or for, residents of the unincorporated community. This service is available for street-lighting purposes only and is not available for parking facilities, temporary, resale, shared, seasonal or public area lighting service. Availability and installation will be consistent with the Company’s Customer Installation Standards.


Service will normally be single-phase, 60 cycles, at approximately 120/240 Volts, however, the service voltage and type of service will be at the Company's option. Lighting service under this Schedule will be furnished from dusk until dawn.


The following net monthly rate is applicable when the Company owns the entire street lighting facility, consisting of the Company's standard fixture on a wood pole, overhead circuits, controls, and all other related equipment. Company will operate and maintain such facility at its expense including the cost of material required for replacing broken outer globes and for the total cost of replacing or repairing broken or damaged poles used primarily for street lighting. If Company provides change-outs or removals of functioning lighting equipment at the request of the municipality, the municipality will be responsible for the costs of such change-outs or removals. Such change-outs and removals will be scheduled reflecting the Company’s available normal resources. If the quantity of change-outs or removals cannot be completed by the Company with normal resources in the time frame requested by the municipality, the Company may utilize additional resources to meet the requested time frame with the consent of the municipality or the municipality may accept the timeline proposed by the Company. In such case, municipality will be responsible for any Company costs associated with the change-outs or removals and the cost of the additional resources. 518


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21.4. NET MONTHLY RATE (continued)

Billing Item Rate Keys / Description

A. High Pressure Sodium Lighting First Unit /Pole

Each Excess Unit/Pole

L1SHA / L1SHAE 150 Watt Cobra Head $6.71 $4.82 L1SHB / L1SHBE 250 Watt Cobra Head $8.07 $6.62 L1SHC / L1SHCE 400 Watt Cobra Head $8.41 $7.29 L1SHD / 150 Watt Post Top Colonial (Subdivision) $6.10 NA

B. Steel Poles The additional monthly charges as shown below will be made for each of Company's standard steel poles. Not applicable when a nonrefundable contribution is made to cover the additional installed cost of steel poles. Rate Key / Description Rate

L1VSH For Poles of 30 Feet or Less Mounting Height: $1.83 L1WSH For Poles of 35 Feet Mounting Height: $2.81

These charges do not include or cover costs for painting steel poles. Any painting service requested by the municipality will be scheduled by the Company utilizing additional resources, and the Company shall recover the cost of acquiring the additional resources from the requesting municipality. The requesting municipality will be informed of such costs prior to the start of any requested painting service.

C. Underground and Other Nonstandard Facilities

If the Company provides underground circuits or equipment other than the standard equipment described above or rearranges existing facilities at the request of the customer, customer may choose to pay (1) a non-refundable cash contribution in aid of construction equal to the additional cost of the non-standard equipment and/or the cost of rearranging existing facilities or (2) an additional monthly facilities charge calculated by multiplying the monthly facilities charge rate in Rate Schedule No. 26, § 26.3 times the additional cost of the non-standard equipment and/or rearrangement costs for existing facilities.

Non-salvageable components of facilities installed or provided by the Company for underground service shall not be considered as Additional Facilities but shall be paid through a contribution in aid of construction. Street lighting facilities provided in accordance with Company's Tariff Governing the Installation of Residential Underground Electric Distribution Systems and Underground Service Connections, Rate Schedule No. 61, will not be subject to such additional monthly facilities charge.

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21.5. MINIMUM MONTHLY BILL

The amount calculated under the Net Monthly Rate plus all Adjustments calculated pursuant to § 21.6.

21.6. ADJUSTMENTS


21.7. PAYMENT

The monthly bill shall be computed in accordance with the Net Monthly Rate, other provisions of the Rate Schedule and all applicable riders. Payment shall be made in accordance with Rate Schedule No. 29, Charges Related to Customer Activity (CAC), § 29.19.1.


As covered by any existing contract now in effect with the Municipality. All new contracts shall be for a period of one year.

In the event the customer ceases to take electric service from the Company or wishes to change the nature of the service being delivered within the initial term of the contract, the Company reserves the right to consent to such cancellation or change provided customer pays the lesser of the following:

1. The applicable monthly charge for the remaining months of the Contract.2. The amount computed under the following formula; provided, however, such

amount shall never be less than zero:

[A + B - C] X D

Where:

A = Original installed cost of the facilitiesB = Cost of removing facilitiesC = Salvage value to Company of equipment and material removedD = 1.12 less .01 times the number of months which have expired since the facilities

were installed.


Service under this Schedule is subject to Policy Schedule No. 9, Service Regulations, of the Company as it is now on file, and as it may in the future be filed, with the APSC and the rules of the Commission.

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Title: Fire and Flood Loads Rider (FFLR) PSC File Mark Only


22.0. FIRE AND FLOOD LOADS RIDER

22.1. AVAILABILITY

To Small General Service (SGS), Large General Service (LGS), Large General Service Time-of-Use (GST), Large Power Service (LPS) and Large Power Service Time-of-Use (PST) Rate Schedules for any customer who has contracted to take from Entergy Arkansas, LLC (“EAL” or the “Company”) at the applicable rate schedule, all requirements for the operation of a fully electrified pumping plant; except that other power sources may be maintained for emergency standby or insurance purposes.

All provisions of Company's applicable rate schedules will apply except as modified herein.

22.2. DEMAND

For installations where fire or flood protection pumps are incidental to customer's total load, Demands during times of fire, flood or test will be eliminated from Billing Demands provided:

1. that the Demand of such pumps shall not exceed 50% of customer's normalDemand.

2. that such Demands are limited to Company's off-peak periods so far as emergencieswill permit, and

3. that customer notifies the Company within five days after any use of such pumpsduring a fire, flood, or test, of the time, duration, and magnitude of such demands.

For installations where fire or flood protection pumps are the primary load and are 500 hp or less, the Minimum provision of the applicable rate schedule is waived provided additional facilities are provided in accordance with the terms of Rate Schedule No. 26, Additional Facilities Charge Rider (AFCR).

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Title: Highly Fluctuating Loads Rider (HFLR) PSC File Mark Only


23.0. HIGHLY FLUCTUATING LOADS RIDER

23.1. AVAILABILITY

This Rider may be attached to and made a part of any Agreement for Electric Service providing for delivery of Entergy Arkansas, LLC ("EAL" or the "Company") service to a customer who uses the service for the operation of hoists, welding machines, x-ray machines or other equipment with an intermittent and rapidly fluctuating load characteristic. All provisions of the customer’s applicable rate schedule will apply except as modified herein.

23.2. SPECIAL EQUIPMENT

Where service to such equipment adversely affects voltage regulation or impairs Company's service to customer, and other users of electric service supplied from the same distribution system, such service to customer will be connected or continued, as the case may be, only after customer provides, installs, and maintains, at its own expense, such special transformers, reactors, series or multiple capacitors or other corrective equipment as Company may recommend to remedy the condition.

23.3. BILLING

There shall be added to the monthly billing, computed in accordance with the applicable rate schedule(s), an amount equal to the greater of the following:

Billing Item Rate

1. Demand Charge per kVA:Applied to the transformer capacity (kVA) installed to serve the highly fluctuating load in excess of the transformer capacity that would normally be installed to serve customer's maximum load as measured over a 15-minute period; or,

$0.27

2. An amount calculated by multiplying the Additional Facilities Charge Riderrate found in § 26.3 of Rate Schedule No. 26 times the estimated installed cost of the facilities provided by Company to serve the customer in excess of the cost of the facilities the Company would otherwise provide to serve customer's maximum load as measured over a 15-minute period.

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Title: Short Term, Temporary, and Intermittent Service Rider (STIR) PSC File Mark Only


24.0. SHORT TERM, TEMPORARY AND INTERMITTENT SERVICE RIDER

NOT AVAILABLE TO NEW APPLICATIONS

24.1. AVAILABILITY

At points on existing facilities where, in the judgment of Entergy Arkansas, LLC (“EAL” or the “Company”), sufficient unsold capacity is available for the service desired. To customers receiving service under this optional Rider as of May 16, 1980 and who receive service under Rate Schedule No. 4, Small General Service, for delivery of electric service to temporarily established service locations and for periods of less than twelve consecutive months.

The furnishing of such service at any point of delivery shall in no way obligate the Company to supply service after a period of disconnection, to extend or renew any agreement for service, to furnish additional service at any other point of delivery.

Service to flood control or drainage pumps, and reservoir relift pumps will, however, be continued under this Rider from year to year, where such service is initially established under the provisions of this Rider without salvage value of facilities constructed being credited against construction costs and when customer contracts with Company for his entire power and energy requirements at the location, as required, under this Rider for a specific term of not less than three years.

Not applicable to standby or supplemental service.

All provisions of Rate Schedule No. 4 will apply except as modified herein.

24.2. BILLING

In accordance with the applicable Rate Schedule, except that no bill will be rendered for any billing period during which no energy is used. Bills will be prorated for a period of less than one month only on termination of the Agreement for Electric Service. The minimum billing period is one month.

24.3. CONSTRUCTION COST

Customer will pay to Company in advance of construction, the estimated gross cost of providing, installing and removing the temporary facilities required to deliver service, less the estimated salvage value of such facilities on removal. When the use of service is discontinued or the Agreement for Electric Service terminated, Company may dismantle such facilities, and the materials and equipment provided by Company will be salvaged by Company and remain its property.

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Title: Short Term, Temporary, and Intermittent Service Rider (STIR) PSC File Mark Only



Open order.

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Title: Seasonal Service Rider (SESR) PSC File Mark Only


25.0. SEASONAL SERVICE RIDER

25.1. AVAILABILITY

To Small General Service (SGS), General Farm Service (GFS) and Large General Service (LGS) Rate Schedules for delivery of electric service to a Customer whose requirements are distinctly of a recurring seasonal nature and limited to certain months of the year and who contracts for service in sufficient quantity and for a sufficient period of time, in accordance with the Entergy Arkansas, LLC ("EAL" or the "Company") Rate Schedule No. 60, Extension of Facilities, to justify the Company in installing its service facilities and leaving them in place from season to season. This rate is applicable to customers who require service for not less than 12 months annually. Not applicable to standby and supplementary service. All provisions of the customer’s primary Rate Schedule will apply except as modified herein.

25.2. BILLING

Billing will be in accordance with the applicable Rate Schedule and will be determined as described below.

1. Calculate the Rate amount for the current month kW/kWh usage under the applicableRate Schedule excluding all Adjustments and taxes;

2. Determine the cumulative revenue amount for the prior 11 months excluding allAdjustments and taxes;

3. Determine the annualized applicable minimum (maximum of the minimums):

A. Annualize the account’s Contract Minimum if applicable;

B. Calculate the annualized SESR minimum (Customer Charge plus the DemandCharge below times the highest load established during the 12 months ended with the current month, times 12. Exclude all Adjustments and taxes);

C. Select the greater of A or B above.

If the cumulative revenue (2) is equal to or greater than the annualized applicable minimum (3.C) the bill for the current month is the Rate amount (1) plus all current month Adjustments and taxes;

If the cumulative revenue (2) is less than the annualized applicable minimum (3.C) the bill for the current month is the greater of the Rate amount (1) and the amount by which the annualized applicable minimum (3.C) exceeds the cumulative revenue (2) plus all current month Adjustments and taxes.

Billing Item Rate Demand Charge per kW for all kW: $3.41

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Title: Seasonal Service Rider (SESR) PSC File Mark Only



The term specified in the Agreement for Electric Service to which this Rider is attached, but not less than 12 consecutive months.

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Title: Additional Facilities Charge Rider (AFCR) PSC File Mark Only


26.0. ADDITIONAL FACILITIES CHARGE RIDER

26.1. AVAILABILITY

Available to all customers whose service is metered at primary voltage or greater and who execute a contract as provided herein. Contracts under previously approved editions of this schedule for service metered at less than primary voltage will continue until terminated but cannot be revised to incorporate new Additional Facilities.

26.2. APPLICATION AND CONDITIONS

Where, because of the character of the customer’s demand, customer’s need for duplicate facilities, legal or engineering requirements with which the customer must comply, customer requests Entergy Arkansas, LLC (“EAL” or the “Company”) to install facilities in addition to those which Company would normally install for the customer’s demand and service requirements, Company will install and maintain such additional facilities (“Additional Facilities”) subject to the following conditions:

1. The location and design of the Additional Facilities must meet Company’s engineering andoperating standards and practices. The Company will not install Additional Facilities on thecustomer’s side of the point of delivery which cross public streets, roads, or alleys, unlessapproved by Commission waiver of APSC GSR 5.20, or inside customer’s building.

2. If additional facilities are installed on the customer’s side of the primary metering pointwhich operate at primary voltage or greater, then the primary service credit under RateSchedule No. 18, Voltage Adjustment Rider, if applicable, shall be limited to 1%.

3. In cases where Company would normally provide secondary metering and the customerrequests primary metering, the difference in the installed cost of the primary and secondarymetering will be considered as Additional Facilities.

4. Title to all facilities installed by Company shall be vested in and will be maintained byCompany, and customer will provide all easements and rights-of-way satisfactory toCompany at no cost to Company.

5. This Schedule is not available to applications involving mixed ownership of facilities on thecustomer’s side of the meter except where the customer installs customer-owned primarycapacitors on the customer’s side of the primary meter in accordance with Company’sInstallation Standards.

The customer will enter into a Facilities Agreement with the Company and pay to the Company a net monthly charge based on the investment by Company in such facilities and the monthly percentages from either Option A or Option B below, as appropriate. At the execution of each Facilities Agreement, the customer will have a one-time election to select either Option A or Option B for the definition of the monthly rate associated with Company’s investment in the Additional Facilities. Any subsequent capital additions, replacements, or modifications of facilities will be treated as described in Option A and Option B below.

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26.3. OPTION A

Customers that select Option A for Additional Facilities must pay a net monthly facilities charge of 0.875 percent (0.875%) per month of the installed cost of all facilities included in the Facilities Agreement. Subsequent capital modifications or additions to such facilities will be subject to the above rate as applied to the cost of the additions or modifications. Subsequent replacement of an Additional Facilities component will be subject to the above rate, as applied to the excess of the cost of replacement over the original installed cost of the replaced facilities.

26.4. OPTION B

Customers that select Option B for Additional Facilities must define in the Facilities Agreement the number of years (the “Recovery Term”) that will define the appropriate monthly rates to be applied to the Company’s investment. The Recovery Term cannot be longer than 10 years. The following table specifies the monthly percentages for application during the selected Recovery Term and any years following the Recovery Term. These percentages will apply monthly to the installed cost of all facilities included in the required Facilities Agreement. Prepayment of any charges associated with an Option B Facilities Agreement prior to expiration of the selected Recovery Term is not allowed.

Selected Recovery Term (Years)

Monthly % During Recovery Term

Monthly % Post- Recovery Term

1 8.939% 0.290% 2 4.764% 0.290% 3 3.374% 0.290% 4 2.681% 0.290% 5 2.266% 0.290% 6 1.991% 0.290% 7 1.795% 0.290% 8 1.649% 0.290% 9 1.537% 0.290% 10 1.447% 0.290%

Subsequent modifications and additions to Additional Facilities covered by a Facilities Agreement shall be subject to a new Option B Facilities Agreement covering the installed cost of such facilities, wherein customer must select a Recovery Term that will define the appropriate monthly rate for such cost.

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Subsequent replacement of an Additional Facilities component shall be subject to a new Facilities Agreement covering the installed cost of such item and the customer may select either Option A or Option B for such item. If the Facilities Agreement covering the replaced item remains in effect because there was not a total replacement of the Additional Facilities covered by the Facilities Agreement, the costs covered by such agreement shall be reduced by the original cost of the replaced facility. If the replacement occurs prior to the end of the Recovery Term for the replaced facility, the replacement installed cost shall be reduced by the salvage value of the replaced facility, if any.

26.5. OPERATION AND MAINTENANCE OF CUSTOMER-OWNED FACILITIES

Customers that own distribution substations and/or other distribution facilities may enter into an agreement with the Company for the ongoing operation and maintenance of such facilities (“O&M Service”), subject to Company inspection of subject facilities and approval of the agreement. The cost of such facilities will be defined in the agreement as the current estimated cost of replacement facilities. The net monthly charge for all facilities included in the agreement will be 0.199% per month of such defined cost of such facilities. Alternatively, the Company and such customers may enter into an arrangement wherein the customer is assessed a charge to reimburse the Company on a task or activity basis.

26.6. CONTRACT TERM

The initial term of any contract for Additional Facilities (Facilities Agreement) provided hereunder shall be for not less than ten years and shall be automatically extended for successive periods of one year each until terminated by written notice given by one party to the other not more than six months nor less than three months prior to the expiration date of the original term or any anniversary thereof. If customer ceases to take electric service from Company, Company may remove said Additional Facilities and customer shall pay Company the termination charges set forth below. In the event the customer does not require the Additional Facilities for the full term of the contract and wishes to cancel the contract prior to the expiration date, Company reserves the right to remove such Additional Facilities and will consent to the cancellation of the contract provided customer pays to Company the lesser of the following:

1. The applicable monthly charge for the remaining months of the contract.2. The amount computed under the following formula; provided, however, such amount shall

never be less than zero:[A + B - C] X DWhere:A = Original installed cost of the facilitiesB = Cost of removing facilitiesC = Salvage value to Company of equipment and material removedD = 1.12 less .001 times the number of months which have expired in the initial term of the

contract.

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26.7.1. Termination of Facilities Agreement

The Facilities Agreement provided herein will not be suspended and may not be terminated except upon payment of the charges set forth herein.

26.7.2. Load Changes

Customer will give the Company reasonable written notice prior to increasing load, shifting load, or rearranging customer-owned facilities which may overload or damage Company-owned facilities.

26.7.3. Cost of Additional Facilities

All additional facilities included in a Facilities Agreement will be included at new or replacement cost at the time of inclusion.

26.7.4. Facilities not Includable

The following facilities may not be included in a Facilities Agreement:

1. Facilities on the customer’s side of the point of delivery crossing public streets, roads oralleys.

2. Facilities inside the customer’s building, except that additional facilities may terminate inthe customer’s switchgear located a short distance inside the customer’s building.

3. Capacitors.4. Non-standard facilities not utilized in the Company’s normal operations.5. Overhead/underground construction differential costs.6. Non-salvageable underground facilities installed or provided by the Company.7. Any item Company deems inadvisable from an economic or good engineering practices

perspective.

The final judgment regarding the inclusion of an item rests solely with the Company.

26.8. PAYMENT

The Net Monthly Bill shall be computed in accordance with § 26.3, 26.4 or 26.5 and other applicable provisions of this schedule. Payment shall be made in accordance with Rate Schedule No. 29, Charges Related to Customer Activity (CAC), § 29.19.1.

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Title: Modification of General Service Minimum Rider (GSMR) PSC File Mark Only


27.0. MODIFICATION OF GENERAL SERVICE MINIMUM RIDER

27.1. AVAILABILITY

To any qualified customer as described herein receiving service under Rate Schedule No. 4, Small General Service or Rate Schedule No. 6, Large General Service Schedules. Qualified customers are nonprofit elementary, junior high, or high schools, churches, recognized nonprofit fraternal societies or lodges, and other similar institutions of an educational, religious or eleemosynary nature, where the premises are used entirely for educational, religious, fraternal or eleemosynary purposes, and the pattern of operation normally causes maximum use of electric service at night, or on weekends and holidays, or during Entergy Arkansas, LLC ("EAL" or the "Company") other off-peak periods. This rider is not applicable if the premises are used for activities of a commercial or industrial nature. If any part of the premises is rented to or shared with others who do not qualify under this rider, the service to that part of the premises so used must be separately metered and billed under all the terms and conditions of the applicable rate schedule; otherwise, this rider shall not be applicable to the part of the premises which qualifies.

27.2. BILLING

27.2.1. NON-MINIMUM BILLINGS

The monthly bill will be in accordance with the applicable rate schedule based on the billing demand established and the energy consumed during the current billing month. If energy consumption increases over 5,000 kWh, demand may be calculated by dividing energy consumption by 300. If energy consumption exceeds 5,000 kWh more than twice or 6,000 kWh more than once during the months of May through October a demand meter will be permanently installed and thereafter billing will be for both kW and kWh.

27.2.2. MINIMUM BILL FOR OTHER THAN ATHLETIC FIELD LIGHTING ACCOUNTS

The monthly minimum bill will be in accordance with the provisions of the applicable rate schedule applied to the billing demand established during the current billing month. Billing demands previously established will not be used in determining the monthly minimum bill.

27.2.3. MINIMUM BILL FOR ATHLETIC FIELD LIGHTING (AFL) ACCOUNTS

Unless and until a demand meter must be installed on an AFL account pursuant to § 27.2.1 the monthly bill will be in accordance with the applicable rate schedule based on the calculated billing demand and the energy consumed during the current billing month. The minimum bill for an AFL account will not be less than the amount calculated using the following Minimum Demand Charge.

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Title: Modification of General Service Minimum Rider (GSMR) PSC File Mark Only


Billing Item Rate Minimum Demand Charge:

Charge per kVA or fraction thereof of transformer capacity installed to serve the customer’s Athletic Field Lighting facilities,

$1.81

The Billing Amount for AFL accounts only will be the greater of the amount calculated in the Rate provision of the applicable Rate Schedule and the Minimum Demand Charge above, plus the Energy Cost Recovery factor times the billed energy, plus all other Adjustments required by the Adjustments provision of the applicable Rate Schedule.

27.3. OTHER CONDITIONS

Except as specifically modified herein, all the terms and conditions of the applicable rate schedule remain unchanged and apply.

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Title: Separately Metered Commercial Space & Water Heating Rider (SMWHR)

PSC File Mark Only


28.0. SEPARATELY METERED COMMERCIAL SPACE & WATER HEATING RIDER

NOT AVAILABLE TO NEW APPLICATIONS AFTER JUNE 16, 2007

28.1. AVAILABILITY

Applicable during the space heating season to any year-round customer receiving service under any of Entergy Arkansas, LLC ("EAL" or the "Company") Rate Schedules Small General Service (SGS), General Farm Service (GFS) and Large General Service (LGS). Customer must have qualifying space and/or water heating equipment as defined below with wiring so arranged that the requirements of the electric space and water heating may be segregated from the customer's other requirements and separately metered at a single point of delivery. This Rider is not applicable to temporary service, standby or supplementary service or primary service.

Space Heating. Customer must have permanently installed and in regular use an electric heat pump providing year-round comfort air conditioning with a total load of at least 2.5 kW, or electric resistance comfort heating equipment with a total rated load of at least 4.0 kW.

Water Heating. Customer must have permanently installed and in regular use electric water heating equipment which is permanently connected, thermostatically controlled and with insulated storage tank capacity of at least thirty gallons and with heating element or elements that can be operated simultaneously of not more than 6,000 Watts or 150 Watts per gallon of tank capacity, whichever is greater.


28.2.1. Rate

Electric energy used during the space heating season for the operation of customer's space and water heating equipment will be billed as follows:


1st 1000 kWh: $0.04543 All additional kWh $0.03765

28.2.2. Minimum

Billing Item Rate Charge per month during the Space Heating Season: $3.98

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PSC File Mark Only



The Billing Amount will be the greater of the amounts calculated in § 28.2.1 or § 28.2.2 above plus the Energy Cost Recovery factor times the billed energy, plus all other Adjustments required by § 28.2.4 below.

28.2.4. Adjustments


28.3. SPACE HEATING SEASON

For those customers in billing cycles 1 through 8, the space heating season is defined as the six billing months of December through May. For those customers in billing cycles 9 through 21, the space heating season is defined as the six billing months of November through April.


In order to qualify under the provisions of this Rider, customer's installation must be approved by the Company and the equipment must meet Company's requirements as to (1) proper sizing of equipment for the space to be heated and for hot water requirements, (2) installation, control and operation of equipment, and (3) sizes and types of heating and water heating equipment and applicable accessories. Company shall have the right to make periodic inspections and tests of the heating and/or water heating installations in order to determine if the equipment and installation continue to conform to the applicable provisions of this Rider and Company's Policy Schedule No. 9, Service Regulations.

Customers with electric resistance heating may connect electric air conditioning equipment to the heating circuits when such equipment is used solely to condition the same space which is electrically heated.

It shall be the responsibility of customer to notify the Company immediately of any changes in space heating and/or water heating equipment.

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PSC File Mark Only


28.5. PAYMENT




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Title: Charges Related to Customer Activity (CAC) PSC File Mark Only


29.0. CHARGES RELATED TO CUSTOMER ACTIVITY (RULES of PRACTICE and PROCEDURE (“RPP”) 7.03(c)(2))



29.2. ANNUAL ADJUSTMENT

The Company will review the charges in this Schedule annually and if an adjustment is necessary to recover the costs of these discretionary services the Company will request revisions in the charges. Each such revision shall be submitted to the Commission on or about March 15 of each year.

29.3. CUSTOMER ACCOUNT RECORD STATEMENT (General Service Rule (“GSR”) 2.04.A.)

The Company does not currently charge a fee for the statement described by GSR 2.04.A.

29.4. ENERGY CONSUMPTION STATEMENT (GSR 2.04.B.)

29.4.1. BASIC ENERGY CONSUMPTION STATEMENT

EAL will provide upon request a Basic Energy Consumption Statement free of charge once every twelve months to customers whose service is metered with interval recording devices. This Basic Energy Consumption Statement consists of a single kVA Analysis Report including twelve consecutive months or less.

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29.4.2. ELECTRONIC LOAD DATA PRODUCTS FEES

The following Load Data Products will be provided upon request to customers whose service is metered with existing interval recording devices. For customers whose service is metered with devices other than interval recorders, Company will install and maintain interval-recording devices upon customer’s request on a job order basis (time and materials). Interval recording devices installed at the customer’s request will remain the property of the Company. Such Load Data Products covering monthly billing periods will be provided at the monthly fees specified below:

Billing Item Monthly Rate kVA Analysis Report (e-mail) $3.20 kVA Peaks Summary Report (email) $3.20

29.5. MEMBERSHIP FEE (GSR 3.01.E.(1)c.)

The fee described by GSR 3.01.E.(1)c. does not apply to the Company

29.6. DEPOSITS FROM APPLICANTS (GSR 4.01.)

29.6.1. RESIDENTIAL

29.6.1.1. The Company may require a deposit for residential service when an applicant meets the criteria listed in GSR 4.01.A.

29.6.1.2. Deposit From Landlord: The Company requires a deposit when an applicant for residential service qualifies as a landlord as defined in the APSC General Service Rules.

29.6.1.3. EAL is currently exempted from GSR 4.01.A. by the addition of the following after GSR 4.01.A.(2)f.:

(3) If any of the conditions in GSR 4.01.A.(2) above apply, the Company may waive all or a portion of a deposit for an applicant for residential service based on the applicant’s credit score as returned by a credit scoring service.

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29.6.2. NON-RESIDENTIAL

29.6.2.1. The Company may require a deposit for non-residential service. The Company may accept the following instruments in amounts and under terms and conditions acceptable to EAL in lieu of cash deposits: an irrevocable bank letter of credit or a surety bond from a bank or surety company acceptable to the Company.

29.6.3. PAYMENT PROCEDURES – RESIDENTIAL AND NON-RESIDENTIAL DEPOSITS

29.6.3.1 EAL is currently exempted from GSR 4.01.C. by replacing GSR 4.01.C. in its entirety with the following language:

C. Payment Procedures

Except for deposits under Rule 4.01.B.(3), applicants shall be allowed to pay the deposit in 2 installments - 1/2 of the deposit at a Company authorized payment location prior to service initiation and the remaining 1/2 with the first bill for electric service. Alternatively, the customer may elect to pay the total amount of the deposit on the first month’s bill for electric service.

29.7. DEPOSITS FROM CUSTOMERS (GSR 4.02.)

29.7.1. RESIDENTIAL

29.7.1.1. EAL is currently exempted from GSR 4.02.A. by replacing § 4.02.A.(1) with the language below and deleting § 4.02.A.(3).

(1) The residential customer’s account appears more than one time in a twelve-month period on the list of customers eligible to be disconnected following the mailing of a Disconnect Notice which contained notification of the deposit billing;

The Company may require a new or increased deposit from a residential customer when that customer meets the criteria listed in GSR 4.02.A. as modified above.

29.7.1.2. Deposits From Customers – Payment Procedures (GSR 4.02.D): EAL is currently exempted from GSR 4.02.D in the following way. If a new or increased residential deposit is allowed under Condition 4.02.A.(1) as exempted above in § 29.7.1.1, GSR 4.02.A.(2), or GSR 4.02.A.(6), the customer will be billed the new or increased deposit in amounts of no more than $50 until the maximum deposit allowed has been collected. The customer may avoid receipt of additional bills for new or increased deposit amounts, after the first new or increased deposit billing, by paying the first deposit amount and all bills for electric service by the close of business on the last day to pay as shown on the Disconnect Notice.

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29.7.2.1. EAL is currently exempted from GSR 4.02.A. by deleting § 4.02.A.(1) and adding § 4.02.A.(8) as shown below.

(8) As of the effective date of Rate Schedule CAC approved in Docket No. 09-084-U, any non-residential customer who fails to maintain a Credit Rating of at least BBB- as determined by the S&P Rating Group, BBB- from Fitch Ratings or Baa3 from Moody’s Investor Service, or their successors may be notified of the intent to obtain or increase a deposit. The customer will be advised in writing noting the information and source that supported the decision to obtain the deposit or deposit increase. The Company may require the amount of the deposit subject to EAL’s monitoring of the customer’s financial metrics in comparison to EAL’s credit risk exposure. If the review indicates an increased credit risk, then the deposit may be increased.

The Company may require a new or increased deposit from a non-residential customer when that customer meets the criteria listed in GSR 4.02.A. as modified above.

29.7.3. DEPOSIT FROM PETITIONER FOR BANKRUPTCY (GSR 4.02.A.(7)) RESIDENTIAL AND NON-RESIDENTIAL: The Company may require an additional deposit from a petitioner for bankruptcy in an amount calculated as in GSR 4.02.B.

29.8. CALCULATION OF AVERAGE BILL (GSR 4.03.)

EAL is currently exempted from GSR 4.03.B. by the addition of the following language:

When a non-residential applicant requests service in a location where the previous customer at that location was of the same business type and size as the applicant for service, the average bill shall not be more than the average monthly bill for that location for the most recently completed representative 12 month period.

29.9. PROCESSING FEE FOR LEVELIZED BILLING WITHDRAWAL (GSR 5.10.C.(3))

The Company does not currently charge a fee for the Levelized Billing Withdrawal described by GSR 5.10.C.(3).

29.10. RETURNED CHECK CHARGE (GSR 5.13)

Charged when payment for services by check or other payment instrument is not honored by customer’s financial institution for any reason other than bank error. The returned check charge shall be the maximum collection fee amount under Ark. Code Ann. § 4-60-103.

29.11. METER READING REPORT CHARGE (GSR 5.16.B.(3))

The Company does not currently charge a fee for a Meter Reading Report described by GSR 5.16.B.(3).

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29.12. METER TEST FEE (GSR 5.18.C.(1))

Billing Item Rate Per occurrence: $53.00

Charged for each customer requested meter test after the first customer requested test in a calendar year if such test shows the meter to be registering within the accuracy limits of APSC Special Rules - Electric, Rule 7.05.

29.13. TRIP FEE (GSR 6.11.)

Billing Item Rate Per occurrence: $15.00

Charged when the last day to pay, as printed on the shut-off notice, has passed; and, a Company employee is dispatched to customer’s premises to terminate service and service is not terminated for either of the following reasons:

1. because receipt of payment at the premises was refused by the Companyemployee but customer was allowed 24 hours to pay at an authorized paymentlocation; or,

2. because customer’s normally accessible meter was inaccessible and the customeror other adult was not at the premises or did not respond.

29.14. RECONNECTION FEES (GSR 6.12.)

29.14.1.DURING NORMAL WORKING HOURS

Billing Item Rate Per occurrence when customer has opted for a non-advanced meter or customer’s advanced meter is not capable of remote reconnection:

When service is reconnected at the customer’s meter $39.00 When service is reconnected at other than the customer’s meter $87.00

Per occurrence when customer has an advanced meter capable of remote reconnection:

Remote reconnect fee $2.50

Charged to reconnect service in the normal course of business when customer or other authorized party requests reconnection between 8:00 a.m. and 5:00 p.m. on a normally scheduled workday and makes payment of the reconnect fee and all amounts due at Company offices designated to accept such payments or at Company authorized payment stations by 5:00 p.m. of that day.

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29.14.2.AFTER NORMAL WORKING HOURS

Billing Item Rate Per occurrence when customer has opted for a non-advanced meter or customer’s advanced meter is not capable of remote reconnection: When service is reconnected at the customer’s meter $56.00 When service is reconnected at other than the customer’s meter $105.00

Per occurrence when customer has an advanced meter capable of remote reconnection:

Remote reconnect fee $2.50

Charged to reconnect service in emergency situations requiring immediate initiation of service when payment of this reconnect fee and all amounts due at a Company authorized payment station is made after 5:00 p.m. All other reconnections for payments made after 5:00 p.m. will be performed the next normally scheduled workday.

29.15. FINANCE CHARGE ON DELAYED PAYMENT AGREEMENTS (GSR 6.13.I.)

The Company will charge interest on Delayed Payment Agreements equal to the daily rate equivalent of the annual rate required to be paid on customer deposits by GSR 4.05.A.

29.16. CHARGE FOR ADDITIONAL METERS (SR-E 3.06.A.)

The Company does not currently charge a fee for additional meters used as special meters or provided for the customer’s convenience. Installation, ownership and maintenance of meters located on the customer’s side of the Company’s billing meter are the responsibility of the customer.

29.17. PAYMENT BY DRAWDRAFT AND LEVELIZED/EQUAL PAYMENT

Billing Item Rate Credit Per Month: $1.00

Credited to account when customer currently authorizes drawdraft payments at the due date for services rendered by Company and the drawdraft is honored for payment in full, and the customer also has either levelized or equal payment of billing.

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29.18. CHARGE FOR DATALINK

DataLink is available to customers receiving electric service under the following Rate Schedules: Small General Service (SGS), Large General Service (LGS), Large General Service Time-Of-Use (GST), Large Power Service (LPS), Large Power Service Time-Of-Use (PST) and customers receiving service under a Commission approved Special Rate Contract.

DataLink provides web based viewing access to interval load data that has been collected by the Company. Subscribing customers have the option of viewing the collected load data on an hourly or daily basis.

Customers that do not have interval metering must have an interval meter installed by the Company to enable interval data collection. Customers may elect to pay for the interval meter installation by a one-time charge or by a recurring monthly charge.

The communication link for the transmission of the collected interval data by the Company will be the telephone line which will be provided by the customer and at the customer’s expense. At the customer’s request, the Company will provide an optional wireless communication link with daily and hourly viewing options priced as shown below.

An Agreement for DataLink Service requires a minimum term of two (2) years. If the customer elects to cancel service before the completion of the minimum term, the customer will pay to the Company liquidated damages equal to the balance of the fees due, based on the current tariff, for the remainder of the minimum term of the Agreement.

All equipment installed to provide service under this Schedule is and will remain the property of Entergy Arkansas, LLC.

The various DataLink Service options and their associated charges are as follows:

Subscription Charge: Daily Viewing Option $ 39.50 per month, per meter Hourly Viewing Option $122.50 per month, per meter

Installation of Interval Meter Charge: Monthly Payment Option $ 12.50 per month, per meter Single Payment Option $300.00 per meter

Optional Wireless Communication Link Charges

Daily Viewing Option $ 9.00 per month, per meter Hourly Viewing Option $ 12.00 per month, per meter Initial Setup/Activation - Single Payment $ 15.00 per meter

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29.19. LATE PAYMENT CHARGE (GSR 5.07)

29.19.1.The Late Payment Charge for all Rate Schedules to which a Late Payment Charge applies except Rate Schedule No. 19, Collective Billing Service Rider (CBR) will apply and be calculated as follows:

All bills are due and may be paid without a Late Payment Charge within twenty-two (22) calendar days after the date the bill is mailed. All amounts billed shall be deemed delinquent after 5:00 PM on the twenty-second (22nd) day after the date the bill is mailed and a Late Payment Charge of ten percent (10%) of the first thirty dollars ($30.00) of the bill amount plus two percent (2%) of the amount over thirty dollars ($30.00) may then apply.

29.19.2.The Late Payment Charge for Rate Schedule No. 19, Collective Billing Service (CBR) will apply and be calculated as follows:

All bills are due and may be paid without a Late Payment Charge within fourteen (14) calendar days after the date the bill is mailed. All amounts billed shall be deemed delinquent after 5:00 PM on the fourteenth (14th) day after the date the bill is mailed and a Late Payment Charge of ten percent (10%) of the first thirty dollars ($30.00) of the bill amount plus two percent (2%) of the amount over thirty dollars ($30.00) may then apply.

29.19.3.The Late Payment Charge shall not apply to Federal or State accounts.

29.20. CHARGE FOR STUDY COSTS TO ACCOMODATE CUSTOMER SERVICE REQUESTS Customer requests for service from and/or interconnection with Company facilities may require analyses of the impacts on the Company’s system and other customers. The Customer will be notified by EAL that such studies are to be conducted. The Customer shall have the option to contact an engineering firm qualified to provide the studies to procure the study, or alternatively, the Company will procure the study and the Customer shall reimburse the Company for the associated costs. EAL will make available to Customers who choose to procure the study a list of at least three approved engineering firms from which the Customer may choose.

29.20.1.The Studies for interconnection of customer generating systems may include, but are not limited to: (a) Service study - An on-site analysis used to determine the interconnection

requirements and the system voltage for providing parallel service to a Customer with an on-site generating facility operating in parallel with Company’s system. All net metering facilities will require this study.

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(b) Coordination study - An engineering analysis that determines whether the presence of the on-site generating facility would interfere with the protective fusing and relaying on the distribution delivery system. It includes an analysis of the renewable energy facilities’ contribution to power flow, available fault current, capacitor bank impact, and effects of voltage under normal and worst case situations.

(b) Distribution delivery system impact study - An engineering study that models the distribution delivery system with the proposed on-site generating facility in place. The modeling must determine whether the distribution delivery system will be able to support the proposed on-site generating facility without reliability problems or interruptions in service to other customers. The study must also include a transient analysis to determine the potential for stability problems. If the model and transient studies indicate that power can flow back to the substation and consequently onto the transmission grid, then similar assessments will be required for the transmission system. This type of study would be required when several Customers have on-site generating facility interconnected on the same feeder circuit and the total output of all interconnected renewable energy facilities on that feeder is 50% or more of the feeder circuit’s base load.

(c) Secondary network study - An engineering analysis to specifically determine whether an on-site generating facility can be safely added to a secondary network. Typically, this study would be required when a Customer’s on-site generating facility is proposed for interconnection to a secondary network.

29.20.2.Studies for system impacts of significant additions of customer demand and energy requirements may include, but are not limited to:

Transmission System Impact Study – An engineering study that models the transmission delivery system with the proposed on-site demand in place. The modeling must determine whether the transmission delivery system will be able to support the proposed on-site demand without reliability problems or interruptions in service to other customers. The study must also include a transient analysis to determine the potential for stability problems. If the model and transient studies indicate that new customer demand will cause violations of the NERC standards, a list of proposed projects to remove the violation will be developed. A Facilities Study will be required to determine the project scope, cost, and schedule. This type of study would be required when the demand cannot be supported with the existing infrastructure and a new substation is required to support the customer’s demand.

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29.21 Advanced Metering Infrastructure (AMI) Opt-Out Fees

This optional service is available to residential customers, except residential customers taking service under Residential Energy Management Time-Of-Use (REMT) Rate Schedule No. 33 or Optional Residential Time-Of-Use (RT) Rate Schedule No. 2, who make the required request to the Company to elect non-standard meter service in lieu of the standard communicating advanced meter service (Opt-Out) and who are currently taking service at no more than 200 Amps under a rate schedule for which a communicating advanced meter is the standard meter service. Such customers may request to receive non-advanced metering service through a non-communicating meter. Customers requesting the Opt-Out service option will be charged a one-time service and administration fee and a monthly manual meter reading fee in addition to all rates and adjustments contained in the customer’s otherwise applicable rate schedule. AMI Opt-Out fees are as follows:

One-Time Service and Administration Fee per Account:* $63.50

Monthly Manual Meter Reading Fee per Account: $21.80

*Existing meters must pass an inspection to ensure the meter meets safety and accuracystandards. If the existing meter fails the safety inspection or accuracy test, the existing meter will be replaced with a refurbished digital non-communicating meter.

Customers taking service under Opt-Out relocating to a new premise who wish to continue service under Opt-Out are required to request new service according to the Company’s Opt-Out request requirements including payment of the one-time service and administration fee at the new premise. Customers who cancel service under Opt-Out and later re-enroll for this service at any location, would also be required to pay another one-time service and administration fee.

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Title: Optional Apartment Service Rider (OASR) PSC File Mark Only


30.0. OPTIONAL APARTMENT SERVICE RIDER

30.1. AVAILABILITY

This Rate Schedule is available only to eligible customers served under this Schedule prior to November 1, 1995; customers who qualify for master metering under General Service Rule (GSR) 5.20; or customers who have obtained an exemption under GSR 5.20.C. This Schedule is available only for residential service to apartment buildings containing four or more single family apartments. Service under this Rider will be supplied through one meter. Service is for the use of the residential tenants and may not be sub-metered and resold. This Rider is not applicable to supplemental or standby service.


The Net Monthly Rate shall be the same as that provided in the Residential Service Rate Schedule which would be applicable if each apartment were separately metered, except the number of kWh to be billed at each step of the Net Monthly Rate shall be determined by multiplying the kWh in each step by the number of single family apartment units in each building.


Service under this rider is for single family apartments including incidental hall or corridor lighting, washaterias or laundry facilities for the exclusive use of the tenants. Commercial and common use facilities such as elevators, swimming pools, barber shops, restaurants and office space will be separately metered and billed under the applicable General Service Rate Schedule.

Except as modified herein, all terms and conditions of the applicable residential rate schedule remain unchanged and apply.

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Title: Commercial Space Heating Rider (CSHR) PSC File Mark Only


31.0. COMMERCIAL SPACE HEATING RIDER

31.1. AVAILABILITY

Available to all customers eligible for service under Entergy Arkansas, LLC (“EAL” or the “Company”) Rate Schedules No. 4, Small General Service (SGS) or No. 6, Large General Service (LGS) on and after the effective date of this schedule and to all customers taking service under this schedule on its effective date who have installed qualifying space heating equipment as described herein. The customer must have permanently installed and in regular use an electric heat pump providing year-round comfort space conditioning with a total load of at least 2.5 kW, or electric resistance comfort heating equipment with a total rated load of at least 4 kW. Electric space heating systems installed after January 1, 2012 must have a coefficient of performance of greater than 3.6 for Closed Loop Water-to-Air systems or greater than 4.1 for Open Loop Water-to-Air systems to qualify for this schedule. Not applicable to temporary, standby, supplemental or seasonal service.

31.2. BILLING

All provisions of the applicable Rate Schedule shall be unchanged and billing to customer shall be in accordance with the charges specified in said Rate Schedule, except that the Billing Loads in the six winter billing months of November through April shall be modified as follows, but in no event will the Billing Load be less than 50% of the maximum load registered during the current billing month.

The Billing Load shall be the lesser of the following:

(1) The maximum load established during the billing months of June, July, August, and September less 1 kW per ton for the first 25 tons of electric air conditioning, eight-tenths (.8) kW per ton for the next 25 tons of electric air conditioning and six-tenths (.6) kW per ton of electric air conditioning in excess of 50 tons.

(2) The load registered during the month.

If applicable, the Minimum provision of the applicable Rate Schedule shall be modified to consider only the highest demand established in the billing months of June, July, August and September.

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Title: Commercial Space Heating Rider (CSHR) PSC File Mark Only



In order to qualify under the provisions of this Rider, customer's installation must be approved by Company and the equipment must meet Company's requirements as to (1) proper sizing of equipment for the space to be heated, (2) installation, control and operation of equipment, and (3) sizes and types of heating equipment and applicable accessories. Company shall have the right to make periodic inspections and tests of the heating installation in order to determine if the equipment and installation continue to conform to the applicable provisions of this Rider and the Company's Service Regulations.

It shall be the responsibility of the customer to notify the Company immediately of any changes in space heating equipment.

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Title: Economic Development Rider (EDR) PSC File Mark Only


32.0. ECONOMIC DEVELOPMENT RIDER

32.1. AVAILABILITY

Available when necessary to induce any new or existing customer receiving service under Large General or Large Power Service Rate Schedules to increase its load (demand) if the customer meets the following criteria.

1. Customer is: (a) a customer classified as Standard Industrial Classification (“SIC”)codes 20 through 39, 40, 42, 46, 4922, 50, 51, 53 or 54; (b) a United StatesGovernment military installation classified as SIC code 9711; (c) a correctional facilityclassified as SIC code 9223; (d) a large research facility classified as SIC codes 8731through 8743; (e) a large computer/data processing or service center classified asSIC codes 7371 through 7375; (f) a customer classified as a corporate headquartersor (g) an enterprise that Entergy Arkansas, LLC (“EAL” or the “Company”) deemssufficiently similar to one of the above.

2. Customer takes service under one of the Company's Rate Schedules within theLarge General Rate Class, LGS, GST, LPS or PST.

3. Customer has increased billing demand for firm full requirements service receivedfrom the Company by 500 kW or greater on a monthly basis, as determined below.

4. Customer has executed an Agreement for Electric Service for service provided byCompany for a minimum term of five (5) years following the effective date that termsof the Rider become applicable to such service.

Customer must indicate such conditions exist by entering into a contract with EAL in substantial form to that set out in Policy Schedule No. 13, § 13.11.

32.2. PROCEDURE

Contracts entered into pursuant to this Rider shall be filed with the Arkansas Public Service Commission (“Commission”) within 15 days of the date the contract is signed by EAL. Contracts filed with the Commission shall become effective upon that date and be approved by the Commission for rate making purposes, including test year revenues and expenses in rate cases.

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32.3. APPLICATION

This Rider shall become applicable when the new or increased monthly demand of the Customer exceeds the Base Period Demand by 500 kW or more.

For new Customers installing facilities which cause new load, the Base Period Demand shall be zero. For customers being served prior to the date of EAL executing a contract pursuant to this Rider (“existing Customers”), the Base Period Demand shall be the average of the monthly demands during the most recent twelve consecutive months of normal and representative usage by the Customer prior to application of the Rider. Start-up months when load is being added in small increments shall not be included in the Base Period Demand. If a Customer assumes the operation of facilities of an existing or former Customer, the new Customer in that instance shall be considered an existing Customer for purposes of determining the Base Period Demand. Under circumstances where it is determined that an existing Customer has informed state and local officials of an impending facility closure, or in the instance of an actual closure, the Base Period Demand for that location may be set to a curtailed level or zero in order to provide an economic incentive to the new Customer. The reasons for a curtailed or zero Base Period Demand determination will be included in the Rider contract.

This Rider shall continue to be applicable to a Customer only if the average monthly demand for the most recent twelve months ending with the current billing month exceeds the Base Period Demand by 500 kW. Billing months before the Rider becomes applicable shall not be included in the twelve month average demand. Monthly demand as used in this Rider is the demand, as defined in EAL’s applicable rate schedule, established during each monthly billing period. (For Customers served on a Time of Use Rate Schedule, demand refers to on-peak demand.) If such condition is not met, then the reduction of demand for billing purposes under this Rider shall not apply and billing shall be made under the otherwise applicable rate schedule for the actual metered demand.

In the application of this Rider, the new or increased demand shall be defined as the excess of the monthly demand over the Base Period Demand. Existing loads served by EAL that are relocated to or combined with another point of metering shall not be included when determining new or increased demand.

A Customer may add additional increments of at least 500 kW in demand. Any such new increment, if it otherwise qualifies under the terms of this Rider, shall be dealt with in a separate contract.

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Except as provided above, all provisions, prices and regulations of EAL’s standard rate schedule effective at the time service is provided shall apply. This Rider reflects a temporary condition with regard to available capacity and therefore EAL reserves the right to modify or discontinue the Rider at any time by making a tariff filing with the Commission. However, elimination or modification of this Rider itself shall not operate to affect contracts previously approved and remaining in effect; that is, demand reductions for billing and rate making purposes previously approved shall continue until they expire or the contract terminates for other reasons.

This Rider is not applicable to resale, stand-by, auxiliary or supplemental service. Service will be supplied at one delivery point and shall be at one standard voltage.

32.3.1 Reduction for Contracts Effective prior to March 31, 2016

For purposes of billing under this Rider only, and pursuant to an effective contract, the new or increased monthly demands of the Customer shall be reduced by forty-five percent (45%) during the first year in which the Rider is applicable before billing under the otherwise applicable rate schedule. The reductions in demand for billing purposes pursuant to this Rider shall be successively decreased by ten percentage points (10%) in each succeeding year in which the Rider is applicable (i.e. applicable demand reduced by 35% in the second year, 25% in the third, etc.) until the expiration of the fifth year when the reduction shall cease to exist.

32.3.2 Reduction for Contracts Effective on or after March 31, 2016

For purposes of billing under this Rider only, and pursuant to an effective contract, the new or increased monthly demands of the Customer will be reduced. Customer may choose a reduction schedule of either:

Option 1: Fifty percent (50%) during the first year in which the Rider is applicable before billing under the otherwise applicable rate schedule. The reductions in demand for billing purposes pursuant to this Rider shall be successively decreased by ten percentage points (10%) in each succeeding year in which the Rider is applicable (i.e. applicable demand reduced by 40% in the second year, 30% in the third, etc.) until the expiration of the fifth year when the reduction shall cease.

Or

Option 2: Thirty percent (30%) per month for a five year period. At the end of the five year period, the reduction the shall cease.

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Title: Residential Energy Management Time-Of-Use (REMT) PSC File Mark Only


33.0. RESIDENTIAL ENERGY MANAGEMENT TIME-OF-USE



33.2. AVAILABILITY

For residential service to single family residences or individual family apartments supplied through one meter, including incidental family use, on the appurtenant premises. This Rate Schedule (REMT) is not applicable to commercial type use on the premises such as chicken brooding and grain drying. Where a portion of the residence premises (not separately metered) is used for nonresidential purposes, the predominant use of the service, as determined by the Company, shall determine the Rate Schedule applicable to all service. Service is for the use of the customer and may not be shared and may not be resold to others. Not applicable to standby or supplementary service. Customers currently taking service under the Company’s Optional Residential Time-of-Use Rate Schedule RT may terminate that service and begin service under this schedule provided they have completed twelve (12) continuous months of service under schedule RT.



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33.4 NET MONTHLY RATE

33.4.1. Rate

Billing Item Rate Customer Charge: $8.40 Energy Charge per kWh:

Used During On-Peak Hours: $0.13880 Used During Mid-Peak Hours: $0.06698 Used During Off-Peak Hours: $0.05716

33.4.1.1 Time of Use Period Definition

Period Hour

Beginning Hour

Ending Days Inclusive Calendar Months

Inclusive On-peak 1:00 p.m. 7:00 p.m. Monday - Friday(1) June - September

Mid-peak 6:00 a.m. 10:00 p.m. Monday - Friday(1) October- May 6:00 a.m. 1:00 p.m. Monday - Friday(1) June - September 7:00 p.m. 10:00 p.m. Monday - Friday(1) June - September 6:00 a.m. 10:00 p.m. Weekends, Holidays(2) June - September

Off-peak 10:00 p.m. 6:00 a.m. All days All months 6:00 a.m. 10:00 p.m. Weekends, Holidays(2) October - May

For purposes of this rate schedule, Company-recognized holidays are New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day.

(1) Except for Company-recognized holidays or the nearest weekday if the holiday is on a weekend.

(2) And the nearest weekday if a Company-recognized holiday is on a weekend.

33.4.2. Minimum

The greater of (1) the Net Monthly Rate Customer Charge shown above as adjusted by § 33.4.4, if applicable, or (2) an amount that may be required under the Company’sRate Schedule No. 60, Extension of Facilities.

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The Billing Amount will be the greater of the amounts calculated in §§ 33.4.1 and 33.4.2 above, plus the Energy Cost Recovery Factor times the billed energy, plus all other Adjustments required by § 33.4.6 below.

33.4.4 Three-Phase Service


Billing Item Rate Charge per Month: $3.31

In the event a primary line extension is necessary, customer will reimburse Company for the estimated construction cost of the three-phase primary extension in excess of the estimated cost of a single-phase extension in advance of construction.

33.4.6. Adjustments


33.5. PAYMENT




After the first year (the “Initial Enrollment Period”), the customer’s service under this schedule will be automatically renewed for a period of one year unless the Company is notified that the Customer wishes to take service under the General Purpose Residential Service Rate Schedule (RS) within 60 days of completion of the Initial Enrollment Period.

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At the completion of the Customer’s second anniversary on Rate Schedule REMT, the customer’s service under this schedule will be automatically renewed for periods of one year each unless the Company is notified no less than 30 days prior to such automatic renewal that the Customer wishes to take service under the General Purpose Residential Service Rate Schedule (RS).

33.7 BEST RATE PROVISION

At the end of the Initial Enrollment Period only, the customer’s billing under this Schedule REMT will be compared to billings under Rate Schedule RS using actual usage for the entire period. If the amount billed and paid is higher than the amount calculated under Rate Schedule RS, the customer will receive a one-time billing credit on subsequent billing(s) equal to the difference between the amount actually paid and the amount that would have been billed under Rate Schedule RS during the Initial Enrollment Period only. Customers receiving such billing credit may choose to continue service under this rate schedule REMT or may choose to return to Rate Schedule RS by notifying the Company pursuant to § 33.6 above. Customers choosing to remain on REMT will not be eligible for a similar credit in subsequent years.



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Title: Small Cogeneration Rider (SCR) PSC File Mark Only

Rd THIS SPACE FOR PSC USE ONLY

34.0. SMALL COGENERATION RIDER

34.1. AVAILABILITY

To any customer who takes service under the provisions of any of the Entergy Arkansas, LLC ("EAL" or the "Company") applicable standard rate schedules, who has installed electric cogeneration or power production facilities with a design capacity of 100 kW or below in size, who desires a permanent electrical connection with Company’s system to allow for the sale of the customer’s excess generation output to the Company and who has entered into a Power Purchase Agreement with the Company. Cogeneration or power production facilities to which this schedule applies may be telemetered based on the Company’s requirements for telemetry. All such facilities must be for customer's sole use at a single location. Customers may elect to sell their total generation output while purchasing their entire electrical requirement from the Company.

Not applicable to short-term or seasonal service.

The provisions of the applicable standard rate schedule are modified only as specified herein.

34.2. BILLING

Billing Item Rate Monthly Customer Charge additional to Customer Charge under applicable standard rate schedule.: $22.42

34.3. ENERGY PAYMENT

Energy generated by customer and delivered into Company's system at the point of interconnection will be credited to the customer based on a projected avoided cost energy rate for the Company’s load zone in MISO.

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34.4. CAPACITY PAYMENT

The maximum dependable output of a customer's facility will receive a capacity payment based on the $/kW value of whatever capacity addition has been avoided. Such avoided capacity costs can be adjusted for individual customers based on the factors specified in APSC - Cogeneration Rules - § 3.4(e).


34.5.1. The customer shall pay to the Company the initial and continuing cost of any additional facilities including special metering facilities which are made necessary by interconnection with customer's generating facilities. Continuing costs are considered to be the operation and maintenance, taxes and replacement costs associated with any additional facilities. The monthly charge pursuant to this § 34.5.1, will be determined by multiplying the then current percentage found in § 26.3. of Rate Schedule No. 26, Additional Facilities Charge Rider (AFCR) or § 53.3. of Rate Schedule No. 53, Additional Facilities Charge Rider – Governmental (AFCRG) if applicable, times the initial cost as modified to include costs associated with subsequent capital modifications or additions to such facilities and in the case of replacement, the excess of the cost of replacement over the original installed cost of the replaced facilities. If telemetering is required pursuant to § 34.1, above customer shall also pay the costs of all telemetering equipment and themonthly charge for a communication circuit between the dispatch center and customer’s generating facility.

34.5.2. Unless provision is made for complete shutdown of customer's electrical power production equipment and disconnection and/or isolation from other sources of Power supply during periods when service is being taken from Company, customer will install and maintain at his own expense:

A. Protective devices necessary for the protection of his personnel and equipment; B. Protective devices necessary in the Company's judgment for the protection of

Company's personnel, equipment and service.


A. To automatically disconnect customer facilities when Company's service is interrupted;

B. To prevent interconnection with Company's system when Company's supply line is de-energized;

C. To protect equipment and personnel during synchronization and interconnection with Company's system;

D. To isolate and protect customer's equipment when his generating equipment is not running.

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34.5.3. The customer shall hold harmless the Company from any loss due to damage or loss to customer's equipment, personnel or property arising from or in connection with interconnection with Company's system. The customer shall indemnify and keep indemnified the Company from and against all loss, damage and expense which the Company may sustain by reason of or in connection with the interconnection.

34.6. PAYMENT

The monthly payment or charge to the customer under this Rider will be handled separately from billing for any customer requirements under the standard rate schedule. If payment to the customer for capacity and/or energy deliveries to the Company during the month do not exceed the charges specified herein, payment shall be made in accordance with Rate Schedule No. 29, Charges Related to Customer Activity (CAC), § 29.19.1.



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ENTERGY ARKANSAS, LLC

AVOIDED CAPACITY AND ENERGY COSTS APPLICABLE TO RIDER SCR

- ARKANSAS - AVOIDED CAPACITY COSTS:

Capacity - $0.0 per kW of capacity under a long-term contract subject to approval of the Arkansas Public Service Commission.

AVOIDED ENERGY COSTS: Summer Period Other Period Energy Deliveries Energy Deliveries Annual Voltage Level of Purchase On-Peak Off-Peak On-Peak Off-Peak Average Generation - ¢/kWh 2.858 2.305 2.730 2.477 2.621 Transmission ≥230kV - ¢/kWh 2.897 2.325 2.734 2.469 2.633 Transmission <230kV - ¢/kWh 2.942 2.361 2.777 2.507 2.674 Primary - ¢/kWh 3.077 2.469 2.905 2.622 2.797 Secondary - ¢/kWh 3.156 2.533 2.979 2.689 2.868 SEASON/TIME PERIOD DEFINITION: Summer Period: April 1st – September 30th On-Peak Hours: 6:00 a.m. - 10:00 p.m., Monday – Saturday Off-Peak Hours All hours not designated as on-peak hours

Other Period: October 1st – March 31st On-Peak Hours: 6:00 a.m. - 10:00 p.m., Monday - Saturday Off-Peak Hours All hours not designated as on-peak hours

NOTES: (1) The avoided energy costs in this Bulletin were developed to be applicable to total energy

of 100 MW per hour. (2) The avoided energy costs in this Bulletin are adjusted to reflect the various losses

appropriate to the voltage level at which purchases are made. (3) This Bulletin is applicable in the EAL load control area only.

(4) Average annual numbers are shown for informational purposes and may be used for

purchases from small qualified facilities if time of use metering is not economical. Avoided Costs Bulletin No. 82 Effective January 1, 2021 ESL Rate Administration Little Rock, Arkansas

APSC FILED Time: 12/21/2020 9:18:59 AM: Recvd 12/21/2020 9:17:58 AM: Docket 81-071-F-Doc. 522


Original Sheet No. 35.1 Schedule Sheet 1 of 5 Including Attachment





Title: Large Cogeneration Rider (LCR) PSC File Mark Only


35.0. LARGE COGENERATION RIDER

35.1. AVAILABILITY

To any customer who takes service under the provisions of any of the Entergy Arkansas, LLC ("EAL" or the "Company") applicable standard rate schedules and who is a qualified facility pursuant to the Arkansas Public Service Commission ("APSC") Cogeneration Rules - § 2 and desires a permanent connection with Company's system to allow for the sale of the customer’s excess generation output and who has entered into a Power Purchase Agreement with Company. Customer must have installed electric cogeneration or power production facilities of 100 kW capacity or greater, the output of which is telemetered to the Entergy Dispatch Center. Such facilities must be for customer's sole use at a single location.

Not applicable to short-term or seasonal service or to purchase of customer's total output if Company is simultaneously supplying electric service.

The provisions of the applicable standard rate schedule are modified only as specified herein.

35.2. BILLING

Billing Item Rate Monthly Customer Charge additional to Customer Charge under the applicable standard rate schedule: $22.42

35.3. ENERGY PAYMENT

Energy generated by customer in excess of his own requirements and delivered into Company's system at the point of interconnection will be adjusted for losses as necessary and will be credited to the customer as described in Attachment A to this schedule. Such costs may be adjusted by contract for individual customers based on the factors specified in the APSC - Cogeneration Rules - § 3.4(e), as well as whether the customer is a qualified facility pursuant to § 2 of such Rules.

35.4. ESTIMATED AVOIDED COST FILING REQUIREMENT

The Company shall file with the APSC the estimated avoided energy costs appropriate for the time and season and voltage level at which energy is delivered not less than every two years (biannual PURPA § 210 filing or its successor).

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35.5. CAPACITY PAYMENT

The maximum dependable output of a customer's facility will receive a capacity payment based on the $/kW value of whatever capacity addition has been avoided. Such avoided capacity costs can be adjusted for individual customers based on the factors specified in APSC - Cogeneration Rules - § 3.4(e).

35.6. MAXIMUM GENERATION

Maximum Generation is the maximum kW, as shown by or computed from the reading of the Company's kW demand meter, for the 15-minute period of customer's maximum power delivery to the Company during the month.


35.7.1. The customer shall pay to the Company the initial and continuing cost of any additional facilities including special metering facilities which are necessary by interconnection with customer's generating facilities. Continuing costs are considered to be the operation and maintenance, taxes and replacement costs, associated with any additional facilities. The monthly charge pursuant to this § 35.7.1, will be determined by multiplying the then current percentage found in § 26.3, of Rate Schedule No. 26, Additional Facilities Charge Rider (AFCR) or § 53.3 of Rate Schedule No. 53, Additional Facilities Charge Rider – Governmental (AFCRG) if applicable, times the initial cost as modified to include costs associated with subsequent capital modifications or additions to such facilities and in the case of replacement, the excess of the cost of replacement over the original installed cost of the replaced facilities. Customer shall also pay the costs of all telemetering equipment and the monthly charge for a communication circuit between the dispatch center and customer's generating facility.

35.7.2. Unless provision is made for complete shutdown of customer's electrical power production equipment and disconnection and/or isolation from other sources of power supply during periods when service is being taken from Company, customer will install and maintain at his own expense:

A. Protective devices necessary for the protection of his personnel and equipment;

B. Protective devices necessary in the Company's judgment for the protection of Company's personnel, equipment and service.


A. To automatically disconnect customer facilities when Company's service is interrupted;

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B. To prevent interconnection with Company's system when Company's supply line is de-energized;

C. To protect equipment and personnel during synchronization and interconnection with Company's system;

D. To isolate and protect customer's equipment when his generating equipment is not running.

35.7.3. The customer shall hold harmless the Company from any loss due to damage or loss to customer's equipment, personnel or property arising from or in connection with interconnection with Company's system. The customer shall indemnify and keep indemnified the Company from and against all loss, damage and expense which the Company may sustain by reason of or in connection with the interconnection.

35.8. PAYMENT

The monthly payment or charge to the customer under this Rider will be handled separately from billing for any customer requirements under the standard rate schedule. If payment to the customer for capacity and/or energy deliveries to the Company during the month do not exceed the charges specified herein, payment shall be made in accordance with Rate Schedule No. 29, Charges Related to Customer Activity CAC), § 29.19.1.



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Docket No.: 18-073-TF

Order No.: Effective Date: 2/1/19

Attachment A to Rate Schedule No. 35 Page 1 of 2: Schedule Sheet 4 of 5

ENTERGY ARKANSAS, LLC RIDER LCR - ATTACHMENT A

- ARKANSAS -

DEFINITIONS:

Applicable Load Zone: for BTM QFs > 20 MWs, the Load Zone created to represent the QF in the MISO settlement system; otherwise, the Load Zone created to represent the rest of EAL’s retail load.

Behind the Meter (BTM) QF – a QF that has not self-registered as a generator in the MISO Commercial Model.

Financial Schedule (or FinSched): an instrument used to transfer ownership of energy within the MISO settlement system.

Hybrid QF: a QFs that register their generator(s) in the MISO commercial model and become MISO Market Participants which allows them to participate (i.e., submit offers or self-schedule) in both the day-ahead and real-time MISO markets up to the generator’s maximum capacity minus the host load. Hybrid QFs are eligible for FinSched.

Load Zone: an asset in the MISO Commercial Model that is used for settlement purposes, and for which separate settlement data exists.

MONTHLY AVOIDED ENERGY COST:

The Company will use MISO settlement data to determine the Monthly Avoided Cost Energy Payment to each customer. Such monthly payment for a Customer’s generated energy delivered to the Company shall be the monthly summation of each hour’s product of the MWh delivered and the applicable hourly prices as reduced by any Other Market Charges included on the MISO settlement statement and Monthly Customer Charges assessed by the Company, also expressed as follows:1

Where:2 LMPQF,i The Real Time Locational Marginal Price for hour “i” at the

Applicable Load Zone for BTM QFs and generator bus for Hybrid QFs as expressed in dollars per megawatt-hour;

1 This formula describes the components of the avoided cost rate and is presented for clarity. The actual calculation of these amounts will be made by MISO and set forth on daily settlement statements provided by MISO along with the underlying price, quantity, and charge type information. 2 The terms used in the definitions in this formula are as defined in the MISO Tariff. 563


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Docket No.:

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Order No.: Effective Date: 2/1/19


MWhQF,i Megawatt-hours either (1) injected by the BTM QF for hour “i” of the month or (2) excess energy scheduled by an accepted asset-sourced FinSched from the Hybrid QF to the Company, consistent with the terms and conditions of the avoided cost tariff; and

OMCQF,i Other Market Charges associated with a QF non-firm energy sale that are assessed by MISO to the Company as they appear on the MISO settlement statements, if the QF is either a BTM QF registered as a separate Load Zone or a Hybrid QF.

MCC Monthly customer service charge for administrative costs incurred directly by the Company to manage QF put.

LIMITATIONS ON THE ACCEPTANCE OF FINANCIAL SCHEDULES FROM HYBRID QFS:

The Company will confirm asset-sourced financial schedules from Hybrid QFs, provided they meet the following specifications: (a) the source, sink, and delivery point are all set equal to the Hybrid QF generator node, (b) the financial schedule is used to transfer ownership of energy in the real-time market, and (c) the amount is declared by the Hybrid QF to the Company within one hour of the operating hour and the amount does not exceed the difference between the Hybrid QF’s actual injection measured by MISO and its day ahead schedule.

The Company will also confirm asset-sourced financial schedules in an amount equal to the difference between a Hybrid QF’s actual injection measured by MISO and its day ahead schedule if the financial schedules meet the requirements of (a) and (b) above, and if the Hybrid QF makes a day ahead declaration of its intent to submit financial schedules equal to the difference between the Hybrid QF’s actual injection measured by MISO and its day ahead schedule.

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Title: ANO Decommissioning Cost Rider (NDCR) PSC File Mark Only


37.0. ANO DECOMMISSIONING COST RIDER

37.1. APPLICATION

The Rider is applicable to all electric service billed under the rate schedules designated in Attachment A to the Rider, whether metered or un-metered, and subject to the jurisdiction of the Arkansas Public Service Commission (APSC).

This rider will become effective for service rendered on and after March 23, 1988 or on the date approved by the APSC, whichever is later.

37.2. CONDITIONS

37.2.1. This rider is necessary in order to collect the decommissioning costs associated with EAL's Arkansas Nuclear One nuclear generating station (ANO).

37.2.2. The Net Monthly Rates in EAL's currently effective rate schedules will be increased by the Rate Adjustment amounts set forth in Attachment A to this Rider, which shall apply during the period indicated thereon. The Rate Adjustment amounts shall be revised annually pursuant to the procedures described in § 37.2.4 and § 37.2.5 below.

37.2.3. Funding Method

A. EAL shall establish external trusts to accumulate the necessary funds to decommission ANO.

B. EAL shall place the maximum possible amount of its internally funded decommissioning reserve balance associated with each ANO unit into an external tax-qualified trust established for each ANO unit pursuant to the laws and Internal Revenue Service regulations in effect at that time. EAL shall place any remaining balance of its internally funded ANO decommissioning balance, net of the associated accumulated deferred tax balance, into an external trust that is not tax-qualified.

C. EAL shall then deposit all future revenues collected under this Rider, net of uncollectible accounts and any applicable taxes, to the tax-qualified trusts described in 37.2.3.B above up to amounts equal to the maximum allowable deduction in any year. Any remaining amount not eligible for the tax-qualified trusts shall be deposited to the external trusts that are not tax-qualified. A transfer of funds shall be made once each month on or before the tenth day of the month to include all revenue billed to customers under this Rate Schedule No. 37 during the second preceding month net of an allowance for uncollectible accounts to be determined by multiplying the uncollectible account ratio for each class as approved in EAL's most recent general rate filing by the revenue amount for each class.

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37.2.4. Annual Revision

A. EAL shall determine revised Rate Adjustment amounts annually in accordance with the provisions of § 37.2.5 below and file a revised Attachment A containing such revised Rate Adjustment amounts with the Commission on or before November 1 of each year.

B. The Commission Staff shall then have until December 15 to review each annual revision of Attachment A to insure that it complies with the requirements of § 37.2.5 below. If any errors are detected in the application of the principles contained in § 37.2.5., they shall be communicated to EAL by the Commission Staff in writing on or before December 15. EAL shall then have until December 31 to prepare and file a corrected Attachment A with the Commission.

C. The initially filed Rate Adjustment amounts or such corrected Rate Adjustments as may be determined pursuant to the terms of § 37.2.4.B above shall then become effective for service on and after the following January 1 and shall remain in effect through December 31 of the following year.

37.2.5. Revenue Requirement and Rate Determination

A. The ANO decommissioning revenue requirement for the Arkansas retail jurisdiction that is to be utilized to develop the Rate Adjustment amounts in Attachment A for each calendar year shall be determined in accordance with the ANO Decommissioning Revenue Requirement Model approved by the Commission in its Order No. 5 in Docket No. 87-166-TF.

The Rate Adjustment amounts to be set out in each revision to Attachment A shall reflect the most currently available estimates of the following input data items:

1. Trust Management Fee Rates for ANO-1 and ANO-2

2. Composite State and Federal Income Tax Rate

3. Arkansas Retail Bad Debt Rate

4. Tax Qualified Trust Earnings Rate Projections

5. Non-Tax Qualified Trust Earnings Rate Projections

6. Percentage of Collections Eligible for transfer to Tax Qualified Trust (ANO-1 andANO-2)

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7. Projections of Annual Decommissioning Expenditures for ANO-1 and ANO-2

8. Projection of Annual Consumer Price Index - Urban

9. The trust fund balances at December 31 of the year in which the update is filed.

The revised Rate Adjustments shall be based on the revenue requirements for the coming calendar year.

B. The Arkansas jurisdictional revenue requirement determined for each calendar year in accordance with § 37.2.5.A above shall be allocated to the same rate classes and in the same proportions as the Arkansas retail revenue requirement in EAL's most recent general rate filing in which a final order has been issued and which has resulted in non-appealable rates.

C. The Rate Adjustments for each rate class shall be determined by dividing the rate class revenue requirements determined in accordance with § 37.2.5.B above by the projected class billing units for the calendar year in which the revised Rate Adjustments will be in effect.

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Attachment 1 Docket No. 87-166-TF Page 1 of 3

Order No.: Effective: 12/31/20 Attachment A to Rate Schedule No. 37 Page 1 of 1 Schedule Sheet 4 of 4


ATTACHMENT A

The Net Monthly Rates set forth in EAL's schedules identified below will be increased by the following Rate Adjustment amounts during the billing months of January 2021 through December 2021:

Rate Class Rate Schedules Rate Adjustment

ANO-1 Residential RS, RT, REMT $0.00000 per kWh Small General Service SGS, GFS, MP, AP, CTV,

SMWHR, CGS, TSS $0.00000 per kWh

Large General Service LGS, LPS, GST, PST, SSR $0.00 per kW Lighting L1, L4, L1SH $0.00000 per kWh ANO-2 Residential RS, RT, REMT $0.00000 per kWh Small General Service SGS, GFS, MP, AP, CTV,

SMWHR, CGS, TSS $0.00000 per kWh

Large General Service LGS, LPS, GST, PST, SSR $0.00 per kW Lighting L1, L4, L1SH $0.00000 per kWh

14

Attachment 1Docket No. 87-166-TFPage 1 of 3

Order No.:Effective: 12/31/20

Attachment A toRate Schedule No. 37Page 1 of 1Schedule Sheet 4 of4

ATTACHMENT A

The Net Monthly Rates set forth in EAL's schedules identified below will be increased by thefollowing Rate Adjustment amounts during the billing months of January 2021 through December2021:

Rate Class

ANO-1ResidentialSmall General Service

Large General ServiceLighting



Rate Schedules

RS, RT, REMTSGS, GFS, MP, AP, CTV,

SMWHR, CGS, TSSLGS, LPS, GST, PST, SSRL1, L4, L1SH



Rate Adiustment

$0.00000 per kWh

$0.00000 per kWh$0.00 per kW$0.00000 per kWh

$0.00000 per kWh



14

Attachment 1Docket No. 87-166-TFPage 1 of 3

Order No.:Effective: 12/31/20

Attachment A toRate Schedule No. 37Page 1 of 1Schedule Sheet 4 of4

ATTACHMENT A

The Net Monthly Rates set forth in EAL's schedules identified below will be increased by thefollowing Rate Adjustment amounts during the billing months of January 2021 through December2021:

Rate Class





Rate Schedules





Rate Adiustment

$0.00000 per kWh


$0.00000 per kWh



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1st Revised Sheet No. 38.1 Schedule Sheet 1 of 7Including Attachment



Kind of Service: Electric Class of Service: All Docket No.: 17-041-UOrder No.:


Title: Energy Cost Recovery Rider (ECR) PSC File Mark Only


38.1. RECOVERY OF ENERGY COST

Energy Cost Recovery Rider ECR (“Rider ECR”) defines the procedure by which the“Energy Cost Rate” of Entergy Arkansas, LLC (“EAL” or “Company”) shall be initiallyestablished and periodically redetermined. The Energy Cost Rate shall recover theCompany's net fuel and purchased energy cost, as defined in this Rider ECR (“EnergyCost”).

38.2. ENERGY COST RATE

The Energy Cost Rate to be initially effective under this Rider ECR shall be determined inthe manner approved by the Arkansas Public Service Commission (“Commission”) inDocket No. 15-015-U, Order No. 18 and shall become effective upon the date establishedby the Commission. The Energy Cost Rate shall then be redetermined annually throughfilings to be made in accordance with the provisions of § 38.3 of this Rider ECR.

The Energy Cost Rate shall be applied to each customer’s monthly billing energy (kWh),except that the Energy Cost Rate shall not apply to a special rate contract unless suchcontract includes specific provisions related to the recovery of the Company’s EnergyCost.

Net benefits achieved pursuant to the Stuttgart Solar and Chicot Solar power purchaseagreements (“PPAs”) and any corresponding additional sum shall be determined in themanner approved by the Commission in Order No. 5 in Docket No. 15-014-U and OrderNo. 4 in Docket No. 17-041-U, respectively.

38.3. ANNUAL REDETERMINATION

On or before March 15 of each year beginning in 2014, the Company shall file aredetermined Energy Cost Rate with the Commission. The redetermined Energy CostRate shall be determined by application of the Energy Cost Rate Formula set out inAttachment A to this Rider ECR. Each such revised Energy Cost Rate shall be filed inthe proper underlying docket and shall be accompanied by a set of workpapers sufficientto fully document the calculations of the revised Energy Cost Rate.

The redetermined Energy Cost Rate shall reflect the projected Energy Cost for the 12-month period commencing on April 1 of each year (“Projected Energy Cost Period”)together with a true-up adjustment reflecting the over-recovery or under-recovery of theEnergy Cost for the 12-month period ended December 31 of the prior calendar year(“Energy Cost Period”). The Energy Cost Rate so redetermined shall be effective for billsrendered on and after the first billing cycle of April of the filing year and shall then remainin effect for twelve (12) months (“Rider Cycle”), except as otherwise provided for below.

APSC FILED Time: 11/1/2019 11:05:25 AM: Recvd 11/1/2019 11:04:49 AM: Docket 17-041-U-Doc. 90

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Original Sheet No. 38.2 Schedule Sheet 2 of 7Including Attachment



Kind of Service: Electric Class of Service: All Docket No.: 18-073-TFOrder No.: 2


Title: Energy Cost Recovery Rider (ECR) PSC File Mark Only


The annual update shall include the reporting requirements as ordered by theCommission Order No. 10 in Docket No. 06-101-U and modified by Order No. 21 inDocket No. 13-028-U.

38.4. INTERIM ADJUSTMENT

Should a cumulative over-recovery or under-recovery balance arise during any RiderCycle which exceeds ten (10) percent of the Energy Cost determined for the Energy CostPeriod included in the most recently filed rate redetermination under this Rider ECR, theneither the Arkansas Public Service Commission General Staff or the Company maypropose an interim revision to the then currently effective Energy Cost Rate.

38.5. TERM

This Rider ECR shall remain in effect subject to eighteen months advance notice oftermination by the Commission following notice and hearing.


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Docket No.: 21-028-U Order No.: 3 Effective: 9/24/21 Attachment A to Rate Schedule No. 38 Page 1 of 5:

Schedule Sheet 3 of 7


ENERGY COST RATE FORMULA

ECR = ENERGY COST RATE

ECR = (TUA + (PEC*EAF)+AS) / PES

WHERE,

TUA = TRUE-UP ADJUSTMENT FOR THE ENERGY COST PERIOD INCLUDING CARRYING CHARGES (1)(3)

TUA = =

12

1

j

(EC* EAF–RRj) + (((BBj + EBj)/2) * (CCR/ 12))

WHERE,

ECj = ENERGY COST FOR MONTH j OF THE ENERGY COST PERIOD

ECj = FEj + PEj + RSCj + SEPOj + TEPj

WHERE,

FEj = FUEL EXPENSE CHARGED TO ACCOUNTS 501, 518, AND 547 IN MONTH j OF THE ENERGY COST PERIOD.

PEj = PURCHASED ENERGY EXPENSE CHARGED TO ACCOUNT 555 (6) (7) OR CREDITED TO ACCOUNT 447 IN MONTH j OF THE ENERGY COST PERIOD (8), BUT EXCLUDING THE RETAINED SHARE PORTION OF GRAND GULF FUEL (9) CHARGES.

RSCj = GRAND GULF RETAINED SHARE ENERGY CHARGE IN MONTH j OF THE ENERGY COST PERIOD (2)

SEPOj = NET COSTS AND CREDITS BILLED THROUGH THE SOLAR ENERGY PURCHASE OPTION

TEPj = NET GAIN OR LOSS FROM EAL’S INTEREST IN SOLAR ASSET TAX EQUITY PARTNERSHIP

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Docket No.: 18-073-TF Order No.: 2 Effective: 2/1/19 Attachment A to Rate Schedule No. 38 Page 2 of 5:



ENERGY COST RATE FORMULA (CONT'D)

RRj = REVENUE UNDER RIDER ECR FOR MONTH j OF THE ENERGY

COST PERIOD EXCLUDING ANY REVENUES ASSOCIATED WITH THE ADDITIONAL SUM AS APPROVED BY THE COMMISSION PURSUANT TO ACT 1088 OF 2015 PLUS AN IMPUTED LEVEL OF REVENUES FOR SALES UNDER SPECIAL RATE CONTRACTS WHERE THE ENERGY COST RATE IS NOT SEPARATELY BILLED

BBj = BEGINNING CUMULATIVE OVER(UNDER)-RECOVERY BALANCE FOR MONTH j (Excluding carrying charges)

EBj = ENDING CUMULATIVE OVER(UNDER)-RECOVERY BALANCE FOR MONTH j (Excluding carrying charges)

CCR = CARRYING CHARGE RATE (3)

PEC = PROJECTED ENERGY COST FOR THE PROJECTED ENERGY COST PERIOD (4)

PEC = NRFAEC12

1+

=jj (5)

WHERE,

ECj = ENERGY COST FOR MONTH j OF THE ENERGY COST PERIOD (1)

NRFA = NUCLEAR REFUELING OUTAGE ADJUSTMENT

NRFA = GACR * (RHD1 * CAP1 + RHD2 * CAP2 + RHDGG * CAPGG)

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Docket No.: 18-073-TF Order No.: 2 Effective: 2/1/19 Attachment A to Rate Schedule No. 38 Page 3 of 5:




WHERE,

GACR = ANNUAL AVERAGE AVOIDED ENERGY COST RATE ($/kWh) AT GENERATION LEVEL FOR THE ENERGY COST PERIOD AS SET OUT IN THE MOST RECENT FILING WITH THE COMMISSION PURSUANT TO SMALL COGENERATION RIDER SCR OR ANY SUPERSEDING RATE SCHEDULE

RHD1 = INCREASE (+) OR DECREASE (-) IN REFUELING OUTAGE HOURS FOR ANO UNIT 1 BETWEEN THE ENERGY COST PERIOD AND THE PROJECTED ENERGY COST PERIOD

CAP1 = NET CAPABILITY (kW) OF ANO UNIT 1 AT THE END OF THE ENERGY COST PERIOD THAT IS AVAILABLE TO THE COMPANY’S RETAIL CUSTOMERS

RHD2 = INCREASE (+) OR DECREASE (-) IN REFUELING OUTAGE HOURS FOR ANO UNIT 2 BETWEEN THE ENERGY COST PERIOD AND THE PROJECTED ENERGY COST PERIOD

CAP2 = NET CAPABILITY (kW) OF ANO UNIT 2 AT THE END OF THE ENERGY COST PERIOD THAT IS AVAILABLE TO THE COMPANY’S RETAIL CUSTOMERS

RHDGG = INCREASE (+) OR DECREASE (-) IN REFUELING OUTAGE HOURS FOR GRAND GULF BETWEEN THE ENERGY COST PERIOD AND THE PROJECTED ENERGY COST PERIOD

CAPGG = NET CAPABILITY (kW) OF EAL’S ALLOCATED SHARE OF GRAND

GULF AT THE END OF THE ENERGY COST PERIOD AS REDUCED BY THE RETAINED SHARE AND THAT IS AVAILABLE TO THE COMPANY’S RETAIL CUSTOMERS

EAF = ENERGY ALLOCATION FACTOR BASED ON PRODUCTION ENERGY FOR THE RETAIL JURISDICTION FOR THE ENERGY COST PERIOD (1)

PES = PROJECTED SALES (kWh) SUBJECT TO THIS RIDER ECR FOR THE PROJECTED ENERGY COST PERIOD

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AS = ADDITIONAL SUMS FOR STUTTGART SOLAR AND CHICOT SOLAR TO BE CALCULATED SEPARATELY AND THEN SUMMED, WITH EACH BEING BASED ON ACTUAL CUMULATIVE NET BENEFITS CALCULATED ON THE ACTUAL ANNUAL SAVINGS FORMULA APPROVED, RESPECTIVELY, IN ORDER NO. 5 IN DOCKET NO. 15-014-U FOR STUTTART SOLAR AND AS DIRECTED IN ORDER NO. 4 IN DOCKET NO. 17-0471-U FOR CHICOT SOLAR.

ACTUAL ANNUAL SAVINGS = MIDCONTINENT INDEPENDENT SYSTEM OPERATOR, INC. (MISO) NET ANNUAL SETTLEMENTS RECEIVED OR PAID BY EAL RELATED TO THE STUTTGART SOLAR AND CHICOT SOLAR PPAS PLUS REVENUES FROM THE SALE OF ENVIRONMENTAL ATTRIBUTES RELATED TO THE STUTTGART SOLAR AND CHICOT SOLAR PPAS AND LIQUIDATED DAMAGES PAID PURSUANT TO THE PPAS LESS THE SUM OF THE NET ANNUAL PAYMENTS MADE BY EAL TO STUTTGART SOLAR AND CHICOT SOLAR PURSUANT TO THE SOLAR PPAS AND THE ANNUAL AMORTIZATION OF THE UPFRONT PAYMENT OF THE STUTTGART SOLAR PPA. (10) (11)

FOR EACH RESPECTIVE PPA, IF THE ACTUAL ANNUAL SAVINGS ARE NEGATIVE, NO SHARING WOULD OCCUR, AND THE NEGATIVE NET SAVINGS WILL BE ACCRUED AND DEDUCTED FROM ANY POSITIVE SAVINGS IN FUTURE YEARS (10); FOR EACH RESPECTIVE PPA, IF THERE IS A REMAINING POSITIVE ACTUAL ANNUAL SAVINGS BALANCE AFTER DEDUCTING ANY ACCUMULATED NEGATIVE NET SAVINGS, THEN AN ADDITIONAL SUM WOULD BE CALCULATED AS 20 PERCENT TIMES ACTUAL ANNUAL SAVINGS.

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NOTE: 1) The Energy Cost Period is the calendar year immediately preceding the filing year.

2) RSCj is to be determined by multiplying the Grand Gulf Retained Share energy (kWh) supplied to the Company’s retail customers in each month by the annual average avoided energy cost rate ($/kWh) at generation level most recently filed with the Commission pursuant to Small Cogeneration Rider SCR or any superseding rate schedule.

3) Monthly carrying charges shall be calculated on the average beginning and ending over(under)-recovery balances, excluding carrying charges, using the Commission approved customer deposit simple interest rate for the period.

4) The Projected Energy Cost Period is the twelve-month period commencing on April 1 of the filing year.

5) Should there be unusual circumstances associated with any Projected Cost Period either the Company or the Staff may propose use of a Projected Energy Cost (Variable PEC) different from that defined by this formula.

6) PEj shall include energy costs associated with long-term renewable energy resources recorded in FERC Account 555 when approved by the Commission prior to inclusion in this Rider ECR.

7) PEj shall include the annual amortization of the upfront payment of the Stuttgart Solar PPA calculated on a straight-line basis over the term of the PPA.

8) PEj shall include the credits from the sale of renewable energy credits from the Stuttgart Solar and Chicot Solar PPAs and credits related to the damages under the terms of the Stuttgart Solar and Chicot Solar PPAs.

9) PEj shall exclude FERC-Ordered System Agreement payments/receipts.

10) The Carrying Charge Rate shall be the authorized rate of return on rate base most recently approved for EAL by the Commission and shall be applied to the cumulative net benefits balance.

11) As referenced in this provision, net annual payments made by EAL to Stuttgart Solar and Chicot Solar are not net of liquidated damage payments that are accounted for elsewhere in the formula.

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ARKANSAS PUBLIC SERVICE COMMISSION Original Sheet No. 39.1 Schedule Sheet 1 of 8 Including Attachment Replacing: Sheet No. Entergy Arkansas, LLC Name of Company Kind of Service: Electric Class of Service: All Docket No.: 18-073-TF Order No.: Part III. Rate Schedule No. 39 Effective: 2/1/19 Title: Municipal Franchise Adjustment Rider (MFA) PSC File Mark Only


39.0. MUNICIPAL FRANCHISE ADJUSTMENT RIDER 39.1. APPLICABLE SERVICE AREA

Applicable to all customers located within the corporate limits of a municipality that imposes a franchise tax or fee upon the Entergy Arkansas, LLC (“EAL” or the “Company”) and which are served under rate schedules subject to the jurisdiction of the Arkansas Public Service Commission (“APSC”).

39.2. BILLING

Billings under said rate schedules to customers located within the municipal limits of a municipality imposing a franchise tax or fee upon the Company will be increased by an amount sufficient to compensate Company for any charges (including, but not limited to, licenses, fees, charges, impositions or taxes of any kind other than special millage taxes or general taxes applicable to all citizens and taxpayers) levied or imposed by any municipality on or against the Company as provided in the standard Franchise Agreement between Company and said municipality or in special ordinances passed by said municipality.

Any such amounts levied or imposed by a municipality shall be billed to customers within the corporate limits of said municipality in the manner in which the tax or fee imposed on the Company is determined in accordance with Order No. 9 of the APSC under Docket No. U-3013 dated January 6, 1981.

39.3 TOWN /CITY ORDINANCE RATES AND BILLING FACTORS

The franchise rates contained in each ordinance and current billing factors for each town or city from which EAL has obtained a Municipal Franchise Agreement are shown in Attachment A to this Rider. Attachment A, as revised, will be provided to the APSC annually on or about February 15, and as otherwise necessary to reflect new or modified Municipal Franchise Agreements.


Except as modified herein, all terms and conditions of the rate schedules applicable within any municipality and the applicable riders remain unchanged and shall apply.

576

APSC FILED Time: 1/10/2019 2:55:36 PM: Recvd 1/10/2019 2:54:30 PM: Docket 18-073-TF-Doc. 6APSC FILED Time: 2/14/2020 8:56:37 AM: Recvd 2/14/2020 8:55:36 AM: Docket 11-013-TF-Doc. 18

` Docket No.: 11-013-TFOrder No.:

Effective: 3/3/21 Attachment A to

Rate Schedule 39Attachment Sheet 1 of 9 Schedule Sheet 2 of 10

Ordinance 2021 Billing Town / City Rate - % Factor - %

ALEXANDER 4.25% 3.9438%ALICIA 5.00% 5.0000%ALLPORT 4.25% 4.2904%ALMYRA 4.25% 4.4339%ALPENA 4.25% 4.6484%ALTHEIMER 4.25% 4.4301%AMITY 4.25% 4.5658%ANTHONYVILLE 4.25% 4.2500%ANTOINE 4.25% 3.9105%ARKADELPHIA 5.00% 5.0000%ARKANSAS CITY 4.25% 4.4624%ASH FLAT 5.00% 5.0000%ATKINS 5.00% 5.0000%AUBREY 4.25% 4.5074%AUGUSTA 4.25% 4.6066%BALD KNOB 4.25% 4.4203%BASSETT 4.25% 4.5745%BATESVILLE 4.25% 4.2500%BAUXITE 4.25% 4.9587%BAY 3.50% 3.5000%BEARDEN 4.25% 4.6479%BEEBE 4.25% 4.8309%BELLEFONTE 4.25% 4.1893%BELLEVILLE 4.25% 4.4076%BENTON 4.25% 4.2500%BERGMAN 4.25% 4.8801%BERRYVILLE 4.25% 1.4569%BIG FLAT 4.25% 4.9841%BIGGERS 5.00% 5.0000%BIRDSONG 4.25% 4.2500%BISCOE 4.25% 4.0100%BLACK OAK 5.00% 5.0000%BLACK ROCK 5.00% 5.0000%BLUFF CITY 4.25% 4.6789%BLYTHEVILLE 5.00% 5.0000%BONO 4.25% 4.0006%BRADFORD 4.25% 4.3828%

Attachment AMunicipal Franchise Adjustment Rider (MFA)

Table of Town / City Ordinance Rates and Current Billing Factors

APSC FILED Time: 1/26/2021 10:06:13 AM: Recvd 1/26/2021 10:05:09 AM: Docket 11-013-TF-Doc. 19







BRINKLEY 4.25% 4.7242%BRYANT 5.20% 5.2000%BUCKNER 4.25% 4.1837%BULL SHOALS 4.25% 4.2500%BURDETTE 5.00% 5.0000%CABOT 4.25% 4.7903%CADDO VALLEY 4.25% 5.0565%CALICO ROCK 4.25% 4.8498%CALION 4.25% 4.1842%CAMDEN 5.00% 5.0000%CAMMACK VILLAGE 4.25% 4.3377%CAMPBELL STATION 4.25% 3.9045%CARAWAY 5.00% 5.0000%CARLISLE 4.25% 4.4865%CARTHAGE 4.25% 4.3755%CASH 4.25% 4.1999%CAVE CITY 4.25% 4.3202%CHEROKEE VILLAGE 4.25% 4.2500%CHERRY VALLEY 4.25% 4.6254%CHIDESTER 4.25% 4.5526%CLARENDON 4.25% 4.3845%CLARKEDALE 0.00% 0.0000%COLLEGE CITY 5.00% 5.0000%COLT 4.25% 4.3526%CORINTH 4.25% 4.3825%CORNING 6.00% 6.0000%COTTER 4.25% 4.5027%COTTON PLANT 4.25% 4.2191%COY 4.25% 4.1678%CRAWFORDSVILLE 4.25% 9.8136%CROSSETT 4.25% 4.9775%CUSHMAN 4.25% 3.8963%DANVILLE 4.25% 4.8730%DARDANELLE 4.25% 4.7567%DATTO 5.00% 5.0000%DELIGHT 4.25% 5.1512%DELL 5.00% 5.0000%








DERMOTT 4.25% 4.9446%DES ARC 4.25% 4.6908%DEVALLS BLUFF 4.25% 4.7459%DEWITT 4.25% 4.7146%DIAMOND CITY 4.25% 4.0333%DIAZ 4.25% 4.2294%DOVER 4.25% 4.6168%DUMAS 4.25% 4.8359%DYESS 4.25% 4.1009%EARLE 4.25% 4.3507%EDMONSON 4.25% 3.9732%EL DORADO 4.25% 4.2500%ELAINE 4.25% 4.1069%EMERSON 4.25% 4.7568%EMMET 4.25% 4.0362%ENGLAND 4.25% 4.2500%ENOLA 4.25% 4.7569%ETOWAH 4.25% 4.2500%EUDORA 4.25% 4.5935%EVERTON 4.25% 3.6557%FARGO 4.25% 4.2500%FELSENTHAL 4.25% 3.9082%FIFTY SIX 4.25% 4.4621%FISHER 4.25% 4.0125%FLIPPIN 4.25% 5.3075%FORDYCE 4.25% 4.2500%FORREST CITY 4.25% 4.8495%FOUNTAIN HILL 4.25% 4.8065%FOUNTAIN LAKE 0.00% 0.0000%FRIENDSHIP 4.25% 4.5157%GARLAND 4.25% 4.4436%GARNER 4.25% 4.0911%GASSVILLE 4.25% 0.7597%GEORGETOWN 4.25% 4.2500%GILBERT 4.25% 3.9790%GILLETT 4.25% 4.2198%GILMORE 4.25% 4.1660%








GLENWOOD 4.25% 4.6499%GOSNELL 5.00% 5.0000%GOULD 4.25% 4.3509%GRADY 4.25% 4.1073%GREEN FOREST 4.25% 4.5630%GREENBRIER 4.25% 4.5023%GREENWAY 5.00% 5.0000%GRIFFITHVILLE 4.25% 4.0380%GRUBBS 4.25% 4.0353%GUION 4.25% 7.2619%GURDON 5.00% 5.4057%HAMBURG 4.25% 4.8526%HARDY 5.00% 5.0000%HARRISBURG 4.25% 4.6845%HARRISON 4.25% 4.2500%HASKELL 4.25% 4.5970%HAVANA 4.25% 4.7696%HAZEN 4.25% 4.5565%HEBER SPRINGS 4.25% 4.7185%HECTOR 4.25% 4.8974%HELENAWESTHELENA 5.00% 5.0000%HERMITAGE 4.25% 4.8329%HICKORY RIDGE 4.25% 4.5509%HIGGINSON 4.25% 4.0805%HIGHLAND 4.25% 4.2500%HOLLY GROVE 4.25% 4.3193%HORSESHOE LAKE 4.25% 4.2500%HOT SPRINGS 4.25% 5.1347%HOXIE 5.00% 5.0000%HUGHES 4.25% 4.3284%HUMNOKE 4.25% 4.3542%HUMPHREY 4.25% 4.6457%HUNTER 4.25% 4.4188%HUTTIG 4.25% 4.1911%IMBODEN 5.00% 5.0000%JACKSONVILLE 3.00% 3.0000%JENNETTE 4.25% 4.2500%








JERICHO 4.25% 4.2500%JEROME 4.25% 4.5451%JOINER 4.25% 3.8508%JUDSONIA 4.25% 4.2116%JUNCTION CITY 4.25% 4.6942%KEISER 4.25% 3.8834%KENSETT 4.25% 4.6078%KEO 4.25% 4.1867%KINGSLAND 4.25% 4.6004%KNOBEL 5.00% 5.0000%LAGRANGE 4.25% 4.2500%LAKE CITY 5.00% 5.0000%LAKE VIEW 4.25% 4.3521%LAKE VILLAGE 4.25% 5.0035%LEACHVILLE 5.00% 5.0000%LEAD HILL 4.25% 4.5874%LEOLA 4.25% 4.5708%LEPANTO 4.25% 4.3537%LESLIE 4.25% 4.3662%LEWISVILLE 4.25% 4.4561%LEXA 4.25% 4.2500%LITTLE ROCK 5.20% 5.2000%LONDON 4.25% 4.2932%LONOKE 4.25% 4.7470%LONSDALE 4.25% 4.3886%LOUANN 4.25% 3.9321%LUXORA 5.00% 5.0000%MADISON 4.25% 4.2069%MAGNESS 4.25% 4.2342%MAGNET COVE 0.00% 0.0000%MAGNOLIA 4.25% 5.1451%MALVERN 4.25% 4.9790%MAMMOTH SPRING 5.00% 5.0000%MANILA 5.00% 5.0000%MARIANNA 4.25% 4.6748%MARIE 4.25% 4.0673%MARION 4.25% 4.2385%








MARKED TREE 4.25% 4.6206%MARMADUKE 5.00% 5.0000%MARSHALL 4.25% 4.5979%MARVELL 4.25% 5.2592%MAUMELLE 4.25% 4.2500%MAYFLOWER 4.25% 4.5163%MCCRORY 4.25% 4.4669%MCGEHEE 4.25% 4.8726%MCNEIL 4.25% 4.4658%MCRAE 4.25% 4.3917%MELBOURNE 4.25% 4.8687%MENIFEE 4.25% 4.5522%MITCHELLVILLE 4.25% 4.5478%MONETTE 5.00% 5.0000%MONTICELLO 4.25% 4.9955%MONTROSE 4.25% 4.1290%MOOREFIELD 4.25% 3.7247%MORO 4.25% 3.9144%MORRILTON 4.25% 4.9170%MOUNT IDA 4.25% 4.8616%MOUNT PLEASANT 4.25% 4.9768%MOUNT VERNON 4.25% 5.0755%MOUNTAIN HOME 4.25% 4.9269%MOUNTAIN PINE 4.25% 4.3416%MOUNTAIN VIEW 4.25% 4.9666%NEWARK 4.25% 4.5414%NEWPORT 4.25% 4.8547%NORMAN 4.25% 4.0733%NORPHLET 4.25% 4.5999%NORTH LITTLE ROCK 4.25% 4.2500%ODEN 4.25% 4.3431%OIL TROUGH 4.25% 4.5349%OKOLONA 4.25% 4.5283%OLA 4.25% 5.8840%OMAHA 4.25% 4.9543%PALESTINE 4.25% 4.6852%PANGBURN 4.25% 4.8993%








PARKDALE 4.25% 4.3638%PARKIN 4.25% 4.3031%PATTERSON 4.25% 4.0888%PEACH ORCHARD 5.00% 5.0000%PERLA 4.25% 4.0862%PINE BLUFF 4.25% 4.2500%PLAINVIEW 4.25% 4.5381%PLEASANT PLAINS 4.25% 5.1248%PLUMMERVILLE 4.25% 4.4975%POCAHONTAS 5.00% 5.0000%PORTIA 5.00% 5.0000%PORTLAND 4.25% 4.5427%POTTSVILLE 4.25% 4.3912%POWHATAN 5.00% 5.0000%POYEN 4.25% 4.9363%PRATTSVILLE 4.25% 4.5302%PYATT 4.25% 4.0575%RAVENDEN 5.00% 5.0000%READER 0.00% 0.0000%RECTOR 5.00% 5.0000%REDFIELD 4.25% 4.2500%REED 4.25% 3.9732%REYNO 5.00% 5.0000%RISON 4.25% 4.7917%ROCKPORT 4.25% 6.1207%ROE 4.25% 4.4756%RONDO 4.25% 3.9946%ROSSTON 4.25% 5.0145%RUSSELL 4.25% 3.7671%RUSSELLVILLE 4.50% 5.1685%SEARCY 4.25% 4.7977%SHANNON HILLS 5.20% 5.2000%SHERIDAN 4.25% 5.2812%SHERRILL 4.25% 4.4258%SHERWOOD 4.25% 4.4414%SIDNEY 4.25% 4.1511%SMACKOVER 4.25% 4.4611%








SOUTH LEAD HILL 4.25% 4.9053%SPARKMAN 4.25% 4.2194%ST. CHARLES 4.25% 3.8877%ST. FRANCIS 5.00% 5.0000%STAMPS 4.25% 4.6407%STEPHENS 4.25% 4.2196%STRONG 4.25% 4.6608%STUTTGART 6.25% 7.2632%SUCCESS 5.00% 5.0000%SULPHUR ROCK 4.25% 4.2341%SUMMIT 4.25% 4.3716%SUNSET 4.25% 3.8024%SWIFTON 4.25% 4.2538%TAYLOR 4.25% 4.3809%THORNTON 4.25% 4.5686%TILLAR 4.25% 4.6046%TRASKWOOD 4.25% 3.9863%TRUMANN 4.25% 4.4561%TUCKERMAN 4.25% 4.3316%TUPELO 4.25% 4.0320%TURRELL 4.25% 4.0178%TWIN GROVES 4.25% 4.2500%TYRONZA 4.25% 4.2656%ULM 4.25% 4.0116%VALLEY SPRINGS 4.25% 4.8121%VICTORIA 4.25% 4.6592%VILONIA 4.25% 4.5400%WABBASEKA 4.25% 4.2508%WALDENBURG 4.25% 5.5621%WALDO 4.25% 4.2697%WALNUT RIDGE 5.00% 5.0000%WARREN 5.00% 5.0000%WEINER 4.25% 4.3899%WEST POINT 4.25% 4.6029%WESTERN GROVE 4.25% 4.7107%WHEATLEY 4.25% 4.8190%WHELEN SPRINGS 4.25% 4.4564%




Rate Schedule 39Attachment Sheet 9 of 9





WHITE HALL 4.25% 4.6333%WIDENER 4.25% 3.9639%WILLIFORD 5.00% 5.0000%WILLISVILLE 4.25% 4.3435%WILMAR 4.25% 4.1910%WILMOT 4.25% 4.3613%WILSON 6.00% 6.0000%WINCHESTER 4.25% 3.9852%WOOSTER 4.25% 4.5587%WRIGHTSVILLE 4.25% 4.2913%WYNNE 4.25% 4.6505%YELLVILLE 4.25% 4.5830%ZINC 4.25% 3.8777%



Original Sheet No. 40.1 Schedule Sheet 1 of 7 Including Attachments





Title: Energy Efficiency Cost Rate Rider (EECR) PSC File Mark Only


40.0 ENERGY EFFICIENCY COST RATE RIDER

40.1. PURPOSE

The purpose of the Energy Efficiency Cost Rate Rider (“Rider EECR”) Tariff is to establish the EECR Rate(s) by which Entergy Arkansas, LLC (the “Company”) will recover its energy efficiency program costs approved by the Commission in Docket No. 07-085-TF; including, but not limited to: (1) incremental energy efficiency program costs (“Incremental Program Costs”); (2) lost contributions to fixed costs (“LCFC”) as described and approved by the Commission in Order No. 14 issued in Docket No. 08-137-U; (3) utility incentive as described and approved by the Commission in Order No. 15 issued in Docket No. 08-137-U; and (4) a “true-up” adjustment (collectively, the “Recoverable Costs”). Recovery of Incremental Program Costs is limited to the incremental costs which represent the direct program costs that are not already included in the then current rates of the Company. The Rider EECR Rate(s) will be calculated to recover the Company’s Recoverable Costs over the period in which the Rider EECR Rate(s) will be in effect.

40.2. ANNUAL REDETERMINATION

On or before May 1 of each year, re-determined Rider EECR Rate(s) shall be filed by the Company with the Commission in accordance with the provisions of Section 7 of the Commission’s Rules for Conservation and Energy Efficiency Programs. The re-determined Rider EECR Rate(s) shall be determined by application of the EECR Rate Formula set out in Attachment A, B, and C to this Rider EECR Tariff. Each such revised Rider EECR Rate shall be filed in Docket No. 07-085-TF and shall be accompanied by supporting testimony and a set of work papers sufficient to fully document the calculations of the revised Rider EECR Rate(s).

The re-determined Rider EECR Rate(s) shall reflect projected Recoverable Cost for the next calendar year (the “Recoverable Year”); including, but not limited to: (1) the approved Incremental Program Costs for the Recoverable Year; (2) the projected LCFC for the Recoverable Year, which shall be inclusive of LCFC for prior reporting years that are not already included within the Company’s most recently established base rates; (3) the incentive earned in the prior calendar year (the “Reporting Year”), if any; and (4) a true-up adjustment reflecting the over-recovery or under-recovery of the EECR Recoverable Costs for the Reporting Year. The true-up adjustment will be calculated to include the effect of carrying costs using the Company’s most recently approved rate of return on rate base. The Rider EECR Rate(s) so re-determined shall be effective on and after the first billing cycle of January of the Recoverable Year and shall then remain in effect for twelve (12) months (“EECR Cycle”), except as otherwise provided for below.

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Title: Energy Efficiency Cost Recovery Rider (EECR) PSC File Mark Only



Should a cumulative over-recovery or under-recovery balance arise during any EECR Cycle which exceeds ten (10) percent of the EECR Recoverable Costs determined for the EECR Cycle included in the most recently filed rate re-determination under this EECR Tariff, then either the Commission General Staff or the Company may propose an interim revision to the then currently effective Rider EECR Rate(s).

40.4 TRACKING AND MONITORING PROGRAM COSTS AND BENEFITS

The Company shall develop and implement appropriate accounting procedures, subject to the review of the Commission General Staff, which provide for separate tracking, accounting, and reporting of all program costs incurred by the Company. The procedures shall enable energy efficiency program costs to be readily identified and clearly separated from all other costs. The Company shall secure and retain all documents necessary to verify the validity of the program costs for which it is seeking recovery. Such documents shall include, but shall not be limited to, vouchers, journal entries, and the date the participant’s project was completed.

The Company shall develop and implement appropriate accounting procedures, subject to the review of the Commission General Staff, which provide for separate tracking, accounting, and reporting of revenues collected through the Rider EECR Tariff. The procedures shall enable the Rider EECR revenues to be readily identified and clearly separated from all other revenues. The Company shall secure and retain all documents necessary to verify the accuracy of the Rider EECR revenues. Such documents shall include, but not be limited to, billing determinants, journal entries, and summary revenue reports.

For the purpose of assessing the benefits and effectiveness of the programs, the Company shall develop and implement appropriate procedures, subject to the review of the Commission General Staff, which provide for separate tracking of the benefits and the effectiveness of the programs. The data that shall be tracked shall include, but shall not be limited to, information that will enable the Commission to assess the effectiveness of the programs. The Company shall secure and retain all documents necessary to verify its assessments.

40.5. TRACKING AND MONITORING LCFC AND INCENTIVE

The Company shall track and monitor LCFC and Incentive in accordance with Order Nos. 14 and 15, respectively, issued in Docket No. 08-137-U and in future Orders addressing LCFC and Incentive.

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Title: Energy Efficiency Cost Recovery Rider (EECR) PSC File Mark Only


40.6. TERM

This Rider EECR Tariff shall remain in effect until modified or terminated in accordance with the provisions of the Rider EECR Tariff or applicable regulations or laws.

If this Rider EECR Tariff is terminated by a future order of the Commission, the Rider EECR Rate(s) then in effect shall continue to be applied until the Commission approves an alternative mechanism by which the Company can recover its energy efficiency costs inclusive of approved program-related capital costs and the return of and on the investment. At that time, any cumulative over-recovery or under-recovery resulting from application of the just terminated Rider EECR Rate(s) shall be applied to customer billings over the twelve (12) month billing period beginning on the first billing cycle of the second month following the termination of the Rider EECR Tariff in a manner prescribed by the Commission.

40.7 APPLICABLE RATE SCHEDULES

Residential: RS, RT, REMT

Small General Service: SGS, GFS, TSS, MP, AP, CGS, CTV, SMWHR

Large General Service: LGS, LPS, GST, PST, SSR

Lighting: L1, L1SH, L4

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Order No.: Effective: 12/31/20


ATTACHMENT A

ENERGY EFFICIENCY COST RECOVERY TARIFF (RIDER EECR)

Line Recoverable Costs

Program Costs Set forth in workpapers

Projected Energy Efficiency Program Costs (PEEC) $70,945,663 1

2 Projected Lost Contribution to Fixed Costs (LCFC) $-

3 EE Program Incentives (EEPI) $5,121,257

4 Prior Period Over/Under Amount (TUA)* ($15,637,578)

5 Recoverable Costs (PCRC)** (1+2 + 3 + 4) $60,429,341

6 Billing Units (PES)*** See Attachment C

7 Rider EECR Rate (5/6) See Attachment C

* The prior period true-up adjustment (TUA) includes carrying costs asapproved by the Commission.

** Projected Costs by Rate Class or “PCRC” includes the total of (1) the projected EECR Incremental Program Costs for the Recoverable Year (PEEC); (2) the projected LCFC for the Recoverable Year (LCFC); (3) the incentive earned during the Reporting Year (EEPI) ; and (4) the prior period true-up adjustment (TUA). This total is allocated to the rate classes using PDAF (see Note 4 on Page 2 of Attachment A).

*** Projected Energy Sales by kWh or “PES” includes the projected sales by rate class (see Note 6 below).

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Order No.: 153 Effective: 1/2/20



ENERGY EFFICIENCY COST RECOVERY TARIFF (CONT'D)

NOTES:

1) The Company’s work papers shall provide the rationale for the particularbilling units selected and for the assignment of the Recoverable Costs to therate classes.

2) The Projected Energy Efficiency Cost Period is the twelve-month periodcommencing on January 1 of the Recoverable Year.

3) The Energy Efficiency Cost Period is the calendar year immediatelypreceding the Recoverable Year.

4) The Production Demand Allocation Factor (“PDAF”) represents each rateclass allocation relative to the retail jurisdiction total and shall be the mostrecently approved for EAL by the Commission in a non-appealable final order,adjusted to remove the customer accounts that are exempt from the RiderEECR charge for the Recoverable Year based on Certificates of Exemptioncurrently approved by the Commission pursuant to the Self-Direct Option.

5) The Carrying Charge Rate shall be the authorized rate of return on rate basemost recently approved for EAL by the Commission in a non-appealable finalorder.

6) The Projected Energy Sales by kWh billed for each rate class (PESi) for theProjected Energy Efficiency Cost Period, adjusted to remove the customeraccounts that are exempt from the Rider EECR charge for the RecoverableYear based on the Certificates of Exemption currently approved by theCommission pursuant to the Self-Direct Option.

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ATTACHMENT B

RIDER EECR RATES

The Net Monthly Rates set forth in EAL’s schedules identified below will be adjusted by the following Rate Adjustment amounts:

Rate Class Rate Schedules Rate Adjustment

Residential RS, RT, REMT $0.00357 per kWh

Small General SGS, GFS, TSS, $0.00372 per kWh Service MP, AP, CGS

CTV, SMWHR

Large General LGS, LPS, GST $0.00319 per kWh Service PST, SSR

Lighting L1, L1SH, L4 $0.00198 per kWh

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Attachment B to Rate Schedule No. 40 Page 3 of 1: Schedule Sheet 6 of 7


ATTACHMENT C

Rider EECR Rate Calculation

Rate Class PCRCi1 PESi2 Rate Adjustments3

Residential $27,280,645 7,634,025,353 $0.00357 per kWh

Small General Service $16,262,382 4,369,568,257 $0.00372 per kWh

Large General Service $16,328,914 5,116,947,942 $0.00319 per kWh

Lighting $557,400 281,462,304 $0.00198 per kWh

Total $60,429,341 17,402,003,856

Notes:

(1) Projected Energy Efficiency Cost by Rate Class (PCRCi).

(2) Projected Energy Sales by kWh billed for each rate class (PESi) for the Projected Energy Efficiency Cost Period, adjusted to remove the customer accounts that are exempt from the Rider EECR charge for the Recoverable Year based on the Certificates of Exemption currently approved by the Commission pursuant to the Self-Direct Option.

(3) The Rider EECR Rate is PCRCi / PESi.

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Title: Optional Interruptible Service Rider (OISR) PSC File Mark Only


41.0. OPTIONAL INTERRUPTIBLE SERVICE RIDER

41.1. AVAILABILITY

Available upon installation of the appropriate metering and communications equipment to any customer receiving service under the Small General Service (“SGS”), Large General Service (“LGS”), Large General Service Time-of-Use (“GST”), Large Power Service (“LPS”) or Large Power Service Time-of-Use (“PST”) Rate Schedules and billed on a calendar month basis that is willing to contract for and use interruptible power and energy from Entergy Arkansas, LLC (“EAL” or the “Company”). Interruptible Power shall be no less than 100 kW and no more than 100 MW unless the Company petitions the Arkansas Public Service Commission for an exception. Upon the stated notice given by the Company, any customer electing this rider shall curtail or interrupt its interruptible service.

41.2 CUSTOMER INFORMATION REQUIREMENT

The Company may register the load of customers who are electing to take service under this rider as Load Modifying Resources (LMRs) in the Midcontinent Independent System Operator (MISO). The Company will notify Customers whose load will be enrolled as an LMR each year and provide Customers with applicable LMR requirements. In order for Company to register the load of electing customer as an LMR, a customer electing this rider shall use its best efforts to provide to Company all information reasonably requested by the Company necessary to satisfy the registration requirements, including providing information that the Customer has the ability to reduce it’s load to it’s Firm Contract Demand. If at any time the LMR requirements become incompatible with the currently effective rate schedule such that the Company’s interruptible customers’ operations cannot meet the minimum requirements for LMRs, the Company may propose an additional tariff for the purpose of enrolling eligible load as an LMR in MISO.

41.3. DEFINITIONS

41.3.1. FIRM CONTRACT DEMAND

Firm Contract Demand is the demand (kW) that the Customer intends to exclude from interruptions. The Firm Contract Demand shall be specified in the customer’s Agreement for Interruptible Service. Customers may change their Firm Contract Demand once each calendar year upon giving 60 days written notice to the Company.

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41.3.2. NONFIRM ENERGY

For SGS Customers, the monthly Nonfirm Energy shall be determined by comparing the monthly billing demand, including any modifications pursuant to § 41.6.4, to the recorded interval data on an interval by interval basis for the current month. The billing demand will be subtracted from the recorded demand by interval and summed for the billing period to determine Nonfirm Energy. Nonfirm energy shall not be less than zero (0) in any interval.

41.3.3. NONFIRM DEMAND

41.3.3.1. For GST and PST Customers, the monthly Nonfirm Demand shall be the difference between the monthly on-peak billing demand, including any modifications pursuant to § 41.6.3, and the maximum demand registered for the current month, but not less than zero (0).

41.3.3.2. For LGS and LPS Customers, the monthly Nonfirm Demand shall be the difference between the monthly billing demand, including any modifications pursuant to § 41.6.4, and the maximum demand registered for the current month, but not less than zero (0).

41.3.4. RESTRICTED HOURS

41.3.4.1. EAL Restricted Hours are those hours for which the customer has been properly notified of an EAL-called interruption in accordance with this rate schedule to take only its Firm Contract Demand.

41.3.4.2. LMR Restricted Hours are those hours for which the customer has been properly notified of a LMR interruption in accordance with this rate schedule to take only its Firm Contract Demand.

41.3.5. PEAK LOAD CONDITIONS

Peak Load Conditions are defined as those conditions on any day that could result in the Company establishing a monthly peak.

41.3.6. CAPACITY SHORTAGE CONDITIONS

Capacity Shortage Conditions are defined as those conditions on any day in which the Company has insufficient generating resources, including firm purchases, capable of supplying its load requirements within EAL’s service area.

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41.3.7. SUMMER MONTHS

The Summer Months are June, July, August, and September.

41.3.8. OTHER MONTHS

Other months are January, February, March, April, May, October, November, and December.

41.3.9. ON-PEAK HOURS

Summer Months Other Months 1:00 p.m. – 8:00 p.m. 7:00 a.m. – 6:00 p.m. Monday – Friday Monday – Friday

41.4. NOTIFICATION PROVISIONS

41.4.1. EAL-CALLED INTERRUPTIONS

The Company will notify the Customer and Customer’s designated representative(s) via e-mail and any other mutually acceptable method by 4:30 p.m. that on the following day the Company may call for interruption (“Day-Ahead Notice”). The Day-Ahead Notice will provide an estimated starting time. Actual interruption should occur within four hours of that estimated starting time. The Day-Ahead Notice shall also be counted towards any interruption limits found in § 41.5.1. For such maximum limits on hours, if no actual interruption is called for on the day following the Day-Ahead Notice, hours of interruption shall be imputed as an amount equal to the amount in the “Hours Per Interruption” column for that month in § 41.5.1. On the day following the Day-Ahead Notice, if the Company is expecting a Peak Load Condition, is experiencing a Capacity Shortage Condition, or is experiencing an emergency condition, the Company may call for an interruption of the customer’s demand in excess of the Firm Contract Demand during the On-Peak Hours by providing thirty minutes advance notice via a mutually acceptable method. The thirty-minute advance notice shall specify the starting time of the interruption period.

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41.4.2. LMR INTERUPTIONS

LMR Interruptions are defined as those conditions when MISO declares an Emergency event (e.g., NERC EEA2 or EEA3 events) such that the Company is required to curtail LMR registered load. The Company will monitor its load in MISO and use best efforts to notify Customers whose load is enrolled as an LMR and Customer’s designated representative(s) via e-mail and any other mutually acceptable method by no later than 4:30 p.m. on the day before any anticipated or scheduled LMR interruption provided that the Company receives sufficient information from MISO. The minimum notification time for LMR interruptions will not be less than 11 hours prior to the hour in which interruption must begin for customers that agree to receive notification via email and not less than 10 hours prior to the hour in which interruption must begin for all other customers. For maximum limits on hours, notices of scheduled LMR interruption shall be imputed as an amount equal to the amount in the “Hours Per Interruption” column for that month in § 41.5.1.

41.5. MAXIMUM INTERRUPTIONS

41.5.1. The maximum hours per interruption are as follows:

Season Days Per Month

Interruptions Per Day

Hours Per Interruption

Hours Per Month

Summer Months 10 1 4 35 Other Months 10 2 3 55

41.5.2 The Company shall not discriminate among customers taking service under this Rider and shall use its best reasonable efforts to interrupt customers taking service under this Rider on an equal basis.

41.5.3. Curtailments imposed in accordance with Policy Schedule No. 10 and service interruptions due to damage or failure of transmission or distribution equipment shall not be considered interruption periods for the purpose of this Rider.

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41.6. BILLING PROVISIONS

41.6.1. Monthly Customer Charge:

Billing Item Rate Monthly Customer Charge additional to Customer Charge under the applicable standard rate schedule: $224.68

41.6.2. Monthly minimum demand charge:

Billing Item Rate Monthly Minimum Demand Charge per kW:

Applied to the lesser of (a) the highest total demand established after the effective date of the Agreement for Interruptible Service or (b) the Firm Contract Demand: $ 4.83

41.6.3. Except as provided in § 41.7.1 for GST and PST Customers, the monthly on-peak billing demand will be the demand as registered for the current month during the On-Peak Hours, but no more than the Firm Contract Demand, and the off-peak billing demand will be the maximum demand as registered during the current month.

41.6.4. Except as provided in § 41.7.2 for SGS, LGS and LPS Customers, the monthly billing demand will be the maximum demand as registered for the current month, but no more than the Firm Contract Demand.

41.6.5. Any other provisions of the Company’s tariffs to the contrary notwithstanding, the demand or energy rates under Rate Schedules No. 37 (NDCR), No. 42 (GGR), and No. 47 (CCR) for Nonfirm demand or energy of customers taking service under this Rate Schedule shall be 57.2% of the otherwise applicable rate.

41.7. EAL-CALLED RESTRICTION PROVISIONS

41.7.1. If, for any reason, a GST or PST Customer does not reduce demand during the EAL Restricted Hours in accordance with this rate schedule the monthly on-peak billing demand for the first such occurrence during that month will be the Firm Contract Demand plus 1.5 times the amount by which the highest demand established during the EAL Restricted Hours in the current month exceeded the Firm Contract Demand. For each subsequent failure, the 1.5 multiplier will be increased by 0.5 but the resultant multiplier will not exceed a value of 5.0 in any month.

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41.7.2. If, for any reason, a SGS, LGS or LPS Customer does not reduce demand during the EAL Restricted Hours in accordance with this rate schedule the monthly billing demand for the first such occurrence during that month will be the Firm Contract Demand plus 1.5 times the amount by which the highest demand established during the EAL Restricted Hours in the current month exceeded the Firm Contract Demand. For each subsequent failure, the 1.5 multiplier will be increased by 0.5 but the resultant multiplier will not exceed a value of 5.0 in any month.

41.8. LMR-CALLED RESTRICTION PROVISIONS

41.8.1 If the Company incurs costs from MISO as a direct result of Company not meeting its LMR commitment at no fault of its own, and if all Customers whose load is enrolled in LMR have been provided proper notice by the Company of the LMR Interruption and Customer has failed to reduce load to Customer’s Firm Contract Demand as required herein, Customer shall reimburse Company for such costs as a result of Company’s failure to meet the LMR commitment, provided, however, Customer shall not be responsible for reimbursement of Company in an amount in excess of the amount of replacement energy costs incurred by the Company from MISO as a direct result of the Company’s failure to meet its LMR commitment. These costs are defined in Module E-1 of the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff as the product of the amount of specified demand reduction not achieved by Customer and the real-time energy price for EAL during the LMR Interruption, plus any applicable Revenue Sufficiency Guarantee charges. The Company shall allocate and assess such costs on a pro rata basis to those Customers who were properly notified and were above their Firm Contract Demand during the applicable interruption period.

In the event the Customer is not available for demand reduction when called upon by Company because of (i) maintenance, (ii) Force Majeure, (iii) other circumstances outside the control of the Customer, or other circumstances asserted by the Customer, which should prevent the Company from assessing Customer with any portion of the costs incurred by the Company from MISO for failing to meet its LMR commitment, the Customer will endeavor to make such information known to the Company within 5 business days following Customer’s receipt of Notice from Company of such failed interruption. Customer agrees to cooperate with any resulting investigation.


The Agreement for Interruptible Service shall be for a minimum period of one year and a maximum of five years at the customer’s option, and shall be automatically renewed for successive terms equal in length to the initial term until terminated by advance written notice from customer no less than three months prior to any anniversary date. Any provision of the Company’s tariffs to the contrary notwithstanding, a customer that changes Rate Schedules concurrently with initiating Optional Interruptible Service shall not be required to contract for service under the new Rate Schedule for a period exceeding one year, provided that existing electric facilities are adequate to serve the total of customer’s firm and interruptible load.

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41.10. OTHER PROVISION

Except as modified herein, all provisions of the applicable Rate Schedules will apply.

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Title: Grand Gulf Rider (GGR) PSC File Mark Only


42.0. GRAND GULF RIDER

42.1. APPLICATION

To all electric service billed under any rate schedule, whether metered or unmetered, subject to the jurisdiction of the Arkansas Public Service Commission (“APSC”).

42.2. CONDITIONS

In Opinion No. 234 in Docket ER82-616-000 and Docket ER82-483-000 the Federal Energy Regulatory Commission (“FERC”) allocated to Entergy Arkansas, LLC (“EAL” or “Company”) 36% of the power from the 90% share of Grand Gulf Unit 1 nuclear generating unit owned by System Energy Resources, Inc. (“SERI”). Entergy Arkansas became responsible for paying SERI for the Grand Gulf power commencing with delivery on July 1, 1985. All costs associated with Grand Gulf Unit 1 incurred by EAL will be retained or recovered by the Company from its Arkansas retail customers in accordance with the Stipulation and Settlement Agreement approved by the APSC in APSC Docket No. 84-249-U as amended (“Stipulation and Settlement Agreement”).

The cost of this power will be allocated in the following manner beginning January 1, 1994 and all succeeding years:

Percent of SERI's Share of Grand Gulf

Unit 1

Company Allocation Share

of Grand Gulf Unit 1 Costs

Current Recovery Share 28.08% 78.00% Retained Share 7.92% 22.00%

36.00% 100.00%

The energy related portion of Grand Gulf costs associated with the Current Recovery Share and the energy from the Retained Share which is sold to the Company’s Arkansas retail customers pursuant to the Stipulation and Settlement Agreement will be recovered under Energy Cost Recovery Rider ECR as purchased power.

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Replacing: 1st Revised Sheet No. 42.2






11

The Net Monthly Rates for Grand Gulf demand related costs for the billing period from January 2021 through December 2021 will be as follows:

Rate Class Rate Schedules Net Monthly Rate

Residential RS, RT, REMT $0.00784 per kWh Small General Service SGS, GFS, MP, AP, CTV,

SMWHR CGS, TSS $0.00797 per kWh Large General Service LGS, GST, LPS, PST, SSR $1.75 per kW Lighting L1, L4, L1SH $0.00912 per kWh

42.3. PROCEDURES FOR RECOVERY OF GRAND GULF COSTS

42.3.1. On or before November 1 of 1998 and each succeeding year thereafter, the Company will file with the APSC a revision to this Grand Gulf Rider which will reflect the demand related Grand Gulf costs which are projected to be incurred over the twelve-month period beginning on January 1 of the following year and will also file new Net Monthly Rates necessary to recover such costs to become effective on the first billing cycle of January of such year. These new Net Monthly Rates will reflect a true-up of any prior over or under recovery of such costs as determined in § 42.3.6 below. In the revision to this Grand Gulf Rider (GGR) filed with the APSC, the 36% allocation to EAL will be further allocated based on the percentages embodied in the Stipulation and Settlement Agreement as the Current Recovery Share and the Retained Share.

42.3.2. The Current Recovery Share allocated to the Company's Arkansas retail customers will be recovered on a current basis.

14



Replacing: 1St Revised Sheet No. 42.2


Kind of Service: Electric Class of Service: fl Docket No.: 20-058—TFOrder No.:



42.3.

42.3.1.

42.3.2.

The Net Monthly Rates for Grand Gulf demand related costs for the billing period fromJanuary 2021 through December 2021 will be as follows:


Residential RS, RT, REMT $0.00784 per kWhSmall General Service SGS, GFS, MP, AP, CTV,

SMWHR CGS, TSS $0.00797 per kWhLarge General Service LGS, GST, LPS, PST, SSR $1.75 per kWLighting L1, L4, L1SH $0.00912 per kWh

PROCEDURES FOR RECOVERY OF GRAND GULF COSTS

On or before November 1 of 1998 and each succeeding year thereafter, the Companywill file with the APSC a revision to this Grand Gulf Rider which will reflect the demandrelated Grand Gulf costs which are projected to be incurred over the twelve-month periodbeginning on January 1 of the following year and will also file new Net Monthly Ratesnecessary to recover such costs to become effective on the first billing cycle of Januaryof such year. These new Net Monthly Rates will reflect a true-up of any prior over orunder recovery of such costs as determined in § 42.3.6 below. In the revision to thisGrand Gulf Rider (GGR) filed with the APSC, the 36% allocation to EAL will be furtherallocated based on the percentages embodied in the Stipulation and SettlementAgreement as the Current Recovery Share and the Retained Share.

The Current Recovery Share allocated to the Company‘s Arkansas retail customers willbe recovered on a current basis.

THIS SPACE FOR PSC USE ONLY 1411





Kind of Service: Electric Class of Service: fl Docket No.: 20-058—TFOrder No.:



42.3.

42.3.1.

42.3.2.

The Net Monthly Rates for Grand Gulf demand related costs for the billing period fromJanuary 2021 through December 2021 will be as follows:


Residential RS, RT, REMT $0.00784 per kWhSmall General Service SGS, GFS, MP, AP, CTV,

SMWHR CGS, TSS $0.00797 per kWhLarge General Service LGS, GST, LPS, PST, SSR $1.75 per kWLighting L1, L4, L1SH $0.00912 per kWh

PROCEDURES FOR RECOVERY OF GRAND GULF COSTS

On or before November 1 of 1998 and each succeeding year thereafter, the Companywill file with the APSC a revision to this Grand Gulf Rider which will reflect the demandrelated Grand Gulf costs which are projected to be incurred over the twelve-month periodbeginning on January 1 of the following year and will also file new Net Monthly Ratesnecessary to recover such costs to become effective on the first billing cycle of Januaryof such year. These new Net Monthly Rates will reflect a true-up of any prior over orunder recovery of such costs as determined in § 42.3.6 below. In the revision to thisGrand Gulf Rider (GGR) filed with the APSC, the 36% allocation to EAL will be furtherallocated based on the percentages embodied in the Stipulation and SettlementAgreement as the Current Recovery Share and the Retained Share.

The Current Recovery Share allocated to the Company‘s Arkansas retail customers willbe recovered on a current basis.



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21 THIS SPACE FOR PSC USE ONLY

42.3.3. The total annual Grand Gulf costs to be recovered from the Company’s Arkansas retail customers under the Grand Gulf Rider will be adjusted to reflect the allocation of 13.87% of the Current Recovery Share, previously known as the Wholesale Baseload allocation, to EAL for sale to third parties pursuant to Docket No. 12-038-U, Order No. 7. The 86.13% Current Recovery Share remaining with EAL will be allocated to theArkansas retail jurisdiction using the production demand related allocation methodology approved or utilized in the Company’s most recent retail rate case.

42.3.4. The total annual Grand Gulf costs for the retail classes will be allocated to the associated retail rate classes on the basis of the level of revenue requirement approved in EAL’s most recent general rate filing in which a final order has been issued and which has resulted in non-appealable rates.

42.3.5. A. For those retail rate classes consisting of customers with maximum demands generally below 100 kW, the Grand Gulf demand related costs as allocated under § 42.3.4 above will be recovered through an energy rate adder determined by dividing such allocated costs by the forecasted sales for each rate class for the next twelve months.

B. For the remaining retail rate classes, the Grand Gulf demand related costs as allocated in § 42.3.4 above will be recovered through a demand rate adder determined by dividing such allocated costs by the forecasted demand billing units for each rate class for the next twelve months.

42.3.6. At the end of each twelve months, the actual recovery of Grand Gulf demand related costs under this Grand Gulf Rider will be compared to the actual cost incurred by the Company for Grand Gulf demand related costs allocable to Arkansas retail customers to determine the net over or under recovery. The net over or under recovery so determined shall be subtracted from or added to the determination of the annual Grand Gulf demand related costs to be recovered as specified in § 42.3.1 above for the following 12-month period. The actual costs as defined above will be adjusted for the Wholesale Baseload allocation as described in § 42.3.3 above. The Current Recovery Share remaining with EAL will be allocated to the Arkansas retail jurisdiction using the Production Demand Allocation Factor in effect on January 1 of the prior year.

42.3.7. Should any conflict or inconsistency arise between the terms of this Grand Gulf Rider and the terms of the Stipulation and Settlement Agreement referenced above, the terms of the Stipulation and Settlement Agreement shall control.

42.3.8. Pursuant to Order No. 6 in Docket No. 18-006-U, the 2019 rate redetermination formula will include the effect of carrying charges related to the Tax Cuts & Jobs Act Credit using the Company’s most recently approved rate of return on rate base.

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Title: Federal Litigation Consulting Fee Rider (FLCF) PSC File Mark Only


43.0 FEDERAL LITIGATION CONSULTING FEE RIDER

43.1 PURPOSE

The Federal Litigation Consulting Fee Rider (“Rider”) defines the procedure by which the Federal Litigation Consulting Fee Rate Adjustment shall be determined. The Federal Litigation Consulting Fee Rate Adjustment shall recover the fees and/or expenses paid by Entergy Arkansas, LLC (“Company”) to contract attorneys and/or consultants retained by the Arkansas Public Service Commission (“Commission”), as authorized by the General Assembly, when it is a party in litigation before a federal agency and/or the federal courts in proceedings which affect the Company. See Ark. Code Ann. § 23-4-102.

43.2 APPLICATION

The Federal Litigation Consulting Fee Rate Adjustment set forth in Attachment A shall apply to each customer’s base rate billing energy, whether metered or unmetered, except that it shall not apply to a special rate contract unless such contract includes specific provisions related to the recovery of the federal litigation and/or consulting fees. The Rate Adjustment amounts shall be revised pursuant to the procedures described in § 43.6 below.

43.3 BILL REVIEW AND PAYMENT

When involved in federal litigation and/or proceedings before a federal agency, bills for litigation and/or consulting fees and expenses shall be submitted by the contracting attorney(s) and/or consultant(s) to the Commission on a monthly basis. After review and approval by the Commission, the Commission will forward the bills for the approved fees and expenses to the Company Designee listed in § 43.4 below. The maximum amount that may be directly paid and recovered shall not exceed $3,000,000 annually.

The Company shall remit payment for federal litigation and/or consulting fees directly to the contracting party within thirty (30) days of the bill’s receipt by the Company from the Commission. A record of the payments will be maintained in an appropriate, distinguishable account.

43.4 COMPANY DESIGNEE

The following individuals are designated to receive bills for litigation and/or consulting fees for the Company:

VP - EAL Regulatory Affairs Manager, EAL Regulatory Affairs P.O. Box 551 P.O. Box 551 425 West Capitol Avenue 425 West Capitol Avenue Little Rock, AR 72203-0551 Little Rock, AR 72203-0551

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43.5 ANNUAL RATE REVISIONS

43.5.1 ANNUAL FILING REQUIREMENTS

On or before February 15 of any year following a calendar year in which federal litigation and/or consulting fees are paid, the Company may file for recovery of the federal litigation and/or consulting fees. The Federal Litigation Consulting Fee Rate Adjustment shall be calculated annually in accordance with the provisions of § 43.6 and filed for approval with the Commission.

Once a docket is established, annual revisions shall be filed in the same docket each year thereafter. Each such Federal Litigation Consulting Fee Rate Adjustment filing shall be accompanied by a set of workpapers sufficient to fully document the timely payment of the third party contract fees and expenses, the accounting treatment of such payments, and the calculation of the rate.

43.6 CALCULATION AND RECOVERY PROCEDURES

43.6.1 FEDERAL LITIGATION CONSULTING FEE RATE ADJUSTMENT CALCULATION

The Federal Litigation Consulting Fee Rate Adjustment shall include the Commission-approved contract fees and expenses paid in the preceding calendar year. The rate adjustment shall not include any interest or carrying charges. The Federal Litigation Consulting Fee Rate Adjustment shall be determined by dividing the federal litigation and/or consulting fees and expenses paid in the prior calendar year by the projected energy sales for the twelve-month period commencing on April 1 of the filing year. This rate shall also include a true-up adjustment reflecting the over-recovery or under-recovery of the federal litigation and/or consulting fees for the preceding calendar year.

The Federal Litigation Consulting Fee Rate Adjustment so determined shall be effective, after Commission approval, for bills rendered on and after the first billing cycle of April of the filing year and shall then remain in effect until the last billing cycle of March of the following year, unless a shorter recovery period is determined to be appropriate as provided by Attachment A.

Should there be unusual circumstances either the Company or the Staff may propose to modify the above calculation and/or recovery period.

43.6.2 FEDERAL LITIGATION CONSULTING FEE RECOVERY

The Federal Litigation Consulting Fee Rate Adjustment, once approved by the Commission, shall be applied to each customer’s monthly base rate billing energy (kWh). The rate shall be constant across all customer classes and applied to the currently effective rate schedules. The Federal Litigation Consulting Fee Rate Adjustment shall be set forth in Attachment A to this Rider and shall be filed with the Company’s tariffs.

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43.6.3 FEDERAL LITIGATION CONSULTING FEE RATE ADJUSTMENT TRUE-UP

At the time of annual filing, the actual recovery of federal litigation and/or consulting fees will be compared to the projected recovery for the preceding calendar year. Any net over-recovery or under-recovery of the federal litigation and/or consulting fees shall be included in setting the Federal Litigation Consulting Fee Rate Adjustment for the next recovery period.

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Docket No.: 07-138-TF Order No.: Effective Date: 4/1/21

Attachment A Rate Schedule No. 43 Page 1 of 1 Schedule Sheet 4 of 4


Attachment A Federal Litigation Consulting Fee Rate Adjustment

The Net Monthly Rate of each Base Rate Schedule shall be adjusted by the following amount for recovery of the federal litigation and/or consulting fees beginning with bills rendered for the first billing cycle of April 2021 and ending with bills rendered for the last billing cycle of March 2022. This rate adjustment shall not apply to a special rate contract unless such contract includes specific provisions related to the recovery of federal litigation and/or consulting fees:

$0.00006 per kWh

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1st Revised Sheet No. 44.1 Schedule Sheet 1 of 39 Replacing: Original Sheet No. 44.1 Including Attachments


Kind of Service: Electric Class of Service: All

Part III. Rate Schedule No. 44

Title: Formula Rate Plan Rider (FRP)

Docket No: 18-004-TF Order No.: Effective: 4/29/21

PSC File Mark Only

44.0. FORMULA RATE PLAN RIDER


The Arkansas General Assembly has delegated authority to the Arkansas Public Service Commission (APSC or the Commission) to regulate public utilities in the State of Arkansas, including Entergy Arkansas, LLC (EAL or the Company). The Arkansas General Assembly has enacted the Formula Rate Review Act, Ark. Code Ann. §§ 23-4-1201 et seq., as also clarified and amended in 2021, which authorizes use of this Formula Rate Plan Rider Tariff (Rider FRP).

44.2. PURPOSE

Rider FRP defines the procedure by which all rates and applicable riders on file with the APSC, except those excluded in Attachment A.1 or A.1 – Extension, as applicable, to this Rider FRP (Rate Schedules) may be periodically adjusted. Rider FRP shall apply to all electric service billed under the Rate Schedules, whether metered or unmetered.

44.3. DEFINITIONS

A. EFFECTIVE DATE Rates pursuant to the initial Rider FRP shall become effective with the first billing cycle of January 2017 and subsequently adjusted Rider FRP rates shall be effective with the first billing cycle of January each year.

B. FORMULA RATE REVIEW TEST PERIOD The Formula Rate Review Test Period shall be a test period based upon a Projected Year. A Projected Year shall be the twelve (12) month period ended December 31 of the calendar year immediately following the filing of an Evaluation Report.

C. HISTORICAL YEAR A Historical Year shall be the twelve (12) month period ended December 31 of the calendar year immediately preceding the filing of an Evaluation Report.

D. FILING YEAR The Filing Year shall be the twelve (12) calendar months preceding the Formula Rate Review Test Period.

EAL Compliance Exhibit MSK-2Docket No. 18-004-TF

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PSC File Mark Only

44.4. ANNUAL FILING AND REVIEW

44.4.1. ANNUAL FILING

On or before July 7 of each year, EAL shall file a report (Evaluation Report) with the Commission containing an evaluation of the Company’s earnings pursuant to Rider FRP for the Formula Rate Review Test Period and the Historical Year when applicable. Attachment A.1 or A.1 – Extension, as applicable, shall be included in each such filing and shall contain the Company’s proposed Rate Adjustment. The Evaluation Report and the Rate Adjustment shall be filed pursuant to Rider FRP.

44.4.2. REVIEW PERIOD

The Parties shall file a statement of error(s) or objection(s) and supporting Testimony with or without Exhibits at least 90 days before the date on which the Rate Adjustment becomes effective. The Company shall have fifteen (15) days to review the statement of error(s) or objection(s), to work with the Parties to resolve any differences, and to address the error(s) and objection(s) raised by the Parties by filing either corrected Attachments, as applicable, or Rebuttal Testimony with or without Exhibits.

44.4.3. HEARING AND APPROVAL OF RATE ADJUSTMENT

Following a hearing at least fifty (50) days before the date on which the Rate Adjustment shall become effective, unless waived by EAL and the Parties, the Commission shall issue a final order in which it resolves any issues in dispute and approves the Rate Adjustment at least twenty (20) days before the date on which the Rate Adjustment shall become effective. If a final order is not issued by such date, the initially filed or revised Rate Adjustment shall become effective for bills rendered on and after the first billing cycle of January, subject to refund, and shall remain in effect until changed by final order of the Commission or by operation of other provisions of Rider FRP.

If the Commission’s final ruling on any disputed issues requires changes to the Rate Adjustment, the Company shall file revised Attachments, as applicable, containing such further modified Rate Adjustment within five (5) days after receiving the Commission’s order resolving the disputed issues. The Parties shall have three (3) days to review the revised Attachments. The revised Attachments shall be implemented as ordered by the Commission.


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PSC File Mark Only

44.5. ANNUAL DETERMINATION OF RATE ADJUSTMENT

44.5.1. INDEX OF ATTACHMENTS

Description Projected

Year Historical

Year ATTACHMENT A.1 is the Formula Rate Plan Rate Adjustment (Rate Adjustment).

A.1

ATTACHMENT A.1 – EXTENSION is the Formula Rate Plan Rate Adjustment (Rate Adjustment) beginning with the 2021 Evaluation Report.

A.1 - Extension

ATTACHMENT A.2 is the Rider FRP Revenue Change and includes the calculation of the total Rider FRP Revenue to be collected in the Projected Year.

A.2

ATTACHMENT A.2 – EXTENSION is the Rider FRP Revenue Change and includes the calculation of the total Rider FRP Revenue to be collected in the Projected Year beginning with the 2021 Evaluation Report.

A.2 - Extension

ATTACHMENTS B.1 and D.1 calculate the Earned Rate of Return on Common Equity. The Earned Return Rate (ERR) is the Company’s return on common equity calculated by dividing the weighted earned common equity rate by the common equity ratio percentage.

B.1 D.1

ATTACHMENTS B.2 and D.2 calculate Rate Base. B.2 D.2 ATTACHMENTS B.3 and D.3 calculate Operating Income. B.3 D.3 ATTACHMENTS B.4 and D.4 calculate Income Tax. B.4 D.4 ATTACHMENTS B.5 and D.5 calculate the Benchmark Rate of Return on Rate Base (BRORB). The BRORB is the composite weighted, embedded cost of capital reflecting EAL’s annual costs of long-term debt, preferred stock, common equity, and other capital components as of June 30.

B.5 D.5

ATTACHMENTS B.6 and D.6 calculate the Revenue Redetermination Formula using the Rate of Return on Common Equity Bandwidth which is an Upper Bandwidth limit equal to the Target Return Rate (TRR) plus 0.5% (50 basis points) and a Lower Bandwidth limit equal to the TRR minus 0.5% (50 basis points). The TRR is the Company’s cost rate for common equity as established by the Commission in Docket No. 15-015-U. The TRR in effect during the initial five-year term of Rider FRP shall continue to be in effect for the five-year term of the extension of Rider FRP.

B.6 D.6

ATTACHMENT C lists Rider FRP adjustments. C C ATTACHMENT E defines the Rider FRP Filing Requirements and describes the supporting documents to be included with the annual Evaluation Report.

E E

ATTACHMENT F defines the Formula Rate Protocols, which include the Rider FRP general provisions and filing requirements for the annual Evaluation Report.

F F


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PSC File Mark Only

44.5.2. RIDER FRP BANDWIDTH CALCULATION

The Total Rider FRP Revenue level shall be adjusted in the Rider FRP review mechanism based on a comparison of the ERR to the TRR calculated using the following formula:

A. If the ERR is less than the TRR minus five-tenths percent (0.50%), the Total Rider FRP Revenue level shall be increased by the amount necessary to increase the ERR to the TRR.

B. If the ERR is greater than the TRR plus five-tenths percent (0.50%), the Total Rider FRP Revenue level shall be decreased by the amount necessary to decrease the ERR to the TRR.

C. There shall be no change to the Rider FRP Revenue level if the ERR is less than or equal to the TRR plus five-tenths percent (0.50%), and greater than or equal to the TRR minus five-tenths percent (0.50%).

44.5.3. NETTING OF HISTORICAL YEAR DIFFERENCES ADJUSTMENT

A. The Netting of Historical Year Differences Adjustment shall be the adjustment to net any differences between the Historical Year change in Rider FRP Revenue and the Formula Rate Review Test Period change in Rider FRP revenue for that same year. The Netting of Historical Year Differences Adjustment shall be determined in accordance with Attachment D.6. The Netting of Historical Year Differences Adjustment shall then be applied to the Formula Rate Review Test Period Rider FRP Revenue to derive the Total Rider FRP Revenue as set out in Attachment A.2 or A.2 – Extension, as applicable. Netting shall not begin until there is an actual twelve (12) months of Historical Year to report.

B. Beginning with the 2020 Evaluation Report filing and for each subsequent Evaluation Report filed throughout the five-year extension term of Rider FRP, the adjustment to net any differences between the Historical Year change in Rider FRP Revenue and the Formula Rate Review Test Period change in Rider FRP Revenue shall include the actual Historical Year change in revenue for the Historical Year, which shall be determined as follows:

1. For the purpose of including all of the elements of the change of revenue in calculatingan adjustment to net any differences, the revenue received for the Historical Year shallbe composed of:

(a) Prior Formula Rate Review Test Period changes in revenue; (b) Netting revenue from the prior Formula Rate Review Test Period; and (c) In order to isolate the change in revenue for the corresponding prior projected

year being netted, prior Projected Year revenue for the year being netted.


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PSC File Mark Only

2. The actual historical year change in revenue shall be proportioned by:

(a) Calculating the sum of: (1) the ROE Band Rate Adjustment and (2) the Netting Adjustment as reported on Attachment A.2 or Attachment A.2 – Extension, as applicable, for the year in which the Historical Year was the prior Projected Year;

(b) Calculating the percentage of the sum represented by (1) the ROE Band Rate Adjustment and (2) the Netting Adjustment; and

(c) Applying the percentages calculated in 44.5.3(B)(2)(b) above to the actual Historical Year change in revenue as determined in 44.5.3(B)(1)(b) and (c) for that same year.

44.5.4. RIDER FRP REVENUE ALLOCATION AND RATE DESIGN

During the initial five-year term, the total change in the formula rate revenue level shall be allocated to each applicable rate class based on an equal percentage of the base rate revenue used in the development of rates approved by the Commission in Docket No. 15-015-U. During the five-year extension term of Rider FRP, the total change in the formula rate revenue level shall be allocated to each applicable rate class based on an equal percentage of the base rate revenue as determined in the EAL cost of service filed with the 2020 Evaluation Report filing. Additionally, the Large General Service (LGS) Rate Class’ allocated amount shall be reduced annually during the five-year extension term by one-fifth of the amount by which the LGS Rate Class’ base rate revenues were adjusted for mitigation in Docket No. 15-015-U; this amount shall be allocated to the remaining classes based on an equal percentage of the base rate revenue as determined in the EAL cost of service that was filed with the 2020 Evaluation Report filing. The total change in the formula rate revenue level for the LGS Rate Class shall not exceed four percent (4%) of the LGS Rate Class’s total revenue for the Filing Year, less the annual reduction equal to one-fifth of the amount by which the LGS Rate Class’s base rate revenues were adjusted for mitigation in Docket No. 15-015-U. The total change in the formula rate revenue level for all other rate classes shall not exceed four percent (4%) of each rate class’s total revenue for the Filing Year.

EAL shall file as part of the annual compliance filing for the first three years of the extension term revised rate schedules for Rate Schedule No. 6, Large General Service (LGS); Rate Schedule No. 7, Large General Service Time-of-Use (GST); Rate Schedule No. 8, Large Power Service (LPS); Rate Schedule No. 9, Large Power Service Time-of-Use (PST); and Rate Schedule No. 18, Voltage Adjustment Rider (VAR) reflecting an equal annual adjustment to the demand and energy components pursuant to Ark. Code Ann. § 23-4-1208(a)(3)(E).


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PSC File Mark Only

44.6. TERM

The initial term of Rider FRP shall not exceed five (5) years from the date of the Commission’s final order in Docket No. 15-015-U. The initial term of Rider FRP will terminate on February 24, 2021 unless EAL requests to extend the term by a period of no more than five years beyond the initial term. If EAL requests an extension of Rider FRP, EAL shall make such request in accordance with the Extension of Term provisions of the Formula Rate Protocols. Pursuant to Ark. Code Ann. § 23-4-1208(a)(2)(A)(ii)(a), the Commission shall grant such an Extension of Term for five-years after the initial term of Rider FRP.

Upon the conclusion of the extension term, either by expiration or otherwise, the then-existing Total Rider FRP rates shall continue to be in effect until new base rates reflecting the then-existing Total Rider FRP Revenue are duly approved and implemented and until the Company recovers or returns the remaining Netting of Historical Year Differences Adjustments.


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Attachment A.1 Rate Schedule No. 44


Formula Rate Plan Rate Adjustment

All retail base rates and applicable riders on file with the APSC will be increased or decreased by a percentage of base revenues listed below, except those specifically excluded below:

Excluded Schedules: Charges Related to Customer Activity (CAC) Additional Facilities Charge Rider (AFCR) Additional Facilities Charge Rider – Governmental (AFCRG) Small Cogeneration Rider (SCR) Large Cogeneration Rider (LCR) ANO Decommissioning Cost Rider (NDCR) Energy Cost Recovery Rider (ECR) Municipal Franchise Tax Adjustment Rider (MFA) Grand Gulf Rider (GGR) Production Cost Allocation Rider (PCA) Energy Efficiency Cost Recovery Rider (EECR) Federal Litigation Consulting Fee Rider (FLCF) Government Mandated Expenditure Surcharge Rider (GMES) Capacity Cost Recovery Rider (CCR) MISO Rider (MISO) Internal Restructuring Credit Rider (IRCR)

Special Rate Contracts: Special Contracted Rates shall be included or excluded pursuant to the terms of the Special Rate Contract.

Rate Class

FRP Rate (%) Billing Months Jan-Apr 2021

FRP Rate (%) Billing Months May-Dec 2021

Effective Annual Rate

Residential 15.5931% 20.0158% 18.6023% Small General Service 13.5273% 17.8007% 16.6006% Large General Service 15.6522% 19.9614% 18.7082% Lighting 15.4158% 19.7092% 18.2692%


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Docket No.: 18-004-TF Order No.: Effective: 4/29/21

Attachment A.1 – Extension Rate Schedule No. 44


Formula Rate Plan Rate Adjustment

Beginning with the 2021 Evaluation Report, all retail base rates and applicable riders on file with the APSC will be increased or decreased by a percentage of base revenues listed below, except those specifically excluded below:

Excluded Schedules: Charges Related to Customer Activity (CAC) Additional Facilities Charge Rider (AFCR) Additional Facilities Charge Rider – Governmental (AFCRG) Small Cogeneration Rider (SCR) Large Cogeneration Rider (LCR) ANO Decommissioning Cost Rider (NDCR) Energy Cost Recovery Rider (ECR) Municipal Franchise Tax Adjustment Rider (MFA) Grand Gulf Rider (GGR) Production Cost Allocation Rider (PCA) Energy Efficiency Cost Recovery Rider (EECR) Federal Litigation Consulting Fee Rider (FLCF) Government Mandated Expenditure Surcharge Rider (GMES) Capacity Cost Recovery Rider (CCR) MISO Rider (MISO) Internal Restructuring Credit Rider (IRCR)

Special Rate Contracts: Special Contracted Rates shall be included or excluded pursuant to the terms of the Special Rate Contract

Rate Class FRP Rate (%)

Residential XX.XXX%Small General Service XX.XXX%Large General Service XX.XXX%Lighting XX.XXX%


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Attachment A.2 Rate Schedule No. 44


Line No. Description Total Residential Small General

ServiceLarge General

Service Lighting

A B C D E F G

1 Base Rate Revenues: Docket No. 15-015-U 1,277,230,243 587,030,889 329,049,596 337,617,728 23,532,030

2 Rate Class Allocation:(Percent of total calculated from L1) 100% 45.9612% 25.7628% 26.4336% 1.8424%

3 Rider FRP Constraint Calculation [1] x4 Total Annualized Filing Year Revenues by Rate Class 1,815,732,167 852,761,448 438,523,056 488,632,725 35,814,938 5 Rider FRP Revenue Change = ±4% per Rate Class 4.00% 4.00% 4.00% 4.00% 4.00%6 +Projected Year upper Rider FRP Revenue Constraint 72,629,287 34,110,458 17,540,922 19,545,309 1,432,598 7 -Projected Year lower Rider FRP Revenue Constraint (72,629,287) (34,110,458) (17,540,922) (19,545,309) (1,432,598)

8 Net Change in Req. Rider FRP Revenue Calc [2]

9 ROE Band Rate Adjustment (B.6 L10 * L2) 44,529,544 20,466,331 11,472,034 11,770,753 820,426

10 Netting Adjustment (D.6 L13 * L2) (4,764,126) (2,189,651) (1,227,370) (1,259,329) (87,776)

11 Net Change in Required Rider FRP Revenue 39,765,418 18,276,680 10,244,664 10,511,424 732,650

12 Incremental Rider FRP Base Rate Change (L11 ÷ (L1 + L14)) 3.0194% 3.0194% 3.0194% 3.0194% 3.0194%

13 Cumulative Rider FRP Revenue Calculation [3] x14 Maximum Inc/Dec in Rider FRP Revenue calculated on

L11 bounded by the constraint defined on L6 and L7. 39,765,418 18,276,680 10,244,664 10,511,424 732,650 15 Projected Year Rider FRP Revenue [4] 191,646,915 91,875,282 43,705,906 52,225,080 3,840,647

16 Cumulative Total Rider FRP Revenue (L14+L15) 231,412,333 110,151,962 53,950,570 62,736,504 4,573,297

17 Rider FRP Rate Development Calculation [5]18 Adjusted Projected Year Base Rate Revenue 1,277,507,581 592,142,021 324,991,018 335,341,713 25,032,829

19 Rider FRP Projected Year Rate Change (L16 ÷ L18) 18.6023% 16.6006% 18.7082% 18.2692%

[1]

[2]

[3]

[4]

[5]

The Net Change in Required Rider FRP Revenue Calculation takes the Total Projected Year Rate Change in Rider FRP Revenue (B.6 Line 10) and the Historical Year Netting adjustment (D.6 Line 13) and allocates the amount required to each rate class based on the class allocation approved by the Commission in Docket No. 15-015-U listed on Line 2. The amounts required are added together by rate class to determine each rate class' net change in required Rider FRP revenue. The netting adjustment on line 10 shall be zero (0) until there is an actual twelve (12) months of Historical Year data to report.

The Cumulative Rider FRP revenue calculation adjusts the Required Rider FRP revenue determined on Line 11 to be within the limits of the Rider FRP constraint calculation and adds the Projected Year Rider FRP Revenues to calculate Cumulative Total Rider FRP Revenue required in the Projected Year.

The Projected Year Rider FRP Revenue will equal the amount of Rider FRP revenues included in the determination of the Projected Year ROE Band Rate Adjustment (B.6 L2).

The Rider FRP Rate Development Calculation determines the percent increase/decrease that will be applied to all base rate components. The Adjusted Projected Year Base Rate Revenue is calculated using the Retail Rate Schedule Revenue (B.3 L2) excluding Projected Year Rider FRP Revenue and any revenue pursuant to excluded schedules listed on Attachment A.1. The percent increase/decrease is calculated by taking the Total Rider FRP Revenue listed on Line 16 and dividing it by the applicable Adjusted Projected Year Revenues listed in Line 18.

Entergy Arkansas, LLCFormula Rate Plan

Rider FRP Revenue ChangeFor the Projected Year 2021

NOTES:

The Rider FRP Constraint Calculation determines the limit of the Rider FRP revenue increase/decrease per rate class, which shall not exceed four percent (4%) of Total Unadjusted Annualized Filing Year (the year in which the Evaluation Report is filed) revenues including all riders.


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Attachment A.2 – Extension Rate Schedule No. 44


Line No. Description Total Residential Small General

ServiceLarge General

Service Lighting

A B C D E F G

1 Rate Schedule Revenue Requirement [1] 1,595,697,654 765,766,421 412,151,492 395,090,323 22,689,418 2 Rate Class Allocation:(Percent of total calculated from L1) 100.0000% 47.9894% 25.8289% 24.7597% 1.4219%

3 Rider FRP Constraint Calculation [2]4 Total Annualized Filing Year Revenues by Rate Class - - - - - 5 Rider FRP Revenue Change = ±4% per Rate Class 4.00% 4.00% 4.00% 4.00% 4.00%6 +Projected Year upper Rider FRP Revenue Constraint - - - - - 7 -Projected Year lower Rider FRP Revenue Constraint - - - - -

8 Large General Service ("LGS") Adjustment (3,294,966) - - (3,294,966) - 9 +PY upper Rider FRP Revenue Constraint after LGS Adj. (3,294,966) - - (3,294,966) -

10 Net Change in Req. Rider FRP Revenue Calc [3]11 ROE Band Rate Adjustment (B.6 L10 * L2) - - - - - 12 Netting Adjustment (D.6 L13 * L2) - - - - -

Net Change in Required Rider FRP Revenue before13 LGS Adjustment (L11 + L12) - - - - - 14 LGS Adjustment [4] - 2,101,582 1,131,116 (3,294,966) 62,268 15 Net Change in Required Rider FRP Revenue (L13 + L14) - 2,101,582 1,131,116 (3,294,966) 62,268

16 Incremental Rider FRP Base Rate Change (L15 ÷ (L1 + L19)) 0.0000% 0.2744% 0.2744% -0.8340% 0.2744%

17 Cumulative Rider FRP Revenue Calculation [5]18

bounded by the constraint defined on L7 and L9 - - - - -

19 Projected Year Rider FRP Revenue [6] - - - - - 20 Cumulative Total Rider FRP Revenue (L18 + L19) - - - - - 21 Rider FRP Rate Development Calculation [7]22 Adjusted Projected Year Base Rate Revenue 1,277,507,581 592,142,021 324,991,018 335,341,713 25,032,829

23 Rider FRP Projected Year Rate Change (L20 ÷ L22) 0.0000% 0.0000% 0.0000% 0.0000%

[1]

[2]

[3]

[4]

[5]

[6]

[7] The Rider FRP Rate Development Calculation determines the percent increase/decrease that will be applied to all base rate components. The Adjusted Projected Year Base Rate Revenue is calculated using the Retail Rate Schedule Revenue (B.3 L2) excluding Projected Year Rider FRP Revenue and any revenue pursuant to excluded schedules listed on Attachment A.1. The percent increase/decrease is calculated by taking the Total Rider FRP Revenue listed on Line 20 and dividing it by the applicable Adjusted Projected Year Base Rate Revenue listed on Line 22.


Rider FRP Revenue ChangeFor the Projected Year 2022

NOTES:

Rate Schedule Revenue Requirement as determined in the EAL unadjusted cost of service ("COS") Schedule G-1 filed with the 2020 Evaluation Report.

The Rider FRP Constraint Calculation determines the limit of the Rider FRP revenue increase/decrease per rate class, which shall not exceed four percent (4%) of Total Unadjusted Annualized Filing Year (the year in which the Evaluation Report is filed) revenues including all riders. The LGS Rate Class’ Rider FRP Constraint shall be lowered by the amount on Line 14.

The Net Change in Required Rider FRP Revenue Calculation takes the Total Projected Year Rate Change in Rider FRP Revenue (B.6 Line 10) and the Historical Year Netting adjustment (D.6 Line 13) and allocates the amount required to each rate class based on Line 2. The amounts required are added together by rate class to determine each rate class' net change in required Rider FRP revenue.

The Large General Service (LGS) Rate Class’ allocated amount shall be reduced annually during the five-year extension term by one-fifth of the amount by which the LGS Rate Class’ base rate revenues were adjusted for mitigation in Docket No. 15-015-U. This amount shall be allocated to the remaining classes based on an equal percentage of the base rate revenue as determined in the EAL unadjusted cost of service that was filed with the 2020 Evaluation Report.

The Cumulative Rider FRP revenue calculation adjusts the Required Rider FRP revenue determined on Line 15 to be within the limits of the Rider FRP constraint calculation and adds the Projected Year Rider FRP Revenues to calculate Cumulative Total Rider FRP Revenue required in the Projected Year.

The Projected Year Rider FRP Revenue will equal the amount of Rider FRP revenues included in the determination of the Projected Year ROE Band Rate Adjustment (B.3 L2).


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Attachment B.1 Rate Schedule No. 44



Earned Rate of Return on Common Equity FormulaFor the Projected Year 2021

Line Description Source AdjustedNo Amount

1 RATE BASE B.2, Line 25 8,373,655,9432 BENCHMARK RATE OF RETURN ON RATE BASE B.5, Line 15, Column F 5.04%

3 REQUIRED OPERATING INCOME Line 1 * Line 2 421,792,0244 NET UTILITY OPERATING INCOME B.3, Line 33 388,714,2025 OPERATING INCOME DEFICIENCY/(EXCESS) Line 3 - Line 4 33,077,8216 REVENUE CONVERSION FACTOR Note [1] 1.346587 REVENUE DEFICIENCY/(EXCESS) Line 5 * Line 6 44,542,021

PRESENT RATE REVENUES8 RETAIL RATE SCHEDULE REVENUE B.3, Line 2 1,515,131,1749 WHOLESALE SALES B.3, Line 3 0

10 REVENUE REQUIREMENT Line 7 + Line 8 + Line 9 1,559,673,195

11 REVENUE REQUIREMENT ALLOCATION FACTOR Note [2] 99.9992%12 RETAIL REVENUE REQUIREMENT Line 10 * Line 11 1,559,660,71813 RETAIL RATE SCHEDULE REVENUE B.3, Line 2 1,515,131,17414 RETAIL REVENUE DEFICIENCY/(EXCESS) Line 12 - Line 13 44,529,54415 REVENUE CONVERSION FACTOR Note [1] 1.3465816 RETAIL OPERATING INCOME DEFICIENCY/(EXCESS) Line 14 / Line 15 33,068,55517 RATE BASE ALLOCATION FACTOR Note [3] 99.9990%18 RETAIL RATE BASE Line 1 * Line 17 8,373,572,89419 COMMON EQUITY DEFICIENCY/(EXCESS) (%) Line 16 / Line 18 0.39%20 WEIGHTED EVALUATION PERIOD COST RATE FOR COMMON EQUITY (%) B.5, Line 3 + Line 8, Column F 3.57%21 WEIGHTED EARNED COMMON EQUITY RATE (%) Line 20 - Line 19 3.18%22 COMMON EQUITY RATIO (%) B.5, Line 3 + Line 8, Column D 36.63%23 EARNED RATE OF RETURN ON COMMON EQUITY (%) Line 21 / Line 22 8.67%

Notes:[1]

[2]

[3]

Revenue Requirement Allocation Factor = Retail Revenue Requirement / Total Company Revenue Requirement. The Retail and Total Company Revenue Requirement shall be the revenue requirement approved by the Commission in Docket No. 15-015-U.

Rate Base Allocation Factor = Retail Rate Base / Total Company Rate Base. The Retail and Total Company Rate Base shall be the rate base approved by the Commission in Docket No.15-015-U.

TOTAL COMPANY

TOTAL RETAIL

Revenue Conversion Factor = 1 / [(1 - Composite Tax Rate * (1 - Bad Debt + Forfeited Discount Rate) ]


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Rate Base For the Projected Year 2021

Line Projected Year Projected Year AdjustedNo Description Per Books Adjustments Projected Year

A B [1] C

1 PLANT IN SERVICE 2 Beginning Balance 13,705,613,548 (1,400,271,574) 12,305,341,9743 Ending Balance 14,354,666,641 (1,414,151,650) 12,940,514,9914 Average Balance 14,030,140,095 (1,407,211,612) 12,622,928,483

5 ACCUMULATED DEPRECIATION 6 Beginning Balance (6,450,026,951) 1,634,103,838 (4,815,923,114)7 Ending Balance (6,633,559,662) 1,632,566,586 (5,000,993,075)8 Average Balance (6,541,793,307) 1,633,335,212 (4,908,458,095)

9 AVERAGE NET UTILITY PLANT (L4 + L8) 7,714,470,388

10 PLANT ACQUISITION ADJUSTMENT11 Beginning Balance 44,516,241 - 44,516,24112 Ending Balance 44,516,241 - 44,516,24113 Average Balance 44,516,241

14 AMORTIZATION OF ACQUISITION ADJ15 Beginning Balance (15,970,826) 111,523.00 (15,859,303)16 Ending Balance (18,584,156) 223,046.00 (18,361,110)17 Average Balance (17,110,206)

18 WORKING CAPITAL ASSETS19 MATERIALS AND SUPPLIES 210,501,709 (26,526,527) 183,975,18220 PREPAYMENTS 3,492,506 12,546,506 16,039,01321 FUEL INVENTORY 104,139,232 (74,909,447) 29,229,78522 WORKING CASH 6,775,492,413 (6,372,956,872) 402,535,54123 TOTAL WORKING CAPITAL ASSETS 7,093,625,861 (6,461,846,340) 631,779,521

24 OTHER - - -

25 TOTAL RATE BASE (L9+L13+L17+L23+L24) 8,373,655,943

Notes:[1] Adjustments as set out in Attachment C to this Rider FRP.


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Entergy Arkansas, LLCFormula Rate PlanOperating Income

For the Projected Year 2021


A B [1] CREVENUES

1 SALES TO ULTIMATE CUSTOMERS2 RETAIL RATE SCHEDULE REVENUE 1,910,127,706 (394,996,532) 1,515,131,1743 WHOLESALE SALES 55,399,040 (55,399,040) - 4 TOTAL SALES TO ULTIMATE CUSTOMERS (L2 + L3) 1,965,526,746 (450,395,572) 1,515,131,174

5 OTHER SALES REVENUE 262,560,375 (261,840,375) 720,0006 OTHER ELECTRIC REVENUE 156,360,225 (125,835,402) 30,524,8237 TOTAL OPERATING REVENUES (Sum of L4 thru L6) 2,384,447,346 (838,071,349) 1,546,375,997

EXPENSES88 OPERATION & MAINTENANCE9 PRODUCTION 899,539,457 (607,762,483) 291,776,974

10 TRANSMISSION 41,070,118 (14,443,475) 26,626,64311 REGIONAL MARKET 4,962,803 (4,962,803) - 12 DISTRIBUTION 89,554,344 641,296 90,195,64013 CUSTOMER ACCOUNTING 26,832,359 (1,183,196) 25,649,16414 CUSTOMER SERVICE & INFORMATION 74,667,434 (70,165,062) 4,502,37215 SALES 938,327 843,205 1,781,53216 ADMINISTRATIVE & GENERAL 235,759,936 (25,609,936) 210,150,00017 TOTAL O & M EXPENSE (Sum of L9 thru L16) 1,373,324,778 (722,642,454) 650,682,324

18 GAIN FROM DISPOSITION OF ALLOWANCES 0 - 019 REGULATORY DEBITS & CREDITS (71,777,491) 72,476,701 699,21020 DEPRECIATION & AMORTIZATION EXPENSES 363,508,818 (17,495,054) 346,013,76521 ACCRETION EXPENSES 76,648,000 (76,648,000) - 22 AMORTIZATION OF PLANT ACQUISITION ADJUSTMENT 2,613,330 (111,523) 2,501,80723 OTHER CREDIT FEES - 300,000 300,000 24 TAXES OTHER THAN INCOME 119,636,850 (45,999,329) 73,637,52125 CURRENT STATE INCOME TAX [2] (6,827,021) 10,728,924 3,901,90326 CURRENT FEDERAL INCOME TAX [2] (16,861,981) 53,238,616 36,376,63527 PROVISION DEFERRED INCOME TAX - STATE - NET [3] 32,047,635 (13,123,460) 18,924,17528 PROVISION DEFERRED INCOME TAX - FEDERAL - NET [3] 81,403,012 (55,551,055) 25,851,95729 INVESTMENT TAX CREDIT - NET [3] (1,227,503) - (1,227,503)30 GAIN/LOSS – DISPOSITION OF UTILITY PLANT 0 - - 31 OTHER - - - 32 TOTAL UTILITY OPERATING EXPENSE (Sum of L17 thru L31) 1,952,488,428 (794,826,633) 1,157,661,794

33 NET UTILITY OPERATING INCOME (L7 - L32) 431,958,918 (43,244,716) 388,714,202

Notes:[1] Adjustments as set out in Attachment C to this Rider FRP.

[2] Reference Attachment B.4. See also Filing Requirement Item No. 15, MFR C-11 for additional support.

[3] Provide supporting schedule of calculation including adjustments and descriptions. See Filing Requirement Item No. 15, MFR C-9 & C-12.


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A B [1] C

1 TOTAL OPERATING REVENUES 2,384,447,346 (838,071,349) 1,546,375,997

2 TOTAL O&M EXPENSE 1,373,324,778 (722,642,454) 650,682,3243 GAIN FROM DISPOSITION OF ALLOWANCES 0 0 04 REGULATORY DEBITS AND CREDITS (71,777,491) 72,476,701 699,2105 DEPRECIATION & AMORTIZATION EXPENSE 363,508,818 (17,495,054) 346,013,7656 ACCRETION EXPENSE 76,648,000 (76,648,000) 07 AMORTIZATION OF PLANT ACQUISITION ADJUSTMENT 2,613,330 (111,523) 2,501,8078 OTHER CREDIT FEES 0 300,000 300,0009 TAXES OTHER THAN INCOME 119,636,850 (45,999,329) 73,637,521

10 GAIN/LOSS – DISPOSITION OF UTILITY PLANT 0 0 011 OTHER 0 0 012 INTEREST EXPENSE [2] 151,081,476 (28,347,844) 122,733,632

13 NET INCOME BEFORE INCOME TAXES (L1- (Sum L2-L12)) 369,411,585 (19,603,847) 349,807,738

14 ADJUSTMENTS TO NET INCOME BEFORE TAXES [3] (465,847,561) 283,849,989 (181,997,572)15 TAXABLE INCOME (L13 + L14) (96,435,976) 264,246,142 167,810,165

COMPUTATION OF STATE INCOME TAX

16 TAXABLE INCOME (L15) (96,435,976) 264,246,142 167,810,16517 STATE ADJUSTMENTS [3] (21,076,359) (91,198,983) (112,275,342)18 STATE TAXABLE INCOME (L16 + L17) (117,512,335) 173,047,158 55,534,82319 STATE INCOME TAX BEFORE ADJUSTMENTS (L18 * Tax Rate) [1] (7,285,765) 10,728,924 3,443,15920 ADJUSTMENTS TO STATE TAX [3] 458,744 0 458,74421 STATE INCOME TAX (L19 + L20) (6,827,021) 10,728,924 3,901,903

COMPUTATION OF FEDERAL INCOME TAX

22 TAXABLE INCOME (L15) (96,435,976) 264,246,142 167,810,16523 STATE INCOME TAX BEFORE ADJUSTMENTS (L19) (7,285,765) 10,728,924 3,443,15924 FEDERAL ADJUSTMENTS [3] 0 0 025 TOTAL FEDERAL TAXABLE INCOME (L22 - L23 + L24) (89,150,211) 253,517,218 164,367,00626 FEDERAL INCOME TAX BEFORE ADJUSTMENTS (L25 * Tax Rate) [1] (18,721,544) 53,238,616 34,517,07127 ADJUSTMENTS TO FEDERAL TAX [3] 1,859,563 0 1,859,56328 FEDERAL INCOME TAX (L26 + L27) (16,861,981) 53,238,616 36,376,635

Notes:[1] Adjustments and applicable tax rate as set out in Attachment C to this Rider FRP.

[2]

[3] List all adjustments including descriptions in a supporting schedule. See Filing Requirement Item No. 15, MFR C-11 for additional support.

Interest Expense for Col. C is Weighted Cost of Debt (COD) Rate as derived from COD elements reflected in Attachment B.5 x Rate Base per Attachment B.2, Column C.


Income TaxFor the Projected Year 2021


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(A) (B) (C) (D) (E) (F)Benchmark

Capital Capital Cost Rate OfAmount ($) Ratio (%) Rate (%) Return On

Line No.

Description [1] [2] [3] Rate Base [4]

1 Long-Term Debt 3,463,950,280 38.59% 3.75% 1.45%2 Preferred Stock - 0.00% 0.00% 0.00%3 Common Equity 3,273,550,258 36.47% 9.75% 3.56%4 Accumulated Deferred Income Taxes 1,821,765,182 20.30% 0.00% 0.00%5 Post-1970 ADITC - LT 15,083,805 0.17% 3.75% 0.01%6 Post-1970 ADITC - ST 25,479 0.00% 0.11% 0.00%7 Post-1970 ADITC - Preferred Stock - 0.00% 0.00% 0.00%8 Post-1970 ADITC - Common Stock 14,254,706 0.16% 9.75% 0.02%9 Customer Deposits 102,626,137 1.14% 0.80% 0.01%

10 Short-Term/Interim Debt 5,851,227 0.07% 0.11% 0.00%11 Current Accrued, and Other Liabilities 90,000,000 1.00% 0.00% 0.00%12 Capital Leases - 0.00% 0.00% 0.00%13 DOE Obligation 188,622,945 2.10% 0.09% 0.00%14 Other Capital Items - 0.00% 0.00% 0.00%

15 Total 8,975,730,018 100.00% 28.11% 5.04%

Notes:[1]

[2]

[3]

[4]

The cost rates shall be calculated in accordance with the calculation applied by the Commission in Docket No. 15-015-U. Support for the cost of Long-Term debt and cost of Preferred Stock shall be provided in the same format and level of detail required by the Filing Requirements, respectively. Support for the Short-Term debt cost rate and the DOE Obligation cost rate should include a general description of how the interest rate is determined and the same level of detail provided in the Filing Requirements in Attachment E, Item No. 15. The cost rate for Customer Deposits shall be the Commission-approved rate in effect during the year. The Cost Rate for Common Equity shall be that approved by Commission Order in Docket No. 15-015-U, which is 9.75%.

Beginning with the 2021 Evaluation Report, should the long-term or short-term debt amounts have to be adjusted in order to achieve the imputed 53/47 DTE ratio, the adjusted values will have a cost rate equivalent to the unadjusted long-term and short-term debt amounts.

Capital amounts each divided by the Total Capital Amount.

The components in Column F are the corresponding Cost Rates multiplied by the associated Capital Ratio.

The capital balances for Long-Term Debt, Department of Energy Obligation (DOE), Preferred Equity and Common Equity shall be mid-year (June 30) balances (1) adjusted to reflect short-term debt using any 13 month average net borrower position from the money pool and (2) further adjusted to remove any 13 month average net lender position to the money pool for the year, if applicable, consistent with Commission Order in Docket No. 15-015-U. Support for the 13 month average of the money pool calculations shall be provided. The total debt-to-equity ratio (DTE) for external capital, including the appropriate short-term debt percentage and the Department of Energy (DOE) Obligation, shall fall within a range of 56/44 to 50/50. Should the DTE ratio fall outside that range, the external capital structure shall be imputed using a 53/47 DTE ratio. Capital amounts shall include mid-year balances for Post-1970 Investment Tax Credits, Customer Deposits, and Short-Term debt balances, beginning and ending year average for Accumulated Deferred Income Tax (ADIT), and 13-month average balances for Current, Accrued and Other Liabilities (CAOL), if applicable. A June 30 balance sheet should be provided as well as a reconciliation between the balance sheet and Column (A) amounts. Support for the CAOL balances shall include the same format and detail as required by the Filing Requirements in Attachment E, Item No. 15.

Beginning with the 2021 Evaluation Report, the total debt-to-equity ratio (DTE) for external capital, including the appropriate short-term debt percentage and the Department of Energy (DOE) Obligation, shall be imputed using a 53/47 DTE ratio consistent with the calculation of the DTE ratio in Docket No. 15-015-U. In order to achieve the imputed ratio of 53/47, EAL will adjust the balances of long-term debt and common equity. If EAL’s short-term debt falls below 0.07% and the Commission imputes a short-term debt amount up to that threshold, the corresponding adjustment will adjust long-term debt to maintain a 53/47 DTE ratio. If the Commission imputes any amount for any liabilities that are reflected in the capital structure for ratemaking purposes, it shall not include any amount stated as a percentage that exceeds the amount stated as a percentage included in the capital structure approved by the Commission in Order No. 40 issued on December 11, 2020 in Docket No. 16-036-FR.


Benchmark Rate of Return on Rate BaseFor the Projected Year 2021


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SECTION 1BANDWIDTH DEVELOPMENT

LineNo DESCRIPTION REFERENCE 1 Earned Rate of Return on Common Equity ("ERR") [1] B.1, Line 23 8.67%2 Target Return Rate ("TRR") B.5, Line 3, Column E 9.75%3 Upper Bandwidth Limit Line 2 + 0.50% 10.25%4 Lower Bandwidth Limit Line 2 - 0.50% 9.25%5 ROE Adjustment If L1 < L4, then L2 - L1; If L1 > L3,

then L2 - L1, but no adjustment if L1 ≥ L4 or L1 ≤ L3 1.08%

SECTION 2ROE BANDWIDTH RATE ADJUSTMENT

LineNo DESCRIPTION REFERENCE 6 ROE Adjustment Per Line 5 1.08%7 Common Equity Capital Ratio B.5, Line 3 + Line 8, Column D 36.63%8 Retail Rate Base B.1, Line 18 8,373,572,8949 Revenue Conversion Factor B.1, Line 15 1.3465810 Total Rate Change in Rider FRP Revenue Line 6 * Line 7 * Line 8 * Line 9 44,529,544

Notes:[1]

[2] The TRR is the Company's cost rate for common equity as established by the Commission in Docket No. 15-015-U (9.75%). The TRR in effect during the initial five-year term of Rider FRP shall continue to be in effect for the five-year term of the extension.

The ERR is the Earned Rate of Return on Common Equity, calculated by dividing the weighted earned common equity rate by the common equity ratio percentage.


Rider FRP Revenue Redetermination FormulaFor the Projected Year 2021


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Attachment C to Rate Schedule No. 44 Attachment Page 1 of 5


ENTERGY ARKANSAS, LLC FORMULA RATE PLAN ADJUSTMENTS

The amounts reflected in Attachments B and D shall be adjusted to reflect the following:

I. General

A) The rate base, revenue and expense effects associated with riders which recover specific costsor other rate mechanisms the utility may have in effect shall not be included in the Formula RatePlan Projected and Historical Year periods.

B) The Historical Year balance sheet shall be the source for rate base and capital for the HistoricalYear used in Attachment D. The Historical Year income statement shall be the source forrevenue and expense amounts used in Attachment D.

C) The Historical Year shall be adjusted to remove rider revenue and expenses, remove amounts,or otherwise make adjustments, consistent with the most recent general rate case (e.g., removalof charitable contributions from expense, or temporary accounts from working capital assets(WCA)), and other adjustments as described in Attachment C.

D) Where the Official Forecast is defined as Entergy Corporation’s Board of Directors approved five-year corporate budget for EAL, the Company’s Official Forecast shall be the source for rate base,capital, revenue, and expense amounts for use in Attachment B unless otherwise supported bythe Company in its filing, and to the extent practicable, EAL shall support the purpose and levelof its Projected Year investments or expenses with those projections based primarily uponhistorical averages and making specific adjustments to those amounts instead of basing thoseprojections primarily on EAL’s corporate budget. To the extent practicable, the Company willutilize its four-year historical averages as the base for its projected capital and expense amountsfor use in Attachment B, with specific modifications to those amounts either higher or lower thanthe four-year average that the Company reasonably expects are likely to occur in the ProjectedYear and are supported by the Company in its annual Evaluation Report filing. Specifically, tothe extent practicable, EAL will utilize four-year average historical plant balances as the baselinefor the development of the enumerated blanket funding projects associated with capitalinvestment that are mandated by law or regulation, customer-driven, or necessary to maintainthe reliability of the electric grid as the baseline for the investments going forward. For anyprojects that fall outside the recurring enumerated categories that are based on the historicalaveraging, EAL shall separately identify, to the extent practicable, each project and support theproject as a specific adjustment to the Projected Year amounts, and to complete this, EAL maydetermine that projects should be grouped together when the projects contain a combination ofproposed investments associated with both baseline reliability and load stability projects, suchas pole, line and circuit inspection programs, and other reliability efforts that EAL plans toundertake in the Projected Year. Again, to the extent practicable, EAL shall use the four-yearhistorical averages described herein except that EAL shall adjust the historical averages upwardor downward for specific capital projects and anticipated cost increases or decreases that EALreasonably expects are likely to occur within the Projected Year and for which EAL providesadditional support consistent with other filing support thresholds that the Commission applied toEAL’s Rider FRP during its initial five-year term; additionally, expenses related to capitalinvestments that EAL already has explained shall not require separate support, includingdepreciation and property taxes. The support for the Projected Year described herein shall beapplied to the transmission and generation functional areas to the extent deemed practicable by


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EAL. If EAL determines that any of the foregoing is not practicable, EAL shall use reasonable efforts to establish a similar framework to present capital investment and expense.

E) The Projected Year shall be adjusted to remove rider revenue and expenses, remove amounts,or otherwise make adjustments, consistent with the Commission’s Order in Docket No. 15-015-U (e.g., removal of charitable contributions from expense, or temporary accounts from WCA),and other adjustments as described in Attachment C.

F) EAL shall include and shall recover Allowance for Funds Used During Construction (AFUDC).AFUDC shall be determined according to the uniform system of accounts adopted by theCommission and any applicable accounting guidance issued by the Federal Energy RegulatoryCommission and conforms with Generally Accepted Accounting Principles.

G) Rate base amounts for both the Historical Year and the Projected Year shall exclude constructionwork in progress (CWIP), Non-Utility Plant, and Plant Held for Future Use. Plant andAccumulated Depreciation amounts for both the Historical Year and the Projected Year shall beadjusted to remove Asset Retirement Obligations and Securitized amounts.

H) No adjustments shall be made in either the Projected or Historical Year to annualize any expense.

I) During the term of Rider FRP the Lost Contribution to Fixed Costs portion of the utility’s EnergyEfficiency Rider shall be set to zero.

J) Depreciation Expenses and Accumulated Depreciation shall reflect Commission-approved rates.No changes in depreciation rates shall be made in the annual Rider FRP filing. During an annualRider FRP filing, a utility may request an interim rate for plant added, which has no approveddepreciation rate, excluding major plant acquisitions. EAL shall request depreciation rates formajor plant acquisitions within the docket requesting approval for the purchase of the plant.

K) Revenue and cost effects that were imputed in the general rate case shall be similarly imputedin the annual Rider FRP filing.

L) EAL shall not record a regulatory asset or regulatory liability representing the amount by whichan FRP increase or decrease absent the operation of the 4 percent cap exceeds the actual FRPincrease or decrease that is implemented pursuant to the operation of this tariff.

II. Cost of Service Categories

A. Revenues

1. For the Filing Year, total revenue used on Attachment A.2 or A.2 – Extension, as applicable,shall be based on EAL’s projected annualized billing determinants and rates which will be ineffect at year-end. Because year-end data will not be available at the time of the filing,revenue projections for the Filing Year shall be updated based on actual data during theRider FRP procedural schedule. Adjustments for growth and thirty-year normal weather shallbe included.


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2. For the Projected Year, revenue shall be based on EAL’s projected annualized billingdeterminants and rates, which will be in effect at year-end. Adjustments for growth and thirty-year normal weather shall be included.

3. The Historical Year shall reflect actual revenues. No adjustments for growth or weather shallbe included.

4. Revenues associated with special rate contracts shall be treated consistent with the terms ofthe contract.

B. Rate Base

1. For the Historical Year, plant shall reflect the average of beginning and ending year balances.

2. For the Projected Year, plant shall reflect the average of beginning and ending year balances.Plant shall include adjustments based on projections, including but not limited to,CCN/CECPN projects approved or expected to be approved by the Commission and inservice by the beginning of the Projected Year for the beginning year balances, and includeprojects in-service by the end of the Projected Year for ending year balances.

3. For the Historical Year, WCA shall reflect a 13-month average.

4. For the Projected Year, WCA shall reflect a 13-month average of the Historical Year withadjustments or projections to reflect a more representative balance.

C. Expenses

1. The Historical Year shall reflect actual expenses, adjusted as described in Attachment C.

D. Income Tax Expense

All state and federal income tax effects including 1) adjustments to taxable income, 2) adjustments to current taxes, and 3) provisions for deferred income tax (debit and credit) shall be adjusted or eliminated, as appropriate, to comport with the following principles:

1. All Projected Year and Historical Year interest expenses shall be eliminated and replacedwith an imputed interest expense amount equal to the rate base multiplied by the weightedembedded cost of debt;

2. Effects associated with other adjustments shall be similarly and consistently adjusted;

3. The Projected Year shall reflect the corporate state and federal income tax laws legally ineffect for the Projected Year to the extent reasonably known on the date the EvaluationReport is filed. The Historical Year shall reflect the corporate state and federal income taxlaws legally in effect during the historical year;

4. For the Projected Year and Historical Year, tax effects normally excluded for ratemakingpurposes shall be eliminated.

E. Benchmark Rate of Return on Rate Base

For the Projected Year and the Historical Year, the following adjustments shall be made:


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Docket No.: 18-004-TF Order No.:

Effective: 4/29/21



1. CAOL shall be based on the Historical Year 13-month averages, with adjustments orprojections to reflect a more representative balance, and include all accounts consistent withthose ordered by the Commission in Docket No. 15-015-U. If the Commission imputes anyamount for any liabilities that are reflected in the capital structure for ratemaking purposes, itshall not include any amount stated as a percentage that exceeds the amount stated as apercentage included in the capital structure approved in the Commission’sDecember 11, 2020 Order No. 40 in Docket No. 16-036-FR, i.e., no greater than 1 percentof total capitalization.

2. Accumulated Deferred Income Taxes (ADIT) shall be based on the beginning and endingtest year average and include all accounts consistent with those ordered by the Commissionin Docket No. 15-015-U, adjusted for any changes made to Projected Year plant additionamounts.

3. The capital balances for Long-Term Debt, DOE Obligation, Preferred Equity and CommonEquity shall be mid-year (June 30) balances (1) adjusted to reflect short-term debt using any13 month average net borrower position from the money pool and (2) further adjusted toremove any 13 month average net lender position to the money pool for the year, ifapplicable, consistent with those ordered by the Commission in Docket No. 15-015-U.

4. For EAL’s first five-year term of Rider FRP, the DTE for external capital, including theappropriate short-term debt percentage and the DOE Obligation, reflected in Attachment B-5 and D-5, the BRORB, shall fall within a range of 56/44 to 50/50. Should EAL DTE ratio falloutside the range, the external capital structure shall be imputed using a 53/47 DTE ratio.

For the extension term of Rider FRP, the debt-to-equity ratio, for the purpose of setting rates,shall be fixed at EAL’s actual debt-to-equity ratio approved in the Commission’sDecember 11, 2020 Order No. 40 in Docket 16-036-FR. In order to achieve the imputed ratioof 53/47, EAL will adjust the balances of long-term debt and common equity. If EAL’s short-term debt below falls below 0.07% and the Commission imputes a short-term debt amountup to that threshold, the corresponding adjustment will adjust long-term debt to maintain the53/47 DTE ratio.

5. The return on equity shall be the value determined in Docket No. 15-015-U and shall continueto be in effect for the term of the extension.

III. Other Adjustments

A. Reclassifications

1. For the Historical Year and Projected Year, revenues included in Other Electric Revenueshall be reclassified to the appropriate jurisdictional rate schedule revenue category.

2. For the Projected Year and Historical Year, costs not allowable for ratemaking purposes shallbe excluded as specified in Section I or removed by adjustment. Likewise, costs that areallowed, but recorded below the utility operating income line, shall be included in the annualRider FRP filing cost data through appropriate reclassification adjustments. Theseadjustments shall include but are not limited to interest income and expense related toEntergy Services, LLC (ESL) and Entergy Operations, Inc. (EOI).


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Effective: 4/29/21



B. Out-of-Period Items

Expenses and revenues that are related to transactions occurring prior to the Historical Year but are recorded in the Historical Year shall be eliminated, including any associated tax adjustments.

C. Other

A public utility or any other party to the proceeding may propose additional adjustments that are based on factors unique to the public utility except that any adjustment(s) beyond those described above shall be consistent with the APSC’s findings in Docket No. 15-015-U and shall be consistent with the Formula Rate Review Act.


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Order No.:

Effective: 4/29/21

Attachment D.1 to Rate Schedule No. 44



Earned Rate of Return on Common Equity FormulaFor the Historical Year 2019

Line Description Source AdjustedNo Amount

1 RATE BASE D.2, Line 27 7,494,288,8542 BENCHMARK RATE OF RETURN ON RATE BASE D.5, Line 13, Column F 5.10%

3 REQUIRED OPERATING INCOME Line 1 * Line 2 381,935,7094 NET UTILITY OPERATING INCOME D.3, Line 33 364,202,5965 OPERATING INCOME DEFICIENCY/(EXCESS) Line 3 - Line 4 17,733,1136 REVENUE CONVERSION FACTOR Note [1] 1.350907 REVENUE DEFICIENCY/(EXCESS) Line 5 * Line 6 23,955,716

PRESENT RATE REVENUES8 RETAIL RATE SCHEDULE REVENUE D.3, Line 2 1,436,009,8539 WHOLESALE SALES D.3, Line 3 (0)

10 REVENUE REQUIREMENT Line 7 + Line 8 + Line 9 1,459,965,569

11 REVENUE REQUIREMENT ALLOCATION FACTOR Note [2] 99.9992%12 RETAIL REVENUE REQUIREMENT Line 10 * Line 11 1,459,953,88913 RETAIL RATE SCHEDULE REVENUE Line 8 1,436,009,85314 RETAIL REVENUE DEFICIENCY/(EXCESS) Line 12 - Line 13 23,944,03615 REVENUE CONVERSION FACTOR Note [1] 1.3509016 RETAIL OPERATING INCOME DEFICIENCY/(EXCESS) Line 14 / Line 15 17,724,46717 RATE BASE ALLOCATION FACTOR Note [3] 99.9990%18 RETAIL RATE BASE Line 1 * Line 17 7,494,214,52719 COMMON EQUITY DEFICIENCY/(EXCESS) (%) Line 16 / Line 18 0.24%20 WEIGHTED EVALUATION PERIOD COST RATE FOR COMMON EQUITY (%) D.5, Line 3, Column F 3.41%21 WEIGHTED EARNED COMMON EQUITY RATE (%) Line 20 - Line 19 3.18%

22 COMMON EQUITY RATIO (%)D.5, Line 3 + Line 8, Column D 35.00%

23 EARNED RATE OF RETURN ON COMMON EQUITY (%) Line 21 / Line 22 9.07%

Notes:[1]

[2]

[3] Rate Base Allocation Factor = Retail Rate Base / Total Company Rate Base. The Retail and Total Company Rate Base shall be the rate base approved by the Commission in Docket No. 15-015-U.

TOTAL COMPANY

TOTAL RETAIL

Revenue Conversion Factor = 1 / [(1 - Composite Tax Rate) * (1 - Bad Debt + Forfeited Discount Rate)].

Revenue Requirement Allocation Factor = Retail Revenue Requirement / Total Company Revenue Requirement. The Retail and Total Company Revenue Requirement shall be the revenue requirement approved by the Commission in Docket No. 15-015-U.


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Effective: 4/29/21




Rate Base For the Historical Year 2019

Line Historical Year Historical Year AdjustedNo Description Per Books Adjustments Historical Year

A [1] B [2] C [3]

1 PLANT IN SERVICE 2 Beginning Balance 12,160,537,152 (939,222,226) 11,221,314,9253 Ending Balance 13,083,838,386 (1,367,059,060) 11,716,779,3264 Average Balance 12,622,187,769 (1,153,140,643) 11,469,047,126

5 ACCUMULATED DEPRECIATION 6 Beginning Balance (5,891,515,473) 1,332,311,555 (4,559,203,918)7 Ending Balance (6,286,450,353) 1,607,753,871 (4,678,696,482)8 Average Balance (6,088,982,913) 1,470,032,713 (4,618,950,200)

9 AVERAGE NET UTILITY PLANT (L4 + L8) 6,850,096,926

10 PLANT ACQUISITION ADJUSTMENT11 Beginning Balance 44,516,241 0 44,516,24112 Ending Balance 44,516,241 0 44,516,24113 Average Balance 44,516,241

14 AMORTIZATION OF ACQUISITION ADJ15 Beginning Balance (10,855,688) 0 (10,855,688)16 Ending Balance (13,357,495) 0 (13,357,495)17 Average Balance (12,106,592)

18 WORKING CAPITAL ASSETS19 MATERIALS AND SUPPLIES 211,338,051 (27,414,282) 183,923,76820 PREPAYMENTS 3,193,506 12,841,024 16,034,53021 FUEL INVENTORY 101,590,614 (61,495,837) 40,094,77722 WORKING CASH 6,723,019,648 (6,351,290,444) 371,729,20423 TOTAL WORKING CAPITAL ASSETS 7,039,141,818 (6,427,359,539) 611,782,279

24 OTHER 0 0 0

25 TOTAL RATE BASE:26 Ending Balances (L3+L7+L12+L16+L23+L24) 13,867,688,596 7,681,023,86927 Adj Historical Year (L9+L13+L17+L23+L24) 7,494,288,854

Notes:[1] Beginning and Ending Balances.

[2] Adjustments as set out in Attachment C to this Rider FRP.

[3] Averages will be used for the netting; Ending Balances will be the source of the Projected Schedules.


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Entergy Arkansas, LLCFormula Rate PlanOperating Income

For the Historical Year 2019


A [1] B [2] CREVENUES

1 SALES TO ULTIMATE CUSTOMERS2 RETAIL RATE SCHEDULE REVENUE 1,861,402,847 (425,392,994) 1,436,009,8533 WHOLESALE SALES 49,053,174 (49,053,174) (0) 4 TOTAL SALES TO ULTIMATE CUSTOMERS (L2 + L3) 1,910,456,021 (474,446,168) 1,436,009,853

5 OTHER SALES REVENUE 208,810,726 (208,303,560) 507,1656 OTHER ELECTRIC REVENUE 126,102,816 (103,000,868) 23,101,9487 TOTAL OPERATING REVENUES (Sum of L4 thru L6) 2,245,369,563 (785,750,597) 1,459,618,966

EXPENSES8 OPERATION & MAINTENANCE9 PRODUCTION 1,002,411,813 (684,222,044) 318,189,769

10 TRANSMISSION 44,625,679 (13,985,803) 30,639,87711 REGIONAL MARKET 4,739,064 (4,739,064) - 12 DISTRIBUTION 81,989,839 (318,778) 81,671,06213 CUSTOMER ACCOUNTING 39,254,958 27,325 39,282,28314 CUSTOMER SERVICE & INFORMATION 67,314,704 (62,133,044) 5,181,66015 SALES 856,774 843,155 1,699,92916 ADMINISTRATIVE & GENERAL 204,412,307 (23,926,605) 180,485,70117 TOTAL O & M EXPENSE (Sum of L9 thru L16) 1,445,605,138 (788,454,858) 657,150,281

18 GAIN FROM DISPOSITION OF ALLOWANCES (34) - (34)19 REGULATORY DEBITS & CREDITS (26,465,514) 27,164,730 699,21620 DEPRECIATION & AMORTIZATION EXPENSES 309,176,831 (12,585,200) 296,591,63121 ACCRETION EXPENSES 68,030,294 (68,030,294) - 22 AMORTIZATION OF PLANT ACQUISITION ADJUSTMENT 2,501,807 0 2,501,80723 OTHER CREDIT FEES - 261,724 261,724 24 TAXES OTHER THAN INCOME 115,500,440 (46,604,697) 68,895,74325 CURRENT STATE INCOME TAX [3] (5,601,205) 10,126,103 4,524,89926 CURRENT FEDERAL INCOME TAX [3] 49,865,815 (14,528,585) 35,337,23127 PROVISION DEFERRED INCOME TAX - STATE - NET [4] 7,989,321 8,575,482 16,564,80328 PROVISION DEFERRED INCOME TAX - FEDERAL - NET [4] (104,168,187) 118,284,760 14,116,57329 INVESTMENT TAX CREDIT - NET [4] (1,227,503) - (1,227,503)30 GAIN/LOSS – DISPOSITION OF UTILITY PLANT - - - 31 OTHER - - - 32 TOTAL UTILITY OPERATING EXPENSE (Sum of L17 thru L31) 1,861,207,204 (765,790,834) 1,095,416,370

33 NET UTILITY OPERATING INCOME (L7 - L32) 384,162,358 (19,959,762) 364,202,596

Notes:[1] Ending Balances.

[2] Adjustments as set out in Attachment C to this Rider FRP.

[3] Reference Attachment D.4. See also Filing Requirement Item No. 15, MFR C-11 for additional support.

[4]Provide supporting schedule of calculation including adjustments and descriptions. See Filing Requirement Item No. 15, MFR C-9 & C-12 for additional support.


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A [1] B [2] C

1 TOTAL OPERATING REVENUES 2,245,369,563 (785,750,597) 1,459,618,966

2 TOTAL O&M EXPENSE 1,445,605,138 (788,454,858) 657,150,2813 GAIN FROM DISPOSITION OF ALLOWANCES (34) 0 (34)4 REGULATORY DEBITS AND CREDITS (26,465,514) 27,164,730 699,2165 DEPRECIATION & AMORTIZATION EXPENSE 309,176,831 (12,585,200) 296,591,6316 ACCRETION EXPENSE 68,030,294 (68,030,294) 07 AMORTIZATION OF PLANT ACQUISITION ADJUSTMENT 2,501,807 0 2,501,8078 OTHER CREDIT FEES 0 261,724 261,7249 TAXES OTHER THAN INCOME 115,500,440 (46,604,697) 68,895,743

10 GAIN/LOSS – DISPOSITION OF UTILITY PLANT 0 0 011 OTHER 0 0 012 INTEREST EXPENSE [3] 134,568,524 (9,656,379) 124,912,145

13 NET INCOME BEFORE INCOME TAXES (L1- (Sum L2-L12)) 196,452,076 112,154,377 308,606,453

14 ADJUSTMENTS TO NET INCOME BEFORE TAXES [4] (206,419,963) 61,297,127 (145,122,836)15 TAXABLE INCOME (L12 + L13) (9,967,887) 173,451,505 163,483,617

COMPUTATION OF STATE INCOME TAX

16 TAXABLE INCOME (L15) (9,967,887) 173,451,505 163,483,61717 STATE ADJUSTMENTS [4] (14,524,468) (86,402,922) (100,927,390)18 STATE TAXABLE INCOME (L16 + L17) (24,492,355) 87,048,583 62,556,22719 STATE INCOME TAX BEFORE ADJUSTMENTS (L18 * Tax Rate) [2] (1,592,003) 5,658,158 4,066,15520 ADJUSTMENTS TO STATE TAX [4] (4,009,202) 4,467,946 458,74421 STATE INCOME TAX (L19 + L20) (5,601,205) 10,126,103 4,524,899

COMPUTATION OF FEDERAL INCOME TAX

22 TAXABLE INCOME (L15) (9,967,887) 173,451,505 163,483,61723 STATE INCOME TAX BEFORE ADJUSTMENTS (L19) (1,592,003) 5,658,158 4,066,15524 FEDERAL ADJUSTMENTS [4] 0 0 025 TOTAL FEDERAL TAXABLE INCOME (L22 - L23 + L24) (8,375,884) 167,793,347 159,417,46326 FEDERAL INCOME TAX BEFORE ADJUSTMENTS (L25 * Tax Rate) [2] (1,758,936) 35,236,603 33,477,66727 ADJUSTMENTS TO FEDERAL TAX [4] 51,624,751 (49,765,187) 1,859,56328 FEDERAL INCOME TAX (L26 + L27) 49,865,815 (14,528,585) 35,337,231

Notes:[1] Ending Balances.

[2] Adjustments and applicable tax rate as set out in Attachment C to this Rider FRP.

[3]

[4] List all adjustments including descriptions in a supporting schedule. See Filing Requirement Item No. 15, MFR C-11 for additional support.


Income TaxFor the Historical Year 2019

Interest Expense is Per Books for Column A, Weighted Cost of Debt (COD) Rate as derived from COD elements reflected in Attachment D.5 x Rate Base per Attachment D.2, Column C.


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Docket No.: 18-004-TF Order No.: Effective: 4/29/21 Attachment D.5 to Rate Schedule No. 44


(A) (B) (C) (D) (E) (F)Benchmark

Capital Capital Cost Rate OfAmount ($) Ratio (%) Rate (%) Return On

Line No.

Description [1] [2] [3] Rate Base [4]

1 Long-Term Debt 3,068,976,697 37.17% 4.28% 1.59%2 Preferred Stock 30,818,797 0.37% 4.55% 0.02%3 Common Equity 2,874,604,290 34.82% 9.75% 3.39%4 Accumulated Deferred Income Taxes 1,820,812,185 22.05% 0.00% 0.00%5 Post-1970 ADITC - LT 16,213,341 0.20% 4.28% 0.01%6 Post-1970 ADITC - ST 192,481 0.00% 2.33% 0.00%7 Post-1970 ADITC - Preferred Stock 162,815 0.00% 4.55% 0.00%8 Post-1970 ADITC - Common Stock 15,186,476 0.18% 9.75% 0.02%9 Customer Deposits 98,586,882 1.19% 0.60% 0.01%

10 Short-Term/Interim Debt 36,434,082 0.44% 2.33% 0.01%11 Current Accrued, and Other Liabilities 108,567,562 1.31% 0.00% 0.00%12 Capital Leases - 0.00% 0.00% 0.00%13 DOE Obligation 185,981,243 2.25% 2.29% 0.05%14 Other Capital Items - 0.00% 0.00% 0.00%

15 Total 8,256,536,852 100.00% 44.71% 5.10%

Notes:[1]

[2]

[3]

[4] The components in Column F are the corresponding Cost Rates multiplied by the associated Capital Ratio.

The capital balances for Long-Term Debt, Department of Energy Obligation (DOE), Preferred Equity and Common Equity shall be mid-year (June 30) balances (1) adjusted to reflect short-term debt using any 13 month average net borrower position from the money pool and (2) further adjusted to remove any 13 month average net lender position to the money pool for the year, if applicable, consistent with Commission Order in Docket No. 15-015-U. Support for the 13-month average of the money pool calculations shall be provided. The total debt-to-equity ratio (DTE) for external capital, including the appropriate short-term debt percentage and the Department of Energy (DOE) Obligation, shall fall within a range of 56/44 to 50/50. Should the DTE ratio fall outside that range, the external capital structure shall be imputed using a 53/47 DTE ratio. Capital amounts shall include mid-year balances for Post-1970 Investment Tax Credits, Customer Deposits, and Short-Term debt balances, beginning and ending year average for Accumulated Deferred Income Tax (ADIT), and 13-month average balances for Current, Accrued and Other Liabilities (CAOL), if applicable. A June 30 balance sheet should be provided as well as a reconciliation between the balance sheet and Column (A) amounts. Support for the CAOL balances shall include the same format and detail as required by the Filing Requirements in Attachment E, Item No. 15.

Beginning with the 2021 Evaluation Report, the total debt-to-equity ratio (DTE) for external capital, including the appropriate short-term debt percentage and the Department of Energy (DOE) Obligation, shall be imputed using a 53/47 DTE ratio consistent with the calculation of the DTE ratio in Docket No. 15-015-U. In order to achieve the imputed ratio of 53/47, EAL will adjust the balances of long-term debt and common equity. If EAL’s short-term debt below falls below 0.07% and the Commission imputes a short-term debt amount up to that threshold, the corresponding adjustment will adjust long-term debt to maintain a 53/47 DTE ratio. If the Commission imputes any amount for any liabilities that are reflected in the capital structure for ratemaking purposes, it shall not include any amount stated as a percentage that exceeds the amount stated as a percentage included in the capital structure approved by the Commission in Order No. 40 issued on December 11, 2020 in Docket No. 16-036-FR.

Capital amounts each divided by the Total Capital Amount.


Benchmark Rate of Return on Rate BaseFor the Historical Year 2019

The cost rates shall be calculated in accordance with the calculation applied by the Commission in Docket No. 15-015-U. Support for the cost of Long-Term debt and cost of Preferred Stock shall be provided in the same format and level of detail required by the Filing Requirements, respectively. Support for the Short-Term debt cost rate and the DOE Obligation cost rate should include a general description of how the interest rate is determined and the same level of detail provided in the Filing Requirements in Attachment E, Item No. 15. The cost rate for Customer Deposits shall be the Commission-approved rate in effect during the year. The Cost Rate for Common Equity shall be that approved by Commission Order in Docket No. 15-015-U, which is 9.75%.

Beginning with the 2021 Evaluation Report, should the long-term or short-term debt amounts have to be adjusted in order to achieve the imputed 53/47 DTE ratio, the adjusted values will have a cost rate equivalent to the unadjusted long-term and short-term debt amounts.


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SECTION 1BANDWIDTH DEVELOPMENT

LineNo DESCRIPTION REFERENCE 1 Earned Rate of Return on Common Equity ("ERR") [1] D.1, Line 23 9.07%2 Target Return Rate ("TRR") [2] D.5, Line 3, Column E 9.75%3 Upper Bandwidth Limit Line 2 + 0.50% 10.25%4 Lower Bandwidth Limit Line 2 - 0.50% 9.25%

5 ROE Adjustment

If L1 < L4, then L2 - L1; If L1 > L3, then L2 - L1, but no adjustment if L1 ≥ L4 or L1 ≤ L3 0.68%

SECTION 2ROE BANDWIDTH RATE ADJUSTMENT

LineNo DESCRIPTION REFERENCE 6 ROE Adjustment Per Line 5 0.68%7 Common Equity Capital Ratio D.5, Line 3 + Line 8, Column D 35.00%8 Retail Rate Base D.1, Line 18 7,494,214,527 9 Revenue Conversion Factor Note [5] 1.3465810 Total Rate Change in Rider FRP Revenue Line 6 * Line 7 * Line 8 * Line 9 23,867,461

SECTION 3TOTAL BANDWIDTH RATE ADJUSTMENT

LineNo DESCRIPTION REFERENCE 11 (Reduction) / Increase in Rider FRP Revenue Line 10 23,867,46112 Adjusted Historical Year Rider FRP Revenue Note [3] 28,631,58713 Netting of Historical Year Differences Adj [4] Line 11 - Line 12 (4,764,126)

Notes:[1]

[2]

[3]

[4]

[5]


Rider FRP Revenue Redetermination FormulaFor the Historical Year 2019

The Revenue Conversion Factor shall reference Attachment D.1, Line 15 unless the state or federal tax rate in effect at the end of the Historical Year has changed. If the state or federal tax rate has changed, the Revenue Conversion Factor will utilize a composite RCF as shown in WP_D.6.1.1.

Netting shall not begin until there is an actual twelve (12) months of Historical Year to report.

The TRR is the Company's cost rate for common equity, 9.75%, as established by the Commission in Docket No. 15-015-U (9.75%).

The ERR is the Earned Rate of Return on Common Equity, calculated by dividing the weighted earned common equity rate by the common equity ratio percentage.

Adjusted Historical Year FRP Rider revenue is the total FRP Rider revenue received for the Historical Year as described in Section 44.5.3.


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Attachment E to Rate Schedule No. 44

Attachment Page 1 of 5


ENTERGY ARKANSAS, LLC FORMULA RATE PLAN

A. FILING REQUIREMENTS

Item No. Filing Requirements

1 EAL shall file all Rider FRP Attachments supporting the Historical and Projected Year.

The following information shall be provided to the Parties: 2 Comparative Balance Sheet as of December 31 for the five (5) years preceding the Filing

Year. Reconcile to the Trial Balances and the Attachment D Schedules that it supports and reconcile to the FERC Form 1.

3 Operating statement of revenues and expenses for twelve months ending December 31 for the five (5) years preceding the Filing Year. Reconcile to the Trial Balances and the Attachment D Schedules that it supports and reconcile to the FERC Form 1.

4 Trial Balance by detail general ledger subaccount number for the five (5) years preceding the Filing Year. Reconcile to the Balance Sheets and the Attachment D Schedules that it supports.

5 Monthly Trial Balance by detail general ledger subaccount number for the beginning of the Historical Year and each of the monthly balances for the calendar year. Reconcile to the Balance Sheet, Income Statement, and the Attachment D Schedules that it supports.

6 Monthly balances for the “300" series plant amounts for the beginning of and each month-end of the Historical Year (13 months). In additional columns, the accumulated depreciation balances, the removal of securitized amounts (plant and accumulated depreciation) and asset retirement obligations and any other adjustments by each “300” series plant amount for the beginning of and each month-end of the Historical Year (13 months). Reconcile to the utility plant accounts in the Trial Balance and the Attachment D Schedules it supports.

7 Monthly plant and accumulated depreciation balances by account for the Historical Year showing the additions and retirements and any adjustments. Provide the cost of removal and salvage amounts by plant account for the year. Reconcile all amounts to the monthly Trial Balances for the “300" series plant accounts.

8 Identify all construction projects or purchases that closed to plant during the Historical Year. Include the project number, project description, start date, completion date, date closed to plant, cost to complete, and plant accounts where it was closed. Provide the detailed costs, including the AFUDC calculation, included in the five (5) largest projects completed during the year.


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9 Identify any construction project or proposed purchase that is approved or expected to be approved by the Commission (CCN, CECPN) and in-service by the end of the Projected Year. Include the project number, project description, start date, expected completion date and expected cost to complete and plant accounts where it will be closed. Reconcile the total amount of the projects for both the beginning and the end of the Projected Year with the plant additions included on Attachment Schedule B.2.

10 Plant balances by account for the ten (10) years preceding the Filing Year showing the additions and retirements. Include the 10-year average of each and explain any amount that deviates from the average by more than thirty percent (30%) Provide the cost of removal and salvage amounts by plant account for the same ten (10) years. Determine the 10-year average percentage of plant additions, by plant account, for retirements and the 10-year average percentage of retirements by plant (accumulated depreciation) account for cost of removal and salvage. Reconcile the total amount of the retirements as a 10-year average percent of plant additions and the cost of removal and salvage as a 10-year average percent of retirements for both the beginning and the end of the Projected Year with the plant and accumulated depreciation amounts included on Attachment Schedule B.2.

11 Detailed chart of accounts, including subaccounts and detailed description (i.e. MFR E-9). List of project codes, activity codes, resource codes and detailed description for each.

12 EAL, ESL, EOI, and Entergy Corporation internal and external audit reports for the Historical Year and any proposed auditor’s adjustments.

13 State and Federal Income Tax Returns for EAL, ESL, and EOI for the Historical Year.

14 Web access to EAL’s database containing all general ledger accounting activity for the Historical Year.

15 Rules of Practice and Procedure, Appendix 8-1 Minimum Filing Requirements (MFR) Schedules, as modified to substitute the Historical Year for the test year and the Projected Year (Official Forecast) for the pro forma year, B-1, B-2, B-4, B-5, B-10, C-4, C-5, C-8, C-9, C-10, C-11, C-12, D-2, D-3, D-5, D-6.1, D-6.2, D-6.3, D-7, F-1, and a schedule that shows the development of forecasted revenues using forecasted energy sales. These schedules shall be used to support the adjustments described in Items 18 and 19 below. Note, D-2 and D-3 shall be modified to substitute the Historical Year as of June 30 for the test year and the Filing Year and Projected Year through June 30 for the pro forma year.

16 Schedule of the expenses paid to each vendor for the Historical Year sorted by vendor name and FERC subaccount.

17 Web access to invoices for all vendors, regardless of originating company (EAL, ESL, etc.) included in Item 16.


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Attachment E to Rate Schedule No. 44 Attachment Page 3 of 5


18 Separate schedules of proposed adjustments to the actual financial statement amounts in determining the Adjusted Historical Year by general ledger subaccount for 1) rate base, 2) revenues and expenses (excluding current and deferred income taxes), 3) current and deferred income taxes, 4) CAOL, 5) ADIT, and 6) other capital components. Within each schedule, the adjustments should be in separate columns, but grouped by 1) adjustments to remove rider revenue and expenses, 2) those consistent with adjustments ordered by the Commission in Docket No. 15-015-U (such as removal of disallowed expenses such as charitable contributions, or exclusion of temporary accounts from WCA), or 3) or other adjustments. The adjustments within each schedule (rate base, revenues and expense, income taxes, cost of capital components) shall directly support and reconcile to the appropriate Attachment D Schedules.

19 Separate schedules of proposed adjustments to the Official Forecast amounts in determining the Adjusted Projected Year by general ledger subaccount for 1) rate base, 2) revenues and expenses (excluding current and deferred income taxes), 3) current and deferred income taxes, 4) CAOL, 5) ADIT and 6) other capital components. Within each schedule, the adjustments should be in separate columns, but grouped by 1) adjustments to remove excluded rider revenue and expenses, 2) those consistent with Docket No. 15-015-U (such as removal of disallowed expenses such as charitable contributions, or exclusion of temporary accounts from WCA), or 3) or other adjustments. The adjustments within each schedule (rate base, revenues and expense, income taxes, cost of capital components) shall directly support and reconcile to the appropriate Attachment B Schedules. Adjustments shall include certain items such as additional plant in service approved by the Commission per CCN/CECPN, if required.

20 For the Historical Year, by rate class and rate schedule, provide a statement showing customer count, kWh, weather adjusted kWh, base rate revenues, and rider revenues. For the Projected Year, by rate class and rate schedule, provide a statement showing customer count, kWh, base rate revenues, and rider revenues. Provide work papers that explain the variance analysis between the Historical Year and Projected Year information.

21 Provide expense totals for the five (5) years preceding the Filing Year by subaccount, source resource code, source activity code, project code, and bill resource code. Each year should include separate columns for expenses included in the determination of base rates and other riders (non-base rates) expenses. Reconcile to Trial Balance.

22 Schedule of payroll and related costs supporting base rates (excluding riders) by FERC subaccount (expense and non-expense (capital) accounts) for the five (5) years preceding the Filing Year. The costs should be shown in separate groups of columns for each company (EAL, ESL, EOI-ANO, and other (identify)). Within each company, for full-time employees only, include separate columns for: base pay, overtime, STIP, LTIP, other bonuses (identify each separately), fringe benefits, and payroll taxes. Provide part-time pay and associated fringe benefits and payroll taxes. Include a separate column for reductions for any payroll costs paid by other affiliates or other companies per loaned labor/mutual assistance programs.


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23 Non-payroll balances supporting base rates (excluding riders) by FERC subaccount, and source resource code and at the 300 FERC subaccount level for Plant in Service, for the twelve (12) months ending December 31 for the five (5) years preceding the Filing Year. Either in a separate analysis or in separate columns, identify the expense amounts in each subaccount, and source resource code by company (EAL, ESL, EOI-ANO, or other). Identify and explain all significant changes in accounting procedures during the five (5) years. For any accounting reclassifications identified in the accounting changes, align and reconcile accounts that reflect accounting changes in order to consistently track the accounting change through the five-year period. Identify and explain changes between the twelve (12) months ending December 31 of the Historical Year costs and the five-year average by FERC Account for all variances greater than thirty percent (30%) and five hundred thousand dollars ($500,000). The explanation and work papers shall include the specific underlying reason for the variance.

24 Provide a forecast validation analysis using the Historical Year data and the Projected Year data. The forecast validation analysis will be developed using the following method: (1) Adjust the Historical Year data as necessary such that it complies with the Commission’s Order in Docket No. 15-015-U. (Note: The Historical Year is presented at the FERC account level for all items excluding Plant in Service. Plant in Service will be presented at the 300 FERC account level); (2) Adjust the Projected Year data as necessary such that it complies with the Commission’s Order in Docket No. 15-015-U. (Note: The Projected Year data started with the Company’s forecast data and is presented at the FERC account); (3) Compare the Historical Year data and Projected Year data, by FERC account balances, and calculate an account specific variance; (4) Establish an account specific threshold by calculating the trended average of each FERC account balance for the five years ending with the Historical Year; and (5) For each FERC account balance variance that exceeds the threshold established in item 4, EAL will provide sufficient data to justify the proposed increase to that FERC account. The explanation and work papers shall include the general underlying reason for the variance. Provide work papers that support and quantify the underlying reason(s) for the variance explanations for those FERC accounts that exceed the threshold.


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Attachment E to Rate Schedule No. 44 Attachment Page 5 of 5


25 Affiliate transaction analysis of EAL expense account and project code shown in separate columns for the following: a) amounts billed, segregated between direct and allocated, from each affiliated company with separate columns for each affiliate; b) amounts directly incurred by EAL for its own operations; c) all other amounts in the account not corresponding to (a) or (b); and d) the sum of columns (a) through (c) which would equal the account’s general ledger balance at the end of the Historical Year. Provide an explanation of all items in (c). Provide copies of all allocation manuals used in allocating common costs among and between the Company and its affiliates, and billing method tables for all affiliates which have direct-billed or allocated charges to EAL.

26 Provide the Company’s Projected Year Budget (capital, payroll, headcount, non-payroll) that includes a reconciliation of the budgeted amounts to the Attachment B schedules. Provide supporting documentation for the development of the budgeted amounts. Provide web access to the Company’s Projected Year Budget.

27 EAL shall file as part of the annual compliance filing for the first three years of the extension term revised rate schedules for Rate Schedule No. 6, Large General Service (LGS); Rate Schedule No. 7, Large General Service Time-of-Use (GST); Rate Schedule No. 8, Large Power Service (LPS); Rate Schedule No. 9, Large Power Service Time-of-Use (PST); and Rate Schedule No. 18, Voltage Adjustment Rider (VAR) reflecting an equal annual adjustment to the demand and energy components pursuant to Ark. Code Ann. § 23-4-1208(a)(3)(E).

To the extent practicable, the following information shall be provided to the eligible Parties forty-five days in advance of the annual Evaluation Report filing:

28 Information regarding EAL’s construction projects and purchases that closed to plant during the Historical Year.

29 To the extent reasonably practicable, an overview of EAL’s planned distribution projects describing its Projected Year planned distribution unadjusted investment and expenses.


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Attachment F to Rate Schedule No. 44 Attachment Page 1 of 7


FORMULA RATE PROTOCOLS

Section I. General Provisions

1. Applicability and Scope

A. The following protocols shall apply to the annual Evaluation Report filings made pursuant to the Formula Rate Plan Rider Tariff (Rider FRP) approved by the Commission in Docket No. 15-015-U and extended in Docket No. 16-036-FR and under the Formula Rate Review Act.

B. The Rules of Practice and Procedure (RPPs) shall apply to all annual Evaluation Report filings, except the following for which the Commission has granted an exemption by approving Rider FRP:

Rule 3.08; Rule 4.02 (a)(2)(A); Rule 4.02 (a)(3); Rule 4.02 (a)(4); Rule 4.03 (c); Rule 4.04 (a)(2); Rule 4.10 (a)(2) & (3); and Rule 5.05(b), (c), & (d).

C. Any proposed modification of the Rider FRP Tariff, including these protocols, is outside the scope of an annual Evaluation Report filing and as such, no Party shall seek to modify the Rider FRP Tariff, including these protocols, as part of any annual Evaluation Report filing. Proposed modifications to the Rider FRP Tariff, including these protocols, shall be brought in a separate docket.

D. The filing of an annual Evaluation Report is a Formal Application. The filings of an annual Evaluation Report are not to be construed as a General Rate Change Application, nor are adjustments to rates that result from the filings of an annual Evaluation Report to be construed as a general change in rates pursuant to any provision of the Arkansas Code that references a general change in rates.

E. The Commission may grant an exemption from compliance with these Protocols if the exemption is found to be in the public interest and for good cause shown.

2. Public Notice

A. At least thirty (30) days prior to filing an annual Evaluation Report, EAL shall give public notice of its intent to file.

B. The notice shall indicate that it is from EAL and shall include: the docket number, if known; the date on or about which the annual Evaluation Report is to be filed; the effective date of Rider FRP rates; reference to the RPPs and these protocols for persons interested in intervening, making a limited appearance, or submitting public comments in writing or orally at the hearing; deadlines for intervention as provided herein; the name, address, phone


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number and email address of the Secretary of the Commission and the URL address of the Commission website; and that further information may be obtained by contacting the Secretary of the Commission or viewing the Commission’s website.

C. Public notice shall be given by any method including but not limited to: bill notation, direct mail, email exploder list, publication on EAL’s website, through social media, or publication in a newspaper of general circulation in EAL’s service area.

D. An annual Evaluation Report filing shall include a declaration that these notice provisions have been complied with.

3. Intervention

A. A Petition to Intervene shall be filed within ten (10) calendar days from the date the annual Evaluation Report is filed.

B. Any Party desiring to file a Response to a Petition to Intervene shall file the Response within five (5) calendar days of the filing of the Petition. No additional responses or replies shall be permitted unless specifically authorized by the Commission.

C. The Commission shall rule on the Petition to Intervene within seven (7) calendar days from the date the Petition is filed. If the Commission does not rule within that time frame, the Petition to Intervene shall be deemed denied.

4. Discovery

A. Time Within Which to Respond or Object

1. The Party upon whom discovery is sought shall serve a written response orobjection within ten (10) calendar days after service of the discovery. Responsesor objections to requests for admission shall be served within ten (10) calendardays of service of the requests. The Commission may prescribe a shorter or longertime. Any objections shall state the specific reasons for such objection.

2. If the response to the discovery request contains protected information for whichno Protective Order has been issued, the responsive Party shall apply for aProtective Order as soon as reasonably practicable after receipt of the discoveryrequest so as to avoid any delays in responding to discovery, and to the greatestextent practicable no later than five (5) calendar days after receipt of the discoveryrequest. EAL shall respond to the discovery request on the next business dayafter the Protective Order is issued or on the date the discovery response is due.

B. Discovery Initiation

Unless otherwise ordered, a Party may initiate discovery at any time after filling of an annual Evaluation Report so long as responses or objections and depositions shall be completed at least sixty (60) days before the date on which rates determined by the


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formula rate review mechanism will go into effect for each year or ten (10) days before a hearing on the merits, whichever is earlier.

C. Service and Format

1. Service shall be made by electronic mail, facsimile transmission, hand delivery, orovernight delivery service unless unusual circumstances otherwise justify deliveryby another method and the Parties agree to the method chosen.

2. Attachments to documents shall be provided in native electronic format, withformulae and viable links intact.

3. Any discovery document served electronically or by facsimile after CommissionBusiness Hours but before midnight or received on a non-business day shall bedeemed served on Persons on the Official Service List with electronic mail on thenext business day. Any discovery document served electronically or by facsimilebetween midnight and the beginning of Commission Business Hours on a businessday shall be deemed served on Persons on the Official Service List on thatbusiness day. Any discovery document served by hand delivery or overnightdelivery service shall be deemed served pursuant to Rule 3.07 of the RPPs.

D. Computation of Time for Performance or Response

In computing the time within which an act must be performed or a response made, the Day of the act from which the designated period of time begins to run shall not be included and the last Day shall be included unless it is a Saturday, Sunday, Legal Holiday, or other Day in which the Commission’s office is closed, in which event the period shall extend to the next business Day. Service by mail or commercial delivery service is prohibited; therefore no additional response time as contemplated by the RPPs is necessary.

5. General Filing Matters

A. Beginning with the initial annual Evaluation Report filing after Rider FRP is approved by the Commission in Docket No. 15-015-U, a separate docket shall be established by the Secretary of the Commission for the annual Evaluation Report filings with an “FR” docket designation.

B. The initial and all subsequent annual Evaluation Reports filed in the “FR” docket. EAL shall submit the annual Evaluation Report with a Commission-approved tariff Docket Summary Cover Sheet. In addition to any other information required by the coversheet, EAL shall reference Docket No. 15-015-U.

C. Stipulations or Settlements

1. Parties shall propose by written motion that the Commission adopt stipulations orsettlements. Such motion shall be filed, along with supporting testimony, no laterthan seven (7) calendar days prior to the hearing scheduled in the annualEvaluation Report filing. If the seventh day falls on a weekend or state holiday


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such settlement agreement and supporting testimony shall be filed on the last business day prior to the seventh day. The motion shall set forth the factual, legal, policy, and other consideration which form the basis for the Parties’ recommendation that the stipulation or agreement be adopted and shall be supported by written testimony.

2. A Party not joining a proposed stipulation or settlement may file a response nolater than five (5) calendar days prior to the scheduled date of the hearing.

3. Such a response shall set forth the factual, legal, policy, and other considerationwhich form the basis for the Party’s opposition to the proposed stipulation orsettlement or portions thereof.

Section II. Advanced Supporting Information

Beginning with the 2021 Evaluation Report, the following information shall be provided, to the extent practicable, to eligible Parties depending on their ability to review highly sensitive protected information forty-five (45) days in advance of the annual Evaluation Report filing:

1. Information regarding EAL’s construction projects and purchases that closed toplant during the Historical Year.

2. To the extent reasonably practicable, EAL shall provide an overview of itsplanned distribution projects describing its projected year planned distributionunadjusted investment and expenses.

Section III. Filing Requirements

1. Testimony and Exhibits

A. Testimony with or without Exhibits shall be filed simultaneously with the annual Evaluation Report and address, at a minimum:

1. A description of the filed schedules and all of the adjustments proposed;

2. A description of any significant cost drivers;

3. A description of any changes in accounting policies, practices, and proceduresif they affect inputs to Rider FRP or the rate redetermination to be made underRider FRP; and

4. A narrative explanation of the rate impact.

2. Workpapers and Supporting Documentation

A. The annual Evaluation Report and any revisions thereto shall include:

1. Data-populated schedules including fully functioning EXCEL spreadsheet withall formulas and links intact, showing all calculations in the annual EvaluationReport;


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2. Sufficient information to enable the Parties to replicate the calculation of theformula results from the applicable schedules; and

3. Documentation fully supporting all calculations and adjustments.

B. Workpapers shall be provided to the Parties simultaneously with the filing of the annual Evaluation Report and any revisions thereto, and shall include:

1. All supporting calculations and documents that explain the calculations in theannual Evaluation Report;

2. Both references to and support from detailed source information; and

3. A complete description of any statistical model used, the data used, and theresults of the analysis if not addressed in testimony or exhibits.

C. With respect to any change in accounting that affects inputs to Rider FRP or the resulting rate redetermination to be billed under Rider FRP, EAL shall identify and provide narrative explanation of the individual impact of such changes on rate redetermination to be billed under Rider FRP including:

1. The initial implementation of an accounting standard or policy;

2. The initial implementation of accounting practices for unusual or unconventionalitems where the Commission has not provided specific accounting direction;

3. Correction of errors and prior period adjustments that impact Rider FRP;

4. The implementation of new estimation methods or policies that change priorestimates; and

5. Changes to income tax elections.

D. EAL shall identify any reorganization or merger transaction and explain the effect of the accounting for such transaction(s) on the inputs to Rider FRP or the resulting rate determination to be billed under Rider FRP.

3. Waiver of Requirements

EAL may omit specific items of information from the annual Evaluation Report filing only with prior Commission approval.

4. Filing Deficiencies

A. The Arkansas Public Service Commission General Staff (“Staff”) may review each annual Evaluation Report filing to ascertain whether it complies with the provisions of these Filing Requirements and Rider FRP, including the provisions of all of the Attachments thereto.

B. If Staff determines that any deficiencies exist Staff shall file a notice detailing the deficiencies within seven (7) calendar days from the date the annual Evaluation Report is filed.


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C. EAL shall correct the deficiencies, within seven (7) calendar days of filing of the notification of deficiency, or upon objection being filed by EAL within that timeframe; the Commission may set a longer period as may be reasonable.

D. Staff shall review corrections made by EAL to determine compliance with all information required by the Filing Requirements and Rider FRP, including the provisions of all of the Attachments thereto.

E. No more than three (3) business days from the filing of corrections, Staff may file a (1) statement of compliance or (2) a second notice of deficiencies, listing each requirement not met and a brief explanation in support.

F. The Commission shall resolve any dispute as to deficiencies within seven (7) calendar days of the filing of the second notice of deficiencies by either accepting the corrections made by EAL or by directing additional corrections to be filed by EAL.

5. Dispute Procedures

A. Any Party filing with the Commission a statement of errors or objections to the Evaluation Report shall file Testimony with or without Exhibits simultaneously with the statement of errors or objections and the filing shall:

1. Clearly identify and explain the error in or objection to the annual EvaluationReport;

2. Make a good faith effort to quantify the financial impact of the error or objection;

3. State specifically any proposed changes to the annual Evaluation Report thatthe Party recommends; and

4. Include all documents and workpapers that support the calculation of the erroror the facts supporting the objection.

B. EAL shall file a corrected Rider FRP rate or Rebuttal Testimony with or without Exhibits to the errors and objections raised by the Parties.

6. Extension of Term

A. If EAL requests an extension of the initial term of Rider FRP, EAL shall include such request as part of its fifth annual Evaluation Report filing. Pursuant to Ark. Code Ann. § 23-4-1208(a)(2)(A)(ii)(a), the Commission shall grant such an Extension of Term for five (5) years after the initial term of Rider FRP.


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B. EAL shall provide a class cost of service study for forecasted year-end 2021.

C. The Commission shall enter a decision on EAL’s request no later than February 1, 2021.


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Title: Internal Restructuring Credit Rider (IRCR) PSC File Mark Only


46.0. INTERNAL RESTRUCTURING CREDIT RIDER

46.1. PURPOSE

The purpose of this rider is to provide retail customers with guaranteed credits associated with the internal restructuring approved by the Arkansas Public Service Commission.

46.2. APPLICATION

IRCR applies to all electric service provided under any rate schedule, whether metered or unmetered, including rates under Special Contracts, subject to the jurisdiction of the Arkansas Public Service Commission.

In addition to the rates and charges applicable to service under other rate schedules and riders, monthly base rate billings will be reduced by the percentage rates on Attachment A to this IRCR. These percentage rates shall become initially effective with the first billing cycle of January, 2019 and subsequently adjusted IRCR percentage rates shall be effective with the first billing cycle of January each year. Monthly billing will continue through cycle 21 of the December, 2024 billing month.

46.3. ANNUAL REVISION

A. EAL shall determine revised IRCR percentage rates annually and file a revised Attachment A containing such revised percentage rates with the Commission on or before November 1 of each year. Such revised percentage rates will be based on the most recent revenue forecast for the effective year.

B. The Commission Staff shall then have until December 15 to review the annual revisions to Attachment A. If any errors are detected, they shall be communicated to EAL by the Commission Staff in writing on or before December 15. EAL shall then have until December 31 to prepare and file a corrected Attachment A with the Commission.

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Docket No.: 17-052-U


Attachment A Rate Schedule No. 46 Schedule Sheet 2 of 2


Internal Restructuring Credit

In addition to the rates and charges applicable to service under other rate schedules and riders, monthly base rate billings will be reduced by the percentage rates below:

Rate Class Rate Schedules IRCR % Credit

Residential RS, RT, REMT -0.5123% Small General Service SGS, GFS, MP, AP, CTV,

SMWHR, CGS, TSS -0.5232% Large General Service LGS, GST, LPS, PST, SSR,

Special Contracts -0.4655% Lighting L1, L4, L1SH -0.4858%

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Title: Capacity Cost Recovery Rider (CCR) PSC File Mark Only


47.0. CAPACITY COST RECOVERY RIDER


The Arkansas Legislature has delegated authority to the Arkansas Public Service Commission (“APSC” or the “Commission”) to regulate public utilities in the State of Arkansas, including Entergy Arkansas, LLC (“EAL” or the “Company”). The APSC’s regulatory authority over the provision of electric service applies not only in the Distribution Service area allocated to EAL by the APSC but also extends service to customers who have been released to EAL by other electric distribution utilities, when such release for service has been approved by the Commission pursuant to Rule 6.07(b) or (c) of the Commission's Rules of Practice and Procedure. Similarly, the Tennessee Regulatory Authority exercises such authority delegated to it by the Tennessee Legislature in areas of the State of Tennessee served by EAL.

47.2. PURPOSE

The purpose of this Capacity Cost Recovery Rider (“Rider CCR”) is to recover from EAL’s retail customers, the cost of purchases of retail capacity1 and to credit EAL’s retail customers with the revenue associated with sales of EAL’s retail capacity, if any. Rider CCR shall apply in accordance with the provisions of § 47.3 below to electric service billed under certain rate schedules, whether metered or unmetered. The initial Rider CCR shall be effective with the first billing cycle for the March 2014 billing month for the collection of costs for the twelve-month period of January 2014 through December 2014. Subsequent Rider CCR redeterminations shall be completed in accordance with the provisions of § 47.4 below.

47.3. CAPACITY RATES

The capacity cost recovery rates (“Capacity Rates”) shall be set forth in Attachment A to this Rider CCR.

47.4. ANNUAL DETERMINATION

The initial determination shall be in compliance with any retail capacity purchases and any sales of retail capacity that meet the criteria established in Paragraph 47.2 as of January 1, 2014. The Capacity Rates shall be set out in Attachment A as determined by application of the Capacity Rate Formula set out in Attachment B to this Rider CCR. This redetermination shall include the reporting requirements as ordered in Commission Order No. 21, Docket No. 13-028-U.

On or about November 1 of each year beginning in 2014, the Company shall file re-determined Capacity Rates with the Commission to reflect any purchases or sales of retail capacity since the last Capacity Rate determination. The Capacity Rates, as set out in Attachment A, shall be determined by application of the Capacity Rate Formula set out in Attachment B to this Rider

1 Pursuant to Order No. 21 in Docket No. 13-028-U, capacity purchases with terms greater than 1 year require Commission pre-approval for recovery.

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Title: Capacity Cost Recovery Rider (CCR) PSC File Mark Only


CCR. The purchased capacity costs shall be based on the projected cost to be incurred over the twelve-month period beginning on January 1 of the year following the filing (“Test Year”) and shall be calculated in accordance with the formula set out in Attachment B to this Rider CCR. The Capacity Rates so determined shall be effective for bills rendered on and after the first billing cycle of January the year following the filing and shall remain in effect until updated.

Beginning in 2015, a True-up Adjustment shall be reflected in the Rider CCR revenue requirement. The True-up Adjustment shall be defined as the difference between the prior year actual purchased capacity revenue requirement and the prior year actual purchased capacity revenues as determined pursuant to Attachment B of this Rider CCR. The true-up adjustment shall also include any prior year net over/under recovery of the Capacity Cost Recovery rates.

Capacity Rates shall be filed by the Company in the most recent base rate proceeding and shall be accompanied by a set of workpapers sufficient to document fully the calculations of the redetermined Capacity Rates including any potential True-up Adjustment.


If the Company’s change in capacity purchases and/or sales subject to this Rider CCR exceeds 10 percent, then either the APSC General Staff or the Company may propose an interim adjustment to the then currently effective Capacity Rates.

47.6. STAFF AND COMMISSION REVIEW

Staff shall review the as filed Capacity Rates to verify that the formula in Attachment B has been correctly applied and shall notify the Company of any necessary corrections. After the Staff completes its review of the rate calculation, the Company shall make appropriate changes to correct undisputed errors identified by the Staff in its review. Any disputed issues arising out of the Staff review are to be resolved by the Commission after notice and hearing. The Capacity Rates shall go into effect, upon Commission approval, with the first billing cycle of the following January.

47.7. TERM

This Rider CCR shall remain in effect until terminated in accordance with applicable regulations or laws.

This Rider CCR shall continue in effect in order to recover any potential changes in the Company’s capacity purchases and or sales subject to this Rider CCR that may occur in the future along with adjusting rates as these purchased capacity contracts terminate. If this Rider CCR is terminated by a future order of the Commission, the Capacity Rates shall continue to be in effect until such costs are recovered through another mechanism or until the implementation of new base rates reflecting such costs.

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EAL Supplemental Direct Exhibit Supporting CCR Annual Redetermination SMC-1

Rider CCR Rates

Docket 15-015-UDocket No.: 15015—6619e 1 of 6Order No.:Effective: 12/31/20

Attachment A toRate Schedule No. 47Attachment Page 1 of 1Schedule Sheet 3 of 5Including Attachments

The Net Monthly Rates set forth in EAL’s schedules identified below will be adjusted by the following RateAdjustment amounts:

Rate Class Rate SchedulesApplicable Rate

Residential

Small General Service

Large General Service

Lighting

RS, RT, REMT

SGS, GFS, TSS, MP, AP,CGS, CTV, SMWHR

LGS, LPS, GST, PST,SSR

L1, L1SH, L4

($0.000010) per kWh

($0.000011) per kWh

($0.002409) per kW

($0.000005) per kWh

13THIS SPACE FOR PSC USE ONLY


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EAL Supplemental Direct Exhibit Supporting CCR Annual Redetermination SMC-1

Docket No.: 15-815-Order No.:Effective:

t15-015-Uage 2 of6

12/31/20

Attachment B toRate Schedule No. 47Attachment Page 1 of 2Schedule Sheet 4 of 5Including Attachments

Entergy Arkansas, LLC2020 Capacity Cost Recovery Rider (CCR)

Revenue Requirement Summary and Rate Development

Class Allocation & Rate Development

LineNo.

Class Capacity Projected BillingClass Revenue Units

Allocator Reqmt ($) (3)(1) (2)

Rate Adjustment(4)

(11-w

4

EAL Retail

Residential 43.8481 % ($76,931) 7,762,972,784 kWh

Small General Service 27.9813% (49,093) 4,279,253,780 kWh

Large General Service 27.4291% (48,124) 19,974,451 kW

Lighting 0.7416% (1,301) 267,491,472 kWh

Total EAL Retail 100.0000% ($175,449)

$0.000010) per kWh$0.000011) per kWh$0.002409) per kW

(((($0.000005) per kWh

Notes:

(1) The Rate Class Allocator shall be based on the Rate Class Retail Production Demand Allocation Factorapproved in the company’s most recent retail rate case.

(2) Attachment B, Page 2, Line 9 * Class Allocator

(3) Projected Billing Units by Rate Class.

(4) Class Capacity Revenue Requirement/ Projected Billing Units

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EAL Supplemental Direct Exhibit Supporting CCR Annual Redetermination SMC-1t 15-015-U

Docket No.: 15-815- age 3 of 6Order No.:Effective: 12/31/20


Entergy Arkansas, LLC2020 Capacity Cost Recovery Rider (CCR)

Revenue Requirement

Line

No. DescriptionAmount

($)|. Retail Purchased Capacity

Net Retail Purchased Capacity Costs (A)

Revenue Related Expense Factor (B)

Purchased Capacity Revenue Requirement (Ln1 * Ln2)

||. True-up Adjustment (C)

Prior Year Actual Net Retail Purchased Capacity Costs

Revenue Related Expense Factor

Prior Year Actual Purchased Capacity Revenue Requirement (Ln4 * Ln5)

Prior Year Actual Rider CCR Revenues

Current Year True-up Adjustment (Ln6 — Ln7)

Total Rider CCR Revenue Requirement (Ln3+Ln8)

(769,504)

99.7845%

(767,845)

(318,493)99.7845%(317,807)

(910,204)

592,396

(175,449)

Notes:

(A) Cost of purchased capacity incurred by the Company for purchases of retail capacity contractsoffset by revenue from sales of retail capacity, if any, that are known and measurable as of the dateRider CCR is filed. Pursuant to Order No. 21 in Docket No. 13-028-U, capacity purchases withterms greater than 1 year require Commission pre-approval for recovery.

(B) Revenue Related Expense Factor = 1 / (1-Arkansas Retail Bad Debt Rate + Forfeited DiscountRate). The Arkansas Retail Bad Debt Rate and the Forfeited Discount Rates shall be developedconsistent with the methodology utilized for calculating them in the most recent EAL general ratecase and shall be based on the most recently available calendar year data at the time of the filing.

(C) Beginning in 2015, a True-up Adjustment shall be reflected in the Rider CCR revenue requirement. 15



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Title: Production Cost Allocation Rider (PCA) PSC File Mark Only


48.0 PRODUCTION COST ALLOCATION RIDER

48.1 REGULATORY AUTHORITY

The Arkansas Legislature has delegated authority to the Arkansas Public Service Commission (“APSC” or the “Commission”) to regulate public utilities in the State of Arkansas, including Entergy Arkansas, LLC (“EAL” or the “Company”). The APSC’s regulatory authority over the provision of electric service applies not only in the Distribution Service area allocated to EAL by the APSC but also extends to service to customers who have been released to EAL by other electric distribution utilities, when such release for service has been approved by the Commission pursuant to Rule 6.07(b) or (c) of the Commission's Rules of Practice and Procedure. Similarly, the Tennessee Regulatory Authority exercises such authority delegated to it by the Tennessee Legislature in areas of the State of Tennessee served by EAL.

48.2 PURPOSE

The purpose of this Production Cost Allocation Rider (“Rider PCA”) is to recover, from EAL’s retail customers, the retail allocation of the Company’s annual payments/receipts (“FERC Allocation”) to/from the other Entergy Operating Companies1 as directed in Docket No. EL01-88-001, Opinion Nos. 480 and 480-A, and any subsequent modification thereof (“FERC Decision”), excluding any refunds that the Federal Energy Regulatory Commission may possibly order to be paid by EAL to the other Entergy Operating Companies in Docket No. EL01-88-000. Rider PCA shall recover from retail customers any payments made or return to retail customers any receipts received pursuant to the FERC Allocation unless and to the extent those payments or receipts are expressly reflected in base rates or another EAL retail rider. Rider PCA shall apply in accordance with the provisions of § 48.3 below to electric service billed under certain rate schedules, whether metered or unmetered.

48.3 PRODUCTION COST ALLOCATION RATES

The Production Cost Allocation rates (“PCA Rates”) shall be set forth in Attachment A to this Rider PCA.

48.4 ANNUAL DETERMINATION

On or about June 21, 2007 and thereafter on or about June 1 each year, beginning in 2008, the Company shall file PCA Rates with the Commission. The PCA Rates, as set out in Attachment A, shall be determined by application of the formula (“PCA Rate Formula”) set out in Attachment B and Attachment C to this Rider PCA. The PCA Rates so determined shall be effective for bills rendered on and after the first billing cycle for July of the filing year and shall remain in effect until

1 The Entergy Operating Companies include the following or their successors: Entergy Arkansas, LLC; Entergy Texas, Inc.; Entergy Louisiana, LLC; Entergy Mississippi, LLC; and Entergy New Orleans, LLC

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Title: Production Cost Allocation Rider (PCA) PSC File Mark Only


updated. Each such set of PCA Rates shall be filed in the proper underlying docket and shall be accompanied by a set of workpapers sufficient to fully document the calculations of the redetermined PCA Rates.

Redetermined PCA rates shall reflect the retail allocation of any payments or receipts relating to the FERC Allocation together with a true-up adjustment reflecting the over- or under-recovery on the last day of June in the filing year. Any over- or under-recovery balance for each rate class will be decreased or increased by monthly carrying charges based on the interest rate ordered by the Commission to be paid on utility service customer deposits by the Company. The cumulative over- or under-recovery for each rate class as of the last day of June in the filing year shall be subtracted from or added to the rider level for the corresponding rate class in the annual Redetermination.

48.5 INTERIM ADJUSTMENT

Should a cumulative over-recovery or under-recovery balance arise which exceeds 55 percent of the APSC jurisdictional portion of the annual FERC Allocation included in the most recently filed rate redetermination under this Rider PCA, then either the APSC General Staff or the Company may propose an interim revision to the then currently effective PCA Rates.

48.6 TERM

This Rider PCA shall remain in effect subject to eighteen months advance notice of termination by the Commission following notice and hearing.

When this Rider PCA expires or is terminated by a future order of the Commission, the PCA Rates shall continue in effect until such costs are reflected for recovery under another mechanism or until the implementation of new base rates reflecting such costs.

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Docket No.: 15-015-U Order No.: Effective: 6/30/21 Attachment A to Rate Schedule No. 48 Page 1 of 1


Rider PCA Rates


Rate Class

Rate Schedules

Total PCA Rate Adjustment

Residential RS, RT, REMT $0.00020 per kWh Small General Service SGS, GFS, TSS, MP,

AP, CGS, CTV, SMWHR

$0.00026 per kWh

Large General Service LGS, LPS, GST

PST, SSR $0.00011 per kWh

Lighting L1, L1SH, L4 $0.00006 per kWh

EAL Supplemental Exhibit JTT-1Docket No. 15-015-U

Page 1 of 4

Rider PCA Rates


Docket No.: 15-015-U Page 1 of4Order No.:Effective: 6/30/21

Attachment A toRate Schedule No. 48Page 1 of 1


Rate Class Rate SchedulesTotal PCA

Rate Adjustment

Residential



Lighting

RS, RT, REMT

SGS, GFS, TSS, MP,AP, CGS, CTV,SMWHR

LGS, LPS, GSTPST, SSR

L1, L1SH, L4

$0.00020 per kWh

$000026 per kWh

$0.0001’l per kWh

$0.00006 per kWh


13

Rider PCA Rates


Docket No.: 15-015-U Page 1 of4Order No.:Effective: 6/30/21

Attachment A toRate Schedule No. 48Page 1 of 1


Rate Class Rate SchedulesTotal PCA

Rate Adjustment

Residential



Lighting

RS, RT, REMT

SGS, GFS, TSS, MP,AP, CGS, CTV,SMWHR

LGS, LPS, GSTPST, SSR

L1, L1SH, L4

$0.00020 per kWh

$000026 per kWh

$0.00011 per kWh

$0.00006 per kWh


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Docket No.: 15-015-U Order No.: Effective: 6/30/21 Attachment B to Rate Schedule No. 48 Page 1 of 1


Rider PCA Rate Calculation

Rate Class

RFAL By Class1

Class kWh2

Rate Adjustments3

Residential $1,512,060 7,700,124,884 $0.00020 per kWh Small General Service $1,092,973 4,288,186,919 $0.00026 per kWh Large General Service $1,067,046 9,838,775,144 $0.00011 per kWh Lighting $16,452 276,430,159 $0.00006 per kWh Total $3,688,531 22,103,517,107

Notes: (1) FERC Allocation Level (RFAL) for each rate class from Attachment C (2) Projected class billed kWh for the 12 month period beginning July 2021 through June 2022. (3) (RFAL By Class) / Class kWh


Page 2 of 4


Docket No.: 15-015-U Page 2 Of 4Order No.:Effective: 6/30/21

Attachment B toRate Schedule No. 48Page 1 of 1


RFAL ClassRate Class By Class1 kt Rate Adjustments3

Residential $1,512,060 7,700,124,884 $000020 per kWhSmall General Service $1,092,973 4,288,186,919 $000026 per kWhLarge General Service $1,067,046 9,838,775,144 $000011 per kWhLighting $16,452 276,430,159 $000006 per kWhTotal $3,688,531 22,103,517,107

Notes:

(1) FERC Allocation Level (RFAL) for each rate class from Attachment C(2) Projected class billed kWh for the 12 month period beginning July 2021 through June 2022.(3) (RFAL By Class) / Class kWh


14


Docket No.: 15-015-U Page 2 Of 4Order No.:Effective: 6/30/21

Attachment B toRate Schedule No. 48Page 1 of 1


RFAL ClassRate Class By Class1 kt Rate Adjustments3

Residential $1,512,060 7,700,124,884 $000020 per kWhSmall General Service $1,092,973 4,288,186,919 $000026 per kWhLarge General Service $1,067,046 9,838,775,144 $000011 per kWhLighting $16,452 276,430,159 $000006 per kWhTotal $3,688,531 22,103,517,107

Notes:

(1) FERC Allocation Level (RFAL) for each rate class from Attachment C(2) Projected class billed kWh for the 12 month period beginning July 2021 through June 2022.(3) (RFAL By Class) / Class kWh


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Attachment C to Rate Schedule No. 48 Page 1 of 2


PRODUCTION COST ALLOCATION RATE FORMULA

RFALi = FERC ALLOCATION LEVEL FOR RATE CLASS i

RFALi = [(AFA* EAFai ) + TUAi] * (1 + RCFi)

WHERE,

AFA = ANNUAL FERC ALLOCATION PAYMENT/RECEIPT (1)

EAFai = RETAIL ENERGY ALLOCATION FACTOR FOR RATE CLASS i FOR THE PRODUCTION COST ALLOCATION PERIOD ADJUSTED FOR KNOWN AND MATERIAL CUSTOMER CHANGES (2) (3)

RCFi = REVENUE CONVERSION FACTOR FOR RATE CLASS i (4)

TUAi = TRUE-UP ADJUSTMENT FOR RATE CLASS i FOR THE PRODUCTION COST ALLOCATION PERIOD INCLUDING CARRYING CHARGES (5)

TUAi = COUBij + ICBij

WHERE,

COUBij = CUMULATIVE (OVER)/UNDER-RECOVERY BALANCE FOR RATE CLASS i FOR MONTH j OF THE PRODUCTION COST ALLOCATION PERIOD

COUBij = FAj * EAFbi – PCARij / (1 + RCFi) + OUBFij

WHERE,

FAj = FERC ALLOCATION FOR MONTH j OF THE PRODUCTION COST ALLOCATION PERIOD

EAFbi = UNADJUSTED RETAIL ENERGY ALLOCATION FACTOR FOR RATE CLASS i FOR THE PRODUCTION COST ALLOCATION PERIOD (6)

PCARij = REVENUE UNDER RIDER PCA FOR RATE CLASS i IN MONTH j OF THE PRODUCTION COST ALLOCATION PERIOD PLUS AN IMPUTED LEVEL OF REVENUES FOR SALES UNDER SPECIAL RATE CONTRACTS WHERE THE PRODUCTION COST ALLOCATION IS NOT SEPARATELY BILLED (7)

RCFi = REVENUE CONVERSION FACTOR FOR RATE CLASS i (4)

OUBFij = (OVER)/UNDER-RECOVERY BALANCES BROUGHT FORWARD APPLICABLE FOR RATE CLASS i FOR MONTH j OF THE PRODUCTION COST ALLOCATION PERIOD

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Attachment C to Rate Schedule No. 48 Page 2 of 2


ICBij = CUMULATIVE INTEREST BALANCE FOR RATE CLASS i FOR MONTH j OF THE PRODUCTION COST ALLOCATION PERIOD

ICBij = (BCOUBj + ECOUBj) / 2 * CCR + IBFij

WHERE,

BCOUBj = BEGINNING CUMULATIVE OVER/(UNDER)-RECOVERY BALANCE FOR MONTH j (EXCLUDING CARRYING CHARGES)

ECOUBj = ENDING CUMULATIVE OVER/(UNDER)-RECOVERY BALANCE FOR MONTH j (EXCLUDING CARRYING CHARGES)

CCR = MONTHLY CARRYING CHARGE RATE (5)

IBFij = INTEREST BALANCES BROUGHT FORWARD APPLICABLE FOR RATE CLASS I FOR MONTH j OF THE PRODUCTION COST ALLOCATION PERIOD

Notes: (1) The Annual FERC Allocation Payment/Receipt is EAL’s annual payment/receipt to/from the other

Entergy Operating Companies pursuant to the FERC Decision. (2) The Production Cost Allocation Period is the 12 month period ending 4 months prior to the filing date

(a June filing would use 12 months ending February data). (3) EAFai is calculated using actual energy usage for rate class i for the Production Cost Allocation Period

adjusted for known and material customer changes. (4) The revenue conversion factor shall be equal to 1 / (1 – Bad Debt Rate + Forfeited Discount Rate).

The Bad Debt Rate is calculated by dividing the net bad debt expenses for each rate class by the corresponding rate schedule revenues for the prior calendar year. The Forfeited Discount Rate is calculated by dividing the revenues recorded in Account 450 – Forfeited Discounts for each rate class by the corresponding rate schedule revenues for the prior calendar year.

(5) Monthly carrying charges shall be calculated on the average beginning and ending over/(under)-recovery balances, excluding carrying charges, using the Commission approved customer deposit simple interest rate for the period divided by 12.

(6) EAFbi is calculated using actual energy usage for rate class i for the Production Cost Allocation Period.

(7) PCARij shall include 12 months of actual data for March – February for the Production Cost Allocation Period and 4 months of estimated data for March – June of the filing year.

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Title: Storm Recovery Charges Rider (SRC) PSC File Mark Only


50.0. STORM RECOVERY CHARGES RIDER

50.1. APPLICATION

This rider is applicable under the regular terms and conditions of Entergy Arkansas, LLC to all existing and future customers located within the Company’s service area as it existed on the date of Commission approval of this Rider, or within any expansion thereof, taking electric service over the transmission or distribution facilities of the Company. The initial Storm Recovery Charges rates shall be billed no earlier than the first day of the revenue month billing cycle following the date of issuance of the Storm Recovery Bonds authorized by the Commission in the Docket indicated above. The initial Storm Recovery Charges Rider rate calculation shall be based upon and reflect the terms of, and payments to be made pursuant to, the Storm Recovery Bonds together with ongoing financing costs.


There shall be added to each monthly bill an adjustment, in the form of a new and separate Storm Recovery Charge, for the recovery of storm restoration costs and bond financing costs as approved by the Commission. Customers’ monthly bills shall include specific charges as shown in Attachment A.

50.3. TRUE-UP

The Storm Recovery Charges Rider rates shall be subject to true-up in accordance with the schedule prescribed in the Commission’s financing order and shall be performed at least semi-annually, in order to:

(a) correct any under-collections or over-collections, for any reason, during the preceding six months; and

(b) to ensure the projected recovery of amounts sufficient to provide timely payment of the scheduled principal of and interest on the Storm Recovery Bonds and all ongoing financing costs during the two (2) subsequent payment periods (approximately twelve months).

To the extent any Storm Recovery Bonds or ongoing financing costs remain outstanding after the scheduled maturity date of the last bond tranche or class, mandatory true-up adjustments shall be made quarterly until all Storm Recovery Bonds and ongoing financing costs are paid in full.

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Title: Storm Recovery Charges Rider (SRC) PSC File Mark Only


True-up filings made by the Company will be based upon the scheduled principal and interest payments on the Storm Recovery Bonds and ongoing financing costs payments (together known as Periodic Payment Requirements or PPR) and the cumulative differences, regardless of the reason, between Storm Recovery Charge collections and the actual amounts paid for scheduled principal and interest payments on the storm recovery bonds and ongoing financing costs. True-up procedures are necessary to ensure full recovery of amounts sufficient to meet on a timely basis the PPR over the expected life of the Storm Recovery Bonds. In order to assure adequate storm recovery charge revenues to fund the PPR and to avoid large overcollections and undercollections over time, the servicer will reconcile the storm recovery charges using EAL’s most recent forecast of electricity deliveries (i.e., forecasted billing determinants) and estimates of transaction-related expenses (i.e., ongoing financing costs). The calculation of the storm recovery charges will also reflect a projection of uncollectible storm recovery charges based upon EAL’s most recent experience regarding collections.

662


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Attachment A to Rate Schedule No. 50 Page 1 of 1: Schedule Sheet 3 of 3 Including Attachment


RIDER SRC ATTACHMENT A

Monthly billings to all EAL retail customers shall include Storm Recovery Charge amounts pursuant to the following rates applied to billed kilowatt-hours or kilowatts whether metered or unmetered:

SRC Rate Class Monthly Rate

Residential $0.00000 per kWh

Small General Service $0.00000 per kWh

Large General Service $0.00000 per kW

Lighting $0.00000 per kWh








Title: Government Mandated Expenditure Surcharge Rider (GMES) PSC File Mark Only


51.0. GOVERNMENT MANDATED EXPENDITURE SURCHARGE RIDER

51.1. APPLICATION

To all electric service provided under any rate schedule, whether metered or unmetered, including rates under Special Contracts, subject to the jurisdiction of the Arkansas Public Service Commission.

In addition to the rates and charges applicable to service under other rate schedules and riders, the following listed surcharges shall be applied to customers’ billings on and after February 28, 2014. These surcharges reflect the jurisdictional revenue requirement associated with governmental mandated expenditures and are imposed pursuant to the provisions of Act 310 of 1981, as amended.

The inclusion of any costs via this surcharge shall not be deemed a finding that the costs are necessary and appropriate or in the public interest. The prudency of such costs shall be addressed in the Company’s next general rate case proceeding. If any costs via this surcharge are not found prudent in the Company’s next general rate case proceeding, then the applicable surcharge collections will be refunded with interest.


Residential RS, RT, REMT $0.000000 per kWh Small General Service SGS, GFS, MP, AP, CTV,

SMWHR, CGS, TSS $0.000000 per kWh Large General Service LGS, GST, LPS, PST, SSR $0.000000 per kWh Lighting L1, L4, L1SH $0.000000 per kWh

664


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ARKANSAS PUBLIC SERVICE COMMISSION 2nd Revised Sheet No. 52.1 Schedule Sheet 1 of 17 Replacing: 1st Revised Sheet No. 52.1 Entergy Arkansas, LLC Name of Company Kind of Service: Electric Class of Service: As Applicable Docket No.: 16-027-R Order No.: 35 Part III. Rate Schedule No. 52 Effective: Title: Net-Metering Service (N-M) PSC File Mark Only


TABLE OF CONTENTS Definitions ......................................................................................................................... 52.1 Tariff Provisions ................................................................................................................ 52.1 Preliminary Interconnection Site Review Request ........................................................... 52.5

Standard Information ........................................................................................... 52.5 Terms and Conditions ......................................................................................... 52.6

Standard Interconnection Agreement for Net-Metering Facilities .................................... 52.8 Standard Information ........................................................................................... 52.8 Interconnection Agreement Terms and Conditions ............................................. 52.10

Disclaimer ......................................................................................................................... 52.17

52.0. NET-METERING 52.1. DEFINITIONS 52.1.1. Avoided Cost – As defined in A.C.A. 23-18-603(1). 52.1.2. Net Metering – As defined in A.C.A. 23-18-603(6). 52.1.3. Net-Metering Customer – As defined in A.C.A. 23-18-603(7). 52.1.4. Net-Metering Facility – As defined in A.C.A. 23-18-603(8). 52.1.5. Electric Utility – As defined in A.C.A. 23-18-603(3). 52.1.6. Net Excess Generation – As defined in A.C.A. 23-18-603(5). 52.1.7. Renewable Energy Credit – As defined in A.C.A. 23-18-603(10). 52.1.8. Quantifiable Benefits – As defined in A.C.A. 23-18-603(9). 52.2. AVAILABILITY 52.2.1. Service under the provisions of this tariff is available to any residential or any other

customer who takes service under standard rate schedule(s) General Purpose Residential Service (RS), Optional Residential Time-Of-Use (RT), Residential Energy Management Time-Of-Use (REMT), Small General Service (SGS), Nonresidential General Farm Service (GFS), Agricultural Water Pumping Service (AP) Optional Monthly Rate (B), Large General Service (LGS), Large General Service Time-Of-Use (GST), Large Power Service (LPS) or Large Power Service Time-Of-Use (PST) who is a Net-Metering Customer and who has obtained a signed Standard Interconnection Agreement for Net-Metering Facilities with Entergy Arkansas, LLC (“EAL” or the “Company”). The generating capacity of Net-Metering Facilities may not exceed the greater of: 1) twenty-five kilowatts (25 kW) or 2) one hundred percent (100%) of the Net-Metering Customer’s highest monthly usage in the previous twelve (12) months for Residential Use. The generating capacity of Net-Metering

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Kind of Service: Electric Class of Service: As Applicable Docket No.: 16—027-ROrder No.: 35

Part III. Rate Schedule No. 52 Effective:

Title: Net-Metering Service (N-M) P30 ”'5 Mark on'y

TABLE OF CONTENTSDefinitions ......................................................................................................................... 52.1Tariff Provisions ................................................................................................................ 52.1Preliminary Interconnection Site Review Request ........................................................... 52.5

Standard Information ........................................................................................... 52.5Terms and Conditions ......................................................................................... 52.6

Standard Interconnection Agreement for Net-Metering Facilities .................................... 52.8Standard Information ........................................................................................... 52.8Interconnection Agreement Terms and Conditions ............................................. 52.10

Disclaimer ......................................................................................................................... 52.17

52.0. NET-METERING

52.1. DEFINITIONS

52.1.1. Avoided Cost — As defined in A.C.A. 23-18-603(1).

52.1.2. Net Metering — As defined in A.C.A. 23-18—603(6).

52.1.3. Net-Metering Customer — As defined in A.C.A. 23-18-603(7).

52.1.4. Net-Metering Facility — As defined in A.C.A. 23-18—603(8).

52.1.5. Electric Utility — As defined in A.C.A. 23-18—603(3).

52.1.6. Net Excess Generation — As defined in A.C.A. 23-18—603(5).

52.1.7. Renewable Energy Credit — As defined in A.C.A. 23-18-603(10).

52.1.8. Quantifiable Benefits — As defined in A.C.A. 23-18—603(9).

52.2. AVAILABILITY

52.2.1. Service under the provisions of this tariff is available to any residential or any othercustomer who takes service under standard rate schedule(s) General Purpose ResidentialService (RS), Optional Residential Time-Of—Use (RT), Residential Energy ManagementTime-Of—Use (REMT), Small General Service (SGS), Nonresidential General Farm Service(GFS), Agricultural Water Pumping Service (AP) Optional Monthly Rate (B), Large GeneralService (LGS), Large General Service Time-Of—Use (GST), Large Power Service (LPS) orLarge Power Service Time-Of—Use (PST) who is a Net-Metering Customer and who hasobtained a signed Standard Interconnection Agreement for Net-Metering Facilities withEntergy Arkansas, LLC (“EAL” or the “Company”). The generating capacity of Net-Metering Facilities may not exceed the greater of: 1) twenty-five kilowatts (25 kW) or 2)one hundred percent (100%) of the Net-Metering Customer’s highest monthly usage in theprevious twelve (12) months for Residential Use. The generating capacity of Net-Metering


APSC FILED Time: 1/25/2021 2:47:43 PM: Recvd 1/25/2021 2:46:33 PM: Docket 16-027-R-Doc. 546

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Facilities may not exceed one thousand kilowatts (1,000 kW) for non-residential use unless otherwise allowed by the Commission. Net-Metering is intended primarily to offset part or all of the customer’s energy use.

The provisions of the customer’s standard rate schedule are modified as specified herein.

52.2.2. Net-Metering Customers taking service under the provisions of this tariff may not

simultaneously take service under the provisions of any other alternative source generation or co-generation tariff except as provided in the Net-Metering Rules.

52.3. MONTHLY BILLING 52.3.1. The Company shall separately meter, bill, and credit each Net-Metering Facility even if one

(1) or more Net-Metering Facilities are under common ownership. 52.3.2. On a monthly basis, the Net-Metering Customer shall be billed the charges applicable

under the currently effective standard rate schedule and any appropriate rider schedules. Under Net-Metering, only the kilowatt hour (kWh) units of a Net-Metering Customer’s bill are netted.

52.3.3. If the kWhs supplied by the Company exceed the kWhs generated by the Net-Metering

Facility and fed back to the Company during the Billing Period, the Net-Metering Customer shall be billed for the net billable kWhs supplied by the Company in accordance with the rates and charges under the Net-Metering Customer’s standard rate schedule.

52.3.4. For Net-Metering Customers who receive service under a rate that does not include a

demand component, the Company shall credit a Net-Metering Customer with the amount of any accumulated Net Excess Generation as measured in kWh or kWh multiplied by the applicable retail rate in the next applicable billing period and base the bill of the Net-Metering Customer on the net amount of electricity as measured in kWh or kWh multiplied by the applicable retail rate that the Net Metering Customer has received from or fed back to the Company during the billing period.

52.3.5. For Net-Metering Customers who receive service under a rate that includes a demand

component with a generating capacity of 1,000 kW or less, the Company shall credit the Net-Metering Customer with any accumulated Net Excess Generation as measured in kWh in the next applicable billing period and base the bill of the Net-Metering Customer on the net amount of electricity as measured in kWh that the Net-Metering Customer has received from or fed back to the Company during the billing period.

52.3.6. For Net-Metering Customers who receive service under a rate that includes a demand

component with a generating capacity over 1,000 kW and up to 20 MW and who receive approval to exceed the statutory limits under A.C.A. 23-18-604(b)(9), the Company shall credit the Net-Metering Customer with the amount of any accumulated Net Excess Generation as measured in kWh in the next applicable billing period and base the bill of

11







Title: Net-Metering Service (N-M) PSC File Mark Only

52.2.2.

52.3.

52.3.1.

52.3.2.

52.3.3.

52.3.4.

52.3.5.

52.3.6.

Facilities may not exceed one thousand kilowatts (1 ,000 kW) for non-residential use unlessotherwise allowed by the Commission. Net-Metering is intended primarily to offset part orall of the customer’s energy use.

The provisions of the customer’s standard rate schedule are modified as specified herein.

Net-Metering Customers taking service under the provisions of this tariff may notsimultaneously take service under the provisions of any other alternative source generationor co-generation tariff except as provided in the Net-Metering Rules.

MONTHLY BILLING

The Company shall separately meter, bill, and credit each Net-Metering Facility even if one(1) or more Net-Metering Facilities are under common ownership.

On a monthly basis, the Net-Metering Customer shall be billed the charges applicableunder the currently effective standard rate schedule and any appropriate rider schedules.Under Net-Metering, only the kilowatt hour (kWh) units of a Net-Metering Customer’s billare netted.

If the kt supplied by the Company exceed the kt generated by the Net-MeteringFacility and fed back to the Company during the Billing Period, the Net-Metering Customershall be billed for the net billable kt supplied by the Company in accordance with therates and charges under the Net-Metering Customer’s standard rate schedule.

For Net-Metering Customers who receive service under a rate that does not include ademand component, the Company shall credit a Net-Metering Customer with the amountof any accumulated Net Excess Generation as measured in kWh or kWh multiplied by theapplicable retail rate in the next applicable billing period and base the bill of the Net-Metering Customer on the net amount of electricity as measured in kWh or kWh multipliedby the applicable retail rate that the Net Metering Customer has received from or fed backto the Company during the billing period.

For Net-Metering Customers who receive service under a rate that includes a demandcomponent with a generating capacity of 1,000 kW or less, the Company shall credit theNet-Metering Customer with any accumulated Net Excess Generation as measured in kWhin the next applicable billing period and base the bill of the Net-Metering Customer on thenet amount of electricity as measured in kWh that the Net-Metering Customer has receivedfrom or fed back to the Company during the billing period.

For Net-Metering Customers who receive service under a rate that includes a demandcomponent with a generating capacity over 1,000 kW and up to 20 MW and who receiveapproval to exceed the statutory limits under A.C.A. 23-18-604(b)(9), the Company shallcredit the Net-Metering Customer with the amount of any accumulated Net ExcessGeneration as measured in kWh in the next applicable billing period and base the bill of



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the Net-Metering Customer on the net amount of electricity as measured in kWh that the Net-Metering Customer has received from or fed back to the Company during the billing period.

The Company shall also bill the Net-Metering Customer a grid charge: Grid Charge Rate: $0.00 52.3.7. If the kWhs generated by the Net-Metering Facility and fed back to the Company during

the Billing Period exceed the kWhs supplied by the Company to the Net-Metering Customer during the applicable Billing Period, the Company shall credit the Net-Metering Customer with any accumulated Net Excess Generation in the next applicable Billing Period.

52.3.8. Net Excess Generation shall first be credited to the Net-Metering Customer’s meter to

which the Net-Metering Facility is physically attached (Generation Meter). 52.3.9. After application of 52.3.8. and upon request of the Net-Metering Customer pursuant to

52.3.11., any remaining Net Excess Generation shall be credited to one or more of the Net-Metering Customer’s meters (Additional Meters) in the rank order provided by the Net-Metering Customer.

52.3.10. Net Excess Generation shall be credited as described in 52.3.8. and 52.3.9. during

subsequent Billing Periods; the Net Excess Generation credits remaining in a Net-Metering Customer’s account at the close of a billing cycle shall not expire and shall be carried forward to subsequent billing cycles indefinitely. For Net Excess Generation credits older than twenty-four (24) months, a Net-Metering Customer may elect to have the Company purchase the Net Excess Generation Credits in the Net-Metering Customer’s account at the Company’s Avoided Cost plus any additional sum determined under the Net Metering Rules if the sum to be paid to the Net-Metering Customer is at least one hundred dollars ($100). The Company shall purchase at the Company’s Avoided Cost, plus any additional sum determined under the Net Metering Rules any Net Excess Generation Credits remaining in a Net-Metering Customer’s account when the Net-Metering Customer: 1) ceases to be a customer of the Company; 2) ceases to operate the Net-Metering Facility; or 3) transfers the Net-Metering Facility to another person.

When purchasing Net Excess Generation credits from a Net-Metering Customer, the

Company shall calculate the payment based on its Avoided Costs plus any additional sum determined under the Net-Metering Rules for the current year.

52.3.11. Upon request from a Net-Metering Customer, the Company must apply Net Excess

Generation to the Net-Metering Customer’s Additional Meters provided that:

(a) The Net-Metering Customer must give at least 30 days’ notice to the Company.

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the Net-Metering Customer on the net amount of electricity as measured in kWh that theNet-Metering Customer has received from or fed back to the Company during the billingpenod.

The Company shall also bill the Net-Metering Customer a grid charge:

Grid Charge Rate: $0.00

52.3.7. If the kt generated by the Net-Metering Facility and fed back to the Company duringthe Billing Period exceed the kt supplied by the Company to the Net-Metering Customerduring the applicable Billing Period, the Company shall credit the Net-Metering Customerwith any accumulated Net Excess Generation in the next applicable Billing Period.

52.3.8. Net Excess Generation shall first be credited to the Net-Metering Customer’s meter towhich the Net-Metering Facility is physically attached (Generation Meter).

52.3.9. After application of 52.3.8. and upon request of the Net-Metering Customer pursuant to52.3.11., any remaining Net Excess Generation shall be credited to one or more of the Net-Metering Customer’s meters (Additional Meters) in the rank order provided by the Net-Metering Customer.

52.3.10. Net Excess Generation shall be credited as described in 52.3.8. and 52.3.9. duringsubsequent Billing Periods; the Net Excess Generation credits remaining in a Net-MeteringCustomer’s account at the close of a billing cycle shall not expire and shall be carriedfonNard to subsequent billing cycles indefinitely. For Net Excess Generation credits olderthan twenty-four (24) months, a Net-Metering Customer may elect to have the Companypurchase the Net Excess Generation Credits in the Net-Metering Customer’s account atthe Company’s Avoided Cost plus any additional sum determined under the Net MeteringRules if the sum to be paid to the Net-Metering Customer is at least one hundred dollars($100). The Company shall purchase at the Company’s Avoided Cost, plus any additionalsum determined under the Net Metering Rules any Net Excess Generation Creditsremaining in a Net-Metering Customer’s account when the Net-Metering Customer: 1)ceases to be a customer of the Company; 2) ceases to operate the Net-Metering Facility;or 3) transfers the Net-Metering Facility to another person.

When purchasing Net Excess Generation credits from a Net-Metering Customer, theCompany shall calculate the payment based on its Avoided Costs plus any additional sumdetermined under the Net-Metering Rules for the current year.

52.3.11. Upon request from a Net-Metering Customer, the Company must apply Net ExcessGeneration to the Net-Metering Customer’s Additional Meters provided that:

(a) The Net-Metering Customer must give at least 30 days’ notice to the Company.



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(b) The Additional Meter(s) must be identified at the time of the request. Additional Meter(s) shall be under common ownership within the Company’s service area; shall be used to measure the Net-Metering Customer’s requirements for electricity; may be in a different class of service than the Generation Meter; shall be assigned to one, and only one, Generation Meter; shall not be a Generation Meter; and shall not be associated with unmetered service.

However, the common ownership requirement shall not apply if more than two customers that are governmental entities or other entities that are exempt from state and federal income tax defined under 23-18-603(7)(c) co-locate at a site hosting the Net Metering Facility.

(c) In the event that more than one of the Net-Metering Customer’s meters is identified,

the Net-Metering Customer must designate the rank order for the Additional Meters to which excess kWh are to be applied. The Net-Metering Customer cannot designate the rank order more than once during the Annual Billing Cycle.

52.3.12. Any Renewable Energy Credit created as the result of electricity supplied by a Net-

Metering Customer is the property of the Net-Metering Customer that generated the Renewable Energy Credit.

52.3.13. Grandfathering shall be governed by A.C.A.23-18-604(b)(10).

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(b) The Additional Meter(s) must be identified at the time of the request. AdditionalMeter(s) shall be under common ownership within the Company’s service area; shallbe used to measure the Net-Metering Customer’s requirements for electricity; may bein a different class of service than the Generation Meter; shall be assigned to one, andonly one, Generation Meter; shall not be a Generation Meter; and shall not beassociated with unmetered service.

However, the common ownership requirement shall not apply if more than twocustomers that are governmental entities or other entities that are exempt from stateand federal income tax defined under 23-18-603(7)(c) co-locate at a site hosting theNet Metering Facility.

In the event that more than one of the Net-Metering Customer’s meters is identified,the Net-Metering Customer must designate the rank order for the Additional Meters towhich excess kWh are to be applied. The Net-Metering Customer cannot designatethe rank order more than once during the Annual Billing Cycle.

52.3.12. Any Renewable Energy Credit created as the result of electricity supplied by a Net-Metering Customer is the property of the Net-Metering Customer that generated theRenewable Energy Credit.

52.3.13. Grandfathering shall be governed by A.C.A.23-18-604(b)(10).



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PRELIMINARY INTERCONNECTION SITE REVIEW REQUEST

I. STANDARD INFORMATION Section 1. Customer Information Name: Contact Person: _________________________________________________ Mailing Address: City: State: Zip Code: Facility Location (if different from above): Daytime Phone: Evening Phone: E-Mail Address: _______________________Fax: ______________________ If the requested point of interconnection is the same as an existing electric service, provide the electric service account number: _____________________ Additional Customer Accounts (from electric bill) to be credited with Net Excess Generation: ____________________________________________________ Annual Energy Requirements (kWh) in the previous twelve (12) months for the account physically attached to the Net-Metering Facility and for any additional accounts listed (in the absence of historical data reasonable estimates for the class and character of service may be made): _________________________ Type of Facility (circle one): customer owned leased service agreement Section 2. Owner Information (if different from customer information) Name: Contact Person: _________________________________________________ Mailing Address: City: State: Zip Code: Daytime Phone: Evening Phone: E-Mail Address: _______________________Fax: ______________________ Section 3. Generation Facility Information System Type: Solar Wind Hydro Geothermal Biomass Fuel Cell Micro Turbine Energy Storage Device (circle all that apply)

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PRELIMINARY INTERCONNECTION SITE REVIEW REQUEST

I. STANDARD INFORMATION

Section 1. Customer InformationName:Contact Person:Mailing Address:City: State: Zip Code:Facility Location (if different from above):Daytime Phone: Evening Phone:E-Mail Address: Fax:If the requested point of interconnection is the same as an existing electricservice, provide the electric service account number:Additional Customer Accounts (from electric bill) to be credited with Net ExcessGeneration:Annual Energy Requirements (kWh) in the previous twelve (12) months for theaccount physically attached to the Net-Metering Facility and for any additionalaccounts listed (in the absence of historical data reasonable estimates for theclass and character of service may be made):Type of Facility (circle one):customer owned leased service agreement

Section 2. Owner Information (if different from customer information)Name:Contact Person:Mailing Address:City: State: Zip Code:Daytime Phone: Evening Phone:E-Mail Address: Fax:

Section 3. Generation Facility InformationSystem Type: Solar Wind Hydro Geothermal Biomass Fuel Cell Micro TurbineEnergy Storage Device (circle all that apply)



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Generator Rating (kW): DC Inverter Rating (kW):___________________________ AC Capacity Factor: __________________________________________ Expected annual production of electrical energy (kWh) of the facility calculated using industry recognized simulation model (PVWatts, etc): _________________ Section 4. Interconnection Information Attach a detailed electrical diagram showing the configuration of all generating facility equipment, including protection and control schemes. Requested Point of Interconnection:___________________________________ Customer-Site Load (kW) at Net-Metering Facility location (if none, so state): ____________________________________________________________ Interconnection Request: Single Phase:_________Three Phase:_____________ Section 5. Signature I hereby certify that, to the best of my knowledge, all the information provided in this Preliminary Interconnection Site Review is true and correct. Net Metering Customer Signature: _____________________________ Date: _______ Owner Signature (if different from Customer): _____________________ Date: _______

II. TERMS AND CONDITIONS Section 1. Requirements for Request For the purpose of requesting that the Company conduct a preliminary interconnection site review for a proposed Net-Metering Facility pursuant to the requirement of Rule 2.06.B.4, or as otherwise requested by the customer, the customer shall notify the Company by submitting a completed Preliminary Interconnection Site Review Request. The customer shall submit a separate Preliminary Interconnection Site Review Request for each point of interconnection if information about multiple points of interconnection is requested. Part 1, Standard Information, Sections 1 through 5 of the Preliminary Interconnection Site Review Request must be completed for the notification to be valid. If mailed, the date of notification shall be the third day following the mailing of the Preliminary

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Generator Rating (kW): DCInverter Rating (kW): ACCapacity Factor:Expected annual production of electrical energy (kWh) of the facility calculatedusing industry recognized simulation model (PVWatts, etc):

Section 4. Interconnection InformationAttach a detailed electrical diagram showing the configuration of all generatingfacility equipment, including protection and control schemes.Requested Point of Interconnection:Customer-Site Load (kW) at Net-Metering Facility location (if none, so state):

Interconnection Request: Single Phase: Three Phase:

Section 5. Signature

I hereby certify that, to the best of my knowledge, all the information provided inthis Preliminary Interconnection Site Review is true and correct.

Net Metering Customer Signature: Date:

Owner Signature (if different from Customer): Date:

II. TERMS AND CONDITIONS

Section 1. Requirements for RequestFor the purpose of requesting that the Company conduct a preliminaryinterconnection site review for a proposed Net-Metering Facility pursuant to therequirement of Rule 2.06.8.4, or as otherwise requested by the customer, thecustomer shall notify the Company by submitting a completed PreliminaryInterconnection Site Review Request. The customer shall submit a separatePreliminary Interconnection Site Review Request for each point of interconnectionif information about multiple points of interconnection is requested. Part 1,Standard Information, Sections 1 through 5 of the Preliminary Interconnection SiteReview Request must be completed for the notification to be valid. If mailed, thedate of notification shall be the third day following the mailing of the Preliminary



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Interconnection Site Review Request. The Company shall provide a copy of the Preliminary Interconnection Site Review Request to the customer upon request. Section 2. Utility Review Following submission of the Preliminary Interconnection Site Review Request by the customer, the Company shall review the plans of the facility interconnection and provide the results of its review to the customer, in writing, within 30 calendar days. If the customer requests that multiple interconnection site reviews be conducted the Company shall make reasonable efforts to provide the customer with the results of the review within 30 calendar days. If the Company cannot meet the deadline it will provide the customer with an estimated date by which it will complete the review. Any items that would prevent Parallel Operation due to violation of safety standards and/or power generation limits shall be explained along with a description of the modifications necessary to remedy the violations. The preliminary interconnection site review is non-binding and need only include existing data and does not require the Company to conduct a study or other analysis of the proposed interconnection site in the event that data is not readily available. The Company shall notify the customer if additional site screening may be required prior to interconnection of the facility. The customer shall be responsible for the actual costs for conducting the preliminary interconnection site review and any subsequent costs associated with site screening that may be required. Section 3. Application to Exceed 1,000 kW Net-Metering Facility Size Limit This Preliminary Interconnection Site Review Request and the results of the Company’s review of the facility interconnection shall be filed with the Commission with the customer’s application to exceed the 1,000 kW facility size limit pursuant to Net Metering Rule 2.06.B.4. Section 4. Standard Interconnection Agreement The preliminary interconnection site review does not relieve the customer of the requirement to execute a Standard Interconnection Agreement prior to interconnection of the facility.

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Interconnection Site Review Request. The Company shall provide a copy of thePreliminary Interconnection Site Review Request to the customer upon request.

Section 2. Utility ReviewFollowing submission of the Preliminary Interconnection Site Review Request bythe customer, the Company shall review the plans of the facility interconnectionand provide the results of its review to the customer, in writing, within 30 calendardays. If the customer requests that multiple interconnection site reviews beconducted the Company shall make reasonable efforts to provide the customerwith the results of the review within 30 calendar days. Ifthe Company cannot meetthe deadline it will provide the customer with an estimated date by which it willcomplete the review. Any items that would prevent Parallel Operation due toviolation of safety standards and/or power generation limits shall be explainedalong with a description of the modifications necessary to remedy the violations.

The preliminary interconnection site review is non-binding and need only includeexisting data and does not require the Company to conduct a study or otheranalysis of the proposed interconnection site in the event that data is not readilyavailable. The Company shall notify the customer if additional site screening maybe required prior to interconnection of the facility. The customer shall beresponsible for the actual costs for conducting the preliminary interconnection sitereview and any subsequent costs associated with site screening that may berequired.

Section 3. Application to Exceed 1,000 kW Net-Meterinq Facility Size LimitThis Preliminary Interconnection Site Review Request and the results of theCompany’s review of the facility interconnection shall be filed with the Commissionwith the customer’s application to exceed the 1,000 kW facility size limit pursuantto Net Metering Rule 2.06.8.4.

Section 4. Standard Interconnection AqreementThe preliminary interconnection site review does not relieve the customer of therequirement to execute a Standard Interconnection Agreement prior tointerconnection of the facility.



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STANDARD INTERCONNECTION AGREEMENT FOR NET-METERING FACILITIES

I. STANDARD INFORMATION Section 1. Customer Information Name: Mailing Address: City: State: Zip Code: Facility Location (if different from above): Daytime Phone: Evening Phone: Utility Customer Account Number (from electric bill) to which the Net-Metering Facility is physically attached: Type of Facility (circle one): Customer-owned Leased Service Agreement Section 2. Owner Information Name: Contact Person: _________________________________________________ Mailing Address: City: State: Zip Code: Daytime Phone: Evening Phone: E-Mail Address: _______________________Fax: ______________________ Section 3. Generation Facility Information System Type: Solar Wind Hydro Geothermal Biomass Fuel Cell Micro Turbine Energy Storage Device (circle all that apply) Generator Rating (kW): DC Inverter Rating (kW): __________________________ AC Describe Location of Accessible and Lockable Disconnect: _____________________________________ ___________ ___________________________________ ___________ Inverter Manufacturer: Inverter Model: _____ Inverter Location: _______________________ Inverter Power Rating: _____ Expected Capacity Factor: __________________________________________

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STANDARD INTERCONNECTION AGREEMENT FOR NET-METERINGFACILITIES

I. STANDARD INFORMATION

Section 1. Customer InformationName:Mailing Address:City: State: Zip Code:Facility Location (if different from above):Daytime Phone: Evening Phone:Utility Customer Account Number (from electric bill) to which the Net-MeteringFacility is physically attached:

Type of Facility (circle one):Customer-owned Leased Service Agreement

Section 2. Owner InformationName:Contact Person:Mailing Address:City: State: Zip Code:Daytime Phone: Evening Phone:E-Mail Address: Fax:

Section 3. Generation Facility InformationSystem Type: Solar Wind Hydro Geothermal Biomass Fuel Cell Micro TurbineEnergy Storage Device (circle all that apply)

Generator Rating (kW): DCInverter Rating (kW): ACDescribe Location of Accessible and Lockable Disconnect:

Inverter Manufacturer:Inverter Model:Inverter Location: Inverter Power Rating:Expected Capacity Factor:



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Expected annual production of electrical energy (kWh) calculated using industry recognized simulation model (PVWatts, etc.): ____________________________ Section 4. Installation Information Attach a detailed electrical diagram of the Net-Metering Facility. Installed by: ________________________ Qualifications/Credentials: Mailing Address: City: State: Zip Code: Daytime Phone: Installation Date: Section 5. Certification The system has been installed in compliance with the local Building/Electrical Code of (City/County) Signed (Inspector): Date: (In lieu of signature of inspector, a copy of the final inspection certificate may be attached.) The system has been installed to my satisfaction and I have been given system warranty information and an operation manual, and have been instructed in the operation of the system. Signed (Net-Metering Customer): ______ Date: Signed (Owner if different from Customer):____________________ Date: Section 6. E-mail Addresses for parties Customer’s e-mail address: __________________________________________ Owner’s e-mail address (if different from Customer):_______________________ Utility’s e-mail address: _________________________________ (To be provided by utility.) Section 7. Utility Verification and Approval Facility Interconnection Approved: Date: Metering Facility Verification by: Verification Date:

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Expected annual production of electrical energy (kWh) calculated using industryrecognized simulation model (PVWatts, etc.):

Section 4. Installation InformationAttach a detailed electrical diagram of the Net-Metering Facility.Installed by:Qualifications/Credentials:Mailing Address:City: State: Zip Code:Daytime Phone: Installation Date:

Section 5. CertificationThe system has been installed in compliance with the local Building/ElectricalCode of (City/County)Signed (Inspector): Date:(In lieu of signature of inspector, a copy of the final inspection certificate may beattached.)

The system has been installed to my satisfaction and l have been given systemwarranty information and an operation manual, and have been instructed in theoperation of the system.

Signed (Net-Metering Customer): Date:Signed (Owner if different from Customer): Date:

Section 6. E-mail Addresses for partiesCustomer’s e-mail address:

Owner’s e-mail address (if different from Customer):

Utility’s e-mail address: (To be providedby utility.)

Section 7. Utility Verification and ApprovalFacility Interconnection Approved: Date:Metering Facility Verification by: Verification Date:



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II. INTERCONNECTION AGREEMENT TERMS AND CONDITIONS This Interconnection Agreement for Net-Metering Facilities ("Agreement") is made and entered into this day of ___________ , 20 , by Entergy Arkansas, LLC (“EAL” or the “Company”) and ________ ("Customer"), a (specify whether corporation or other) and ___________________________(“Owner”), a _____________ (specify whether corporation or other), each hereinafter sometimes referred to individually as "Party" or collectively as the "Parties". In consideration of the mutual covenants set forth herein, the Parties agree as follows: Section 1. The Net-Metering Facility The Net-Metering Facility meets the requirements of Ark. Code Ann. § 23-18-603(8) and the Arkansas Public Service Commission's Net-Metering Rules. Section 2. Governing Provisions The Parties shall be subject to the provisions of Ark. Code Ann. § 23-18-604 and the terms and conditions set forth in this Agreement, the Commission’s Net-Metering Rules, the Commission’s General Service Rules, and the Company’s applicable tariffs. Section 3. Interruption or Reduction of Deliveries The Company shall not be obligated to accept and may require Customer to interrupt or reduce deliveries when necessary in order to construct, install, repair, replace, remove, investigate, or inspect any of its equipment or part of its system; or if it reasonably determines that curtailment, interruption, or reduction is necessary because of emergencies, forced outages, force majeure, or compliance with prudent electrical practices. Whenever possible, the Company shall give the Customer reasonable notice of the possibility that interruption or reduction of deliveries may be required. Notwithstanding any other provision of this Agreement, if at any time the Company reasonably determines that either the facility may endanger the Company’s personnel or other persons or property, or the continued operation of the Customer's facility may endanger the integrity or safety of the Company’s electric system, the Company shall have the right to disconnect and lock out the Customer's facility from the Company’s electric system. The Customer's facility shall remain disconnected until such time as the Company is

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II. INTERCONNECTION AGREEMENT TERMS AND CONDITIONS

This Interconnection Agreement for Net-Metering Facilities ("Agreement") is madeand entered into this day of , 20by Entergy Arkansas, LLC (“EAL” or the “Company”) and

("Customer"), a (specify whethercorporation or other) and

(“Owner”), a (specify whethercorporation or other), each hereinafter sometimes referred to individually as "Party"or collectively as the "Parties". In consideration of the mutual covenants set forthherein, the Parties agree as follows:

Section 1. The Net-Meterinq FacilityThe Net-Metering Facility meets the requirements of Ark. Code Ann. § 23-18-603(8) and the Arkansas Public Service Commission's Net-Metering Rules.

Section 2. Governinq ProvisionsThe Parties shall be subject to the provisions of Ark. Code Ann. § 23-18-604 andthe terms and conditions set forth in this Agreement, the Commission’s Net-Metering Rules, the Commission’s General Service Rules, and the Company’sapplicable tariffs.

Section 3. Interruption or Reduction of DeliveriesThe Company shall not be obligated to accept and may require Customer tointerrupt or reduce deliveries when necessary in order to construct, install, repair,replace, remove, investigate, or inspect any of its equipment or part of its system;or if it reasonably determines that curtailment, interruption, or reduction isnecessary because of emergencies, forced outages, force majeure, or compliancewith prudent electrical practices. Whenever possible, the Company shall give theCustomer reasonable notice of the possibility that interruption or reduction ofdeliveries may be required. Notwithstanding any other provision of this Agreement,if at any time the Company reasonably determines that either the facility mayendanger the Company’s personnel or other persons or property, or the continuedoperation of the Customer's facility may endanger the integrity or safety of theCompany’s electric system, the Company shall have the right to disconnect andlock out the Customer's facility from the Company’s electric system. TheCustomer's facility shall remain disconnected until such time as the Company is



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reasonably satisfied that the conditions referenced in this Section have been corrected. Section 4. Interconnection Customer shall deliver the as-available energy to the Company at the Company’s meter. The Company shall furnish and install a standard kilowatt hour meter. Customer shall provide and install a meter socket for the Company’s meter and any related interconnection equipment per the Company’s technical requirements, including safety and performance standards. The customer shall submit a Standard Interconnection Agreement to the Company at least thirty (30) days prior to the date the customer intends to interconnect the Net-Metering Facilities to the Company’s facilities. Part I, Standard Information, Sections 1 through 6 of the Standard Interconnection Agreement must be completed to be valid. The customer shall have all equipment necessary to complete the interconnection prior to such notification. If mailed, the date of notification shall be the third day following the mailing of the Standard Interconnection Agreement. The Company shall provide a copy of the Standard Interconnection Agreement to the customer upon request. Following submission of the Standard Interconnection Agreement by the customer, the Company shall review the plans of the facility and provide the results of its review to the customer, in writing, within 30 calendar days. Any items that would prevent Parallel Operation due to violation of applicable safety standards and/or power generation limits shall be explained along with a description of the modifications necessary to remedy the violations. If the Company’s existing facilities are not adequate to interconnect with the Net-Metering Facility, the Customer shall pay the cost of additional or reconfigured facilities prior to the installation or reconfiguration of the facilities. To prevent a Net-Metering Customer from back-feeding a de-energized line, the customer shall install a manual disconnect switch with lockout capability that is accessible to utility personnel at all hours. This requirement for a manual disconnect switch will be waived if the following three conditions are met: 1) The

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reasonably satisfied that the conditions referenced in this Section have beencorrected.

Section 4. InterconnectionCustomer shall deliver the as-available energy to the Company at the Company’smeter.

The Company shall furnish and install a standard kilowatt hour meter. Customershall provide and install a meter socket for the Company’s meter and any relatedinterconnection equipment per the Company’s technical requirements, includingsafety and performance standards.

The customer shall submit a Standard Interconnection Agreement to the Companyat least thirty (30) days prior to the date the customer intends to interconnect theNet-Metering Facilities to the Company’s facilities. Part I, Standard Information,Sections 1 through 6 of the Standard Interconnection Agreement must becompleted to be valid. The customer shall have all equipment necessary tocomplete the interconnection prior to such notification. If mailed, the date ofnotification shall be the third day following the mailing of the StandardInterconnection Agreement. The Company shall provide a copy of the StandardInterconnection Agreement to the customer upon request.

Following submission of the Standard Interconnection Agreement by the customer,the Company shall review the plans of the facility and provide the results of itsreview to the customer, in writing, within 30 calendar days. Any items that wouldprevent Parallel Operation due to violation of applicable safety standards and/orpower generation limits shall be explained along with a description of themodifications necessary to remedy the violations.

If the Company’s existing facilities are not adequate to interconnect with the Net-Metering Facility, the Customer shall pay the cost of additional or reconfiguredfacilities prior to the installation or reconfiguration of the facilities.

To prevent a Net-Metering Customer from back-feeding a de-energized line, thecustomer shall install a manual disconnect switch with lockout capability that isaccessible to utility personnel at all hours. This requirement for a manualdisconnect switch will be waived if the following three conditions are met: 1) The



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inverter equipment must be designed to shut down or disconnect and cannot be manually overridden by the customer upon loss of utility service; 2) The inverter must be warranted by the manufacturer to shut down or disconnect upon loss of utility service; and 3) The inverter must be properly installed and operated, and inspected and/or tested by utility personnel. Customer, at customer’s expense, shall meet all safety and performance standards established by local and national electrical codes including the National Electrical Code (NEC), the Institute of Electrical and Electronics Engineers (IEEE), the National Electrical Safety Code (NESC), and Underwriters Laboratories (UL). Customer, at customer’s expense, shall meet all safety and performance standards adopted by the Company and filed with and approved by the Commission that are necessary to assure safe and reliable operation of the Net Metering Facility to the utility's system. Customer shall not commence Parallel Operation of the Net-Metering Facility until the Net-Metering Facility has been inspected and approved by the Company. Such approval shall not be unreasonably withheld or delayed. Notwithstanding the foregoing, the Company’s approval to operate the Customer's Net-Metering Facility in parallel with the Company’s electrical system should not be construed as an endorsement, confirmation, warranty, guarantee, or representation concerning the safety, operating characteristics, durability, or reliability of the Customer's Net-Metering Facility. Section 5. Modifications or Changes to the Net-Metering Facility Described

in Part 1, Section 2 Prior to being made, the Customer shall notify the Company of, and the Company shall evaluate, any modifications or changes to the Net-Metering Facility described in Part 1, Standard Information, Section 2 of the Standard Interconnection Agreement for Net-Metering Facilities. The notice provided by the Customer shall provide detailed information describing the modifications or changes to the Company in writing, including a revised Standard Interconnection Agreement for Net-Metering Facilities that clearly identifies the changes to be made. The Company shall review the proposed changes to the facility and provide the results of its evaluation to the Customer, in writing, within thirty (30)

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inverter equipment must be designed to shut down or disconnect and cannot bemanually overridden by the customer upon loss of utility service; 2) The invertermust be warranted by the manufacturer to shut down or disconnect upon loss ofutility service; and 3) The inverter must be properly installed and operated, andinspected and/or tested by utility personnel.

Customer, at customer’s expense, shall meet all safety and performancestandards established by local and national electrical codes including the NationalElectrical Code (NEC), the Institute of Electrical and Electronics Engineers (IEEE),the National Electrical Safety Code (NESC), and Underwriters Laboratories (UL).

Customer, at customer’s expense, shall meet all safety and performancestandards adopted by the Company and filed with and approved by theCommission that are necessary to assure safe and reliable operation of the NetMetering Facility to the utility's system.

Customer shall not commence Parallel Operation of the Net-Metering Facility untilthe Net-Metering Facility has been inspected and approved by the Company.Such approval shall not be unreasonably withheld or delayed. Notwithstanding theforegoing, the Company’s approval to operate the Customer's Net-MeteringFacility in parallel with the Company’s electrical system should not be construedas an endorsement, confirmation, warranty, guarantee, or representationconcerning the safety, operating characteristics, durability, or reliability of theCustomer's Net-Metering Facility.

Section 5. Modifications or Chanqes to the Net-Meterinq Facilitv Describedin Part 1I Section 2

Prior to being made, the Customer shall notify the Company of, and theCompany shall evaluate, any modifications or changes to the Net-MeteringFacility described in Part 1, Standard Information, Section 2 of the StandardInterconnection Agreement for Net-Metering Facilities. The notice provided bythe Customer shall provide detailed information describing the modifications orchanges to the Company in writing, including a revised Standard InterconnectionAgreement for Net-Metering Facilities that clearly identifies the changes to bemade. The Company shall review the proposed changes to the facility andprovide the results of its evaluation to the Customer, in writing, within thirty (30)



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calendar days of receipt of the Customer's proposal. Any items that would prevent Parallel Operation due to violation of applicable safety standards and/or power generation limits shall be explained along with a description of the modifications necessary to remedy the violations. If the Customer makes such modification without the Company’s prior written authorization and the execution of a new Standard Interconnection Agreement, the Company shall have the right to suspend Net-Metering service pursuant to the procedures in Section 6 of the Commission’s General Service Rules. A Net-Metering Facility shall not be modified or changed to generate electrical energy in excess of the amount necessary to offset all of the Net-Metering Customer requirements for electricity. Section 6. Maintenance and Permits The customer shall obtain any governmental authorizations and permits required for the construction and operation of the Net-Metering Facility and interconnection facilities. The Customer shall maintain the Net-Metering Facility and interconnection facilities in a safe and reliable manner and in conformance with all applicable laws and regulations. Section 7. Access to Premises The Company may enter the Customer's premises to inspect the Customer's protective devices and read or test the meter. The Company may disconnect the interconnection facilities without notice if the Company reasonably believes a hazardous condition exists and such immediate action is necessary to protect persons, or the Company’s facilities, or property of others from damage or interference caused by the Customer's facilities, or lack of properly operating protective devices. Section 8. Indemnity and Liability The following is Applicable to Agreements between the Company and to all Customers and Owners except the State of Arkansas and any entities thereof, local governments and federal agencies: Each Party shall indemnify the other Party, its directors, officers, agents, and employees against all loss, damages, expense and liability to third persons for injury to or death of persons or injury to property caused by the indemnifying

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calendar days of receipt of the Customer's proposal. Any items that wouldprevent Parallel Operation due to violation of applicable safety standards and/orpower generation limits shall be explained along with a description of themodifications necessary to remedy the violations.

If the Customer makes such modification without the Company’s prior writtenauthorization and the execution ofa new Standard Interconnection Agreement, theCompany shall have the right to suspend Net-Metering service pursuant to theprocedures in Section 6 of the Commission’s General Service Rules.

A Net-Metering Facility shall not be modified or changed to generate electricalenergy in excess of the amount necessary to offset all of the Net-MeteringCustomer requirements for electricity.

Section 6. Maintenance and PermitsThe customer shall obtain any governmental authorizations and permits requiredfor the construction and operation of the Net-Metering Facility and interconnectionfacilities. The Customer shall maintain the Net-Metering Facility andinterconnection facilities in a safe and reliable manner and in conformance with allapplicable laws and regulations.

Section 7. Access to PremisesThe Company may enter the Customer's premises to inspect the Customer'sprotective devices and read or test the meter. The Company may disconnect theinterconnection facilities without notice if the Company reasonably believes ahazardous condition exists and such immediate action is necessary to protectpersons, or the Company’s facilities, or property of others from damage orinterference caused by the Customer's facilities, or lack of properly operatingprotective devices.

Section 8. Indemnity and LiabilityThe following is Applicable to Agreements between the Company and to allCustomers and Owners except the State of Arkansas and any entities thereof,local governments and federal agencies:

Each Party shall indemnify the other Party, its directors, officers, agents, andemployees against all loss, damages, expense and liability to third persons forinjury to or death of persons or injury to property caused by the indemnifying



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party's engineering, design, construction, ownership, maintenance or operations of, or the making of replacements, additions or betterment to, or by failure of, any of such Party's works or facilities used in connection with this Agreement by reason of omission or negligence, whether active or passive. The indemnifying Party shall, on the other Party's request, defend any suit asserting a claim covered by this indemnity. The indemnifying Party shall pay all costs that may be incurred by the other Party in enforcing this indemnity. It is the intent of the Parties hereto that, where negligence is determined to be contributory, principles of comparative negligence will be followed and each Party shall bear the proportionate cost of any loss, damage, expense and liability attributable to that Party’s negligence. Nothing in this paragraph shall be applicable to the Parties in any agreement entered into with the State of Arkansas or any entities thereof, or with local governmental entities or federal agencies. Furthermore, nothing in this Agreement shall be construed to waive the sovereign immunity of the State of Arkansas or any entities thereof. The Arkansas State Claims Commission has exclusive jurisdiction over claims against the state. Nothing in this Agreement shall be construed to create any duty to, any standard of care with reference to or any liability to any person not a Party to this Agreement. Neither the Company, its officers, agents or employees shall be liable for any claims, demands, costs, losses, causes of action, or any other liability of any nature or kind, arising out of the engineering, design, construction, ownership, maintenance or operation of, or the making of replacements, additions or betterment to, or by failure of, the Customer's facilities by the Customer or any other person or entity. Section 9. Notices The Net-Metering Customer shall notify the Company of any changes in the information provided herein. All written notices shall be directed as follows: Attention: Customer Service Net-Metering ENTERGY ARKANSAS, LLC P.O. Box 551 Little Rock, Arkansas 72203

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party's engineering, design, construction, ownership, maintenance or operationsof, or the making of replacements, additions or betterment to, or by failure of, anyof such Party's works or facilities used in connection with this Agreement byreason of omission or negligence, whether active or passive. The indemnifyingParty shall, on the other Party's request, defend any suit asserting a claimcovered by this indemnity. The indemnifying Party shall pay all costs that may beincurred by the other Party in enforcing this indemnity. It is the intent of theParties hereto that, where negligence is determined to be contributory, principlesof comparative negligence will be followed and each Party shall bear theproportionate cost of any loss, damage, expense and liability attributable to thatParty’s negligence. Nothing in this paragraph shall be applicable to the Parties inany agreement entered into with the State of Arkansas or any entities thereof, orwith local governmental entities or federal agencies. Furthermore, nothing in thisAgreement shall be construed to waive the sovereign immunity of the State ofArkansas or any entities thereof. The Arkansas State Claims Commission hasexclusive jurisdiction over claims against the state.

Nothing in this Agreement shall be construed to create any duty to, any standardof care with reference to or any liability to any person not a Party to this Agreement.Neither the Company, its officers, agents or employees shall be liable for anyclaims, demands, costs, losses, causes of action, or any other liability of any natureor kind, arising out of the engineering, design, construction, ownership,maintenance or operation of, or the making of replacements, additions orbetterment to, or by failure of, the Customer's facilities by the Customer or anyother person or entity.

Section 9. NoticesThe Net-Metering Customer shall notify the Company of any changes in theinformation provided herein.

All written notices shall be directed as follows:

Attention:Customer Service Net-MeteringENTERGY ARKANSAS, LLCPO. Box 551Little Rock, Arkansas 72203



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Email: [email protected] Attention: [Customer] Name: Address: City: Email: Customer notices to the Company shall refer to the Customer's electric service account number set forth in Section 1 of this Agreement. Section 10. Term of Agreement The term of this Agreement shall be the same as the term of the otherwise applicable standard rate schedule. This Agreement shall remain in effect until modified or terminated in accordance with its terms or applicable regulations or laws. Section 11. Assignment This Agreement and all provisions hereof shall inure to and be binding upon the respective Parties hereto, their personal representatives, heirs, successors, and assigns. The Customer and/or Owner shall not assign this Agreement or any part hereof without the prior written consent of the Company, and such unauthorized assignment may result in termination of this Agreement. Section 12. Net-Metering Customer and Owner Certification I hereby certify that all of the information provided in this Agreement is true and correct, to the best of my knowledge, and that I have read and understand the Terms and Conditions of this Agreement. Signature (Customer): ____________________________________ Date: _____ Signature (Owner if different from Customer): ___________________ Date: _____

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Email: [email protected]

Attention:[Customer]Name:Address:City:Email:

Customer notices to the Company shall refer to the Customer's electric serviceaccount number set forth in Section 1 of this Agreement.

Section 10. Term of AgreementThe term of this Agreement shall be the same as the term of the otherwiseapplicable standard rate schedule. This Agreement shall remain in effect untilmodified or terminated in accordance with its terms or applicable regulations orlaws.

Section 11. AssiqnmentThis Agreement and all provisions hereof shall inure to and be binding upon therespective Parties hereto, their personal representatives, heirs, successors, andassigns. The Customer and/or Owner shall not assign this Agreement or any parthereof without the prior written consent of the Company, and such unauthorizedassignment may result in termination of this Agreement.

Section 12. Net-Meterinq Customer and Owner CertificationI hereby certify that all of the information provided in this Agreement is true andcorrect, to the best of my knowledge, and that l have read and understand theTerms and Conditions of this Agreement.

Signature (Customer): Date:

Signature (Owner if different from Customer): Date:



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mailto:[email protected]



IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their duly authorized representatives. Dated this day of , 20__. Customer: Electric Utility: Entergy Arkansas, LLC By: By: Title: Title: Mailing Address: Mailing Address: E-mail Address: E-mail Address: ________________________________ ___________________________ Third-Party Owner (if applicable): ________________________________ By: _____ Title: _____ Mailing Address: _____ _____ E-mail Address: _____

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2nd Revised Sheet No. 52.16



Kind of Service: Electric


Title: Net-Metering Service (N-M)

Class of Service: As Applicable


Docket No.: 16-027-ROrder No.: 35Effective:

PSC File Mark Only

IN WITNESS WHEREOF, the Parties have caused this Agreement to be executedby their duly authorized representatives.

Dated this day of

Customer:

By:

Title:

Mailing Address:

E-mail Address:

Third-Party Owner (if applicable):

, 20_

Electric Utility:


By:

Title:

Mailing Address:

E-mail Address:

By:

Title:

Mailing Address:

E-mail Address:



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STANDARD INTERCONNECTION AGREEMENT FOR NET-METERING FACILITIES

Disclaimer

POSSIBLE FUTURE RULES OR RATE CHANGES, OR BOTH AFFECTING YOUR NET-METERING FACILITY

The following is a supplement to the Interconnection Agreement you signed with Entergy Arkansas, LLC (“EAL” or the “Company”).

1. Electricity rates, basic charges, and service fees, set by the Company and approved by the Arkansas Public Service Commission (Commission), are subject to change.

2. I understand that I will be responsible for paying any future increases to my electricity rates, basic charges, or service fees from the Company.

3. My Net-Metering System is subject to the current rates of the Company, and the rules and regulations of the Commission. The Company may change its rates in the future with approval of the Commission or the Commission may alter its rules and regulations, or both may happen. If either or both occurs, my system will be subject to those changes.

By signing below, you acknowledge that you have read and understand the above disclaimer. ___________________________________ Name (printed) ___________________________________ Signature (Customer) ______________________________________ Date

26







Title: Net-Metering Service (N-M) PSC File Mark Only

STANDARD INTERCONNECTION AGREEMENT FOR NET-METERINGFACILITIES

DisclaimerPOSSIBLE FUTURE RULES OR RATE CHANGES, OR BOTH

AFFECTING YOUR NET-METERING FACILITY

The following is a supplement to the Interconnection Agreement yousigned with Entergy Arkansas, LLC (“EAL” or the “Company”).

. Electricity rates, basic charges, and service fees, set by the Company andapproved by the Arkansas Public Service Commission (Commission), aresubject to change.

I understand that I will be responsible for paying any future increases tomy electricity rates, basic charges, or service fees from the Company.

My Net-Metering System is subject to the current rates of the Company,and the rules and regulations of the Commission. The Company maychange its rates in the future with approval of the Commission or theCommission may alter its rules and regulations, or both may happen. Ifeither or both occurs, my system will be subject to those changes.

By signing below, you acknowledge that you have read and understand theabove disclaimer.

Name (printed)

Signature (Customer)

Date



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Title: Additional Facilities Charge Rider – Governmental (AFCRG)

PSC File Mark Only


53.0. ADDITIONAL FACILITIES CHARGE RIDER - GOVERNMENTAL

53.1. AVAILABILITY

Available to agencies of the State of Arkansas or any entities thereof, local governmental entities, or federal agencies whose service is metered at primary voltage or greater and who execute a contract as provided herein.

53.2. APPLICATION AND CONDITIONS

Where, because of the character of the customer’s demand, customer’s need for duplicate facilities, legal or engineering requirements with which the customer must comply, customer requests Entergy Arkansas, LLC (“EAL” or the “Company”) to install facilities in addition to those which the Company would normally install for the customer’s demand and service requirements, Company will install and maintain such additional facilities (“Additional Facilities”) subject to the following conditions:

1. The location and design of the Additional Facilities must meet the Company’s engineeringand operating standards and practices. The Company will not install Additional Facilities onthe customer’s side of the point of delivery which cross public streets, roads, or alleys,unless approved by Commission waiver of APSC GSR 5.20, or inside customer’s building.

2. If Additional Facilities are installed on the customer’s side of the primary metering pointwhich operate at primary voltage or greater, then the primary service credit under RateSchedule No. 18, Voltage Adjustment Rider, if applicable, shall be limited to 1%.

3. In cases where the Company would normally provide secondary metering and the customerrequests primary metering, the difference in the installed cost of the primary and secondarymetering will be considered as Additional Facilities.

4. Title to all facilities installed by the Company shall be vested in and will be maintained bythe Company, and the customer will provide all easements and rights-of-way satisfactory tothe Company at no cost to the Company.

5. This Schedule is not available to applications involving mixed ownership of facilities on thecustomer’s side of the meter except where the customer installs customer-owned primarycapacitors on the customer’s side of the primary meter in accordance with the Company’sInstallation Standards.

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The customer will enter into a Facilities Agreement - Governmental with the Company and pay to the Company a net monthly charge based on the investment by Company in such facilities and the monthly percentages from either Option A or Option B below, as appropriate. At the execution of each such Agreement, the customer will have a one-time election to select either Option A or Option B for the definition of the monthly rate associated with the Company’s investment in the Additional Facilities. Any subsequent capital additions, replacements, or modifications of facilities will be treated as described in Option A and Option B below.

53.3. OPTION A

Customers that select Option A for Additional Facilities must pay a net monthly facilities charge of 1.428 percent (1.428%) per month of the installed cost of all facilities included in the Facilities Agreement. Subsequent capital modifications or additions to such facilities will be subject to the above rate as applied to the cost of the additions or modifications. Subsequent replacement of an Additional Facilities component will be subject to the above rate, as applied to the excess of the cost of replacement over the original installed cost of the replaced facilities.

53.4. OPTION B

Customers that select Option B for Additional Facilities must define in the Facilities Agreement the number of years (the “Recovery Term”) that will define the appropriate monthly rates to be applied to the Company’s investment. The Recovery Term cannot be longer than 10 years. The following table specifies the monthly percentages for application during the selected Recovery Term and any years following the Recovery Term. These percentages will apply monthly to the installed cost of all facilities included in the required Facilities Agreement. Prepayment of any charges associated with an Option B Facilities Agreement prior to expiration of the selected Recovery Term is not allowed.

Selected Recovery Term (Years)

Monthly % During Recovery Term

Monthly % Post- Recovery Term

1 9.492% 0.843% 2 5.317% 0.843% 3 3.927% 0.843% 4 3.234% 0.843% 5 2.819% 0.843% 6 2.544% 0.843% 7 2.348% 0.843% 8 2.202% 0.843% 9 2.090% 0.843% 10 2.000% 0.843%

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Subsequent modifications and additions to Additional Facilities covered by a Facilities Agreement shall be subject to a new Option B Facilities Agreement covering the installed cost of such facilities, wherein customer must select a Recovery Term that will define the appropriate monthly rate for such cost.

Subsequent replacement of an Additional Facilities component shall be subject to a new Facilities Agreement covering the installed cost of such item and the customer may select either Option A or Option B for such item. If the Facilities Agreement covering the replaced item remains in effect because there was not a total replacement of the Additional Facilities covered by the Facilities Agreement, the costs covered by such agreement shall be reduced by the original cost of the replaced facility. If the replacement occurs prior to the end of the Recovery Term for the replaced facility, the replacement installed cost shall be reduced by the salvage value of the replaced facility, if any.

53.5. OPERATION AND MAINTENANCE OF CUSTOMER-OWNED FACILITIES

Customers that own distribution substations and/or other distribution facilities may enter into an agreement with the Company for the ongoing operation and maintenance of such facilities (“O&M Service”), subject to the Company inspection of subject facilities and approval of the agreement. The cost of such facilities will be defined in the agreement as the current estimated cost of replacement facilities. The net monthly charge for all facilities included in the agreement will be 0.752% per month of such defined cost of such facilities. Alternatively, the Company and such customers may enter into an arrangement wherein the customer is assessed a charge to reimburse the Company on a task or activity basis.

53.6. CONTRACT TERM

The initial term of any contract for Additional Facilities (Facilities Agreement) provided hereunder shall be for not less than ten years and shall be automatically extended for successive periods of one year each until terminated by written notice given by one party to the other not more than six months nor less than three months prior to the expiration date of the original term or any anniversary thereof. If the customer ceases to take electric service from the Company, the Company may remove said Additional Facilities and customer shall pay Company the termination charges set forth below. In the event the customer does not require the Additional Facilities for the full term of the contract and wishes to cancel the contract prior to the expiration date, the Company reserves the right to remove such Additional Facilities and will consent to the cancellation of the contract provided customer pays to the Company the lesser of the following:

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1. The applicable monthly charge for the remaining months of the contract.2. The amount computed under the following formula; provided, however, such amount shall

never be less than zero:[A + B - C] X DWhere:A = Original installed cost of the facilitiesB = Cost of removing facilitiesC = Salvage value to the Company of equipment and material removedD = 1.12 less .001 times the number of months which have expired in the initial term of the

contract.


53.7.1. Termination of Facilities Agreement

The Facilities Agreement provided herein will not be suspended and may not be terminated except upon payment of the charges set forth herein.

53.7.2. Load Changes

A participating customer must give the Company reasonable written notice prior to increasing load, shifting load, or rearranging customer-owned facilities which may overload or damage Company-owned facilities.

53.7.3. Cost of Additional Facilities

All Additional Facilities included in a Facilities Agreement will be included at new or replacement cost at the time of inclusion.

53.7.4. Facilities not Includable

The following facilities may not be included in a Facilities Agreement:

1. Facilities on the customer’s side of the point of delivery crossing public streets, roads, oralleys, unless approved by Commission waiver of APSC GSR 5.20.

2. Facilities inside the customer’s building, except that additional facilities may terminate inthe customer’s switchgear located a short distance inside the customer’s building.

3. Capacitors.4. Non-standard facilities not utilized in the Company’s normal operations.5. Overhead/underground construction differential costs.6. Non-salvageable underground facilities installed or provided by the Company.7. Any item Company deems inadvisable from an economic or good engineering practices

perspective.

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The final judgment regarding the inclusion of an item rests solely with the Company.

53.8. PAYMENT

The Net Monthly Bill shall be computed in accordance with § 53.3 or 53.4 and other applicable provisions of this schedule. Payment shall be made in accordance with Rate Schedule No. 29, Charges Related to Customer Activity (CAC), § 29.19.1.

53.9. ANNUAL ADJUSTMENT

The Company will review the charges in this Schedule annually and may request Commission approval for revisions if an adjustment is necessary to recover the costs of this service.

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Title: MISO Rider PSC File Mark Only


54.0 MISO RIDER

54.1 REGULATORY AUTHORITY

The Arkansas Legislature has delegated authority to the Arkansas Public Service Commission (“APSC” or the “Commission”) to regulate public utilities in the State of Arkansas, including Entergy Arkansas, LLC (“EAL” or the “Company”). The APSC’s regulatory authority over the provision of electric service applies not only in the Distribution Service area allocated to EAL by the APSC but also extends to service to customers who have been released to EAL by other electric distribution utilities, when such release for service has been approved by the Commission pursuant to Rule 6.07(b) or (c) of the Commission's Rules of Practice and Procedure. Similarly, the Tennessee Regulatory Authority exercises such authority delegated to it by the Tennessee Legislature in areas of the State of Tennessee served by EAL.

54.2 PURPOSE

The purpose of this MISO Rider is to define the procedure by which EAL shall implement and adjust rates contained in the rate classes designated in Attachment A to this MISO Rider for recovery of the costs designated in § 54.3 below, including but not limited to costs charged to EAL pursuant to the Midcontinent Independent System Operator, Inc. (“MISO”) Federal Energy Regulatory Commission (“FERC”)-approved Open Access Transmission Energy and Operating Markets Tariffs that are not recovered via the Energy Cost Recovery Rider as ordered by the APSC in Docket No. 13-028-U, Order No. 21. The MISO Rider shall apply in accordance with the provisions of § 54.3 below to all electric service billed under the rate schedules, whether metered or unmetered, and subject to the jurisdiction of the Commission.

54.3 MISO RIDER RATES

The rates associated with the MISO Rider (“MISO Rider Rates”) as set forth on Attachment A shall be derived by the formula set out in Attachment B to this MISO Rider (“MISO Rider Rate Formula”). The MISO Rider Rates shall be added to the rates set out in the Net Monthly Bill section in the Company's rate schedules. The MISO Rider Rates shall be determined in accordance with the provisions of this MISO Rider.

The initial MISO Rider Rates shall be based on the estimated Net MISO Charges/(Credits) as reflected on Attachment B that the Company expects to incur on an Arkansas Retail basis for the twelve (12) months ended December 31, 2014, and that are not recovered via the Energy Cost Recovery Rider in Docket No. 13-028-U, Order No. 21.

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54.4 MISO IMPLEMENTATION DEFERRAL

Pursuant to Order No. 76 in Docket No. 10-011-U, the Company deferred certain costs related to the pursuit of MISO membership (“MISO Implementation Deferral”). The Company shall be allowed to recover through this MISO Rider a return of the MISO Implementation Deferral. The MISO Implementation Deferral shall be amortized over sixty (60) months beginning January 1, 2014.

54.5 ANNUAL DETERMINATION

On or about October 1, beginning in 2014, the Company shall file a redetermination of the MISO Rider Rates by filing updated versions of Attachments A and B with supporting workpapers and documentation. This redetermination shall include the reporting requirements as ordered in Commission Order No. 21, Docket No. 13-028-U.

Beginning with the annual redetermination in 2015, an exact recovery true-up of the actual net retail MISO Rider revenue requirement to the actual net retail MISO Rider revenues for the twelve (12) months ended June 30 of the filing year shall be reflected in MISO Rider revenue requirement.

The MISO Rider Rates so determined shall be effective for bills rendered on and after the first (1st) billing cycle of January of the calendar year immediately following the filing year and shall remain in effect until superseded.

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54.6 STAFF AND COMMISSION REVIEW

Staff shall review the filed MISO Rider Rates to verify that the formula in Attachment B has been correctly applied and shall notify the Company of any necessary corrections. After the Staff completes its review of the rate calculation, the Company shall make appropriate changes to correct undisputed errors identified by the Staff in its review. Any disputed issues arising out of the Staff review are to be resolved by the Commission after notice and hearing. The MISO Rider Rates shall go into effect, upon Commission approval, with the first billing cycle of January 1, 2014.

54.7 INTERIM ADJUSTMENT

If the cumulative true-up of Net Retail MISO Rider Revenue Requirement exceeds 10 percent of the annual Net MISO Rider Revenue Requirement included in the most recently filed MISO Rider, then either the APSC General Staff or the Company may propose an interim adjustment of the MISO Rider Rates.

54.8 TERM

The MISO Rider shall remain in effect until otherwise terminated by Commission order, subject to three (3) months advance notice of termination by the Commission following reasonable notice and opportunity for hearing. If the MISO Rider is terminated by mutual agreement of the Commission and the Company, or if this MISO Rider is terminated by a future order of the Commission, the then-existing MISO Rider Rates shall continue to be in effect until new base rates reflecting the then-existing MISO Rider Rates are duly approved and implemented. Nothing contained in this MISO Rider shall limit the right of any party to file an appeal as provided by law.

54.9 CARRYING CHARGES

Pursuant to Order No. 6 in Docket No. 18-006-U, the 2019 rate redetermination formula will include the effect of carrying charges related to the Tax Cuts & Jobs Act Credit using the Company’s most recently approved rate of return on rate base. Such charges will be included in Line No. 1 of Attachment B, page 6 of this tariff.

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Docket No.: 15-015-U


Attachment A to Rate Schedule No. 54 Attachment Page 1 of 1 Schedule Sheet 4 of 7 Including Attachments


MISO Rider Rates


Rate Class Rate Schedules Applicable Rate

Residential RS, RT, REMT $-0.00555 per kWh

Small General Service SGS, GFS, TSS, MP, AP, CGS, CTV, SMWHR $-0.00510 per kWh

Large General Service LGS, LPS, GST, PST, SSR $-1.46 per kW

Lighting L1, L1SH, L4 $-0.00133 per kWh

10

Rate Class

MISO Rider Rates

Rate Schedules

Docket No.: 15-015-UOrder No.:Effective: 12/31/20

Attachment A toRate Schedule No. 54Attachment Page 1 of 1Schedule Sheet 4 of 7Including Attachments


Applicable Rate

Residential



Lighting

RS, RT, REMT

SGS, GFS, TSS, MP, AP,CGS, CTV, SMWHR

LGS, LPS, GST, PST,SSR

L1, L1SH, L4

$-0.00555 per kWh

$-0.00510 per kWh

$-1.46 per kW

$-0.00133 per kWh


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Docket No.: 15-015-U Order No.: Effective: 12/31/20 Attachment B to Rate Schedule No. 54 Attachment Page 1 of 3 Schedule Sheet 5 of 7 Including Attachments



MISO Rider Rate Formula


Line No.

Rate Class

Class Allocator (%)

(1)

Net Retail

MISO Rider Revenue

Requirement ($) (2)

Projected Billing

Units (3)

Rate Adjustment (4)

EAL Retail 1 Residential 45.6283% ($43,103,661) 7,762,972,726 kWh $-0.0555 per kWh

2 Small General Service 23.1051% ($21,826,694) 4,279,253,629 kWh $-0.00510 per kWh

3 Large General Service 30.8892% ($29,180,056) 19,974,449 kW $-1.46 per kW

4 Lighting 0.3775% ($356,590) 267,490,811 kWh $-0.00133 per kWh

5 Total EAL Retail 100.0000% ($94,467,000)

Notes:

(1) The Rate Class Allocator shall be made consistent with the Retail Transmission High Demand Allocation Factor approved in the most recent retail rate case.


(3) Projected Billing Units by Rate Class WP 1.1.

(4) Net Retail Class MISO Rider Revenue Requirement / Projected Billing Units

11



Entergy Arkansas, LLCMISO Rider Rate Formula


Net RetailMISO Rider . . .. Proiected BillingLine Class Revenue . .No. Rate Class Allocator (0/0) Requirement Units Rate Adjustment

(1) ($) (2) (3) (4)EAL Retail

1 Residential 45.6283% ($43,103,661) 7,762,972,726 kWh $-0.0555 per kWh

2 Small General Service 23.1051% ($21,826,694) 4,279,253,629 kWh $-0.00510 per kWh

3 Large General Service 30.8892% ($29,180,056) 19,974,449 kW $-1.46 per kW

4 Lighting O.3775% ($356,590) 267,490,811 kWh $-0.00133 per kWh

5 Total EAL Retail 100.0000% ($94,467,000)

Notes:

(1) The Rate Class Allocator shall be made consistent with the Retail Transmission High Demand AllocationFactor approved in the most recent retail rate case.


(3) Projected Billing Units by Rate Class WP 1.1.

(4) Net Retail Class MISO Rider Revenue Requirement/ Projected Billing Units


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EALAmount Reference

1 MISO Rider Charges/(Credits) (92,059) WP 2.1

2 Amortization of MISO Implementation Deferral (2) - 3 Total MISO Rider Costs (92,059) L1 + L2

4 Retail Allocation Factor 99.9989% WP 3.15 Retail MISO Rider Costs (92,058) L3 * L4

6 Revenue Related Expense Factor (3) 0.997845 WP 4.17 Retail MISO Rider Revenue Requirement (91,859) L5 * L6

8 True-up of Net Retail MISO Rider Revenue Requirement (2,607) Att B Page 3, L8

9 Net Retail MISO Rider Revenue Requirement (94,467) L7 + L8

Notes:(1) Pursuant to paragraph 54.3 of this MISO Rider.(2)(3) Revenue Related Expense Factor = 1 / (1-Arkansas Retail Bad Debt Rate + Forfeited Discount Rate). For

subsequent redeterminations, the Arkansas Retail Bad Debt and the Forfeited Discount Rates shall be developed consistent with the methodology utilized for calculating them in the most recent EAL general rate case and shall be the most recently available calendar year data at the time of the filing.

MISO Implementation Deferral per paragraph 54.4 of this MISO Rider. Amortization complete as of


For the Rate Effective Twelve Months Ended December 31, 2021($000’S Omitted)

Ln No. Description

MISO Rider Rate Formula (1)

12



Entergy Arkansas, LLCMISO Rider Rate Formula (1)

For the Rate Effective Twelve Months Ended December 31, 2021

($000’S Omitted)Ln EALNO- Description Amount Reference

1 MISC Rider Charges/(Credits) (92,059) WP 2.1

2 Amortization of MISO Implementation Deferral (2)

3 Total MISO Rider Costs (92,059) L1 + L2

4 Retail Allocation Factor 99.9989% WP 3.1

5 Retail MISO Rider Costs (92,058) L3 * L4

Revenue Related Expense Factor (3) 0.997845 WP 4.1

Retail MISO Rider Revenue Requirement (91,859) L5 * L6

8 True-up of Net Retail MISO Rider Revenue Requirement (2,607) Att B Page 3, L8

9 Net Retail MISO Rider Revenue Requirement (94,467) L7 + L8

Notes:(1) Pursuant to paragraph 54.3 of this MISO Rider.(2) MISC Implementation Deferral per paragraph 54.4 of this MISO Rider. Amortization complete as of

(3) Revenue Related Expense Factor = 1 / (1-Arkansas Retail Bad Debt Rate + Forfeited Discount Rate). Forsubsequent redeterminations, the Arkansas Retail Bad Debt and the Forfeited Discount Rates shall bedeveloped consistent with the methodology utilized for calculating them in the most recent EAL generalrate case and shall be the most recently available calendar year data at the time of the filing.


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EAIAmount Reference

Actual MISO Charges/(Credits)1 MISO Rider Charges/(Credits) (89,443) WP 5.1

2 Amortization of MISO Implementation Deferral (3) 0


4 Retail Allocation Factor 99.9989% WP 3.15 Revenue Related Expense Factor (4) 99.7845% WP 4.16 Actual Net Retail MISO Rider Revenue Requirement (89,249) L3 * L4 * L5

7 Actual Net Retail MISO Rider Revenues (86,642) WP 7.1

8 True-up of Net Retail MISO Rider Revenue Requirement (2,607) L6 - L7

Notes:(1) Pursuant to Paragraph 54.3 of this MISO Rider.(2)

(3)

(4) See Attachment B, Page 2 Note (3)

Return of MISO Implementation Deferral per Paragraph 54.4 of this MISO Rider. Amortization complete as of 12/31/2018.

This schedule is not applicable for the Initial Filing. The filing for the 12ME 12/31/16 will include a true-up calculation for the period 12/18/2013 - 6/30/2015. Each subsequent filing will true-up the MISO Rider costs and revenues for the 12 month period ending June 30 of the filing year.


True-up of Net Retail MISO Rider Revenue Requirement (2)For the Rate Effective Twelve Months Ended December 31, 2021

($000’S Omitted)Ln No. Description

Actual Charges/ Credits for Twelve Months Ended June 30, 2020

13




True-up of Net Retail MISO Rider Revenue Requirement (2)For the Rate Effective Twelve Months Ended December 31, 2021Actual Charges/ Credits for Twelve Months Ended June 30, 2020

($000’S Omitted)Ln EAlNo. Description Amount Reference

Actual MISO Charges/(Credits)1 MISO Rider Charges/(Credits) (89,443) WP 5.1

2 Amortization of MISO Implementation Deferral (3) 0


4 Retail Allocation Factor 99.9989% WP 3.1Revenue Related Expense Factor (4) 99.7845% WP 4.1

Actual Net Retail MISO Rider Revenue Requirement (89,249) L3 * L4 * L503

01

7 Actual Net Retail MISO Rider Revenues (86,642) WP 7.1

00 True-up of Net Retail MISO Rider Revenue Requirement (2,607) L6 - L7

Notes:(1) Pursuant to Paragraph 54.3 of this MISO Rider.(2) This schedule is not applicable for the Initial Filing. The filing for the 12ME 12/31/16 will include a true-up

calculation for the period 12/18/2013 - 6/30/2015. Each subsequent filing will true-up the MISO Rider costsand revenues for the 12 month period ending June 30 of the filing year.

(3) Return of MISO Implementation Deferral per Paragraph 54.4 of this MISO Rider. Amortization complete asof 12/31/2018.

(4) See Attachment B, Page 2 Note (3)


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Title: Economic Redevelopment Rider (ERDR) PSC File Mark Only


56.0. ECONOMIC REDEVELOPMENT RIDER

56.1. AVAILABILITY

Available to customers taking service under Entergy Arkansas, LLC (“EAL” or the “Company”) Small General Service (“SGS”), Large General Service (“LGS”), or Large General Service Time-of-Use (“GST”) rate schedules when the customer meets the following criteria:

1. Customer takes service in a previously occupied building which has been unoccupiedfor a minimum of six months prior to the request for service and where no materialchanges to existing facilities are necessary to serve the new customer.

2. Customer’s anticipated monthly billing demand is at least 150 kW and no more than500 kW.

3. Customer has executed an Agreement for Electric Service for service provided byCompany for a minimum term of two (2) years.

4. Customer must take service under the SGS, LGS, or GST rate schedule which, in anannual rate comparison, would result in the lowest bill amount before application ofthe reduction associated with this ERDR.

This Rider is not available to customers taking service under the Standby Service Rider (SSR), Seasonal Service Rider (SESR), Fire and Flood Loads Rider (FFLR), or Optional Interruptible Service Rider (OISR).

Determination that the above criteria have been met is in the sole judgment of the Company.

56.2. APPLICABILITY

In any month when Customer’s net monthly billing is greater than or equal to any applicable rate schedule minimum or contract minimum, and

a. Billing demand exceeds149 kW for Customers served under Rate Schedules SGS orLGS, or

b. The higher of the on peak billing demand or the off peak billing demand exceeds 149kW for customers served under Rate Schedule GST

the net monthly billing under Rate Schedules SGS, LGS, or GST will be reduced by twenty-five percent (25%). This reduction will be applicable for a period of twenty-four (24) consecutive months. In the twenty-fifth month, the reduction will no longer apply.

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Title: Economic Redevelopment Rider (ERDR) PSC File Mark Only


The net monthly billing amount subject to reduction will include billing provisions and/or modifications associated with the Voltage Adjustment Rider (VAR) and the Commercial Space Heating Rider (CSHR) when those riders are applicable.

Except as provided above, all provisions, prices and regulations of EAL’s standard rate schedule effective at the time service is provided shall apply.

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ARKANSAS PUBLIC SERVICE COMMISSION EAL

OriQinal

Replacing;

Entergy Arkansas, LLCName ofCompany

Kind ofService: Electric

Sheet No. 58.1

Sheet No.

Schedule Sheet 1 of2

Class of Service: Residential


Title: Peak Time Rebate Rider (PTR) Pilot

Compliance Exhibit MSK-5DocketNo 16-060-U

Page 1 of2

DocketNo.: 16-060-UOrder No.:Effective:

PSC File Mark Only

58.0. PEAK TIME REBATE RIDER PILOT

58.1. PURPOSE

The purpose of this schedule is to establish participation, subject to the provisions of thisschedule, in Entergy Arkansas, LLC's ("EAL" or the "Company") Peak Time Rebate Rider("PTR") Pilot in which eligible residential customers may receive a bill credit when theyrespond to the Company's notification of an upcoming PTR Pilot event period.

58.2. AVAILABILITf

The rider is available on a voluntary and experimental basis to qualifying residentialcustomers taking service under EAL's General Purpose Residential Service Rate ScheduleNo. 1 ("RS") who have fully-commissioned (as determined by the Company) AdvancedMetering Infrastructure.

This rider is not avaitable to customers who take service under Residential EnergyManagement Time-Of-Use Rate Schedule No. 33 or Optional Residential Time-Of-UseRate Schedule No. 2 or Net-Metering Service Rate Schedule No 52 This rider is notavailable to customers who have elected non-standard meter service in lieu of the standardcommunicatlng advanced meter service or customers participating in demand responseprograms.

Initial participation in EAL's PTR Pilot will be limited to the first 100 qualifying customers toapply for service successfully, as determined by the Company, and in accordance withcriteria established by the Arkansas Public Service Commission in Docket No. 16-060-U.

58.3. APPLICABILITY

In a billing month for a service period in which a PTR Pilot event period has occurred,participating customers will receive a bill credit of:

$0.42 per kWh

for each kWh of actual reduction in consumption during the PTR Pilot event period. TheActual Consumption Reduction will be measured using Customer-specific Usage Levels("CUL"). If no PTR Pilot event periods are called or the Actual Consumption Reduction isless than or equal to zero, no bill credit will be given.

Customers participating in demand response programs are ineligible to subscribe to thisrider. Under no circumstances will a customer participating in demand response programsbe entitled to receive any incentive payment for a PTR Pilot event period under this rider.



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ARKANSAS PUBLIC SERVICE COMMISSION EAL Compliance Exhibit MSK-5DocketNo 16-060-U

Sheet No. 58.2

Sheet No.

Schedule Sheet 2 of2

Replacing:

Entergy Arkansas, LLCName ofCompany

Kind of Service: Electric Class of Service: Residential


Title: Peak Time Rebate Rider (PTR) Pilot

Page2 of2

DocketNo: 16-060-UOrder No.:Effective:

PSC File Mark Only

All provisions of rate and nder schedules applicable to the RS Rate Schedule, except asprovided herein, will apply to billing under the PTR Pilot.

58.4. DEFINITIONS

PTR event period: The PTR Pilot event period, as initiated by the Company, will be from3:00 p m. to 7:00 p m. on non-holiday weekdays in the months of July 2020 throughOctober 2020, and May 2021 through October 2021

CUL: The CUL is customer-specific, based on the customer's average consumption forthe hours of 3:00 p.m. to 7:00 p.m. determined from a limited number of non-holidayweekdays that occur before the day the PTR Pilot event period occurs.

Actual Consumption Reduction: The Actual Consumption Reduction is the differencebetween the customer's total usage during the PTR Pilot event period and the CUL for thesame event period.

Event Notification/Communication: The Company will notify enrolled customers of anupcoming PTR Pilot event period by email and text message by 8:00 p.m. the day beforethe PTR Pilot event period is to occur. Consistent with 58.6. below, it is the customer'sresponsibility to update the Company on all changes to the customer's contact information.

Event Cancellation: The Company will not cancel a PTR Pilot event period once the eventhas been initiated.

58.5. COMPANY RECOGNIZED HOLIDAYS

For purposes of this rider, recognized holidays that affect this Rate Schedule are MemorialDay, Independence Day, and Labor Day

58.6. TERMS AND CONDITIONS

A customer must consent to notification of PTR Pilot event periods by email and text messageand to receipt of sun/eys by email to be eligible to participate in EAL's PTR Pilot. In order tobe enrolled in the rider, the customer must provide EAL an active email address and mobiletelephone number where an email and text message can be received. The customerimmediately must notify EAL of any changes to contact information to continue to be enrolledin the rider and must participate in the sur^ey processes for providing feedback about thecustomer's participation. The customer's continued eligibility to participate in the PTR Pilot iscontingent on the customer providing this information to the Company.



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Original Sheet No. 60.0.1 Schedule Sheet 1 of 14





Title: Extension of Facilities (EOFP) PSC File Mark Only


60.0.0. EXTENSION OF FACILITIES

60.0.1. TABLE OF CONTENTS

SECTION TITLE SCHEDULE

SHEET 60.1. REGULATORY AUTHORITY 3 60.2 GENERAL PROVISIONS 3

60.2.1. SCOPE 3 60.2.2. REGULATORY APPROVAL 3 60.2.3. DEFINITIONS 4

A. Construction Services 4 B. Contribution in Aid of Construction (“CIAC”) 4 (1) Optional CIAC 4 (2) Mandatory CIAC 4 C. Estimated Investment 4 D. Guaranteed Payment 4 E. Permanent Residential Customer 4 F. Residential Allowance 5 G. Revenue 5 H. Seasonal Agricultural Allowance 5 I. Seasonal Agricultural Customer 5 J. System Improvements 5

60.2.4. COMPANY’S RIGHT TO DISCONNECT FACILITIES 6 60.2.5. CONTRIBUTION IN AID OF CONSTRUCTION (CIAC) 6 60.2.6. AGREEMENTS 6

A. Type 6 (1) Extension of Service Agreement 6 (2) Agreement for Electric Service 6 (3) Extension of Service Agreement for Planned Land Use

Developments 6

B. Term 6 C. Successor’s Responsibility 6

60.2.7. ADDITIONAL OR UNUSAL COSTS 7 60.2.8. EASEMENT 7

A. Responsibility to Provide 7 B. Residential Clearing 7 C. Seasonal Agricultural Clearing 8

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SHEET 60.2.9. CONSTRUCTION POWER SERVICE 8

A. Residential Single-Family Construction 8 B. Non-Residential, Seasonal Agricultural, and Residential Multi-

Family Construction 8

60.2.10. RELOCATION, REMOVAL OR UPGRADE OF EXISTING FACILITIES

9

A. Required 9 B. Not Required 9 C. Damaged Facilities 9

60.2.11. COMPANY’S OPTIMAL SERVICE ROUTE 9 60.3. EXTENSIONS 9

60.3.1. PERMANENT RESIDENTIAL EXTENSIONS 9 A. To a Single Customer 10 B. To Multiple Customers 10 C. Small Three-Phase Loads 11

60.3.2. PERMANENT NON-RESIDENTIAL EXTENSIONS 11 A. Seasonal Agricultural Customer Payment Options 12 B. Payment Options for All Other Permanent Non-Residential

Customers 12

C. Small Three-Phase Loads 13 60.3.3. NON-PERMANENT SERVICE LOCATIONS 13 60.3.4. PLANNED LAND USE DEVELOPMENTS 13

A. Estimated Net Investment 14 B. Revenue Guarantee 14

(1) Single-phase Facilities 14 (2) Three-phase Facilities 14

C. Annual Payment 14

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The Arkansas Legislature has delegated authority to the Arkansas Public Service Commission (“APSC” or the “Commission”) to regulate public utilities in the State of Arkansas, including Entergy Arkansas, LLC (EAL or the Company). The APSC’s regulatory authority over the provision of electric service applies not only in the service area allocated to EAL by the APSC but also extends to service to customers who have been released to EAL by other electric utilities, when such release for service has been approved by the Commission pursuant to Rule 6.07(b) or (c) of the Commission's Rules of Practice and Procedure. Similarly, the Tennessee Regulatory Authority exercises such authority delegated to it by the Tennessee legislature in areas of the State of Tennessee served by EAL.

This schedule is filed pursuant to Rule 3.02 of the Commission’s Special Rules - Electric (“SR – E”), Rule 3.03 of its General Service Rules (“GSR”) and Rule 7.03(e) of its Rules of Practice and Procedure (“RPP”).

60.2. GENERAL PROVISIONS

60.2.1. SCOPE

This Schedule applies to the installation of overhead electric delivery facilities for use by the Company in providing electric service to its customers and supersedes all prior policies, rules and regulations pertaining to such overhead facilities. However, the Company may install underground facilities in lieu of overhead facilities under the terms of this Schedule where it is not feasible to make overhead installations or where the cost of underground facilities is comparable to or less than the cost of comparable overhead facilities. All other underground facilities will be installed pursuant to the provisions of Rate Schedule No. 61, Tariff Governing the Installation of Electric Underground Residential Distribution Systems and Underground Service Connections (UGP).

60.2.2. REGULATORY APPROVAL

Any line extension provided for herein is subject to the Company obtaining, when required, a Certificate of Public Convenience and Necessity from the Commission.

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60.2.3. DEFINITIONS

A. Construction Services: The installation, removal, improvement, relocation, or replacement of electric delivery facilities as requested by a customer.

B. Contribution in Aid of Construction (“CIAC”):

(1) Optional CIAC: The amount a customer may pay to offset the costs of Construction Services as determined in accordance with § 60.3.1 Permanent Residential Extensions, § 60.3.2. Permanent Non-Residential Extensions or § 60.3.4 Planned Land Use Developments.

(2) Mandatory CIAC: The cost of Construction Services required to be paid by the customer by § 60.2.7, Additional Costs or Unusual Costs, by § 60.3.2, Permanent Non-Residential Extensions, or by § 60.3.3, Non-Permanent Service Locations.

C. Estimated Investment: The total estimated cost of electric delivery lines, rights-of-way, vegetation clearing, etc. to complete the requested Construction Services excluding any System Improvements included in the project. The Estimated Investment will not include the cost of commonly used distribution transformation, as determined by the Company.

D. Guaranteed Payment: A monthly bill amount excluding Riders ECR, NDCR, GGR and all other Rate Riders that may become effective by Commission order, franchise adjustment and sales tax that will be paid by the customer if greater than the Revenue calculated for the month in accordance with the customer’s rate schedule. The Guaranteed Payment is determined as:

1) (Estimated Investment - CIAC paid) times 1.25% (15% / 12) forsingle-phase extensions; or

2) (Estimated Investment – CIAC paid) times 2.5% (30% / 12) for three-phase extensions.

Where appropriate, this Guaranteed Payment determination will include provisions for the Residential Allowance or the Seasonal Agricultural Allowance.

E. Permanent Residential Customer: A customer having a residence of permanent type construction on a fixed foundation that is not readily movable and is intended for full-time, year-round occupancy. Mobile homes on permanent fixed foundations and intended for full-time year-round occupancy shall qualify as permanent residences, structures which are readily movable or which are not on permanent fixed foundations shall not qualify as permanent residences.

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F. Residential Allowance: The Company will extend up to 800 feet of single phase overhead primary and/or secondary facilities to a residential customer with no Total Customer Responsibility, as defined in § 60.3.1. When the extension exceeds 800 feet, the calculation of the customer’s Total Customer Responsibility will exclude the cost of the transformer and will reflect a credit equal in amount to the value of an 800 foot extension determined by expressing the 800 foot extension as a dollar amount based on the average cost per foot of the extension.

G. Revenue: An amount calculated in accordance with the rate schedule(s) under which the prospective customer will take electric service excluding Riders ECR, NDCR, GGR and all other Rate Riders that may become effective by Commission order, franchise adjustment and sales tax.

H. Seasonal Agricultural Allowance: The Company will extend up to 1,320 feet of single or three phase overhead primary and/or secondary facilities to a Seasonal Agricultural customer with no Total Customer Responsibility, as defined in § 60.3.2. When the extension exceeds 1,320 feet, the calculation of the customer’s Total Customer Responsibility will exclude the cost of the transformer and will reflect a credit equal in amount to the value of a 1,320 foot extension determined by expressing the 1,320 foot extension as a dollar amount based on the average cost per foot of the extension.

I. Seasonal Agricultural Customer: A customer qualifying for service under the terms and conditions of the General Farm Service (GFS) Rate Schedule No. 5 where the service requirements are of a recurring seasonal nature or a customer qualifying for service under the terms and conditions of the seasonal Agricultural Water Pumping Service (AP) Rate Schedule No. 14.

J. System Improvements: Improvements made to the electric delivery system, at the Company’s discretion, which are not necessary to provide the requesting party’s extension. This can also include the installation of three-phase facilities where the company desires to balance the load or provide for future expansions.

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60.2.4. COMPANY'S RIGHT TO DISCONNECT FACILITIES

Whenever an extension has been made to provide electric service to a customer or group of customers and said customer or customers cease to use or pay for service in accordance with the provisions of this Schedule and Company's Rate Schedules and Policy Schedules, applicable to such service, Company may, at its option, disconnect said facilities.

60.2.5. CONTRIBUTION IN AID OF CONSTRUCTION (CIAC)

Contributions payable under this Schedule are not refundable and are due in advance of the construction start date.

The Company shall retain ownership of all facilities and may use them in the normal course of business to serve other customers.

60.2.6. AGREEMENTS

A. Type: A customer or developer requesting Construction Services under this Rate Schedule must enter into the Agreements below as applicable. (1) Extension of Service Agreement with Customers (Policy Schedule

13.7.1): required if CIAC or Guaranteed Payment is required by this Rate Schedule.

(2) Agreement for Electric Service (Policy Schedule 13.3): required if a Guaranteed Payment is required by this Rate Schedule or if the customer’s electric service schedule requires an Agreement for Electric Service.

(3) Extension of Service Agreement for Planned Land Use Developments (Policy Schedule 13.7.2): required for developers when it is not possible to contract for service with ultimate customers.

B. Term: As required by the customer’s electric service schedule or this EOFP.

C. Successor’s Responsibility: If a customer elects and agrees on or after the effective date of this Schedule, or any customer agreed prior to the effective date of this Schedule, to make a monthly Guaranteed Payment and subsequently ceases to take service at the location to which service is extended, the monthly Guaranteed Payment shall be applicable to any successor owner or tenant. The Company may refuse service at such location to any successor owner or tenant who refuses to accept such Guaranteed Payment obligation.

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60.2.7. ADDITIONAL OR UNUSUAL COSTS

Additional or Unusual Costs are those arising from any cost-causing situation not normally encountered in the course of construction of Company facilities. Such costs include but are not limited to those such as the following: cost caused by right-of-way acquisition (including litigation expense if eminent domain procedures are required); excess right-of-way clearing costs as defined in § 60.2.8.B and 60.2.8.C; cost caused by construction on terrain unsuitable for the use of Company’s construction equipment; or cost caused by extended hours for expedited completion of a job at the request of the customer. All Additional or Unusual Costs mentioned in this schedule are governed by this § 60.2.7. Additional or Unusual Costs are not included in Estimated Investment as defined above and therefore shall not be offset by the Residential Allowance for residential customers or the Seasonal Agricultural Allowance. Such Additional or Unusual Costs shall be paid by the customer through a Mandatory CIAC only.

60.2.8. EASEMENT

A. Responsibility to Provide: Customer must provide at no cost to the Company suitable easements for Company’s facilities.

B. Residential Clearing: Residential customers will receive a right-of-way clearing cost credit for up to 800 linear feet of extension at the Company’s current average clearing cost per foot. The customer is responsible for clearing costs in excess of the clearing cost credit for up to 800 linear feet, the total clearing cost for the remainder of the length of the extension and for grading the easement to final grade. At the Company’s option, the Company may clear the easement and be reimbursed by the customer for the amount in excess of the clearing cost credit. All right-of-way on property owned by the customer may be cleared, to Company specifications, by the customer including that portion for which the customer receives a clearing cost credit. In areas where side trimming is needed after the customer has completed the clearing, the Company will trim only those trees the customer cannot trim. The customer will be responsible for removal of all debris. If the customer chooses to do the clearing and the Company must subsequently do additional clearing which cost exceeds the clearing cost credit, or if the Company installs its facilities and the grade is subsequently changed, customer will be required to pay such amount in excess of the clearing cost credit and the cost of grade re-work as Additional Cost or Unusual Costs (§ 60.2.7). Such Additional Cost shall not be offset by the Residential Allowance for residential customers but shall be paid by the customer through a Mandatory CIAC.

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C. Seasonal Agricultural Clearing: Seasonal Agricultural Customers will receive a right-of-way clearing cost credit for up to 1,320 linear feet of extension at the Company’s current average clearing cost per foot. The customer is responsible for clearing costs in excess of the clearing cost credit for up to 1,320 linear feet, the total clearing cost for the remainder of the length of the extension and for grading the easement to final grade. At the Company’s option, the Company may clear the easement and be reimbursed by the customer for the amount in excess of the clearing cost credit. All right-of-way on property owned by the customer may be cleared, to Company specifications, by the customer including that portion for which the customer receives a clearing cost credit. In areas where side trimming is needed after the customer has completed the clearing, the Company will trim only those trees the customer cannot trim. The customer will be responsible for removal of all debris. If the customer chooses to do the clearing and the Company must subsequently do additional clearing which cost exceeds the clearing cost credit, or if the Company installs its facilities and the grade is subsequently changed, customer will be required to pay such amount in excess of the clearing cost credit and the cost of grade re-work as Additional Cost or Unusual Costs (§ 60.2.7). Such Additional Cost shall not be offset by the Seasonal Agricultural Allowance for Seasonal Agricultural Customers but shall be paid by the customer through a Mandatory CIAC.

60.2.9. CONSTRUCTION POWER SERVICE

A. Residential Single-Family Construction: If there is no Total Customer Responsibility for permanent service as defined in § 60.3.1, temporary service for the construction of single-family residential dwellings will be provided by the Company, without requiring a CIAC or Guaranteed Payment. Customer will be billed in accordance with the Company’s approved rate schedules and rules and regulations when low capacity, single-phase service is required and the facilities will be utilized in place to serve the ultimate customer. Otherwise, the customer must make a Mandatory CIAC equal to 2.5 times the estimated costs (excluding salvageable material) of installing the required facilities for temporary service plus any Additional or Unusual Costs as defined in § 60.2.7.

B. Non-Residential, Seasonal Agricultural, and Residential Multi-Family Construction: The Company will provide either single-phase or three-phase service for construction power in accordance with this § 60.2.9.B. The customer must make a Mandatory CIAC equal to 2.5 times the estimated costs (excluding salvageable material) of installing the required, non-permanent facilities for temporary service plus any Additional or Unusual Costs as defined in § 60.2.7.

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60.2.10. RELOCATION, REMOVAL OR UPGRADE OF EXISTING FACILITIES

A. Required: When, in order to serve a new load for a residential customer, it is necessary to relocate, remove, or upgrade existing facilities, the costs of such relocation, removal, or upgrade shall be treated under the provisions of Section 60.3.1. PERMANENT RESIDENTIAL EXTENSIONS. When, in order to serve a new load for a Seasonal Agricultural Customer or other non-residential customer, it is necessary to relocate, remove, or upgrade existing facilities, the costs of such relocation, removal, or upgrade shall be treated under the provisions of Section 60.3.2. PERMANENT NON-RESIDENTIAL EXTENSIONS.

B. Not Required: When, the Company determines that such relocation or removal is not necessary in order to serve the customer’s new load, because the facilities are not in a hazardous location, and/or will not be out of useful service, the cost of such relocation, removal or upgrade of existing facilities will be paid by the customer. Charges for these costs shall be paid by the customer through a Mandatory CIAC.

C. Damaged Facilities: If the customer requests replacement, upgrade, and/or repair of facilities which have been damaged due to tampering, due to the customer’s failure to take reasonable care to protect them from physical damage and/or electrical demands, or due to failure to notify the Company of electrical load increase, the customer will be required to pay for the repair or replacement of the damaged facilities and other costs. The charges for such repair or replacement of such damaged facilities shall be paid by the customer through a Mandatory CIAC.

60.2.11. COMPANY’S OPTIMAL SERVICE ROUTE

The Company will build facilities to an optimal delivery point and along an optimal route with regard to Company’s costs. If a non-optimal delivery point or route is requested and provided, any cost in excess of the cost for the optimal delivery point and route shall be paid by the customer through a Mandatory CIAC.

60.3. EXTENSIONS

60.3.1. PERMANENT RESIDENTIAL EXTENSIONS

Construction of extensions under § 60.3.1 shall not begin until applicants for service from the proposed line extension have commenced construction or in the Company’s opinion, have invested significant time, effort, and resources into the site, and have completed other customer responsibilities as required by this Rate Schedule EOFP.

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A. To a Single Customer: The Company will extend its lines to provide single-phase electric service within its allocated area to permanent residential customers in accordance with its approved rate schedules and rules and regulations provided the customer agrees to pay the Total Customer Responsibility as determined by the formula below, pursuant to one of the Residential Customer Payment Options below.

Non-Seasonal Residential Customer Payment:

Total Customer Responsibility = Estimated Investment – Residential Allowance + Additional or Unusual Costs (§ 60.2.7).

The Estimated Investment – Residential Allowance cannot be less than zero.

All Additional or Unusual Costs (§ 60.2.7) must be paid as a Mandatory CIAC. The remaining Total Customer Responsibility may be paid: (1) as an Optional CIAC; or (2) as a monthly Guaranteed Payment equal to:

a) 1.25% multiplied by the result of the Estimated Investment minusthe Residential Allowance for single-phase extensions; or

b) 2.5% multiplied by the result of the Estimated Investment minus theResidential Allowance for three-phase

(3) as a combination of Optional CIAC and monthly Guaranteed Payment where the Guaranteed Payment is based on the Estimated Investment less both the Residential Allowance and Optional CIAC paid.

Customers choosing option (2) or (3) above must enter into an Agreement for Electric Service with an initial term of no less than three years.

Seasonal Residential Customer Payment:

Seasonal residential customers must pay the Total Customer Responsibility including all Additional or Unusual Costs (§ 60.2.7) as a Mandatory CIAC.

B. To Multiple Customers: In the event a single extension is made to provide service to more than one permanent residential customer, the above formula shall apply based on the total Estimated Investment and total Residential Allowance for all of the customers. In the case of platted and recorded residential subdivisions or separately metered apartment complexes, the Residential Allowance will be multiplied by the number of lots or apartments to determine the total allowance. However, no credit for unused allowances will be applied against the Additional Costs or Unusual Costs (§ 60.2.7).

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C. Small Three-Phase Loads: A residential location qualifies for three-phase service only if the location’s single motor rating exceeds 7½ hp or the sum of the location’s multiple motor ratings exceeds 20 hp. If a customer requests three-phase service but the location qualifies only for single-phase service, the Company will build three-phase facilities following the customer’s payment for the construction of the requested facilities. The customer will receive the Residential Allowance as determined in § 60.2.3.F. The Additional Cost to be paid by the customer will be the difference in cost between three-phase and single-phase primary wires, transformers and secondary wires.

60.3.2. PERMANENT NON-RESIDENTIAL EXTENSIONS

All customers requiring Permanent Non-Residential Extensions must enter into an Agreement for Electric Service for a minimum term of three years or such longer time as may be required by the customer’s applicable rate schedule. However, where the customer chooses to pay the Estimated Investment and all Additional or Unusual Costs prior to construction, the customer will not be required to enter into an Agreement for Electric Service, unless one is otherwise required, and the customer’s account will not be subject to a Guaranteed Payment. All other customers will be subject to a Guaranteed Payment as described in § 60.2.3.D in any month that the customers’ Revenue is less than the Guaranteed Payment.

Company will construct the facilities necessary to provide service in accordance with its approved rate schedules and rules and regulations, provided the customer agrees to pay the Total Customer Responsibility, as determined by the formulas below, utilizing the Non-Residential Customer Payment Options below.

Anyone requesting a line extension to a location which will ultimately be comprised of multiple service points shall be required to pay the Total Customer Responsibility as a Mandatory CIAC, except in cases where line extension costs are allocable between the developer and known tenants taking service at the time of construction. In that case, each service location for such developer and known tenants will be responsible for an allocated share of the Total Customer Responsibility and be subject to a Guaranteed Payment with payment options the same as described below for any other permanent non-residential customer. If the total Customer Responsibility is paid as a Mandatory CIAC, an Agreement for Electric Service will not be required by this policy and the accounts established at that site will not be subject to a Guaranteed Payment.

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A. Seasonal Agricultural Customer Payment Options:

Total Customer Responsibility = Estimated Investment – Seasonal Agricultural Allowance + Additional or Unusual Costs (§ 60.2.7).

The Estimated Investment – Seasonal Agricultural Allowance cannot be less than zero.

All Additional or Unusual Costs (§ 60.2.7) must be paid as a Mandatory CIAC. The remaining Total Customer Responsibility may be paid: (1) as an Optional CIAC; or (2) as a monthly Guaranteed Payment equal to:

a) 1.25% multiplied by the result of the Estimated Investment minusthe Seasonal Agricultural Allowance for single-phase extensions; or

b) 2.5% multiplied by the result of the Estimated Investment minus theSeasonal Agricultural Allowance for three-phase

(3) as a combination of Optional CIAC and monthly Guaranteed Payment where the Guaranteed Payment is based on the Estimated Investment less both the Seasonal Agricultural Allowance and Optional CIAC paid.

Customers choosing option (2) or (3) above must enter into an Agreement for Electric Service with an initial term of no less than three years.

B. Payment Options for All Other Permanent Non-Residential Customers:

Total Customer Responsibility = Estimated Investment + Additional or Unusual Costs

All Additional or Unusual Costs (§ 60.2.7) must be paid as a Mandatory CIAC. The Customer may pay all, some portion or none of the remaining Total Customer Responsibility as an optional CIAC. If the Customer opts to pay less than the entire amount of the remaining Total Customer Responsibility as an optional CIAC, then the Customer will be subject to a monthly Guaranteed Payment as described in § 60.2.3.D.

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C. Small Three-Phase Loads: A location qualifies for three-phase service only if the location’s single motor rating exceeds 7½ hp or the sum of the location’s multiple motor ratings exceeds 20 hp. If a customer requests three-phase service but the location qualifies only for single-phase service, the Company will build three-phase facilities following the customer’s payment for the construction of the requested facilities. If applicable, the customer will receive the Seasonal Agricultural Allowance as determined in §60.2.3.H. The Additional Cost to be paid by the customer will be the difference in cost between three-phase and single-phase primary wires, transformers and secondary wires. These charges shall be paid by the customer through a Mandatory CIAC.

60.3.3. NON-PERMANENT SERVICE LOCATIONS

In cases where the customer has requested the installation of single- or three-phase electric delivery facilities to a non-permanent service location, the customer will be required to pay in advance the costs for installing and removing the facilities. The customer must pay a Mandatory CIAC equal to 2.5 times the estimated costs (excluding salvageable material) of installing the temporary extension plus the cost of right-of-way and right-of-way clearing. Charges for costs associated with temporary extensions shall not be offset by the Residential Allowance for residential customers or the Seasonal Agricultural Allowance for non-residential customers but shall be paid by the customer through a Mandatory CIAC.

60.3.4. PLANNED LAND USE DEVELOPMENTS

The Company will extend single-phase and three-phase facilities into planned land use developments as provided in this § 60.3.4. A planned land use development is defined as an area of at least 100 acres in size which is being developed over a period of several years for residential, commercial or industrial use and in which it will be necessary for the Company to construct three-phase feeder circuits to provide adequate service for the anticipated electric loads of the completed planned development. In order for the Company to extend its facilities to provide electric service when needed and since it is not possible to contract for service with the ultimate customers, it is necessary that the Company and the Developer enter into an Extension of Service Agreement for Planned Land Use Development (Policy Schedule 13.7.2) describing the facilities to be provided by Company and the Revenue Guarantee required by the Developer. The Company will provide the necessary facilities as requested by the Developer if the Developer agrees to make an Annual Revenue Guarantee to the Company as determined in 60.3.4.B and an Annual Payment as determined in 60.3.4.C below.

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A. Estimated Net Investment: The Company's Estimated Net Investment in such facilities will be determined by estimating the cost of the facilities, including overhead and underground facilities, and subtracting contributions for underground facilities and/or other contributions made by the Developer and/or allowances granted in accordance with this Schedule. For residential subdivisions the Residential Allowance will be multiplied by the number of lots to determine the total allowance. However, no credit for unused allowances will be applied against the Additional or Unusual Costs (§ 60.2.7).

B. Revenue Guarantee:

(1) Single-phase Facilities: The Company's Estimated Net Investment in single-phase facilities, as determined in 60.3.4.A. above, which have been in place for the entire contract year, will be multiplied by 1.25% times 12. The Company's Estimated Net Investment in single-phase facilities, as determined in A above, which have not been in place for the entire contract year, will be multiplied by 1.25% times the number of months in the contract year in which said facilities were in place.

(2) Three-phase Facilities: The Company's Estimated Net Investment in three-phase facilities, as determined in 60.3.4.A. above, which have been in place for the entire contract year will be multiplied by 2.5% times 12. The Company's Estimated Net Investment in three-phase facilities, as determined in A above, which have not been in place for the entire contract year, will be multiplied by 2.5% times the number of months in the contract year in which said facilities were in place.

C. Annual Payment: Annually the total accumulated electric revenue excluding Riders ECR, NDCR, GGR and all other Rate Riders that may become effective by Commission order, franchise adjustment and sales tax from all customers within the planned development will be subtracted from the sum of the amounts determined in 60.3.4.B. above, and the Developer will pay the positive difference, if any, at the end of each contract year. If such Revenue exceeds the Revenue Guarantee no payment will be made by either party.

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Title: Tariff Governing the Installation of Electric Underground Residential Distribution Systems and Underground Service Connections (UGP)

PSC File Mark Only


61.0. TARIFF GOVERNING THE INSTALLATION OF ELECTRIC UNDERGROUND RESIDENTIAL DISTRIBUTION SYSTEMS AND UNDERGROUND SERVICE CONNECTIONS

61.0.1. TABLE OF CONTENTS


SHEET

61.1. REGULATORY AUTHORITY 3 61.2. GENERAL REGULATIONS 3

61.2.1. SCOPE 3 61.2.2. REGULATORY APPROVAL 3 61.2.3. DEFINITIONS 4 61.2.4. GENERAL PROVISIONS 4

A. Character of Service 4 B. Extension of Facilities for Metered Service Across Public Ways 5 C. Ownership of Facilities 5 D. Payments and Charges 5 E. Street Lighting 6 F. Removal, Relocation or Conversion of Existing Facilities 6 G. Conflicts 6

61.3. CONSTRUCTION STANDARDS 7 61.3.1. SITE PREPARATION 7 61.3.2. CODES AND STANDARDS 7 61.3.3. JOINT OCCUPANCY OF TRENCHES 7

61.4. UNDERGROUND DISTRIBUTION SYSTEMS IN SUBDIVISIONS AND MOBILE HOME PARKS

7

61.4.1. APPLICATION BY DEVELOPER 7 61.4.2. LOCATION AND ORIGIN 8 61.4.3. RESPONSIBILITY OF PARTIES 8 61.4.4. TEMPORARY SERVICE 9 61.4.5. PAYMENTS TO COMPANY BY DEVELOPER 9 61.4.6 CONTRACT AND PAYMENTS BY DEVELOPER 11

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SHEET 61.5. UNDERGROUND PRIMARY AND SECONDARY EXTENSIONS 12

61.5.1. RESIDENTIAL 12 61.5.2. NON-RESIDENTIAL 13

61.6. RESIDENTIAL AND NON-RESIDENTIAL UNDERGROUND SERVICE CONNECTIONS

13

61.6.1. AVAILABILITY 13 61.6.2. APPLICATION BY CUSTOMER 14 61.6.3. LOCATION AND ORIGIN 14 61.6.4. METERS AND METER ENCLOSURES 14 61.6.5. RESPONSIBILITY OF PARTIES 15

61.7. CHARGES AND PAYMENTS FOR SERVICE CONNECTIONS 16 61.7.1. RESIDENTIAL CUSTOMERS 16 61.7.2. INDIVIDUALLY METERED APARTMENTS 16 61.7.3. NON-RESIDENTIAL CUSTOMERS 16

61.8. CONVERSION OF EXISTING OVERHEAD SERVICE TO UNDERGROUND

17

61.9. DIFFERENTIAL COSTS FOR UNDERGROUND SERVICE 18

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The Arkansas Legislature has delegated authority to the Arkansas Public Service Commission (“APSC” or the “Commission”) to regulate public utilities in the State of Arkansas, including Entergy Arkansas, LLC (EAL or the Company). The APSC’s regulatory authority over the provision of electric service applies not only in the Distribution Service area allocated to EAL by the APSC but also extends to service to customers who have been released to EAL by other electric distribution utilities, when such release for service has been approved by the Commission pursuant to Rule 6.07(b) or (c) of the Commission's Rules of Practice and Procedure. Similarly, the Tennessee Regulatory Authority exercises such authority delegated to it by the Tennessee legislature in areas of the State of Tennessee served by EAL.

61.2. GENERAL REGULATIONS

61.2.1. SCOPE

A. This Tariff applies to the installation of underground electric distribution systems, including street lighting facilities, in residential subdivisions and permanent mobile home parks and to underground service connections for use by Company in providing electric service to its customers, and supersedes all prior policies, rules and regulations pertaining to such underground facilities.

B. Subdivisions and mobile home parks to be served pursuant to this Tariff shall consist of a single parcel of land arranged and situated so that an underground electric distribution system will be the only electric distribution system required within the subdivision or mobile home park.

C. Underground service connections from Company's underground or overhead distribution facilities will also be installed pursuant to this Tariff.

61.2.2. REGULATORY APPROVAL

Any line extension provided for herein is subject to Company obtaining, when required, a Certificate of Public Convenience and Necessity from the Arkansas Public Service Commission.

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61.2.3. DEFINITIONS

A. Construction Services - The installation, removal, improvement, relocation, or replacement of Company-owned distribution facilities as requested by a customer.

B. Contribution in Aid of Construction (CIAC) - The amount a customer must pay to offset any excess costs of Construction Services as determined in this Schedule UGP.

C. Developer - A person, partnership, association, corporation, or governmental agency that owns, operates, or develops a subdivision or a mobile home park.

D. Distribution System - Electric service facilities consisting of primary cables, transformers, secondary cables and necessary accessories and appurtenances for the furnishing of electric power and energy at utilization Voltage to electric customers but not including service connections.

E. Mobile Home Park - A platted and recorded single parcel of land divided into five or more mobile home sites with permanent sewer, water, and individually metered electric connections at each home site designed to be occupied on a year-round basis. A mobile home park which does not meet these requirements is outside the scope of this Tariff.

F. Service Connections - The electrical facilities extending from the secondary connection on the distribution system to the point of metering, but not including meters.

G. Subdivision - A platted and recorded single parcel of land subdivided into five or more building lots on which dwelling units are to be built.

61.2.4. GENERAL PROVISIONS

A. Character of Service

The Company will normally provide three-wire, single phase service at 120/240 Volts to subdivision and mobile home customers. However, three-phase service of 120/240, 120/208Y or 277/480Y Volts may be made available to commercial installations in a subdivision or mobile home park in accordance with the provisions and charges in § 61.4.5.A and § 61.4.5.B.

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B. Extension of Facilities for Metered Service Across Public Ways

(1) No facilities on the load side of any meter shall pass under or over any public street, alley or other public way except pursuant to the Commission's General Service Rule 5.20.

(2) In the event that an apartment or commercial development is so built that a public way separates the buildings of the project, each individual building or group of buildings so separated shall be treated as a separate development for purposes of installing underground facilities and metering and billing electric service.

C. Ownership of Facilities

(1) All facilities provided hereunder by Company will remain the property of Company to be operated and maintained by Company.

(2) All facilities provided hereunder by Company for which Developer or owner makes either full or partial payment shall remain the property of Company and will be operated and maintained by Company.

(3) All facilities provided hereunder by Developer or customer for Company's use under this Tariff will be the property of the Company and will be operated and maintained by Company.

D. Payments and Charges

(1) All payments due Company from Developer or customer under this Tariff will be paid in advance of any underground construction. Provided, however, all payments due Company under this Tariff from applicants for permanent individual residential service may, at the customer's request and if the Company deems appropriate, be billed and paid with the first month's billing for service.

(2) Payments and/or contributions made or facilities furnished by Developer or customer pursuant to this Tariff shall not be in lieu of or in substitution for any amounts due Company under Company's Rate Schedule No. 60, Extension of Facilities.

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(3) All facilities provided and/or installed and all trenching and backfilling performed by Developer or customer shall be provided, installed or performed in accordance with Company’s construction standards pursuant to § 61.3. Any costs incurred by Company to bring such facilities provided, installed or performed by customer into compliance with Company standards shall be paid by Developer or customer.

(4) Underground differential charges made pursuant to this policy shall not be included as Additional Facilities under the Additional Facilities Charge Rider.

E. Street Lighting

(1) When street lights are to be installed in the subdivision at the time of installation of underground distribution system, and the municipality contracts with Company for such street lighting service, Company will furnish, install, own, and maintain the entire street lighting system, including poles, fixtures and underground cable in accordance with the provisions of Company's then effective Municipal Street Lighting Service Rate Schedule and the provisions of § 61.4.5.

(2) When the municipality does not contract with Company for street lighting service within the subdivision, any street lighting service furnished by Company will only be supplied in accordance with Company's then effective All Night Outdoor Lighting Service Rate Schedule L4, § 12.4 or Small General Service Rate Schedule SGS as metered service with underground charges paid for under the provisions of § 61.4.5. Subdivisions in unincorporated areas may also be served pursuant to L4 § 12.4 or SGS.

F. Removal, Relocation or Conversion of Existing Facilities

Where Company has overhead facilities located within a subdivision at the time Developer applies for an underground distribution system under this Tariff, Company shall remove, relocate or convert such facilities to underground and Developer shall pay Company in accordance with the charges and provisions of § 61.4.5.E.

G. Conflicts

The terms and provisions of this Tariff are subject to the terms and provisions of the Company's Policy Schedule No. 9, Service Regulations and Rate Schedule No. 60, Extension of Facilities unless there is a direct conflict between the terms and provisions of this Tariff and the provisions of the Company's Policy Schedule No. 9 or Rate Schedule No. 60, in which case the terms and provisions of this Tariff shall control.

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61.3. CONSTRUCTION STANDARDS

61.3.1. SITE PREPARATION

No underground installation of electric distribution system or service connection facilities will be made until all rough site grading has been completed and final grade is established for the area in which such facilities are to be installed. If final grade is later changed all costs required to adjust Company facilities to such change will be paid by developer or customer.

61.3.2. CODES AND STANDARDS

Company's installation of facilities under this Tariff will be in accordance with Company's construction standards which meet or exceed the minimum requirements of the National Electrical Safety Code at the time of installation.

Developer's installation of facilities for Company use under this Tariff shall be in accordance with Company's construction standards.

Customer installation of facilities as a part of the service connections, including a service ground, shall be in accordance with all applicable Company construction standards the National Electrical Code and all state and local codes applicable thereto at the time of installation.

61.3.3. JOINT OCCUPANCY OF TRENCHES

Joint occupancy of trenches with communication utilities will be used except where not feasible from the standpoint of safety or economics provided that all utilities occupying a trench share equitably in the cost of the trenching and backfilling where the trenching and backfilling is not provided by the Developer.

61.4. UNDERGROUND DISTRIBUTION SYSTEMS IN SUBDIVISIONS AND MOBILE HOME PARKS

61.4.1. APPLICATION BY DEVELOPER

A. Developer desiring underground electric distribution will submit application to Company before plat of easements and Bill of Assurance are filed for record. It is important that this application be submitted as early in the planning stage as possible so that the installation can be engineered and sufficient facilities constructed in time to serve construction power requirements of the subdivision as needed.

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B. Developer will furnish to Company, before recordation, a plat showing the location and nature of the area to be developed. Developer will, at no cost to Company, provide and record all easements and rights-of-way required by Company and will execute or cause to be executed all other contracts and agreements required by Company.

C. Developer will notify all purchasers of lots and/or dwelling units of all provisions of the easements and rights-of-way granted to Company by incorporating same in the Bill of Assurance, plat of easements and other documents which shall be filed for recordation prior to the sale of any lot.

61.4.2. LOCATION AND ORIGIN

A. Company's underground distribution system will originate at its overhead and/or underground terminal(s) located on Developer's property adjacent to the property line at point(s) determined by Company, and will be installed on the street side of all lots except that by agreement Company may take easements on rear property lines for the installation of all or part of its facilities.

B. In the event that Company's overhead facilities are across the street or otherwise separated from Developer's property and it is requested that facilities be extended to the property line underground instead of overhead, or in the event that it is impossible or impractical to locate a terminal pole on Developer's property, Company will make such extension underground from the closest practical point on its overhead system to the nearest point on Developer's property line in accordance with the provisions and charges of § 61.4.5.D.

61.4.3. RESPONSIBILITY OF PARTIES

A. Developer Responsibility

(1) Developer will furnish and provide completely installed for Company's use all conduits and primary junction boxes as required, will open all trenches, prepare trench for cable installation and, after installation of cable, close all trenches, all according to Company specifications. Company may by agreement perform the trenching and backfill operations and be reimbursed its estimated cost by Developer.

(2) Mobile home park Developer will, in addition to providing the items required in § 61.4.3.A.(1) above, provide a suitable structure at each mobile home location for the meter installation and furnish and install a meter enclosure and the conduit and fittings from the meter enclosure to the service trench adjacent to the structure.

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B. Company Responsibility

(1) Company will furnish, install, own and maintain a complete distribution system, including all primary cables, transformers, transformer protective devices, secondary cables, and other related equipment, and, if contracted for, street lights and street light cables.

(2) For mobile home parks, the Company will, in addition to providing the items called for in § 61.4.3.B.(1) above, furnish, install, own and maintain an underground service connection from the point of attachment to its distribution system up to the point of connection at each meter location.

61.4.4. TEMPORARY SERVICE

Under this Tariff there is no provision for a temporary distribution system to serve Developer and/or building contractors. Temporary service, if required, will be supplied by Company only at the full expense of Developer or building contractors for all installation and removal charges in accordance with Company's Rate Schedules and Policy Schedules.

61.4.5. PAYMENTS TO COMPANY BY DEVELOPER

A. For single or three-phase distribution, Developer shall pay to Company the difference in the estimated cost of the underground distribution system and the estimated cost of a comparable overhead distribution system prior to installation of underground facilities.

(1) If three-phase service is requested initially, Developer will pay to Company, in addition to other applicable charges, the difference between the estimated installed cost of additional equipment and materials necessary to provide three-phase distribution and the estimated installed cost of comparable overhead three-phase facilities.

(2) If three-phase service is requested after the single-phase distribution system has been installed, the party requesting three phase-service will pay to Company, in addition to the charges listed in § 61.4.5.A.(1) above, the estimated cost of opening and closing the trench, the estimated installed cost of all conduit required, and the estimated cost of crossing or repairing streets and other paved areas.

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B. For single or three-phase distribution in a mobile home park, Developer will pay to Company the difference in the estimated cost of the underground distribution system and service connections and the estimated cost of a comparable overhead distribution system and service connections.

C. Where street or all night outdoor lighting is installed in a subdivision or mobile home park under the Company's then effective Rate Schedules, all provisions of the applicable Rate Schedule shall apply except that:

(1) Where underground street lighting cable is installed in a common trench with the distribution cable at the time the underground distribution is installed, or in a trench which has been opened and closed by Developer, the extra facilities charge applicable to underground street lighting service under the above-mentioned Rate Schedules will not be applied.

(2) The extra facilities charge for steel poles under the above-mentioned Rate Schedules will not be applied when Developer pays Company the difference between the cost of a 30-foot wood pole included in such Rate Schedule and a standard 17-foot pole (as shown in § 61.9) for each such street lighting pole installed.

(3) Where Developer requests equipment other than that which is standard with Company and such equipment is acceptable to Company, Developer will purchase and install all such non–standard equipment. The Company shall not own or be responsible for the maintenance of such non-standard equipment.

(4) Where added costs will be incurred for any other equipment related only to underground construction of the street lighting system that would not be required for overhead construction Developer will pay such costs. Such costs will include but not be limited to the cost of additional transformation, pull boxes and junction cabinets.

D. Charges to be paid to Company by Developer for underground extension(s) from Company's overhead facilities to terminal point(s) on Developer's property will be computed as the difference between the estimated cost of the underground extension(s) and the estimated cost of comparable overhead extension(s).

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E. Charges to be paid to Company by Developer for removal, relocation or conversion of overhead facilities to underground shall be the net amount of the following debit and credit items.

(1) Debit Items

a. The total installed cost (labor, material, and other costs) of the new facilityincluding transformers and metering equipment.

b. Cost of removing the existing facilities.

c. Any operating and maintenance expense necessary in connection with theremoval, relocation or conversion of the existing facilities.

(2) Credit Items

a. The cost of any improvement, such as increased capacity not necessary toprovide service to the subdivision, made voluntarily by Company as part ofthe replacement of existing facilities.

b. Salvage allowance based on estimated remaining life of reusable materialsremoved including transformers and metering equipment.

(3) Removal of Idle Facilities

No charge or credit will be made for the removal of overhead facilities which are no longer in use to serve any of Company's customers.

F. Where Company incurs additional cost as a result of changes made in the initial subdivision layout or the final grade as agreed upon between Company and Developer or customer, Developer or customer shall reimburse Company for all such additional cost.

61.4.6 Contract and Payments by Developer

A. Contract The Company will provide the necessary facilities as requested by the Developer if the Developer agrees to pay the required CIAC to the Company prior to construction as determined in § 61.4.6.B. and § 61.4.6.C. below. The Company and the Developer shall enter into an Agreement for Residential Underground Electric Distribution System in Subdivision describing the facilities to be provided by each party and the CIAC, if any, required of the Developer.

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B. Initial Estimated Net Investment The Company’s Estimated Net Investment in such facilities will be determined by estimating the cost of the Company facilities, including overhead and underground facilities less any CIAC paid for underground differential costs. Prior to construction the Developer will be required to pay a CIAC for all additional differential costs not covered by the value of the Developer furnished items described in § 61.4.3.A.(1).

C. Adjusted Estimated Net Investment The Adjusted Estimated Net Investment will be the Estimated Net Investment reduced by the Residential Allowance times the number of lots within the subdivision. Prior to construction the Adjusted Estimated Net Investment will be paid as a CIAC by the Developer. Such CIAC will be paid in addition to the CIAC required for underground differential costs as described in § 61.4.6.B. above. If the Adjusted Estimated Net Investment is zero or less no additional CIAC will be required, however, if the Adjusted Estimated Net Investment is negative it cannot be used to reduce the CIAC determined under § 61.4.6.B.

61.5. UNDERGROUND PRIMARY AND SECONDARY EXTENSIONS

61.5.1. RESIDENTIAL

The Company will extend its primary and/or secondary facilities underground to serve the customer as follows: A. Where the customer has requested construction and has paid a CIAC for all costs of

construction in excess of the cost of overhead construction (“OH/UG Differential Costs”); B. Where no OH/UG Differential Costs exist; or C. Where, in the Company’s opinion, it is not feasible to make overhead extensions.

The Residential Allowance defined in the Company’s Extension of Facilities Policy, Rate Schedule 60, § 60.2.3.F applies only to the cost of comparable overhead construction for up to 800 feet of single phase overhead primary and/or secondary facilities to a residential customer.

The total charges for the extension of facilities will be calculated pursuant to the terms of the Company’s Extension of Facilities Policy, Rate Schedule 60, § 60.3.1.A wherein the Estimated Investment will be determined based on the least cost method of providing service and the applicable OH/UG Differential Costs will be included in the Total Customer Payment calculation as Additional Costs and will therefore be paid as CIAC. The payment terms of § 60.3.1.A shall also apply.

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The Company will extend its primary and/or secondary facilities underground to serve the customer as follows: A. Where the customer has requested construction and has paid a CIAC for all costs of

construction in excess of the cost of overhead construction (“OH/UG Differential Costs”);

B. Where no OH/UG Differential Costs exist; or C. Where, in the Company’s opinion, it is not feasible to make overhead extensions. The customer will pay a CIAC calculated to include any applicable OH/UG Differential Costs.

Seasonal Agricultural Customers:

The Seasonal Agricultural Allowance defined in the Company’s Extension of Facilities Policy, Rate Schedule 60, § 60.2.3.H applies only to the cost of comparable overhead construction for up to 1,320 feet of single or three phase overhead primary and/or secondary facilities to a seasonal agricultural customer.

The total charges for the extension of facilities will be calculated pursuant to the terms of the Company’s Extension of Facilities Policy, Rate Schedule 60, § 60.3.2.A wherein the Estimated Investment will be determined based on the least cost method of providing service and the applicable OH/UG Differential Costs will be included in the Total Customer Payment calculation as Additional Costs and will therefore be paid as CIAC. The payment terms of § 60.3.2.A shall also apply.

61.6. RESIDENTIAL AND NON-RESIDENTIAL UNDERGROUND SERVICE CONNECTIONS

61.6.1. AVAILABILITY

A. Service connections from underground distribution systems must be underground.

B. Underground service connections are available from the Company pursuant to this Tariff, except for temporary service, for any customer served from Company's overhead or underground distribution facilities. Company will install no underground service connections smaller than 100 Amperes

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61.6.2. APPLICATION BY CUSTOMER

Underground service connections will be installed under an Agreement for Underground Service Connection between the customer and the Company in substantially the same form as shown in Policy Schedule No. 13, § 13.6 when:

A. Customer chooses to be billed for charges calculated pursuant to § 61.7.1.A and returns the signed Agreement For Underground Service Connection to Company; and

B. Customer provides Company with any easements the Company deems necessary.

61.6.3. LOCATION AND ORIGIN

A. Underground service connection will originate at the secondary conductors on the pole (in the case of an overhead distribution system) or transformer or secondary conductor (in the case of an underground distribution system) located at or near the customer's property line at a point determined by Company, and will follow the most direct practical route to the agreed upon meter location.

B. Where underground service connections are to be provided from overhead facilities and such facilities are located across a street or otherwise separated from customer's property, the extension to customer's property line will normally be overhead. However, in the event customer desires such extension underground and Company deems such feasible, the extension will be made underground and customer will pay Company all costs in excess of an overhead extension.

61.6.4. METERS AND METER ENCLOSURES

The Company will furnish, install, own, and maintain all meters and metering equipment except as noted below.

A. Customer will furnish and install at the agreed upon location the meter enclosure for any single or three phase service connection of 320 Amperes or less.

B. Company will furnish and customer will install at the agreed upon location the meter enclosure (does not include the current transformer enclosure) for all service connections requiring instrument rated transformers.

All equipment supplied by customer must be to Company specifications.

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61.6.5. RESPONSIBILITY OF PARTIES

A. Customer Responsibility:

(1) The customer shall be responsible for all trenching and backfilling to Company specifications.

(2) The customer shall be responsible for the installation and maintenance of an electrical ground, which meets or exceeds all requirements of the National Electrical Code and of all state and local codes applicable thereto at the time of such installation, and for grounding the neutral bus of the service entrance panel, main disconnecting switch or main circuit breaker.

(3) The customer shall, at his expense, furnish and install at the agreed upon location the meter enclosure and the conduit and fittings from the meter enclosure to the service trench or junction box at a point adjacent to the building.

(4) Installation of service conductors under any area to be paved should be avoided where possible. If it is known that paving will be placed over the service conductors, the customer shall install conduit under the area to be paved to contain such conductors prior to paving.

B. Company Responsibility

(1) The Company will install service conductors or cable from the meter enclosure to the point of connection to its distribution system including the riser conduit if required and bend at the terminal pole, transformer or secondary conductor and will make the connections at the meter enclosure and at the terminal pole, transformer or secondary conductor.

(2) In the event the customer prefers to install, own, and maintain his underground service, customer shall furnish and install an approved meter pedestal within 5 feet of the pad-mount transformer, secondary pedestal, or transformer pole. Company will install and connect Company-owned underground cable to the meter pedestal. Customer-owned service cable must be installed on the load side of the meter.

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61.7. CHARGES AND PAYMENTS FOR SERVICE CONNECTIONS

61.7.1. RESIDENTIAL CUSTOMERS

A. Charges to be paid to Company by customer are an amount equal to the differential cost, if any, between the estimated cost of the underground service connection and the estimated cost of a comparable overhead connection. Such differential costs are shown in § 61.9 of this schedule.

B. Charges to be paid Company by customer for single-phase service connections in excess of 320 Amperes and for three-phase service connections is an amount equal to the difference, if any, between the estimated cost of the underground service connection and the estimated cost of a comparable overhead service connection.

61.7.2. INDIVIDUALLY METERED APARTMENTS

A. Apartment buildings will be served from a single service connection per building. Where permitted by local codes, sections of a building isolated by a fire wall(s) may be considered as separate buildings.

B. When the dwelling units in an apartment building(s) are individually metered, with the service entrances and meter enclosures grouped at a single location on an exterior wall of the building, each dwelling unit will be considered a separate residential customer and provided with the appropriate meter enclosure. The customer shall, at his expense, furnish and install at the agreed upon location the meter enclosure and the conduit and fittings from the meter enclosure to the service trench or junction box at a point adjacent to the building.

C. Where national or local codes require a main disconnecting device ahead of a group of individual meters such disconnecting device will be the responsibility of the owner of the premises to furnish, install and maintain.

D. Charges to be paid to Company by customer for the installation of underground service connections are the Company's total estimated cost of the installation of such facilities less the estimated cost of comparable overhead facilities.

61.7.3. NON-RESIDENTIAL CUSTOMERS

A. Nonresidential customers are all customers not served on residential rate schedules and include apartment buildings served through a single meter under a general service rate schedule.

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B. Charges to be paid to Company by customer are an amount equal to the difference, if any, between the estimated cost of the underground service connection and the estimated cost of a comparable overhead connection.

C. The underground service connections to serve a customer should be installed in the manner resulting in the lowest installed cost. The most economical installation may, in some cases, be underground primary from the customer's property line to a transformer near the building and a secondary run from the transformer to the point of metering.

D. To determine the cost difference between underground and overhead service connections, the underground cost estimate will be compared with the estimated cost of an equivalent overhead installation. The estimated cost of the underground facilities includes the differential cost between the transformer used for underground service and an equivalent overhead transformer installation.

61.8. CONVERSION OF EXISTING OVERHEAD SERVICE CONNECTIONS TO UNDERGROUND

A. Existing overhead service connections which require a change because load growth makes the existing facilities inadequate will be treated as new service connections except that customer will be responsible for all trenching and backfilling to Company specifications.

B. Removal of an adequate existing overhead service connection and conversion to underground service by the Company will be performed on the following basis:

(1) Customer will be responsible for all trenching and backfilling to Company specifications.

(2) Customer will reimburse the Company for the cost of all materials and labor required to provide the underground service and all labor costs associated with removal of the existing facilities.

(3) Charges for such removal and installation, and credits due customer for existing facilities shall be calculated in accordance with § 61.4.5.E.(1), (2) and (3) and customer shall pay the net charge resulting from such calculation.

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61.9. DIFFERENTIAL COSTS FOR UNDERGROUND SERVICE

Single-phase 100 Amp (3)

Single-phase 200 Amp (3)

Single-phase 320/400 Amp (3)

Base Cost Originating From: Overhead In Company Provided Conduit $295.00 $320.00 $325.00 In Customer Provided Conduit(4) $284.00 $308.00 $307.00

Underground ($16.00) ($9.00) ($54.00)

Incremental Cost - $/Foot: (2) In Company Provided Conduit (1) $5.64 $5.96 $8.49 In Customer Provided Conduit (1) $2.70 $3.02 $4.61

Differential cost per pole: See § 61.4.5.C.(2) $60.00

NOTES:

(1) Due to widely varying soil composition in the service area these costs do not include trenching or backfilling. The cost to be paid by customer for trenching and backfilling will be provided at the time service is requested.

(2) The incremental cost per foot applies to the total service length from a point on the ground below the connection to Company’s distribution facilities to a point on the ground below the customer’s meter.

(3) The Differential Costs in this § 61.9 shall be reviewed annually. If the costs have changed they will be reflected in the above table and filed with the Commission for approval. Such filing shall be made with the filing of the updates to Rate Schedule 29, Customer Activity Charges (CAC) if the CAC requires changes. If the CAC does not require changes in a year but § 61.9 does require changes it may be filed as a stand alone update to this Rate Schedule 61.

(4) The customer is responsible for supplying the 36” radius long sweep factory bend 90 degree Schedule 80 elbow at the base of the dip pole. The Company will supply the conduit on the Company’s pole. See Entergy Customer Installation Standards for Electric Service drawing # SS8.6.3.

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Title: Solar Energy Purchase Option (SEPO) PSC File Mark Only


62.0. SOLAR ENERGY PURCHASE OPTION

62.1. GENERAL AVAILABILITY

Available only to Customers taking service from Entergy Arkansas,LLC (“EAL” or the “Company”) who enter into a Solar Energy Purchase Option Agreement (Policy Schedule No. 13.21) Option A or Option B, as applicable, with the Company.

A Customer who qualifies to take service for a specific account under either SEPO Option A or SEPO Option B, as applicable, can take service under the applicable option, but a single account for electric service cannot subscribe to both at the same time.

This SEPO schedule is not available to Customers taking service under Net-Metering Service N-M.

The total amount of subscriptions offered to those Customers taking service under this SEPO schedule is limited to fifty (50) percent of EAL’s Designated Solar Resource (Stuttgart Solar, LLC) offering, or 40.5 MW.

Availability to eligible customers is on a first-come, first-serve basis in the order that Solar Energy Purchase Option Agreements are received and approved, except that Customers who have submitted a Letter of Intent (LOI) associated with a SEPO Option B offering as of June 15, 2020 and existing SEPO Option A Customers as of June 15, 2020, will have priority eligibility to request service under SEPO Option B.

If, after one year following the effective date of this SEPO schedule, any portion of the 40.5 MW of EAL’s Designated Solar Resource is not fully subscribed by those Customers with priority eligibility, other qualifying Customers may request to take service under SEPO Option B. In the event, however, that the 40.5 MW of EAL’s Designated Solar Resource is fully subscribed, other qualifying Customers, including qualified low- and fixed-income customers, interested in enrolling in this SEPO schedule may request to be included on a waiting list on a first-come, first served basis. These customers will indicate a preference for SEPO Option A or SEPO Option B at that time. As additional capacity is made available, waitlisted customers will be contacted to complete the enrollment process by determining the appropriate subscribed capacity and class of service as described in 62.2 and 62.4 and executing the SEPO contract.

62.2. OPTION A AVAILABILITY

SEPO Option A is available to Customers served under one of the following rate schedules:

1. Residential Service Rate Schedules RS, RT, and REMT2. Small General Service Rate Schedules SGS, GFS, MP, AP, SMWHR, and CGS3. Large General Service Rate Schedules LGS, GST, LPS, and PST

EAL Further Responsive Compliance Exhibit AMW-1Docket No. 19-042-TF

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Residential Service: Customers may opt for a minimum of 1 kW of available solar capacity and may elect additional blocks of 1 kW up to 5 kW.

Small General Service: Customers may opt for a minimum of 5 kW of available solar capacity and may elect additional blocks of 5 kW. Large General Service: Customers may opt for a minimum of 100 kW of available solar capacity and may elect additional blocks of 100 kW.

62.3. OPTION A MONTHLY BILLING

A. In addition to the monthly billing amount under applicable rate and rider schedules, Customer’s bill will include an amount equal to:

SEPO Energy x (SEPO Option A Energy Rate - MISO Market Settlement Rate)

B. SEPO Option A Energy Rate $0.05345 per kWh

The Company shall file a revised SEPO Option A Energy Rate for approval in the event that additional Designated Solar Resources become available.

62.4. OPTION B AVAILABILITY

SEPO Option B is available to Customers served under one of the following rate schedules:

1. Residential Service Rate Schedules RS, RT, and REMT2. Small General Service Rate Schedules SGS, GFS, AP (optional monthly rate B

only), and SMWHR3. Large General Service Rate Schedules LGS, GST, LPS, and PST.

Non-residential customers taking service under SEPO Option B must be demand metered.

SEPO Option B is not available to Customers who take service under the Small Cogeneration Rider (SCR), Large Cogeneration Rider (LCR), or the Optional Interruptible Service Rider (OISR).

The applicable standard rate schedule for Customers taking service under SEPO Option B will be the standard rate schedule deemed most economical before the provisions of SEPO B are applied.

SEPO Option B Customers may opt for a minimum of 1 kW of available capacity and may elect additional blocks of 1 kW. Customer’s election is intended to offset all or a portion of its electricity requirements.


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Replacing: 1st Revised Sheet No. 62.3


Kind of Service: Electric Class of Service: All Docket No.: 10-008-UOrder No.: 8




EAL may evaluate a Customer’s subscription on an annual basis to determine if the subscription for a Customer’s account results in an energy offset greater than the Customer’s electricity requirements over a twelve- month period. If, in the sole judgement of the Company, the subscription results in an energy offset that exceeds a Customer’s electricity requirements, the Company may require a new contract modifying the kW subscription for the account to align with the Customer’s electricity requirements.

62.5. OPTION B MONTHLY BILLING

A. The monthly billing kWh as defined in the applicable rate and rider schedules will bereduced by the Customer’s monthly SEPO Energy. In the event that the difference inthe standard rate schedule monthly billed kWh and the monthly SEPO Energy resultsin kWh less than 0, the billing kWh for that month will be 0 kWh, and the creditdifference will carry over to the next billing month as a credit to billing kWh for the nextmonth. kWh credits will not expire and can be carried forward to subsequent billingcycles indefinitely.

B. In addition to the amount resulting from 62.5.A., Customer’s bill will include an amountequal to:

SEPO Energy x SEPO Option B Energy Rate

C. SEPO Option B Energy Rate $0.05345 per kWh

D. If an account under the Customer’s SEPO Option B agreement is permanently closed,then for that account the Company will purchase any uncredited energy associatedwith 62.5.A. at the estimated annual average Avoided Cost rate for wholesale energy.


62.6.1 SEPO Option A

The initial term of agreement under SEPO Option A shall be for a one year period and shall automatically be extended for successive periods of one year each until terminated by written notice given by one party to the other not more than six months nor less than two months prior to the expiration of the original term or any anniversary thereof.

If Customer discontinues service with EAL, the agreement for SEPO Option A will be terminated except if 1) the Customer is relocating within the EAL service area, 2) initiates service at a new location at the time of discontinuing the original service, and 3) takes service at the new location under the same rate schedule as the original service, then Customer may opt to transfer his SEPO agreement to the new account for service.



Replacing: 15‘ Revised Sheet No. 62.3


Kind of Service: Electric Class of Service: fl Docket No.: 10-008-UOrder No.: 8


Title: Solar Enerqv Purchase Option (SEPO) PSC ”'5 Markon'y

62.5.

62.6.

62.6.1

EAL may evaluate a Customer’s subscription on an annual basis to determine if thesubscription for a Customer’s account results in an energy offset greater than theCustomer’s electricity requirements over a twelve- month period. If, in the sole judgementof the Company, the subscription results in an energy offset that exceeds a Customer’selectricity requirements, the Company may require a new contract modifying the kWsubscription for the account to align with the Customer’s electricity requirements.

OPTION B MONTHLY BILLING

A. The monthly billing kWh as defined in the applicable rate and rider schedules will bereduced by the Customer’s monthly SEPO Energy. In the event that the difference inthe standard rate schedule monthly billed kWh and the monthly SEPO Energy resultsin kWh less than 0, the billing kWh for that month will be 0 kWh, and the creditdifference will carry over to the next billing month as a credit to billing kWh for the nextmonth. kWh credits will not expire and can be carried forward to subsequent billingcycles indefinitely.

B. In addition to the amount resulting from 62.5.A., Customer’s bill will include an amountequal to:

SEPO Energy x SEPO Option B Energy Rate

C. SEPO Option B Energy Rate $005345 per kWh

D. If an account under the Customer’s SEPO Option B agreement is permanently closed,then for that account the Company will purchase any uncredited energy associatedwith 62.5.A. at the estimated annual average Avoided Cost rate for wholesale energy.

CONTRACT PERIOD

SEPO Option A

The initial term of agreement under SEPO Option A shall be for a one year period and shallautomatically be extended for successive periods of one year each until terminated bywritten notice given by one party to the other not more than six months nor less than twomonths prior to the expiration of the original term or any anniversary thereof.

If Customer discontinues service with EAL, the agreement for SEPO Option A will beterminated except if 1) the Customer is relocating within the EAL service area, 2) initiatesservice at a new location at the time of discontinuing the original service, and 3) takesservice at the new location under the same rate schedule as the original service, thenCustomer may opt to transfer his SEPO agreement to the new account for service.



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62.6.2 SEPO Option B

The term of agreement for SEPO Option B service shall be the remaining life of the Purchase Power Agreement (PPA) associated with the Designated Solar Resource upon which the Customer’s contractual SEPO Capacity subscription is based.

If the Customer discontinues service with EAL, the agreement for SEPO Option B will be terminated and Customer will be ineligible to re-enroll in SEPO Option B, except that Customer may choose to transfer its SEPO Option B agreement to a new account for service if 1) the Customer is relocating within the EAL service area, 2) the Customer initiates service at a new location at the time of discontinuing the original service, and 3) the Customer takes service at the new location under the same rate schedule as the original service. In the event that a SEPO Option B customer elects to transfer a subscription to a new account under these circumstances, the subscription will be adusted, if appropriate, to reflect the anticipated usage at the new location.

The SEPO Option B agreement may not be cancelled except in the case where the Customer permanently discontinues electric service with the Company. In the event that the Customer has multiple accounts for electric service included on a single SEPO Option B Agreement and changes or cancels one or more accounts but not all of the accounts included in the agreement, the SEPO Option B Agreement will not terminate and will remain in force for the remainder of accounts. The Company reserves the right to periodically review and adjust subscription levels to ensure the Customer’s SEPO energy does not exceed the remaining accounts.

62.7. RENEWABLE ENERGY CREDITS (RECS)

For new Customers taking service under and/or existing Customers remaining under SEPO Option A, Company shall retire the RECs associated with the Customer’s SEPO Energy under this Rider on behalf of each Customer. Company shall not reitre the RECs for Customers taking service under SEPO Option B; RECs associated with service under SEPO Option B shall be retained by non-participating customers pursuant to Order No. 11 in Docket No. 19-042-TF.

62.8. DEFINITIONS

Capacity of Solar Resources: Capacity associated with EAL’s Designated Solar Resource(s).

Designated Solar Resource(s): the renewable solar resource(s) designated by the Company and approved by the Commission to supply renewable energy for this SEPO.

MISO Market Settlement Rate: Per kWh rate derived from monthly net settlements from Midcontinent Independent System Operator, Inc. (MISO) energy markets and the MISO

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Planning Resource Auction associated with the Designated Renewable Resource(s). Application for billing purposes will be on a two month lag.

Monthly Solar Resource kWh Output: Amount of kWh generated each calendar month by EAL’s Designated Solar Resource(s). Application for billing purposes will be on a two month lag.

SEPO Capacity: The total amount of kW demand contracted by a Customer as described in 62.2. and 62.4.

SEPO Energy: The monthly energy associated with the Customer’s contracted SEPO Capacity. [(Customer’s SEPO Capacity / Capacity of Designated Solar Resources) x Monthly Solar Resource kWh Output]. Application for billing purposes will be on a two month lag.

62.9. PAYMENT

Payment shall be made in accordance with Rate Schedule No. 29, Charges Related to Customer Activity (CAC), § 29.19.


All other provisions, prices and regulations of EAL’s standard rate schedules effective at the time service is provided shall apply and are not modified by this SEPO schedule.

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Original Sheet No. P1.1 Schedule Sheet 1 of 2




Part IV. Policy Schedule No. 1 Effective: 2/1/19

Title: Pick A Date Plan (PADP) PSC File Mark Only


1.0. PICK A DATE PLAN (Extended Due Date Plan)

1.1. This Pick A Date Plan (“the PLAN”) has been filed and approved pursuant to Arkansas Public Service Commission (‘APSC”) General Service Rule (“GSR”) 5.09. and meets all of the requirements of that Rule. Under the Plan, Entergy Arkansas, LLC (“EAL” or the “Company”) will, at the request of eligible customers, move their normal bill due date, to a date of the customer’s choosing (“Chosen Due Date”). Such customers shall pay by the Chosen Due Date and payments so made will be considered as having been made timely.

1.2. AVAILABILITY

This Plan is available to all EAL customers except those listed below as not eligible. The Plan may be beneficial to customers who may have a fixed income from sources such as Aid to Families with Dependent Children (AFDC), Aid to the Aged, Blind and Disabled (AABD), Supplemental Security Income (SSI), or Social Security or Veterans Administration disability or retirement, where checks may normally be received after the due date of their electric service bill.

Customers that are not eligible are: (1) those being served under the Collective Billing Rider (CBR), Rate Schedule No. 19 or

other accounts whose billing date is set by contract; (2) those that are in arrears and arrangements have not been made to pay such arrears; (3) those that have been removed from the plan within the last 12 months either at the

customer’s request or for the reasons set out in § 1.4 below.

1.3. APPLICATION

1.3.1. Customers shall become participants in the Plan upon either written or oral application to the Company. Participation in the Plan will continue for each month thereafter, regardless of account location, as long as the customer's account remains active and customer has not violated any of the provisions of § 1.4 below.

1.3.2. After the Company accepts the customer as a participant in the Plan, the customer shall select a Chosen Due Date and inform the Company of such Chosen Due Date which will become a permanent part of the customer's record. During the billing procedure each month, the Chosen Due Date will replace the customer’s normal due date. If payment is not received by the Chosen Due Date, the Company will follow the established notification process as set forth in the APSC GSR 6.04, which could result in termination of electric service.

1.3.3. Customer may elect to change the elected Chosen Due Date no more than four times in a twelve month period.

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Title: Pick A Date Plan (PADP) PSC File Mark Only


1.4. REMOVAL FROM THE PLAN

A Customer who violates any of the following provisions may be removed from the Plan:

(1) the customer pays after the Chosen Due Date two times in a row or any three times in twelve months;

(2) the customer is disconnected for non-payment.

The Company shall notify the customer in writing upon the customer’s removal from the Plan under this provision.

1.5. REINSTATEMENT IN THE PLAN

Customers removed from the plan pursuant to § 1.4. above may be reinstated upon request after twelve months with no violations of the provisions of § 1.4 above.

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Title: Budget Billing Plan (BBP) PSC File Mark Only


2.0. BUDGET BILLING PLAN (Levelized Billing Plan)



2.2. BILLING OPTIONS

2.2.1. Levelized Billing Option

2.2.1.1 Availability

This Levelized Billing Option is available upon request only to customers in the following groups who take service year-round under the conditions specified herein:

• customers served under Rate Schedule No. 1, General Purpose ResidentialService (RS); Rate Schedule No. 2, Optional Residential Time-of-use (RT); orRate Schedule No. 33, Residential Energy Management Time-of-Use (REMT);

• any church account;• any elementary or secondary school account (pre-kindergarten through twelfth

(12th) grade);• accounts taking service under Rate Schedule No. 4, Small General Service

(SGS) or Rate Schedule No. 5, General Farm Service (GFS).

EAL applies the following credit criteria to determine eligibility:

• Residential Customers are eligible if:(a) Customer has no balance in arrears for sixty days or greater,(b) Customer has had no more than one returned check within the past twelve

months, (c) Customer has no unpaid balance resulting from a returned check, and(d) Customer has no past due deposit charges;

• Non-residential Customers are eligible if they have no previous balances pastdue and have not received a disconnect notice in the most recent twelve (12)months.

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This Levelized Billing Option is not available to customers taking temporary or seasonal service.

2.2.1.2 Billing Procedure

The Customer's monthly bill will be computed in accordance with the applicable rate schedule and the Customer's account will be debited with such amount (“Billed Amount”). The net amount payable for the current month (“Levelized Amount”) will equal, to the nearest whole dollar, the average monthly Billed Amount debited to the Customer's account during the twelve (12 ) months ending with the current month, plus or minus one-twelfth (1/12) of the accumulated difference between previous debits and the Levelized Amounts payable under this option.

2.2.1.2.A.Fold-In Option

At the time of enrollment, a residential customer may request that an existing bill amount be rolled into the accumulated difference when that amount is not in arrears for more than 29 days. Deposit amounts will not be included in the existing bill amount to be rolled into the accumulated difference.

2.2.2. Equal Pay Billing Option

2.2.2.1. Availability

For any year-round Residential Customer or church account that desires to take service under the conditions specified herein and who requests such service. Not applicable to temporary or seasonal service.

2.2.2.2. Billing Procedure

The Customer's monthly bill will be computed in accordance with the applicable rate schedule and the Customer's account will be debited with the Billed Amount. The net amount payable for service for the current month (“Equal Pay Amount”) will equal, to the nearest whole dollar, one-twelfth (1/12) of the current plus eleven (11) prior months’ amounts billed for all metered electric service to the account. During the billing process of the thirteenth (13th) month (“Anniversary Month”), and during the billing process of each subsequent Anniversary Month, the Equal Pay Amount will be recalculated. The new Equal Pay Amount for the current and next eleven (11) months will equal one-twelfth (1/12) of the sum of the current and prior eleven (11) months’ Billed Amounts plus the current balance of the accumulated differences between the previous twelve (12) months’ Billed Amounts and Equal Pay Amounts. The Equal Pay Amount may be adjusted in any month in which there is significant variation between the Equal Pay Amount and the current balance of the accumulated difference.

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2.3. ACCOUNT HISTORY AVAILABILITY

Customers who take service under Rate Schedule SGS or GFS, or who are church, or elementary or secondary school accounts, must have twelve (12) complete months of billing history at the present service location.

Residential customers must have twelve (12) months’ representative billing history at the present service location to determine the Levelized or Equal Pay amounts. Where the billing history is complete and representative, the customer’s twelve-month history will be used. Where the billing history is incomplete but representative, estimates of monthly bills may be made for incomplete periods based on the average for the class or the customer’s available history. Where the customer’s billing history is complete but non-representative, estimates based on the average for the class may be used for the months that are not representative. Where the customer’s billing history is incomplete and non-representative, estimates of monthly bills may be made based on the average for the class. All such estimates will be made solely to determine the current month's Levelized amount or the next twelve (12) months Equal Pay Amount.

2.4. WITHDRAWAL

Customers who voluntarily or involuntarily withdraw from either of the above options for any reason will not be eligible for service under this Plan until the seventh (7th) billing month following such withdrawal. The transfer of all or portions of accumulated difference credit balance at the request of the customer to satisfy payment of a current bill shall constitute voluntary withdrawal from service under this Plan.

2.5. TERMINATION AND SETTLEMENT

Billing under this Plan may be terminated by the customer at any time by giving reasonable notice to the Company and may be automatically terminated by the Company upon discontinuance of service for any reason appearing in the Commission’s General Service Rule 6.01, Authorized Suspension (GSR 6.01). In the event billing under this Plan is terminated at the request of the customer or for any reason appearing in GSR 6.01 settlement shall be made immediately for the balance of the customer's account. A Delayed Payment Agreement may be available to qualifying residential or commercial customers as defined in GSR 6.13.

Customers taking service under this Plan who for any reason subsequently request that their service be provided under a Rate Schedule not named in the Availability Section above will be withdrawn from service under this Plan.


Except as modified herein, all terms and conditions of the applicable rate schedule(s) shall remain unchanged and apply.

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Title: Extended Absence Payment Plan (EAPP) PSC File Mark Only


3.0. EXTENDED ABSENCE PAYMENT PLAN (General Service Rule 5.11.)

3.1. This Extended Absence Payment Plan provides payment options for Customers planning to be away from their homes for an extended period but who wish to avoid suspension of service by keeping their electric service account current.

3.2. PAYMENT OPTIONS

3.2.1. Option 1:

The Customer may apply for a draw draft plan, which automatically pays the Customer's electric service bill through Customer’s checking or savings accounts, by contacting their financial institution or Entergy Arkansas, LLC (“EAL” or the “Company”).

3.2.2. Option 2:

The Customer may ask the Company to forward the Customer’s bill to a temporary mailing address.

3.2.3. Option 3:

The Customer may make a prepayment to Customer’s electric service account. The Customer may contact the Company for assistance in determining the amount of prepayment needed. However, the final determination of the adequate amount of prepayment will be the sole responsibility of the Customer. Any amounts billed for electric service for which prepayment was not provided and for which payment is not received by the due date shall be considered a late payment pursuant to GSR 5.06.

3.3. NOTIFICATION:

The Customer must notify the Company in order to take advantage of any of the extended absence payment options listed above.

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Title: Provisions for Landlords and Tenants (LTP) PSC File Mark Only


4.0. PROVISIONS FOR LANDLORDS AND TENANTS (General Service Rule 6.19.)

4.1. ACCOUNT IDENTIFICATION

4.1.1. Entergy Arkansas, LLC (“EAL” or the “Company”) has established the following procedures for identifying landlord/tenant accounts:

A. At the time of application, EAL will mail to the new customer an informational booklet that describes the provisions of the Landlord/Tenant process. Landlords may identify themselves to the Company and identify their tenants by name, address, and account number. This can be done at the time of application or any subsequent call to the Company’s Customer Service Center.

B. When EAL is made aware of a landlord tenant relationship at a particular account, they will mail the landlord a form to be completed and returned to EAL. When the completed form is received, the account will be coded so that it is identified as a landlord tenant relationship.

4.2. PROCEDURES FOR SUSPENDING SERVICE

4.2.1. Prior to suspending service to accounts constituting a landlord/tenant relationship as identified by GSR 6.19.A., the Company shall take the following actions:

A. A suspension notice shall be mailed or delivered to the landlord. B. If no response is received from the landlord within 7 days from the mail date of the

suspension notice, the Company shall post a suspension notice in conspicuous locations at the premises, such as near mail boxes, building entrances and exits, and any other areas of common usage. In cases where the premises contains 20 or less individual units, the Company may mail a suspension notice to each tenant at least 14 days before suspending service.

C. Service will not be suspended until the account is at least 30 days past due. D. If separate metering is feasible at the premises, the Company will allow any tenant to

apply for service in the tenant's name. 4.2.2. No tenant will be required to pay any amounts owed by the landlord to the Company.

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Title: Standard Nominal Voltages (SNVP) PSC File Mark Only


5.0. STANDARD NOMINAL VOLTAGES (Special Rules - Electric 6.01.A.)

Rule 7.03(g)(1) of the Arkansas Public Service Commission (the “Commission”) Rules of Practice and Procedure and Rule 6.01.A. of the Commission's Special Rules - Electric provide that each electric utility shall file the nominal voltage to be supplied to a customer as a tariff.

5.1. NOMINAL VOLTAGES - SECONDARY

The following secondary voltages are available from Entergy Arkansas, LLC (the “Company”) depending on the size of the customer's electrical load, application, and location on the Company's distribution system:

5.1.1. Single Phase - Three Wire:

120/240 120/208 240/480

5.1.2. Three Phase - Three Wire:

240 480 2,400

5.1.3. Three Phase - Four Wire:

120/240 120/208Y 277/480Y 4,160Y/2,400

5.2. NOMINAL VOLTAGES - PRIMARY

The following primary voltages are available from the Company depending on the size of the customer's electrical load, application, and location on the Company's distribution system:

13,800Y/7,960 12,470Y/7,200 34,500Y/19,920

5.3. OTHER VOLTAGE SERVICE

Depending on the size of the customer's electrical load, application, and location, customers requiring other voltages may be served through special arrangements under written agreements.

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Kind of Service: Electric Class of Service: Not Applicable Docket No.: 18-073-TF Order No.:


Title: Voltage Vertification Plan (VVP) PSC File Mark Only


6.0. VOLTAGE VERIFICATION PLAN (Special Rules - Electric 6.01.C.(2))

Rule 6.01.C.(2) of the Arkansas Public Service Commission (“Commission”) Special Rules - Electric and Rule 7.03(g)(3) of the Commission's Rules of Practice and Procedure provide that each electric utility shall file, within one year of Commission adoption of these Rules, its plan for verifying voltage standards at each distribution substation through continual voltage recordings.

6.1. ELECTRIC VOLTAGE VERIFICATION PLAN

Entergy Arkansas, LLC employs a SCADA (Supervisory Control & Data Acquisition) system and/or voltmeters at each of its distribution substations. SCADA continually monitors and stores data regarding the voltage levels at each substation and voltmeters verify voltage levels by recording continual voltage readings.

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Title: All Night Outdoor Lighting Maintenance Policy (OLMP) PSC File Mark Only


7.0. ALL NIGHT OUTDOOR LIGHTING MAINTENANCE POLICY

7.1. NORMAL MAINTENANCE

Entergy Arkansas, LLC (“EAL” or the “Company”) will install, own, operate and provide normal maintenance for the luminaire or floodlight, which will include repair or replacement of bulbs, photoelectric cells and heads (containment devices) which were defective when installed or have become defective through the normal aging process. Such normal maintenance will be provided at Company's expense within three (3) business days after notice is given by the customer. If in Company's sole judgment repair or replacement is required due to purposeful physical damage or vandalism of Company's All Night Outdoor Lighting facilities the repair or replacement of the facilities shall be considered unusual maintenance.

7.2. UNUSUAL MAINTENANCE

Company will perform such unusual maintenance up to three times in a twelve-month period for a single account at Company's expense. After the third such occurrence Company shall notify customer that unusual maintenance has been required and that the cost of the next such unusual maintenance within the twelve month period shall be the responsibility of and billed to customer's account. If payment for such unusual maintenance is not made within the time period allowed in the Payment provision of Rate Schedule No. 12, All Night Outdoor Lighting Service (L4), the Agreement For All Night Outdoor Lighting Service shall be terminated and Company's facilities will be removed.

7.3. NOTICE TO CUSTOMER

Notice to Customer will be in substantially the following form:

Dear Customer:

Entergy Arkansas, LLC has performed unusual maintenance on All Night Outdoor Lighting Facilities installed for your account three times within the last twelve month period. In accordance with the Company's Policy Schedule No. 7, All Night Outdoor Lighting Maintenance Policy filed with the Arkansas Public Service Commission you will be billed for the cost of any further unusual maintenance required for this account within the twelve month period which began ___________, 20__. If a billing is rendered for unusual maintenance costs you shall have twenty-one (21) days after the bill is mailed in which to make payment. If payment is not made within the twenty-one (21) day time period the Agreement For All Night Outdoor Lighting Service shall be terminated and Company's All Night Outdoor Lighting facilities will be removed.

If you have questions concerning this notice or your All Night Outdoor Lighting Service account you may call your EAL Customer Service Specialist at __________________.

Thank you for allowing EAL to serve you. 756


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Title: Quick Pay Center Payment (QPCP) PSC File Mark Only


8.0. QUICK PAY CENTER PAYMENT



8.2. AUTHORITY

This Quick Pay Center Policy Schedule (“Policy”) has been filed with and approved by the Arkansas Public Service Commission (“APSC”) to describe the policy of Entergy Arkansas, LLC (“EAL” or “Company”), regarding payment of EAL issued customer invoices at non Company-owned locations by non Company employees.

8.3. APPLICATION

The Company has entered into agreements with a number of privately owned retail businesses (“Authorized QPC(s)”) throughout its service territory creating a network of locations where any EAL customer may present and pay an EAL electric service invoice. Non-EAL employees staff these Authorized QPCs. The Policy applies to all EAL issued customer invoices paid at an EAL Authorized QPC. When such payment is tendered the Authorized QPC will be allowed to charge a fee of $0.75 per transaction.

The Company maintains “free” Quick Pay Centers (“QPCs”), also authorized by the Company and consistent with Order No. 2 in APSC Docket No. 02-150-TF, where customers may present and pay an EAL electric service invoice without charge. All savings achieved through the operation of this schedule will be used to offset the increased cost of “free” QPCs and make improvements to the QPC processes. Information regarding the locations of such payment centers may be obtained by dialing 1-800-ENTERGY.

The Policy does not modify or supersede any of the provisions of any of EAL’s filed and approved Rate Schedules, in particular, the requirement that the customer must pay the full amount of the invoice by its Due Date to avoid penalty remains unchanged. The Company assumes no responsibility for late payments when such payments are received after the Due Date.

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Title: Quick Pay Center Payment (QPCP) PSC File Mark Only



Service under this schedule is subject to Policy Schedule No. 9, Service Regulations, as it is now or may in the future be approved by the Commission, and the Rules of the Commission and the Company.

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Title: Service Regulations (SRP) PSC File Mark Only





9.2. DEFINITIONS

The following expressions when used in these Service Regulations, Rate Schedules, and in Service Agreements, shall, unless otherwise indicated, have the meanings given below.

9.2.1. POINT OF DELIVERY

The point at which Company ownership of facilities terminates and at which customer's ownership of facilities begins, or as otherwise defined and agreed upon in an Agreement for Electric Service.

9.2.2. CUSTOMER'S INSTALLATION

In general, all electrical circuits and facilities of any kind or nature on customer's side of the point of delivery (except Company's meter installation).

9.2.3. SERVICE DROP

The wires owned by Company connecting Company's distribution facilities to customer's service terminals.

9.2.4. MONTH

An interval of approximately 30 days, except when the calendar month is specified.

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9.2.5. NOTICE

A written notification delivered personally or mailed by one party to the other at such other party's last known address -- the period of notice being computed from the date of such personal delivery or mailing.

9.2.6. METER

The meter or meters, excluding the meter enclosure and current transformer enclosure, together with auxiliary devices, if any, constituting the complete installation needed to measure the power and energy supplied to any individual customer at a single point of delivery.

9.2.7. COMPANY EXTENSION TO CUSTOMER

Any branch from, or continuation of, an existing line to the point of delivery to customer, including increases in capacity of any of Company's existing facilities, or the changing of any lines to meet the customer's requirements, including all transformers, service drops, meters, and installed service facilities owned by Company.

9.2.8. NATIONAL ELECTRICAL CODE

The current edition of the National Electrical Code Standard of the National Board of Fire Underwriters for Electric Wiring and Apparatus as recommended by the National Fire Protection Association.

9.2.9. INTERCONNECTION FACILITIES

All facilities installed to interconnect and receive power from or deliver power to the customer including, but not limited to, connection, transmission, distribution, transformation, switching, metering and safety equipment. Interconnection Facilities shall include any additions and/or reinforcements to the Company's system required to facilitate interconnection, that the Company, in a reasonable exercise of its judgment, deems necessary.

9.2.10. ON-SITE GENERATION

Any device(s) capable of generating power and energy that is (are), or may be, connected on the customer’s side of the point of delivery for the purpose of satisfying all or a portion of the customer’s electrical requirements at any time. The customer’s facility and equipment shall meet all requirements of applicable codes, and all requirements of any duly constituted regulatory or municipal authority having jurisdiction. The Company’s determination of the applicability of a code, or any portion thereof, shall be subject to review by the Commission upon petition by the customer.

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9.3. AGREEMENTS FOR ELECTRIC SERVICE - NONRESIDENTIAL

9.3.1. CUSTOMER'S RIGHT TO CANCEL AGREEMENT FOR ELECTRIC SERVICE OR SUSPEND OPERATIONS

Unless Company has made an out of the ordinary investment, or has a specific contract to provide service to customer for a term of years, under the Agreement for Electric Service, customer, after giving 10 days written notice and receiving Company's written approval, may suspend operation if no electric service is required during the period of suspension of operation. In the event of such suspension of operation, the expiration date of the Agreement for Electric Service shall be extended for a period of time equal to the period of suspension of operation. Under like circumstances customer may give Company 30 days written notice of desire to cancel the Agreement, if due to permanent and total abandonment of operation, electric service is no longer required on the premises. If Company is satisfied that customer no longer requires any electric service, the Agreement may be canceled by Company, at its option, giving customer written acceptance of such notice of permanent and total abandonment.

9.3.2. COMPANY'S RIGHT TO CANCEL AGREEMENT FOR ELECTRIC SERVICE OR TO SUSPEND SERVICE

The Company may terminate the Agreement For Electric Service pursuant to Section 6 of the APSC General Service Rules and for use of service in a manner prohibited by any of Company’s applicable tariffs. Failure of Company to act at any time pursuant to the foregoing except as noted in GSR 6.09.A.(4), shall not affect any of the Company's rights hereunder or constitute a waiver of any remedy or defense afforded by law.

9.4. SUPPLYING AND TAKING OF ELECTRIC SERVICE

9.4.1. CONTINUITY OF ELECTRIC SERVICE

Company will use all reasonable diligence in providing a regular and uninterrupted supply of electric service, but does not guarantee the electric service against interruptions or irregularities. In case the supply of electricity shall fail, or be interrupted, or become defective through an act of God, or the public enemy, or state, municipal or other public authority, or because of accident, strike, or any other causes beyond the reasonable control of the Company, Company shall not be liable for such failure, interruption or defect.

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9.4.2. INTERRUPTION OF ELECTRIC SERVICE FOR REPAIRS AND CHANGES

When necessary to make repairs to or changes in Company's plant, transmission or distribution system, or other property, Company may, without incurring any liability, interrupt electric service for such periods as may be reasonably necessary. Company will notify customer in advance of such interruption whenever possible.

There shall be no reduction of demand, minimum or similar charges for months in which such interruptions do not exceed an aggregate of twenty-four hours. There shall be a pro rata reduction in such charges for months in which such interruptions do exceed that amount, which reductions shall be liquidated damages to customers for all defaults of Company in electric service rendition.

9.4.3. USE OF ELECTRIC SERVICE

Customer shall use service only for the purpose specified in the Agreement for Electric Service and in accordance with the provisions of the Rate Schedule designated therein.

In no case shall customer extend or connect his installation to lines across or under a street, alley, lane, court, avenue or other public space in order to obtain electric service for adjacent property through one meter even though such adjacent property be owned by customer unless such extension is made pursuant to Arkansas Public Service Commission General Service Rule (GSR) 5.20., Separate Metering and Billing.

Company shall have the right to refuse to commence or to continue electric service whenever it appears that customer's installation is not in good operating condition. Company does not in any event assume any responsibility whatever in connection with any hazards or injury caused by the customer’s failure to maintain the customer’s installation.

9.4.4. CUSTOMER'S RESPONSIBILITY

Customer assumes all responsibility on customer's side of the point of delivery for the electric service supplied or taken, as well as for the electrical installation, appliances and apparatus used in connection therewith, and shall save Company harmless from and against all claims for injury or damage to persons or property occasioned by or in any way resulting from such electric service or the use thereof on customer's side of the point of delivery. Company does not in any event assume any responsibility in connection with such matters. Notwithstanding the foregoing, a customer who is prohibited by law shall not be required to save Company harmless from and against claims for injury or damage to persons or property as set forth above.

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Customers that have On-Site Generation facilities shall not operate such facilities in parallel with the facilities of the Company unless all of the safety and technical requirements of the Company’s published policies on parallel operation of generation are satisfied and the customer has executed a written agreement covering such parallel operation and the proper coordination of protective devices. The reasonableness of the Company’s published policies, or any portion thereof, shall be subject to review by the Commission upon petition by the customer. Such customers shall be solely responsible for providing protective devices to disconnect their facilities from those of the Company when a disturbance on the Company's system results in their generation becoming isolated from the Company's generation.

9.4.5. RIGHT OF WAY

Without reimbursement customer shall make or procure conveyance to Company of right of way (to include licenses for franchises, if essential) for all Company owned distribution facilities whether installed by Company, purchased by Company or contributed to Company by customer and for all future extensions and modifications to such facilities, satisfactory to Company for Company's extension and shall protect Company in its peaceful use and occupancy of such right of way.

9.5. CUSTOMER'S INSTALLATION

9.5.1. COMPLIANCE WITH RECOGNIZED STANDARDS

Customer's installation shall meet or exceed all requirements of the National Electrical Code and all state and local regulations applicable thereto, at the time of such installation.

9.5.2. SERVICE FROM COMPANY

In all cases where new installations or alterations and additions to existing installations are to be made, Company shall be consulted as to the location of all service connections and/or meters and metering equipment. The Company shall also be consulted regarding the size and character of load to be connected or added and the characteristics of service to be supplied.

The point of attachment of Company's facilities to the customer's building and the nature and characteristics of service will be given in writing for all new installations and for alterations or additions to existing installations. The Company will not be responsible for re-work when such information is given orally.

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9.5.3. NATURE AND USE OF INSTALLATIONS

Customer will select and operate his equipment in such manner that it will not adversely affect Company's electric service either to the customer or to others. When Company supplies three phase service, the customer will control his use of the electric service so that the load at the point of delivery will be maintained in reasonable electrical balance between the phases.

Customer will so select and operate his equipment as to maintain a power factor of not less than 90% at the point of metering. Company may, at its option, install meters or others instruments to measure the kilovolt-ampere demand or power factor or for other tests. If Company, at its option, installs kVA demand metering the kW demand as measured may be adjusted to correspond to the customer's maximum kVA demand.

9.5.4. GROUNDING

Customer shall be responsible for the installation and maintenance of an electrical ground which meets or exceeds all requirements of the National Electrical Code, and all state and local regulations applicable thereto at the time of such installation for grounding the neutral bus of the service entrance panel, main disconnecting switch or main circuit breaker.

9.6. COMPANY'S INSTALLATION

9.6.1. INSTALLATION AND MAINTENANCE

Except as otherwise provided in these Service Regulations, in Agreements for Electric Service or Rate Schedules, Company will install and maintain its lines and equipment on its side of point of delivery. Company shall not be required to install, inspect, or maintain any lines or equipment except meters on customer's side of the point of delivery. Only Company's employees or its designees are authorized to connect Company's service drop to customer's service terminals.

9.6.2. PROTECTION BY CUSTOMER

Customer shall protect Company's wiring and apparatus on customer's premises and shall permit no one but Company employees or persons authorized by law to inspect or handle same. In the event of any loss or damage to the Company's property arising out of carelessness, neglect, or misuse by customer or other unauthorized persons, the cost of making good such loss or repairing such damage shall be paid by customer.

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All wiring and apparatus supplied by Company, purchased by Company or contributed to Company by customer shall remain its property, and if in customer's possession, shall on termination of Agreement for Electric Service be returned to Company by customer in as good condition as when received by customer, ordinary wear and tear excepted. Company may at any time examine, change or repair its property on the premises of customer and may remove its property upon or at any time after termination of Agreement for Electric Service.

9.7. METERING

9.7.1. INSTALLATION

The Company will furnish, install, own, and maintain all meters and metering equipment except as noted below.

A. Customer will furnish and install at the agreed upon location the meter enclosure for any single or three phase service connection of 320 Amperes or less.

B. Company will furnish and customer will install at the agreed upon location the meter enclosure and current transformers (does not include the current transformer enclosure) for all service connections requiring instrument rated transformers.

All equipment supplied by customer must be to Company specifications.

No retail customer will furnish or install any meter or other measuring device for the purpose of measuring electric service for resale to any person, firm, corporation, association, or to any third party.

9.7.2. EVIDENCE OF CONSUMPTION

The registration of Company's meter shall be accepted and received at all times and places as prima facie evidence of the amount of service taken by customer.

9.8. BILLING

9.8.1. BILLING PERIODS

Customer bills for electric service supplied will be rendered at regular intervals. Non-receipt of bills by customer shall not release or diminish the obligation of customer with respect to payment thereof. Bills for service periods of less than 25 days or greater than 35 days shall be prorated except for initial or final service periods. Initial and final bills will be prorated for determining blocking only; the Customer Charge will not be prorated on any bill.

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9.8.2. UNAUTHORIZED USE OF ELECTRIC SERVICE

If electric service has been suspended, or the Agreement For Electric Service terminated, because of unauthorized use or disposition of such electric service by customer, Company shall be entitled to collect from customer at the appropriate rate for any electric service not properly recorded on the meter (the amount of which may be estimated by Company from the best available data), and also for all expenses incurred by Company on account of such unauthorized act or acts.

9.8.3. SELECTION OF RATE SCHEDULE

When a prospective customer makes application for electric service, the Company will upon request assist in the selection of the rate schedule most favorable to customer for the electric service requested. The selection will be based on the prospective customer's statement as to the class of electric service desired, the amount and manner of use, and any other pertinent information, which statement will be recorded and filed with the application. Company shall not be liable for any errors in connection herewith.

A customer being billed under one of two or more optional schedules applicable to his class of electric service may elect to be billed on any other applicable schedule by notifying Company in writing, and Company will bill customer under such elected schedule from and after the date of the next meter reading. However, a customer having made such change of schedule may not make another such change within the next twelve months.

9.9. ALTERATION OF ADEQUATE COMPANY FACILITIES AT CUSTOMER’S REQUEST

Alteration of existing adequate Company facilities at the customer’s request shall be performed only if the customer pays the Company in advance of construction for the entire Company estimated cost of such alteration less any salvage value.

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Title: Contingency Emergency Power Conservation and Curtailment Plan (EPCP)

PSC File Mark Only


10.0. CONTINGENCY EMERGENCY POWER CONSERVATION AND CURTAILMENT PLAN

10.1. DEFINITIONS

As used herein, "Company" shall mean Entergy Arkansas, LLC, "Plan" or "Curtailment Plan" shall mean the following rules and regulations, and "Commission" shall mean the Arkansas Public Service Commission.

10.2. APPLICABILITY

The provisions of this Policy Schedule No. 10., shall apply at any time, and for such periods of time, when in the judgment of the Company, it is necessary to reduce the use of electricity due to projected emergencies or dynamic emergencies as described below.

10.2.1. PROJECTED EMERGENCY

A projected emergency is any situation for which, in the near future, the projected system demand exceeds available generating capacity and purchased power. Capacity may not be available because of extended outages caused by the time needed to repair a failure in existing equipment, because of delays in construction of new generating facilities, because of unanticipated excessive peak load demands, or because of shortages or interruptions of the supply of fuels for electric generation. The action to be taken for projected emergencies is described in § 10.4.

10.2.2. DYNAMIC EMERGENCY

A dynamic emergency is any situation of such a severe nature that the automatic system protective and control equipment, coupled with manual operator intervention, cannot supply the load demand with available capacity within the time necessary to maintain the integrity of the bulk power facilities. These emergencies are generally caused by major system disturbances. The action to be taken for dynamic emergencies is described in § 10.5.

10.2.3. IMPLEMENTATION

This Plan will be implemented only after all feasible alternatives for obtaining the necessary power and energy from outside sources have been exhausted.

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PSC File Mark Only


10.3. SCOPE

The action plan has been formulated to reduce load and energy consumption throughout the Company's service area on an equitable basis and to continue providing for human needs and essential public services. The Region Vice President shall be the Company officer responsible for the formulation and implementation of this Plan and shall serve as the Company's designated representative to coordinate with other responsible parties in authorizing the implementation of applicable provisions of the Plan.

10.4. ACTION TO BE TAKEN FOR PROJECTED EMERGENCIES

10.4.1. CURTAILMENT DUE TO FUEL SHORTAGE

Serious shortages of fuel could conceivably require a reduction in load and total energy generated. Burn days as defined by the formula,

Burn Days = Usable inventory of fuel at plant site (bbls)x no. of days in month (days) Anticipated burn in month (bbls)

will be used as points at which to review the necessity for implementation of proposed action steps. Whenever it is determined that a fuel shortage is imminent, the steps will be performed in the order listed or possibly simultaneously depending on the nature and extent of the projected condition.

Step Burn Days Action 1 - An internal Company procedure will be implemented at any

time there is a national energy crisis to manually reduce energy use at all Company offices and other facilities to the maximum extent possible.

2 45 a. Request industrial and commercial customers to voluntarilycurtail power not essential to production, processing, orcommercial services.

b. Make public requests through radio, television, and othernews media to all customers to voluntarily reduce electricalenergy use to the maximum extent possible.

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PSC File Mark Only


Step Burn Days Action c. Request other electric systems served at wholesale by the

Company to begin immediate implementation of their own conservation and curtailment plans among their respective retail customers to the extent necessary to be equivalent to the steps taken under this Plan.

3 30 a. Reduce distribution system voltage levels as practicable up tofive (5) percent, when it is expected to be effective for loadreduction.

b. Request emergency oil allocation.

c. Request industrial and commercial customers to cut back orreschedule production, processing, or commercial services tosubstantially reduce power consumption to minimumrequirements necessary under the existing circumstances.Such requests shall be on a proportional or other equitablebasis taking into consideration the necessity of minimizingequipment or product damage.

4 25 Buy Emergency power.

5 20 Request emergency gas.

6 15 Open selected circuits for short periods of time. If further orcontinued reduction is necessary, circuits to be opened wouldbe alternated or rotated on a scheduled short-term basis. Thecircuits selected for this program do not serve criticalcustomers, such as hospitals, water systems, sewer systems,military reprisal facilities, life-sustaining equipment, and otherloads vital to public needs. Other circuits excluded, if possible,include those serving emergency shelters, Civil Defensecontrol centers, communication facilities, governmentalservices, and essential Company operations facilities. Duringthe winter season, preference will be given where possible toproviding electrical service to residential customers.

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PSC File Mark Only


10.4.2. CURTAILMENT DUE TO CAPACITY SHORTAGE

Serious shortages of generation capacity and/or loss of generation units or bulk transmission greater than the available supply from operating generating units and from purchased power through system interconnections.

The following curtailment steps will be implemented in the order listed and as necessary to reduce system loads within the capability of available generation and interconnected system purchases. Every reasonable effort will be made to assure that electrical service is not interrupted to critical customers and other loads vital to human and public needs.

Step Action 1 An internal Company procedure will be implemented during any time there is

an anticipated or imminent generation shortage on the Entergy System and/or system interconnections. This procedure will manually reduce electric power usage at all Company offices and other facilities to the maximum extent possible.

2 Request municipal electric systems and other systems served at wholesale to start and run all operable generation and to reduce as much electric power use as possible at their offices and other facilities.

3 Make public requests through radio, television, and other news media to all customers to voluntarily reduce electric power use to the maximum extent possible.

4 Request municipal systems and other systems served at wholesale to begin immediate implementation of their own conservation and curtailment plans among their respective retail customers to the extent necessary to be equivalent to the steps taken under this Plan.

5 Reduce distribution system voltage levels as practicable up to five (5) percent, when it is expected to be effective for load reduction.

6 Ask industrial and commercial customers to curtail power not essential to production, processing, or commercial services in accord with pre-established schedules.

7 Implement the emergency provision of Company rate schedules to switch off any controlled loads covered under Controlled Service Rates.

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PSC File Mark Only


Step Action 8 Ask industrial and commercial customers to cut back or reschedule production,

processing, or commercial services to substantially reduce power consumption to minimum requirements necessary under the existing circumstances. Such requests shall be on a proportional or other equitable basis taking into consideration the necessity of minimizing equipment or product damage.

9 Open selected circuits for short periods of time. If further or continued reduction is necessary, circuits to be opened would be alternated or rotated on a scheduled short-term basis. The circuits selected for this program do not serve critical customers, such as hospitals, life-sustaining equipment, water systems, sewer systems, military reprisal facilities, and other loads vital to public needs. Other circuits excluded, if possible, include those serving emergency shelter, Civil Defense control centers, communication facilities, governmental services, and essential Company operations facilities. During the winter season, preference will be given where possible to providing electrical service to residential customers.

10.5. Action To Be Taken For Dynamic Emergencies

In the event of sudden unanticipated forced outages of major generating units or failure of major transmission facilities, it may be necessary to curtail loads until there is adequate generation capacity available to maintain frequency at 60 hertz and supply all load variation requirements. Under these conditions the following steps will be taken by the Transmission Dispatch Center Dispatchers at Pine Bluff upon the request of the Entergy System Operator:

10.5.1. Implement emergency provisions of applicable contracts and Company rate schedules to switch off interruptible loads and controlled loads covered under Controlled Service Rates.

10.5.2. Reduce distribution system voltage levels as practicable up to five (5) percent, when such reductions are expected to be effective for load reduction.

10.5.3. The Company has selected certain distribution circuits which will be opened by Supervisory Control. Opening of these circuits will be initiated to prevent operation of the under frequency relays as described in § 10.5.4., below and to prevent damage to other generation and interconnected system facilities. The criteria for selection of these circuits are the same as stated in § 10.4.2., Step 9. The circuits and loads to be shed are based on increments of load which the System Operator might require to be shed in order to maintain integrity of the system. The Company's share is approximately 30 percent of the total load to be shed.

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PSC File Mark Only


10.5.4. The Company has also equipped certain distribution circuits with under frequency relays which will open selected circuits when the system frequency drops below a predetermined level. Criteria for selection of these circuits are the same as stated in § 10.4.2., Step 9.

In the event distribution circuits are interrupted by the methods detailed in 10.5.3., and 10.5.4., above and these interruptions are anticipated to last for a substantial period of time, the Company will proceed in an orderly fashion to implement the curtailment steps detailed in § 10.4.2., "Curtailment Due to Capacity Shortage," until sufficient load has been shed to allow restoration of service to the affected circuits.

10.6. Compliance by Customers

In the event any customer, as set forth in § 10.4., and 10.5., above, who has been requested to reduce or reschedule use of power and energy, fails to comply with a request of a Company representative to do so pursuant to this Plan, the Company shall have the right to totally discontinue service to said customer without further notice during the period this Plan is in effect. Such discontinuance shall not be deemed a violation of law or the Rules and Regulations of the Commission, and the Company shall not be liable for penalties or damages, direct or indirect, by reason thereof; provided, however, that upon taking such action, the Company shall forthwith notify the Commission of the identity and location of the customer and the circumstances leading to such discontinuance.

10.7. SUPERSEDES OTHER COMPANY POLICIES AND RATE SCHEDULES

The foregoing Contingency Emergency Power Conservation and Curtailment Plan shall apply during any and all times and periods when implementation thereof is necessary in the judgment of the Company. During such times and periods, the terms and provisions hereof shall supersede any and all terms and provisions of any other rule, regulation, rate schedule, or service agreement which may be in conflict herewith.

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PSC File Mark Only


10.8. TERM OF APPLICATION OF THIS CONTINGENCY EMERGENCY POWER CONSERVATION AND CURTAILMENT PLAN

The Company will take such reasonable and prudent actions as are available to it to eliminate or reduce the extent and term of the application of this Plan. Whenever the need for curtailment no longer exists, the Company will initiate restoration of service to all parts of the system as quickly as possible in an orderly fashion.

10.9. REPORT TO COMMISSION

As soon as practicable after implementation of all or any part of this Plan, the Company shall report to the Commission in writing the significant details thereof, the customer classifications affected, the duration or anticipated duration thereof, and the estimated units of power and energy conserved or curtailed and expected to be conserved or curtailed. The Company shall notify the Federal Energy Regulatory Commission pursuant to FPC Order No. 331-1.

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Kind of Service: Electric Class of Service: Not Applicable Docket No.: 18-073-TF Order No.:


Title: Transformer Company No., Location No., & Birthmark PSC File Mark Only


11.0 TRANSFORMER COMPANY NO., LOCATION NO., & BIRTHMARK

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1st Revised Sheet No. P12.1 Schedule Sheet 1 of 1

Replacing: Original Sheet No. P12.1


Kind of Service: Electric Class of Service: Not Applicable Docket No.: 16-060-U Order No.:

Part IV. Policy Schedule No. 12 Effective:

Title: Meter Testing Program (MTP) PSC File Mark Only


12.0. METER TESTING PROGRAM

Rule 7.03(g)(2) of the Arkansas Public Service Commission (“Commission”) Rules of Practice and Procedure requires that each electric utility file its test method for in-service meters. Rule 7.08.C of the Commission’s Special Rules - Electric (SR-E) provides that a utility shall state in its tariffs on file with the Commission which sampling method is used by the utility for testing new meters and which sampling method is used for testing in-service meters.

12.1. TEST PROGRAM FOR NEW METERS

To ensure that new meters conform to the accuracy requirements of Rule 7.05.B of the Commission’s Special Rules - Electric, before installation by the utility, all new meters will be inspected and tested in a meter shop or laboratory under the sampling method indicated below:

(1) 100% of all new combination kW/kWh and kVA/kWh meters will be tested. (2) New kWh only meters will be tested on a sampling basis conforming to ANSI

C12.1-1982, § 8.1.5.

12.2. IN-SERVICE METER TESTING PROGRAM

In accordance with 7.08.B of the Commission’s Special Rules - Electric, all in-service meters will be tested by the utility under the program indicated below. All meters will be tested under the same program:

(1) Periodic interval ANSI C12.1-1982, § 8.1.8.4 and § 8.2.3.1, for combination kW/kWh, kVA/kWh and Three Phase kWh only meters.

(2) Variable interval ANSI C12.1-1982, § 8.1.8.5. (3) Statistical sampling ANSI C12.1-1982, § 8.1.8.6, for Single Phase kWh only

meters.

12.3. METER TESTING PROGRAMS AND FILING REQUIREMENTS § 7.08.B Meter Test Programs for In-Service Meters

Entergy Arkansas, LLC is exempted from complying with in-service meter testing of SRE § 7.08.B. during the Company’s Advanced Metering Infrastructure (“AMI”) deployment.In-service meter testing will resume following the completion of the deployment of AMI.


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Original Sheet No. P13.0.1 Schedule Sheet 1 of 1





Title: Contract Forms PSC File Mark Only


13.0. CONTRACT FORMS

13.1. Use of Forms

The standard contract forms contained in this schedule are to be used, as applicable, for service that, under the appropriate rate schedule, is to be provided pursuant to a written contract. The Company reserves the right to use other standard contract forms for service not governed by any of the standard contract forms included herein, to the extent any other standard contract form is not inconsistent with an existing rate schedule, the rules and regulations of the Commission, or otherwise prohibited by law.

Omission of a standard contract form from this schedule for a service provided pursuant to a rate schedule that requires a written contract for such service does not constitute a waiver of the Customer's obligation to sign a written contract to obtain service.

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Kind of Service: Electric Class of Service: As Applicable Docket No.: 18-073-TF Order No.: 2




13.2. TABLE OF CONTENTS

CONTRACT TITLE SECTION

Agreement for Electric Service 13.3 Agreement For All Night Outdoor Lighting Service L4, § 12.3 13.4.1 Agreement For All Night Outdoor Lighting Service L4, § 12.4 13.4.2 Agreement For Collective Billing Service 13.5 Agreement For Underground Service Connections 13.6 Extension Of Service Agreements 13.7

Extension of Service Agreement with Customer 13.7.1 Extension of Service Agreement for Planned Land Use Developments 13.7.2

Agreement To Change Existing Facilities 13.8 Agreements for Residential Underground Electric Distribution System in Subdivision

Incorporated Communities Unincorporated Communities

13.9 13.9.1 13.9.3

Additional Facilities Agreements Facilities Agreement

Attachment A To Facilities Agreement Amendment To Facilities Agreement For Removal/Relocation Of Facilities

Attachment A To Amendment To Facilities Agreement For Removal/ Relocation Of Facilities

Agreement For Operation And Maintenance Of Customer Facilities Attachment A – Customer Facilities Subject To Operation And Maintenance Attachment B – Other Provisions To Agreement For Operation And Maintenance Of Customer Facilities

13.10 13.10.1 13.10.1.1 13.10.2

13.10.2.1 13.10.3

13.10.3.1

13.10.3.2 Agreement Implementing Economic Development Rider (EDR) 13.11 Amendment to Agreement for Electric Service for Interruptible Service 13.12 RESERVED FOR FUTURE USE 13.16 Agreement for DataLink Service 13.17


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ARKANSAS PUBLIC SERVICE COMMISSIONAPSC FILED Time: 8/21/2020 3:55:48 PM: Recvd 8/21/2020 3:54:36 PM: Docket 19-042-TF-Doc. 149

2nd Revised Sheet No. P13.2.2 Schedule Sheet 2 of 2

Replacing: 1st Revised Sheet No. P13.2.2






Additional Facilities Agreements – Governmental Facilities Agreements - Governmental

Attachment A To Facilities Agreement - Governmental Amendment To Facilities Agreement For Removal/Relocation Of Facilities - Governmental

Attachment A To Amendment To Facilities Agreement For Removal/ Relocation Of Facilities - Governmental

Agreement For Operation And Maintenance Of Customer Facilities - Governmental

Attachment A – Customer Facilities Subject To Operation And Maintenance - Governmental Attachment B – Other Provisions To Agreement For Operation And Maintenance Of Customer Facilities - Governmental

13.20 13.20.1 13.20.1.1 13.20.2

13.20.2.1

13.20.3

13.20.3.1

13.20.3.2

Agreement for Solar Energy Purchase Option Agreement for Solar Energy Purchase Option A Agreement for Solar Energy Purchase Option B Attachment A to Agreement for Solar Energy Purchase Option B

13.21 13.21.1 13.21.2 13.21.2.1


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13.3. Agreement for Electric Service

This Agreement, made and entered into on _______, by and between __________________ ("Customer") and Entergy Arkansas, LLC (“EAL” or the “Company”), a corporation;

1. CHARACTERISTICS OF SERVICE

Company shall make available to Customer on or before ________ at the point of deliveryspecified herein, electric service up to a maximum of ______ kVA, at approximately___________ volts, ___ wire, ___________, ___ phase and a nominal frequency of 60cycles per second to be supplied for the operation of Customer's_________________________ ________________________________ locatedin _____________________ County at or near _________________, Arkansas. Companywill use due diligence to begin service hereunder on the date specified above, but its failureto do so shall not constitute a breach of this Agreement for Electric Service.

2. DEFINITIONS

Firm Service - Full requirements of Customer supplied under one of Company’s standard electric service schedules;

Supplemental Service - Partial requirements of Customer supplied under one of Company’s standard electric service schedules that is Supplemental to Customer requirements served by Customer owned generating equipment;

Contract Power - The highest kW demand established in the twelve months ending with the current month pursuant to the Minimum provision of the rate schedule under which Firm or Supplemental Service is supplied, referred to as contract, or ratcheted power or demand;

Standby Service - Composed of Reserved Service, Maintenance Service Backup Service and Non-Reserved Service, restricted to a total number of kW that shall not exceed the nameplate rating of the Customer’s generating equipment which may be operated in parallel with the Company’s system;

Reserved Service - Electric energy and capacity the Company stands ready to supply during a scheduled or unscheduled outage of the Customer’s on-site generation equipment;

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Non-Reserved Service - Electric energy and capacity the Company may supply during a scheduled outage of the Customer’s on-site generation equipment during the service months of October through May when Customer has requested this service no less than twenty (20) days in advance.

Maintenance Service - Electric energy and capacity supplied by the Company during a scheduled outage of the Customer’s generating equipment when Company has been given no less than seven (7) days advance notice of such requested Maintenance period;

Backup Service - Electric energy and capacity supplied by the Company during an unscheduled outage of the Customer’s generating equipment and electric energy and capacity supplied by the Company during a scheduled outage that exceeds scheduled Maintenance Service;

Reserved Service Contracted kW - An amount of kW not greater than the nameplate rating of Customer’s on-site generation, for this Contract ___________ kW.

3. RATES FOR SERVICE

Company shall supply and Customer shall take and/or pay for all Firm Service and/orStandby Service required by Customer for the above operation in accordance with RateSchedule(s) _________________________copy(ies) of which are attached hereto and madea part hereof, and Company's Policy Schedule No. 9, Service Regulations as approved bythe regulatory authority having jurisdiction, or such other effective superseding RateSchedule(s) and Service Regulations as may be authorized by duly constituted regulatoryauthority exercising lawful jurisdiction, or as may become effective in the manner provided bylaw.

4. MINIMUM BILLING

No monthly bill for electric service will be less than or, if seasonal,______________during the Customer’s season and Customer agrees to pay, as a minimumcharge, the greater of such monthly bill or the amount calculated under the minimumprovision of the then effective rate schedule under which the Customer is served until thisAgreement is terminated pursuant to the provisions of § 10 below.

5. DEPOSITS

EAL collects deposits consistent with Arkansas Public Service Commission’s General ServiceRule, Section 4, Deposits as may be modified thereafter by approval of the Commission.Such deposits are based upon the projected usage characteristics described herein.Accordingly a deposit in the amount of ___________ is due with the first bill.

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6. POINT OF DELIVERY

The point of delivery of such electric service shall be _______________________________________________________________________________________________________.

7. SUSPENSION OF SERVICE

Any suspension of service for non-payment of bills shall be without prejudice to any otherright of action to which Company is entitled. In the event of cancellation of this Agreement byCompany for any breach or default on the part of Customer, there shall immediately becomedue and payable, in addition to the amount then due for service hereunder, as liquidateddamages and not by way of penalty, a further sum equal to the total minimum monthly orseasonal bills which Customer would have paid during the unexpired term had the Companynot canceled the Agreement.

8. SERVICE RELIABILITY

Company will use reasonable diligence to supply steady and continuous electric service butdoes not guarantee the electric service against irregularities or interruptions. Company shallnot be liable to Customer for any damages occasioned by irregularities or interruptions.

9. ASSIGNMENT OF CONTRACT

This Agreement shall be binding upon and inure to the benefit of the respective successorsand assigns of the Parties hereto but no assignment shall be binding upon Company untilaccepted in writing by the latter.

10. TERM OF AGREEMENT

The term of this Agreement shall be from the date service is first made available hereunder to _______________, and shall be automatically extended for successive periods of one year each until terminated by written notice given by one party to the other not more than six months nor less than three months prior to the expiration date of the initial term or any anniversary thereof. Customer’s obligation to pay the monthly minimum contained in § 4 does not terminate with the initial term of this Agreement, but continues in effect as long as service is provided hereunder.

If Customer requests cancellation of this Agreement after the date entered in the preamble above and before the effective date of the Agreement, Customer will be responsible and shall pay for all costs incurred by the Company regarding provision of the service defined in § 1 from that date to the date of Company’s receipt of the Customer’s written request for cancellation.

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11. CUSTOMER’S USE OF SERVICE AND IMPACTS ON COMPANY’S SYSTEMS

To prevent or correct interference with the service to other Entergy customers, theCustomer’s electrical equipment shall not cause the voltage on the Company’s system todrop below nor rise above the range required of utilities by the Arkansas Public ServicesCommission’s Special Rules – Electric, Rule 6.01, Section A, and shall not cause excessivevoltage flicker, as defined by IEEE Std. 141-1993. The voltage flicker is not to exceed 2% ontransmission, 3% at the substation, or 5% on distribution. The Customer’s equipment shallnot introduce excessive total harmonic distortion as defined by IEEE Std. 519. Additionally,individual harmonic distortion at the point of common coupling with the customer shall be lessthan 1%. If harmful effects are experienced by other customers due to the operation ofCustomer’s equipment, it shall be the Customer’s responsibility, at Customer’s expense, totake corrective actions to comply with the above standards. Failure to comply may be causefor suspension of service, pursuant to the Arkansas Public Services Commission’s GeneralService Rules, Rule 6.01, Section J. Customer assumes all responsibility on customer's sideof the point of delivery for the electric service supplied or taken, as well as for the electricalinstallation, appliances and apparatus used in connection therewith.

12. OTHER PROVISIONS

Any other provisions appended to this Agreement are made a part hereof.

13. ENTIRETY OF AGREEMENT

This constitutes the entire and only agreement between the Parties hereto with reference tothe subject matter hereof and supersedes all previous understandings whether written or oral.

14. APPROVAL

This Agreement is contingent upon approval by Company's President; Vice President, orDepartment Director.

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CUSTOMER

By: _________________________________ CUSTOMER OFFICER

Signature Date:________________________

ATTEST:_____________________________

Customer's Secretary


By: _________________________________ COMPANY AGENT

Approved: ____________________________

Title: ________________________________

Signature Date________________________

DIS WR #:_______________ Project #:_______________ Business Unit: A0000

Department:_____________ Resource:_______________ Activity:________________

Physical Location: DAR Location:_______________ Account Number:________

Residential __________ Commercial __________ Industrial ___________

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Original Sheet No. P13.4.1.1 Schedule Sheet 1 of 5







13.4. Agreements for All Night Outdoor Lighting Service

13.4.1 Agreement for All Night Outdoor Lighting Service Rate Schedule L4, § 12.3, Company Owned and Maintained Lighting Facilities

This Agreement, made this __ day of _______, 20__, between ________ ("Customer") located at _______, Arkansas, and Entergy Arkansas, LLC (“EAL” or the “Company”);

1. OBLIGATIONS

Company shall supply, install and maintain on property located at __________ thehereinafter specified number of automatically controlled overhead lighting fixtures installed onwood poles, and Company shall deliver approximately 120 volt electric current thereto.Customer shall pay for such service in accordance with the terms and conditions hereinafterset forth and in accordance with the terms and conditions of Rate Schedule No. 12 andapplicable Riders as Rate Schedule No. 12 and/or applicable Riders may be lawfullyamended from time to time.

2. CHARGE

Existing and newly installed Nightwatchers and Floodlights and their associated additionalfacilities, if any, and poles and pole equipment, if any, shall be billed at the monthly chargesshown on Attachment A to this agreement.

3. MAINTENANCE

All necessary normal service, maintenance and bulb replacements will be furnished atCompany's expense within three (3) business days after notice is given by customer. Thecost of unusual maintenance resulting from purposeful physical damage or vandalism shallbe the responsibility of and billed to customer. If payment for such unusual maintenance isnot made within the time period allowed in the Payment provision of Rate Schedule No. 12this Agreement shall be terminated and Company's facilities will be removed in accordancewith Company's Policy Schedule No. 7 All Night Outdoor Lighting Service Maintenance Policyas filed with the APSC and as provided to Customer with Customer's copy of this Agreement.

4. OWNERSHIP OF FACILITIES

The facilities installed by the Company in the performance of this Agreement shall remain theproperty of Company and Customer hereby grants to Company the right to enter and to useCustomer's premises as it is necessary for the installation, maintenance and removal of suchfacilities.

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5. LOCAL REGULATIONS

Where Nightwatchers and Floodlights for service hereunder are installed on Companyfacilities located along public streets or alleys, this contract is subject to any requirements oflocal municipal authorities.

6. TERM

The term of this Agreement shall be from ________ 20__, to _______, 20__, or from the dateservice is first made available hereunder and continuing for a period of twelve (12) months,and shall be automatically extended for successive periods of one year each until terminatedby written notice given by one party to the other not more than six months nor less than threemonths prior to the expiration of the original term or any anniversary thereof.

7. ENTIRETY OF AGREEMENT

This document, including any other provisions which may be shown below constitutes theentire and only agreement between the Parties hereto with reference to the subject matterhereof and supersedes all previous understandings whether written or oral.

CUSTOMER ENTERGY ARKANSAS, LLC

by______________________________ by______________________________

Representative

DIS WR #:_______________ Project #:_______________ Business Unit: A0000

Department:_____________ Resource:_______________ Activity:________________

Physical Location: DAR Location:_______________ Account Number:________

Residential __________ Commercial __________ Industrial __________

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ATTACHMENT A

Additional Additional

Facilities Facilities Current Current Estimated Estimated Monthly Monthly

Rate Cost Cost Facilities Rate / Rider Number Watts Key Lamp Type / Fixture Type Rate Riders Existing New Charge (1) Charge

Nightwatchers

150 N4f HPS / Acorn Unshielded $11.83 $ . $ . $ . $ . $ .

400 N4g HPS / Square Unshielded (2) $16.11 $ . $ . $ . $ . $ .

250 N4b HPS / Cobra Unshielded $10.53 $ . $ . $ . $ . $ .

250 N4u HPS / Traditionaire $14.52 $ . $ . $ . $ . $ .

400 N4c HPS / Cobra Unshielded $11.89 $ . $ . $ . $ . $ .

150 N4e HPS / Colonial Unshielded $10.22 $ . $ . $ . $ . $ .

100 N4a HPS / Open Unshielded (2) $ 8.40 $ . $ . $ . $ . $ .

150 L4e HPS / Open Unshielded $ 6.32 $ . $ . $ . $ . $ .

250 L4f HPS / Open Unshielded $ 7.45 $ . $ . $ . $ . $ .

400 L4g HPS / Open Unshielded $ 8.71 $ . $ . $ . $ . $ .

400 L4t HPS / Shoebox Unshielded $13.22 $ . $ . $ . $ . $ .

1000 N4h HPS / Shoebox Unshielded $22.37 $ . $ . $ . $ . $ .

150 N4ps HPS / Cobra Shielded $ 8.81 $ . $ . $ . $ . $ .

250 N4qs HPS / Cobra Shielded $11.64 $ . $ . $ . $ . $ .

400 N4rs HPS / Cobra Shielded $12.91 $ . $ . $ . $ . $ .

150 N4ss HPS / Colonial Post Top Shielded $ 8.91 $ . $ . $ . $ . $ .

300 L4h Incandescent Unshielded (2) $ 5.74 $ . $ . $ . $ . $ .

100 L4a MV / Open Unshielded (2) $ 4.94 $ . $ . $ . $ . $ .

175 L4b MV / Open Unshielded (2) $ 5.08 $ . $ . $ . $ . $ .

250 L4c MV / Open Unshielded (2) $ 5.41 $ . $ . $ . $ . $ .

400 L4d MV / Open Unshielded (2) $ 6.63 $ . $ . $ . $ . $ .

400 L4s MV / Shoebox Unshielded (2) $10.03 $ . $ . $ . $ . $ .

175 N4j MH / Acorn Unshielded (2) $15.39 $ . $ . $ . $ . $ .

150 N4p MH / Acorn Unshielded $13.35 $ . $ . $ . $ . $ .

400 N4k MH / Square Unshielded (2) $19.11 $ . $ . $ . $ . $ .

1000 N4m MH / Square Unshielded (2) $28.11 $ . $ . $ . $ . $ .

400 N4d MH / Cobra Unshielded (2) $15.59 $ . $ . $ . $ . $ .

320 N4r MH / Cobra Unshielded $15.67 $ . $ . $ . $ . $ .

400 L4n MH / Open Unshielded (2) $ 9.08 $ . $ . $ . $ . $ .

320 N4q MH / Open Unshielded $ 9.80 $ . $ . $ . $ . $ .

320 N4v MH / Shoebox $21.23 $ . $ . $ . $ . $ .

400 L4u MH / Shoebox Unshielded (2) $14.35 $ . $ . $ . $ . $ .

1000 N4l MH / Shoebox Unshielded $25.84 $ . $ . $ . $ . $ .

Page Totals $ . $ . $ . $ .

(1) Total Additional Facilities Estimated Cost @ Monthly Rate from section 26.3 of Rate Schedule No. 26. (2) Not Available to new customers. (3) Includes supply line. (4) Excludes supply line; includes internal 12/2 Romex or equivalent to connect fixture to underground secondary.

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ATTACHMENT A (continued)

Additional Additional Facilities Facilities Current Current Estimated Estimated Monthly Monthly

Rate Cost Cost Facilities Rate / Rider

Number Watts Key Lamp Type / Fixture Type

HPS Equivalent Rate Riders Existing New Charge (1) Charge

Lights Emitting Diode (LED)

N4LED1 2,150 Lumen Traditional

75W HPS $ 9.90 $ . $ . $ . $ . $ .


100W HPS $10.34 $ . $ . $ . $ . $ .


150W HPS $10.78 $ . $ . $ . $ . $ .

N4LED4 5,200 Lumen Granville

100W HPS $15.15 $ . $ . $ . $ . $ .

N4LED5 7,700 Lumen Granville

150W HPS $15.71 $ . $ . $ . $ . $ .

N4LED6 5,200 Lumen Acorn

100W HPS $14.07 $ . $ . $ . $ . $ .

N4LED7 8,400 Lumen Acorn

150W HPS $14.77 $ . $ . $ . $ . $ .

N4LED8 12,200 Lumen Shoebox

250W HPS $11.94 $ . $ . $ . $ . $ .


400W HPS $14.39 $ . $ . $ . $ . $ .


1,000W HPS $17.09 $ . $ . $ . $ . $ .

N4LED11 4,800 Lumen NEMA

100W HPS $ 7.69 $ . $ . $ . $ . $ .

N4LED12 6,900 Lumen NEMA

150W HPS $ 8.16 $ . $ . $ . $ . $ .

Floodlights

100 N4n HPS / Flood (2) $ 9.49 $ . $ . $ . $ . $ .

250 L4l HPS / Flood $10.71 $ . $ . $ . $ . $ .

400 L4m HPS / Flood $11.51 $ . $ . $ . $ . $ .

1,000 L4p HPS / Flood $15.09 $ . $ . $ . $ . $ .

400 L4j MV / Flood (2) $ 8.35 $ . $ . $ . $ . $ .

1,000 L4k MV / Flood (2) $13.12 $ . $ . $ . $ . $ .

250 N4o MH / Flood (2) $14.57 $ . $ . $ . $ . $ .

400 L4q MH / Flood (2) $12.69 $ . $ . $ . $ . $ .

320 N4s MH / Flood $12.72 $ . $ . $ . $ . $ .

1000 L4r MH / Flood $17.22 $ . $ . $ . $ . $ . F4LED1 5,500 Lumen

Flood 100W HPS $10.55 $ . $ . $ . $ . $ .

F4LED2 7,600 Lumen Flood

150W HPS $11.05 $ . $ . $ . $ . $ .


250W HPS $12.27 $ . $ . $ . $ . $ .


400W HPS $14.49 $ . $ . $ . $ . $ .


1,000W HPS $17.58 $ . $ . $ . $ . $ .

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Poles / Pole Equipment

P4a 30 foot Wood Pole (3) $ 3.26 $ . $ . $ . $ .

P4b 35 foot Wood Pole (3) $ 3.99 $ . $ . $ . $ . P4c 30 foot Steel-5" Square Pole

(4) (5) $ 8.46 $ . $ . $ . $ .

P4d 28 foot Concrete Octagon Pole (4) (5)

$ 5.41 $ . $ . $ . $ .

P4e 18 foot Fiberglass Round Pole (4) (5)

$ 2.66 $ . $ . $ . $ .

P4f 39 foot Steel Round Tapered Pole (4) (5)

$11.97 $ . $ . $ . $ .

P4g Plugged 4-way Adapter (5) $ 1.93 $ . $ . $ . $ .

Cost of Other Facilities (additional facilities not listed above)

$ . $ . $ . $ . $ . $ . $ .

Total Monthly Charges. Contract will contain Riders current on signing date. $ . $ . $ . $ .

Company’s Total Estimated Cost of Existing and New Facilities: $ .

(1) Total Additional Facilities Estimated Cost @ Monthly Rate from section 26.3 of Rate Schedule No. 26. (2) Not Available to new customers. (3) Includes supply line. (4) Excludes supply line; includes internal 12/2 Romex or equivalent to connect fixture to underground secondary. (5) Available only as additional facilities to new applications

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13.4.2 Agreement for All Night Outdoor Lighting Service Rate Schedule L4, § 12.4 Energy Rate for Subdivision Owned Lighting Facilities

This Agreement, made this XX day of XXXXXXX, 20XX, between XXXXXXXX Property Owners Association ("Customer") located at XXXXXXX, Arkansas, and Entergy Arkansas, LLC (“EAL” or the “Company”), (collectively the “Parties”), provides the following;

The Parties agree as follows:

1. Customer Obligations

Customer shall provide, install, operate and maintain all facilities beyond theCompany’s point(s) of delivery and Company shall deliver thereto single-phase, 60cycle, nominal 120 volt electric service. Customer’s lighting facilities shall beequipped with photocells that automatically control the lamps to permit only dusk todawn operation.

Customer shall provide the Company with a written inventory, in the form ofAttachment A hereto, of all unmetered lighting at each point of delivery for whichCustomer requests service under § 12.4 of Rate Schedule L4, including the type,number and wattage rating for each lighting fixture to be installed. Customer shallupdate Attachment A for changes and inform the Company as such changes occurby sending the revised Attachment A to the Company noting changes in lamp type,rating, and/or quantity of lighting equipment.

Customer shall provide fusing that disconnects the Customer’s facilities from those ofthe Company. Customer’s facilities shall be disconnected from those of theCompany prior to and during all maintenance except lamp replacements.

Customer shall identify Customer-owned facilities as not being the facilities of theCompany through a Company supplied insignia that shall be attached to the facilitiesof the Customer at points designated by the Company.

2. Company Obligations

Company shall connect Customer’s facilities to Company’s existing undergroundsecondary voltage facilities and shall provide only energy therefrom for Customer’soutdoor lighting facilities as described herein on property located as noted below.Where additional facilities, including transformation must be installed toaccommodate the additional load the Customer must pay the installed cost of suchadditional facilities.

XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX.

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3. Charges

Customer shall pay for such service under the terms and conditions set forth in thisAgreement and in accordance with the provisions of Rate Schedule No. 12 andapplicable Riders and as such Rate Schedule and/or applicable Riders may belawfully amended from time to time.

4. Inspection / Maintenance

The Company has no duty to inspect, repair, replace lamps or otherwise maintain thelighting facilities of Customer to which this energy only service is provided.

5. Ownership Of Facilities

Company’s existing or additional underground secondary voltage facilities installedby the Company in the performance of this Agreement shall remain the property ofCompany and Customer hereby grants to Company the right to enter and to useCustomer's premises as it is necessary for the installation, maintenance and removalof such facilities.

6. Indemnity

In the event of injury or death to any person as a result of contact with said Customerowned facilities, the Customer shall defend, indemnify and hold the Companyharmless from any and all claims, actions, causes of action and demands arisingtherefrom. Said obligation to defend, indemnify and hold harmless includes, but isnot limited to payment of judgment, settlements or claims and litigation andpreparation expense in connection therewith for discovery, expert witness fees,reasonable attorney's fees, and other such expenses.

7. Term

The term of this Agreement shall be from XXXXXXXX, 20XX, to XXXXXXX, 20XX, orfrom the date service is first made available hereunder and continuing for a period oftwenty-four (24) months, and shall be automatically extended for successive periodsof one year each until terminated by written notice given by one party to the other notmore than six months nor less than three months prior to the expiration of the originalterm or any anniversary thereof.

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8. Entirety Of Agreement

This document constitutes the entire and only agreement between the Parties heretowith reference to the subject matter hereof and supersedes all previousunderstandings whether written or oral.

CUSTOMER

By: __________________________________

(Property Owners Association Representative)

Title: _________________________________

Signature Date:_________________________


By: _____________________________________

(Company Representative)

Title: ____________________________________

Signature Date:____________________________

DIS WR #:________________ Project #:________________ Business Unit: A0000

Department:______________ Resource:________________ Activity:____________________

Physical Location: DAR Location:________________ Account Number:____________

Commercial_______________

(If private subdivision Lighting)

Public Street & Highway Lighting______ (If public lighting for municipality or other divisions or agencies of state or federal governments.)

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Attachment A To Agreement for All Night Outdoor Lighting Service Rate Schedule L4, § Energy Rate for Subdivision Owned Lighting Facilities

Equipment Inventory

Send to: ___________________________

Engineering Representative

___________________________

___________________________

Lamp Type Wattage/Lamp Quantity

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13.5. Agreement for Collective Billing Service

This Agreement is made _______________, 20____ between_________________________ __________________________________________________________________________ (“Customer”) and Entergy Arkansas, LLC (“EAL” or the “Company”), collectively Parties.

WHEREAS:

Customer currently has multiple service locations in Company’s service area as indicated by the accounts listed on Exhibit A attached hereto (the “Accounts”).

The Company currently issues Customer a separate bill for each of the Accounts.

Customer has requested Company to summarize the billings for such Accounts in one statement.

Company is willing to offer such a Collective Billing Service wherein the billings are summarized on one or more Collective Bills each month under the terms and conditions set forth below.

THEREFORE, the Parties hereto agree as follows:

1. COLLECTIVE BILL

Company will monthly render a Collective Bill, summarizing the bills for the customer’sindividual accounts for which the customer has requested such service.

2. PAYMENT

The amount shown as owed on each Collective Bill will be due upon receipt. Paymentshall be made in accordance with Rate Schedule No. 29, Charges related to CustomerActivity (CAC), § 29.19.2. Payment will be considered delinquent if not received by theCompany, either (a) via physical delivery by mail or courier or (b) via electronic fundstransfer, within the period specified in Rate Schedule No. 29, § 29.19.2 . If the paymentbecomes delinquent, Company may exercise the rights and privileges afforded it by theArkansas Public Service Commission (“APSC” or the “Commission”) General ServiceRules, or successor thereto, with regard to delinquent accounts, and all Accounts on thatCollective Bill will be subject to service interruption. Collective Bill accounts that becomedelinquent may be deemed ineligible for this Collective Billing Service Rider at theCompany’s sole option and be removed from Collective Billing. When applicableholidays occur from the date of mailing through the date by which the bill must be paid to

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avoid delinquency, the due date will be extended by one day per applicable holiday. The following is a list of the applicable holidays:

1. New Year’s Day 4. Memorial Day 7. Thanksgiving Day2. M. L. King, Jr. Day 5. Fourth of July 8. Christmas Eve Day3. President’s Day 6. Labor Day 9. Christmas Day

If Customer in good faith disagrees with any individual account on a Collective Bill rendered by Company, it shall so notify Company prior to the day the Collective Account becomes delinquent. All disputed bills shall be handled in accordance with the APSC Rules.

3. CHARGE FOR SERVICE

There will be no additional charge for the service initially. However, Company reservesthe right to implement a charge for the service upon appropriate regulatory approval andthirty (30) days written notice to Customer.

4. RIGHT TO CANCEL

Either party hereto may cancel this Agreement upon thirty (30) days notice to the other.

5. NOTICE

Any notice, consent, or other communication, except the mailing and payment of theCollective Bill as described in § 2 above, shall be properly given when deposited in theU.S. mail, postage prepaid, registered or certified, and addressed to the appropriateaddress as shown below, or to such other address as a party may stipulate in writing.

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6. CONFLICTS

This Agreement deals only with the rendering of bills and payment dates under theCompany’s Collective Billing Service procedure. This Agreement does not alter orsupersede any contract, rate schedule or other agreement except to the extent that suchcontract, rate schedule or other agreement may be in conflict with this Agreement withregard to the rendering of bills under the Collective Billing Service procedure.

7. APPROVALS

Customer

By: __________________________________

Date:________________________________


By: __________________________________

Title: ________________________________

Date:________________________________

Address:_____________________________ ____________________________________

Attn: _______________________________

Address: P. O. Box 551 Little Rock, AR 72203-0551

Attn: ________________________________

DIS WR #: Project #: Business Unit: A0000

Department: Resource: Activity

Physical Location: DAR Location: Account Number:

Residential ________ Commercial ________ Industrial _________

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13.6. Agreement for Underground Service Connection

Date of Letter

Customer Name Address City, State Zip Code

RE: Underground Service to (Property Location)

Dear Customer Name:

On (Date of Request), you requested that Entergy provide underground electrical service at the referenced location. With respect to the options you have chosen, the approximate charge you will incur by the Company is a base cost of ($ Base Cost) and ($ Cost per foot) per foot.

Example of Formula: Base Cost: $ Base Cost Number of feet: 100 feet Costs per foot: $ Cost per foot Total (Base Cost + 100 X cost per foot): $ Total Cost

The above formula is simply an example of how the charges will be calculated. The Company will measure the service length and include the installation charge on your next monthly bill. This charge will appear on the bill as a line item described as “Contribution in Aid of Construction.” The Company reserves the right to require payment of the full amount in advance of construction if it deems such requirement appropriate.

You will be required to build and install a meter loop according to the attached specifications prior to service installation. The meter base used in this installation must meet Company specifications. The Company will complete its installation only after your installation has passed any electrical inspection that may be required by local building codes.

The Company’s responsibility does not include the replacement or repair of customer’s real estate amenities associated with the installation of this customer requested service. These amenities include, but are not limited to, grass, sod, topsoil, shrubbery, trees, landscape or vegetation item.

Sincerely,

Company Representative Centralized Administration Attachment: Meter Loop Specifications

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13.7. EXTENSION OF SERVICE AGREEMENTS

13.7.1 Extension of Service Agreement with Customers

This Agreement was made and entered into on __________________, by and between ______________________________________________ (“Customer” or “Applicant”) and Entergy Arkansas, LLC (“EAL” or the “Company”), a corporation.

1. GENERAL

When service to an Applicant requires an extension of the Company’s facilities and there willbe a cost to the Applicant for such extension, Arkansas Public Service Commission GeneralService Rule 3.03.B provides that the Company may require the Applicant to sign anExtension of Service Agreement (“Agreement”). The Agreement and any required pre-construction payment by the Applicant must be returned to the Company before constructionof the extension can begin.

2. APPLICANT DATA

Address of Applicant:

Initial application date:

Service point location and description:

Description of work:

Characteristics of service: _______kVA, @ approximately _______volts,____ wire, ________ (grounding), ____phase and a nominal frequency of 60 cycles

3. SKETCH OF CONSTRUCTION ROUTE

A sketch of the construction route is provided as Attachment A.

4. EXPLANATION OF COSTS

An explanation of all costs in reasonable detail is provided as Attachment B.

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5. PRE-CONSTRUCTION APPLICANT OBLIGATIONS

The Applicant shall obtain all necessary rights of way from all property owners over whoseproperty the line shall be located, and complete the applicable form(s) supplied by theCompany, that grants to the Company (or its successors and assigns) the rights andprivileges to construct, maintain and operate said line. Such completed forms shall beappropriately signed and delivered to the Company prior to construction.

It is expressly understood that said rights of way and all electrical facilities erected for servingthe Customer under this Agreement shall always be and remain the property of theCompany. The Company has the right to serve any other customers from said line or anyextension thereof at any time.

The Customer agrees to complete the additional items listed below before the Companybegins construction. These items may include but are not limited to the acquisition of permitsand right-of-way clearing. If the Customer has no such obligations the space below shallshow “None”.

6. ESTIMATED CONSTRUCTION START AND COMPLETION DATES

Construction will start when this Agreement and any required pre-construction payment arereturned to the Company and the items in § 5 above, if any, have been completed. Weatherand/or ground conditions permitting construction will begin within _____ Business Days of thereceipt of this Agreement or the completion of § 5 items, whichever is later. It is estimatedthat under normal conditions the construction will require approximately ______ BusinessDays from the start of construction.

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7. TERMS OF PAYMENT (Pursuant to Rate Schedule No. 60)

Under the terms of EAL’s Rate Schedule No. 60, Extension of Facilities, the Applicant maychoose one of the following options:

1. make monthly Guaranteed Payments based on the amount of the EstimatedInvestment but make no non-refundable contribution in aid of construction(“Contribution”);

2. make a Contribution in the form of cash, labor and/or material equal to the amount ofthe Estimated Investment but make no monthly Guaranteed Payments based on theamount of the Estimated Investment;

3. make a Contribution in the form of cash, labor and/or material equal to any portion ofthe Estimated Investment and also agree to make monthly Guaranteed Paymentscalculated based on the Estimated Investment less such Contribution.

The “amount” blanks below will be completed according to the option chosen above.

The Applicant shall pay the Company a Contribution of $__________ prior to the beginning of construction. After service is initiated the Customer agrees to pay monthly the greater of $__________, (the Guaranteed Payment calculated pursuant to Rate Schedule No. 60, Extension of Facilities) or the amount calculated according to the rate schedule under which the Customer is receiving service. If the Guaranteed Payment is greater than zero, the Customer will also be required to enter into an Agreement For Electric Service (AES) for a Term of not less than three years (“Initial Term”) and Section 4 of the AES shall contain the Guaranteed Payment inserted above. The obligation to pay such Guaranteed Payment will continue after the Initial Term for as long as service is provided to the Customer by the Company. If the Customer ceases to take service prior to the end of the Initial Term the balance of the monthly bill amounts specified above for the remainder of the Initial Term shall become due and payable by the Customer.

8. REIMBURSEMENT BY COMPANY

There will be no reimbursement by the Company to the Customer.

9. ENGINEERING STUDY SUMMARY

The engineering study if necessary to design this extension is attached as Attachment C.

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10. OTHER CONTRACT REQUIREMENTS

An Agreement for Electric Service shall be required dated with the above date and executedby the Parties hereto if the Customer chooses to pay Guaranteed Payments pursuant to § 7.

11. APPROVALS

APPLICANT

By: ____________________________________

Date:________________________________


By: ____________________________________

Approved: ____________________________________

Title: ____________________________________

Date:________________________________





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13.7.2 Extension of Service Agreement for Planned Land Use Developments

This Agreement was made and entered into on _______________, by and between ____________________ (“Developer” or “Applicant”) and Entergy Arkansas, LLC (“EAL” or the “Company”), a corporation.

1. GENERAL

When a planned land use development is defined by the Company to be an area of at least 100contiguous acres in size for purposes of the Company’s facilities installation and is being developedover a period of several years for residential, commercial, or industrial use and in which it will benecessary for the Company to construct three-phase feeder circuits to provide adequate service forthe anticipated electric loads of the completed planned development, the Company and theDeveloper will sign this Extension of Service Agreement Planned Land Use Developments(“Agreement”) in order for the Company to extend its facilities to provide electric service whenneeded, including as set forth in Rate Schedule No. 60. This Agreement will describe the facilities tobe provided by the Company and the Revenue Guarantee required by the Developer.

The terms used in this Agreement will have the same meaning as set forth in the Company’s RateSchedule No. 60, and in the event of any conflict between this Agreement and Rate Schedule No. 60,Rate Schedule No. 60 will control.

The Company will provide the necessary facilities as reasonably requested by the Developer if theDeveloper agrees to make an Annual Revenue Guarantee and an Annual Payment to the Companyas set forth herein. With respect to the facilities provided by EAL, the Company’s Estimated NetInvestment in the facilities will be determined by the Company by estimating the cost of the facilities,including overhead and underground facilities, and subtracting contributions for underground facilitiesand/or other contributions made by the Developer and/or allowances granted in accordance with theCompany’s Rate Schedule §60.3.4. For residential subdivisions the Residential Allowance will bemultiplied by the number of platted lots to determine the total allowance. However, no credit forunused allowances will be applied against the Additional or Unusual Costs as set forth in theCompany’s Rate Schedule No. §60.2.7.

Developer will not voluntarily assign in whole or in part its rights or delegate its duties under thisAgreement without the prior written consent of the Company, which consent will not be unreasonablyconditioned, delayed, or withheld.

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2. APPLICANT DATA

Address of Applicant:

Initial application date:

Service point location and description:

Description of work:

3. SKETCH OF DEVELOPER’S CONSTRUCTION PLAN

A sketch of the Developer’s construction plan is provided as Attachment A.

4. EXPLANATION OF COSTS

An explanation of all Company costs in reasonable detail is provided as Attachment B. Attachment Bmay be amended by the Company from time to time to reflect additional costs that may be incurredby the Company. The Company will provide reasonable notice to the Developer of any suchamendments to Attachment B.

5. PRE-CONSTRUCTION APPLICANT OBLIGATIONS

The Applicant shall obtain all necessary rights-of-way from all property owners over whose propertythe facilities shall be located, and complete the applicable form(s) supplied by the Company, thatgrants to the Company (or its successors and assigns) the rights and privileges to construct, maintainand operate said facilities. Such completed forms shall be appropriately signed and delivered byDeveloper to the Company prior to construction.

It is expressly understood that said rights-of-way and all electrical facilities erected for serving theapplicable planned land use development under this Agreement shall always be and remain theproperty of the Company. The Company has the right, at its discretion, to serve any other customersor land use developments from said facilities or any extension thereof at any time.

Developer will complete the additional items listed below before the Company begins construction.These items may include but are not limited to the acquisition of permits and right-of-way clearing. IfDeveloper has no such obligations the space below shall show “None”.

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6. ESTIMATED CONSTRUCTION START AND COMPLETION DATES

Construction will start when this Agreement is executed and approved and when any required pre-construction payment is returned to the Company and the items in § 5 above, if any, have beencompleted

7. TERMS OF PAYMENT (Pursuant to Rate Schedule No. 60, including Section 60.3.4)

With respect to the Annual Revenue Guarantee to be paid by the Developer to the Company forsingle-phase facilities that have been in place for the entire contract year, the Company’s EstimatedNet Investment will be multiplied by 1.25% times 12 months. The Company’s Estimated NetInvestment in single-phase facilities that have not been in place for the entire contract year will bemultiplied by 1.25% times the number of months in the contract year in which said facilities were inplace.

With respect to the Annual Revenue Guarantee to be paid by the Developer to the Company forthree-phase facilities that have been in place for the entire contract year, the Company’s EstimatedNet Investment will be multiplied by 2.5% times 12 months. The Company’s Estimated NetInvestment in three-phase facilities that have not been in place for the entire contract year will bemultiplied by 2.5% times the number of months in the contract year in which said facilities were inplace.

With respect to the Annual Payment to be made on an annual basis at the end of each contract yearby the Developer to the Company, the Developer will pay the positive difference, if any, between thesum of the amounts determined for the applicable Annual Revenue Guarantee and the annual totalaccumulated electric revenue excluding Riders ECR, NDCR, GGR and all other Rate Riders that maybecome effective by Commission order, franchise adjustment, and sales tax from all customers withinthe planned development. In the event that such Revenue exceeds the Annual Revenue Guarantee,then no payment will be made by either Developer or the Company.

Failure by the Developer to make any of the required payments or guarantees shall constitute amaterial breach of this Agreement and a violation of the Company’s Rate Schedule No. 60. In suchcase, the Company, without further notice to the Developer, may pursue all legal and equitable rightsthe Company has including seeking a lien with respect to the Developer’s property.

The Company may require developer to pay a Contribution of $______ prior to the beginning ofconstruction.

Any “amount” or “timing” blanks herein will be completed by the Company.

8. REIMBURSEMENT BY THE COMPANY

There will be no reimbursement by the Company to Developer.

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9. ENGINEERING STUDY SUMMARY

The engineering study if necessary to design this extension is attached as Attachment C.

10. APPROVALS

By: ____________________________________

Date:________________________________


By: ____________________________________

Approved: ____________________________________

Title: ____________________________________

Date:________________________________





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13.8. Agreement to Change Existing Facilities

THIS AGREEMENT, made and entered into on ______________________, by and between _________________ (“Customer”) of the City of ____________, County of ______________, Arkansas, and Entergy Arkansas, LLC, (“EAL” or the "Company");

1. Company, will within a reasonable time, change existing electric facilities as follows:____________________________________________________________________________________________________________________________________________________________________________________________________________

2. CUSTOMER, having requested the aforementioned work, and in consideration of thefacilities to be provided by Company, does hereby agree to contribute to Companyprior to construction cash in the amount of $ _______.

3. It is not intended that Customer will acquire any rights or interest in the facilities ofCompany by reason of this payment toward the cost of the aforementioned work.

4. CUSTOMER shall obtain all necessary rights of way, and complete the applicableform(s) supplied by Company, from all property owners over which the line shall belocated granting to Company, its successors and assigns, the rights and privileges toconstruct, maintain and operate said line. Such completed forms shall beappropriately signed and delivered to Company prior to construction.

5. It is expressly understood that said rights of way and all electrical facilities erected forserving Customer under this Agreement shall always be and remain the property ofCompany, and Company has the right to serve any other customers from said line orany extension thereof at any time.

6. Other Provisions: _____________________________________________________

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CUSTOMER

By: _________________________________

Title: ________________________________


By: _________________________________ COMPANY AGENT

Approved: ___________________________

Title: ________________________________





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13.9. Agreements for Residential Underground Electric Distribution System in Subdivision

13.9.1 Agreement for Residential Underground Electric Distribution System in a Subdivision in an Incorporated Area

THIS AGREEMENT made and entered into on ____________, by and between Entergy Arkansas, LLC, (“EAL” or the “Company”), and _________________________________, (“Developer”), collectively (the “Parties”);

WHEREAS, Developer has requested Company to, and Company is willing to, provide an underground electric distribution and street lighting system for Lots _______ inclusive, of the _________________ Subdivision to the City of ___________, State of Arkansas.

NOW, THEREFORE, the Parties hereto agree as follows:

A. The construction proposed and electric utility easements required by Company are shown on a plat entitled ________________________________________________ attached hereto and made a part hereof, which plat is based upon subdivision plat provided by Developer, dated ________________, prepared by _______________, and owner certified that said plat has been approved by appropriate municipal authorities in the City of __________, County of _______, and has been filed in the office of the Circuit Clerk of ________ County, Arkansas, and that all information and detail is full and correct as shown.

B. Company agrees:

(1). To furnish and install in trenches, excavations, primary junction boxes and conduits to be provided by Developer all primary and secondary cables and appurtenant equipment, to provide a complete electric distribution system as shown on the attached plat including, but not limited to, cables, transformers, and service connection points.

(2). To operate and maintain the electrical distribution system owned by it.

(3). To make all connection of underground residential services to its underground distribution system.

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C. Developer agrees:

(1). To provide all easements and rights-of-way and protective provisions required by Company and include such provisions in the plat and Bill of Assurance after the provisions have been approved by Company.

(2). That all provisions of the easements and rights-of-way granted to Company shall be incorporated in the plat, Bill of Assurance, or other documents which shall be filed for record prior to sale of any lot and to provide in the Bill of Assurance that any change in the plat and/or Bill of Assurance shall require the prior approval of the Company.

(3). That the Bill of Assurance shall include the following language: “Obstructions around electrical equipment may cause delays in restoring electrical service. Fences, shrubs, trees and other permanent structures may not be placed closer than 12 feet in front of the doors or 3 feet from the sides or back of any electrical equipment or junction boxes”. Developer must provide a copy of the filed plat and Bill of Assurance to EAL before construction can begin.

(4). To require electric service to all structures in said subdivision to be underground.

(5). To grade the easements to final grade, excavate and later backfill all trenches and other excavations required by Company for its electrical distribution facilities and install conduit and primary junction boxes as required.

(6). That all excavation, backfill and other work done by Developer shall be done in accordance with Company specifications, properly located within the easements granted and accomplished in a manner as to allow for continuous installation of cables, transformers, street lights (if applicable) and other equipment.

(7). To install and maintain during any construction in vicinity of Company's facilities, construction survey stakes indicating grades, property lines and locations of any underground facilities in order to avoid damage to Company's facilities or to other facilities by Company's construction.

(8). To reimburse Company for any cost of relocation, additions to, or changes in its facilities occasioned by changes in grade, re-plat of lots, or change in usage designated in the Bill of Assurance.

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D. Agreement Regarding Street Lighting - If Applicable

(1). Company Agrees:

a. To furnish and install in trenches, excavations and conduits to be provided byDeveloper all street lighting cables and appurtenant equipment, to provide acomplete street lighting system of _____ street lighting units as shown on theattached plat, including, but not limited to, poles, fixtures, cables andconnections. Each of said units will consist of ____________________________________________________________________________________.

b. To operate and maintain the electrical street lighting system in accordancewith an agreement for street lighting service.

(2). Developer Agrees:

a. To grade the easements to final grade, excavate and later backfill alltrenches required by Company for its street lighting facilities, install conduitsas required and erect necessary foundations for all street light poles.

b. To pay Company a non-refundable contribution in aid of this specialunderground street lighting construction in the amount of_________________________________________ Dollars ($_______) foreach complete unit installed.

E. It is further agreed that:

1. In the event any lot(s) covered by said easements are conveyed by Developerbefore construction of Company facilities is completed on said conveyed lot(s),Developer shall nevertheless be required to comply with the terms of thisagreement and in connection therewith to indemnify and hold harmless Companyfrom any and all damages in connection therewith.

2. Temporary service for construction power is not a part of this Agreement but canbe provided in accordance with Company's rate schedules.

3. This agreement, insofar as it relates to the underground street lighting system,shall become binding upon Company only after proper authorization has beenobtained from the City of _______________ for the installation of the street lightscalled for herein and an agreement has been executed by the City to payCompany for maintenance and operation of these lights in accordance with theCompany's Rate Schedule L1 for municipal street lighting service.

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4. This agreement is contingent upon compliance by Developer with allrequirements of Company's Rate Schedule No. 61, Tariff Governing theInstallation of Electric Underground Residential Distribution Systems andUnderground Service Connections, Policy Schedule No. 9, Service Regulationsand Company’s other applicable rate schedules.

5. This Agreement is further contingent upon approval by Company's President,Vice President or Department Director.

(6) The Parties have also agreed to the following other provisions: _____________ ________________________________________________________________________________________________________________________________________________________________________________________________

IN WITNESS WHEREOF, the Parties hereto have caused this agreement to be executed on _____________.

(CUSTOMER)

By:___________________________________

Print Name:____________________________

Signature Date:________________________

ATTEST:______________________________

(Customer's Secretary)

Print Name:____________________________


By: ____________________________________

Print Name:______________________________

Approved:_______________________________

Print Name:______________________________

Title:____________________________________

Signature Date:___________________________




Residential___________ Commercial___________ Industrial_____________

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13.9.3 Agreement for Residential Underground Electric Distribution System in a Subdivision in an Unincorporated Area

THIS AGREEMENT made and entered into on ____________, by and between Entergy Arkansas, LLC, (“EAL” or the “Company”), and _________________________________, (“Developer”), collectively (the “Parties”);

WHEREAS, Developer has requested Company to, and Company is willing to, provide an underground electric distribution and street lighting system for Lots _______ inclusive, of the _________________ community of the County of ___________, State of Arkansas.

NOW, THEREFORE, the Parties hereto agree as follows:

A. The construction proposed and electric utility easements required by Company are shown on a plat entitled ________________________________________________ attached hereto and made a part hereof, which plat is based upon plat provided by Developer, dated ________________, prepared by _______________, and owner certified that said plat has been approved by all appropriate governmental authorities and has been filed in the office of the Circuit Clerk of ________ County, Arkansas, and that all information and detail is full and correct as shown.

B. Company agrees:

(1). To furnish and install in trenches, excavations, primary junction boxes and conduits to be provided by Developer all primary and secondary cables and appurtenant equipment, to provide a complete electric distribution system as shown on the attached plat including, but not limited to, cables, transformers, and service connection points.

(2). To operate and maintain the electrical distribution system owned by it.

(3). To make all connection of underground residential services to its underground distribution system.

C. Developer agrees:

(1). To provide all easements and rights-of-way and protective provisions required by Company which shall be incorporated and include such provisions in the plat and Bill of Assurance after the provisions have been approved by Company.

(2). That all provisions of the easements and rights-of-way granted to Company shall be incorporated in the plat, Bill of Assurance, or other documents which shall be filed for record prior to sale of any lot and to provide in the Bill of Assurance that any change in the plat and/or Bill of Assurance shall require the prior approval of the Company.

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(3). That the Bill of Assurance shall include the following language: “Obstructions around electrical equipment may cause delays in restoring electrical service. Fences, shrubs, trees and other permanent structures may not be placed closer than 12 feet in front of the doors or 3 feet from the sides or back of any electrical equipment or junction boxes”. Developer must provide a copy of the filed plat and Bill of Assurance to EAL before construction can begin.

(4). To require electric service to all structures in said subdivision to be underground.

(5). To grade the easements to final grade, excavate and later backfill all trenches and other excavations required by Company for its electrical distribution facilities and install conduit and primary junction boxes as required.

(6). That all excavation, backfill and other work done by Developer shall be done in accordance with Company specifications, properly located within the easements granted and accomplished in a manner as to allow for continuous installation of cables, transformers, street lights (if applicable) and other equipment.

(7). To install and maintain during any construction in vicinity of Company's facilities, construction survey stakes indicating grades, property lines and locations of any underground facilities in order to avoid damage to Company's facilities or to other facilities by Company's construction.

(8). To reimburse Company for any cost of relocation, additions to, or changes in its facilities occasioned by changes in grade, re-plat of lots, or change in usage designated in the Bill of Assurance.

D. Agreement Regarding Street Lighting – If Applicable

(1). Company Agrees:

a. To furnish and install in trenches, excavations, conduits to be provided byDeveloper all street lighting cables and appurtenant equipment, to provide acomplete street lighting system of _____ street lighting units as shown on theattached plat, including, but not limited to, poles, fixtures, cables andconnections. Each of said units will consist of ____________________________________________________________________________________.

b. To operate and maintain the electrical street lighting system in accordancewith an agreement for street lighting service.

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(2). Developer Agrees:

a. To grade the easements to final grade, excavate and later backfill alltrenches required by Company for its street lighting facilities, install conduitsas required and erect necessary foundations for all street light poles.

b. To pay Company a non-refundable contribution in aid of this specialunderground street lighting construction in the amount of___________________ _______________________ Dollars ($_____) foreach complete unit installed.

E. It is further agreed that:

(1). In the event any lot(s) covered by said easements are conveyed by Developer before construction of Company facilities is completed on said conveyed lot(s), Developer shall nevertheless be required to comply with the terms of this agreement and in connection therewith to indemnify and hold harmless Company from any and all damages in connection therewith.

(2). Temporary service for construction power is not a part of this Agreement but can be provided in accordance with Company's rate schedules.

(3). This Agreement, insofar as it relates to the underground street light system, shall become binding upon Company only after:

a. The execution of an agreement for all night outdoor lighting service inaccordance with Company Rate Schedule No. L4 between Company and aproperty owner's association duly authorized to contract on behalf ofresidents of __________________________________community; or

b. the execution of an agreement for metered service in accordance withCompany Rate Schedule No. 4, Small General Service between Companyand Developer for service to such underground street light system as may bebuilt by Developer consistent with Company standards and specifications.

(4). This agreement is contingent upon compliance by Developer with all requirements of Company's Rate Schedule No. 61, Tariff Governing The Installation of Electric Underground Residential Distribution Systems and Underground Service Connections, Policy Schedule No. 9, Service Regulations and Company’s other applicable rate schedules.

(5). This Agreement is further contingent upon approval by Company's President, Vice President or Department Director.

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(6) The Parties have also agreed to the following other provisions: _____________ ________________________________________________________________________________________________________________________________________________________________________________________________

IN WITNESS WHEREOF, the Parties hereto have caused this agreement to be executed on _____________.

(CUSTOMER)

By:___________________________________

Print Name:____________________________

Signature Date:_________________________

ATTEST:______________________________

(Customer's Secretary)

Print Name:____________________________


By: _____________________________________

Print Name:________________________________

Approved:_______________________________

Title:_____________________________________

Signature Date:____________________________





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13.10. Facilities Agreements

13.10.1. Facilities Agreement

This Agreement, made and entered into _________________, by and between ______________________________, ("Customer") and Entergy Arkansas, LLC, (“EAL” or the "Company");

A. Premise Location Customer has contracted with Company for the supply of electric power and energy for the operation of Customer's _________________ located at or near ________________, Arkansas.

B. Additional Facilities Requested Customer has requested Company to additionally provide, install, operate and maintain the Additional Facilities listed on Attachment A to this Agreement which are over and above those facilities that Company would normally install for the Customer's load and service requirements.

C. Rate Schedules Company will provide said Additional Facilities in accordance with Additional Facilities Charge Rider (AFCR), Rate Schedule No. 26 and Company's Policy Schedule No. 9, Service Regulations, copies of which are attached and made a part hereof, or such other effective superseding rate schedule(s) and Service Regulations as may be authorized by duly constituted regulatory authority exercising lawful jurisdiction or as may become effective in the manner provided by law. Customer agrees to promptly pay all charges for such additional facilities as provided in said schedule and regulations.

D. Monthly Charges The monthly charges under the Additional Facilities Charge Rider (AFCR), Rate Schedule No. 26 shall be based on the installed cost of such Additional Facilities as shown below in accordance with § 26.3, Option A or § 26.4, Option B whichever is applicable. Option A: Customer’s monthly payment under Option A will be based on an installed cost of such additional facilities of XXXXXXXXXXXXXXXXX and will be calculated by multiplying such cost by the then current rate per month under Option A.

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Option B: Customer’s monthly payment under Option B will be based on an installed cost of such additional facilities of XXXXXXXXXXXXXXXX and will be calculated by multiplying such installed cost by the “Monthly % During Recovery Term” applicable to the “Selected Recovery Term” selected by the Customer. Beginning with the first month after the end of the “Selected Recovery Term” and each month thereafter the Customer will pay an amount calculated by multiplying such installed cost by the “Monthly % Post Recovery Term”.

E. Indemnity Company shall have exclusive control of and access to said facilities and Customer will not permit its employees or agents to come in contact with said facilities. In the event an employee or agent of Customer is injured or killed by contacting said facilities, the Customer shall defend, indemnify and hold the Company harmless from any and all claims, actions, causes of action and demands arising from such injuries or death of agents, or employees of Customer. Said obligation to defend, indemnify and hold harmless includes, but is not limited to payment of judgment, settlements or claims and litigation and preparation expense in connection therewith for discovery, expert witness fees, reasonable attorney's fees, and other such expenses.

F. Term The term of this Agreement shall be as follows in accordance with Additional Facilities Charge Rider (AFCR), Rate Schedule No. 26: Option A: The term of this Agreement shall be from Month Day, Year or the date said facilities are first made ready for use, whichever occurs earlier, and for a period of 10 years thereafter. This term shall be automatically extended for successive periods of one year each until terminated by written notice given by one party to the other not more than six months nor less than three months prior to the expiration date of the original term or any anniversary thereof. Option B: The term of this Agreement shall be from Month Day, Year or the date said facilities are first made ready for use, whichever occurs earlier, and for a period of ____ years thereafter.

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G. Termination Charges: If Customer ceases to take electric service from Company at the above Premise Location, Company may remove said additional facilities and Customer shall pay Company the termination charges set forth in the Contract Term provisions of Rate Schedule No. 26. In the event the Customer does not require the additional facilities for the full term of the Contract and wishes to cancel this Contract prior to the expiration date, Company reserves the right to remove such additional facilities and will consent to the cancellation of the Contract provided Customer pays to the Company the applicable termination charges set forth in the Contract Term provisions of Rate Schedule No. 26.

H. Ownership of Facilities Title to all such additional facilities shall remain in the Company. Upon termination of this Agreement or in the event of non-payment of the applicable charges therefor, Company shall have the right to remove all such facilities.

I. Approval This Agreement is contingent upon approval by Company's President, Vice President or Department Director.

CUSTOMER

By: ____________________________________

Title: ___________________________________

Signature Date ____________________________

ATTEST:_________________________________ Customer's Secretary

Signature Date ____________________________


By: _____________________________________

Title: ____________________________________

Approved: ________________________________

Title: ____________________________________

Signature Date ____________________________





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Original Sheet No. P13.10.1.1.1 Schedule Sheet 1 of 1







13.10.1.1. Attachment A to Facilities Agreement

A. The following additional facilities requested by the Customer shall be installed by the Company and Customer shall pay a monthly charge based on the estimated installed cost of such facilities of $________. The monthly charge shall be calculated using the then current rates from the provisions of Option A or Option B of Rate Schedule No. 26 as applicable. The monthly charge shall become effective Month Year.

B. The monthly charge shall be modified to reflect actual installed costs when such costs are available and the balance of the Facilities Agreement reflecting such actual costs shall be completed and signed by the Customer and Company.

C. The Additional Facilities to be installed are as follows:

ITEM ESTIMATED INSTALLED COST

xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx $xxxxxxxxxxxx

CUSTOMER By: ___________________________________

Title: __________________________________

Signature Date __________________________

ATTEST: ______________________________ Customer's Secretary

Signature Date __________________________

ENTERGY ARKANSAS, LLC By: ___________________________________

Title: __________________________________

Approved: ______________________________

Title: __________________________________

Signature Date __________________________





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13.10.2. AMENDMENT TO FACILITIES AGREEMENT FOR REMOVAL/RELOCATION OF FACILITIES

Amendment No. XX To Facilities Agreement Dated XXXXXXXXXXX

Pursuant To Additional Facilities Charge Rider (AFCR) § 26.3 or § 26.4 (For Removal/Relocation of Facilities)

THIS AMENDMENT is made and entered into this XXX day of XXXXXX, XXXX, by and between XXXXXXXXXXXXX (“Customer”) and Entergy Arkansas, LLC (“Company).

A. Company and Customer are parties to a Facilities Agreement dated XXXXXXXXXXX (“Agreement”) in accordance with the provisions of Company’s Additional Facilities Charge Rider, Rate Schedule No. 26, (“AFCR”) whereby Company has installed facilities over and above those which Company would normally install for Customer’s load and service requirements.

B. Pursuant to the provisions of § 26.3 or § 26.4 of AFCR Customer requests the Amendment of said Agreement to reflect the removal or relocation of existing additional facilities as listed in Attachment A of this Amendment.

C. Company agrees to amend said Agreement and to remove or relocate such existing additional facilities.

D. Customer will pay Company $XXXXXX, the cost of removing the existing facilities as listed in Attachment A of this Amendment.

E. The original installed cost of the remaining additional facilities shall be determined as the sum of the original installed cost of additional facilities before removals of $XXXXXX less the original installed cost of the additional facilities removed pursuant to this Amendment of $XXXXXX, and shall be the adjusted cost of $XXXXXX. Customer’s revised monthly charge under AFCR shall be based on such adjusted cost and shall be calculated by multiplying such adjusted cost by the then current rate per month from AFCR § 26.3, Option A or the appropriate “Monthly % During Recovery Term” from § 26.4, Option B of AFCR. Such monthly charge shall then prospectively replace the monthly charge under the Agreement dated XXXXXXXXXX including any and all amendments thereto.

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CUSTOMER NAME

By _____________________________________

Title: ___________________________________

Signature Date:___________________________

ATTEST:_______________________________ Customer's Secretary


By: _____________________________________

Title: ____________________________________

Approved: _______________________________

Title: ____________________________________

Signature Date:___________________________





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Kind of Service Electric Class of Service: All Docket No.: 18-073-TF Order No.:




13.10.2.1. ATTACHMENT A TO AMENDMENT TO FACILITIES AGREEMENT FOR REMOVAL/RELOCATION OF FACILITIES

Attachment A To Facilities Agreement Amendment No._______

Additional Facilities To Be Removed By Company

A. The Company shall remove the following additional facilities (Removals) as requested by the Customer and Customer shall pay a revised monthly charge based on the revised installed cost determined as the current total original installed cost of the existing additional facilities of $XXXXX less the estimated installed cost of the Removals of $XXXXX. The revised monthly charge shall be calculated based on the revised installed cost using the then current rates from the provisions of § 26.3, Option A. of Rate Schedule No. 26 (AFCR). The revised monthly charge shall become effective XXXXXXXXX and will replace the monthly charge under the contract dated, XXXXXXXXX including any and all amendments thereto.

B. For those additional facilities removed Customer shall pay Company a cancellation payment of $XXXXXX, if required, calculated pursuant to the lesser of parts 1 and 2 of § 26.6 of AFCR plus any rearrangement costs associated with the removal of facilities.

C. The revised monthly charge shall be further modified and billed prospectively to reflect the remaining installed costs when the actual cost of Removals is available and the balance of this Amendment No. XXX reflecting such actual remaining installed costs shall be completed and signed by the Customer and Company.

D. The following Additional Facilities shall be removed:

XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX

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CUSTOMER NAME

By: __________________________________

Title: _________________________________

Signature Date_________________________

ATTEST:______________________________ Customer's Secretary


By: ___________________________________

Title: __________________________________

Approved: _____________________________

Title: __________________________________

Signature Date:__________________________





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13.10.3. AGREEMENT FOR OPERATION AND MAINTENANCE OF CUSTOMER FACILITIES

This Agreement is made and entered into this date, XXXXXXXXXXXXXX, by and between XXXXXXXXXXXXXXXXX, ("Customer") and Entergy Arkansas, LLC, (“EAL” or the "Company"):

A. Premise Location

Customer has contracted with Company for the supply of electric power and energy for the operation of Customer's XXXXXXXXXXXXXX located at or near XXXXXXXXXXX, Arkansas.

B. Operation and Maintenance (“O&M”) Services

Customer has requested that Company provide O&M services for the Customer-owned Facilities listed on Attachment A to this Agreement. Company will provide O&M services as described below:

(1). O&M Service for Distribution Substation Facilities

EAL will inspect and service Customer-owned substation facilities according to EAL standard practices for similar Company-owned substation facilities. Services provided will include but not necessarily be limited to: a. Emergency O&M services will be performed at the Company’s sole

reasonable discretion based on factors including but not limited to resource availability that may be diminished by System emergencies and/or trouble incidents, Good Utility Practices, or safety or health concerns.

b. Monthly ground level inspections of all facilities.c. Routine maintenance activities to include filtering transformer oil as

necessary, servicing substation batteries, and testing switches andbreakers. Customer will receive a written report identifying the servicesperformed and any problems or needed repairs discovered by servicepersonnel.

d. Upon Customer’s notification to Company of a continuing serviceinterruption at Customer’s facilities, Company will dispatch servicepersonnel to inspect Customer’s facilities and determine the source(s) oftrouble. The number of trouble cases and availability of Entergy resourceswill influence response time. If equipment damage is found and Companyagrees to repair or replace the damaged equipment, Company will provideCustomer an estimated cost and schedule for the necessary repairs.

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e. Equipment refurbishing, repair, and replacement of worn systems are notconsidered routine maintenance activities and are not provided as part ofthis Agreement, however, if Company agrees, such activities may beperformed by the Company under Service Agreements for SpecificTasks or Activities below.

(2). O & M Service Agreements for Other Distribution Facilities

Company will inspect and service other Customer-owned distribution facilities according to standard practices for Company-owned distribution facilities. Services provided will include but not necessarily be limited to: a. Emergency O&M services will be performed at the Company’s sole


b. Company will perform an annual ground level distribution facilitiesinspection, limited to visual means from ground level, and provide a written report on the condition of the Customer-owned facilities covered by the agreement.

c. Company will tighten hardware found as a result of this annual inspectionand perform minor service work (re-fuse, re-splice overhead services, and photocell and/or bulb replacement) with Customer provided items.

d. Upon Customer’s notification to the Company of a continuing serviceinterruption at Customer’s facilities, Company will dispatch service personnel to inspect Customer’s facilities and determine the source(s) of trouble. The number of trouble cases and availability of EAL resources will influence response time. If equipment damage is found and EAL agrees to repair or replace the damaged equipment, Company will provide Customer an estimated cost and schedule for the necessary repairs.

e. Refurbishing, repair, and replacement of poles, conductor, hardware,transformers, switches, capacitor banks, and lighting fixtures are not considered routine maintenance activities and are not provided as part of this service, however, if Company agrees, such activities may be performed under Service Agreements for Specific Tasks or Activities below.

C. Service Agreements for Specific Tasks or Activities (Job Order Billing)

As described above, this O&M Service Agreement does not provide all possible service and repair activities for Customer-owned distribution facilities or substation facilities. When tasks or activities are in the Company’s sole judgment beyond the scope of routine O&M services, Customer may request the Company to perform

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these specific tasks or activities for the Customer. In such cases if the Company agrees to do the work, the Customer will be assessed a charge that fully reimburses Company for the individual tasks or activities. Customer is under no obligation to have the Company perform such tasks and may choose other vendors to provide such services. A Service Agreement for Specific Tasks or Activities will be required for all such tasks or activities including but not limited to detailed pole ground-line inspections, infrared inspections, and conductor termination cleaning and tightening.

D. Rate Schedules

Company will provide said O&M Services in accordance with AFCR, and Company's Policy Schedule No. 9, Service Regulations, copies of which are attached hereto and made a part hereof, or such other effective superseding rate schedule(s) and Service Regulations as may be authorized by duly constituted regulatory authority exercising lawful jurisdiction or as may become effective in the manner provided by law. Customer agrees to promptly pay all charges for such services as provided in said schedule and regulations.

E. Monthly Charges

The monthly charges under AFCR, § 26.5, Operation and Maintenance of Customer-Owned Facilities (O&M Service) shall be based on the current estimated cost of replacement facilities as shown below. Customer’s monthly payment for O&M Service will be based on an estimated replacement cost of such facilities of XXXXXXXXXXXXXXXXX and will be calculated by multiplying such installed cost by the then current rate per month under § 26.5 of AFCR.

F. Indemnity

In the event of injury or death to any person as a result of contact with said Customer owned facilities, the Customer shall defend, indemnify and hold the Company harmless from any and all claims, actions, causes of action and demands arising therefrom. Said obligation to defend, indemnify and hold harmless includes, but is not limited to payment of judgment, settlements or claims and litigation and preparation expense in connection therewith for discovery, expert witness fees, reasonable attorney's fees, and other such expenses.

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G. Term

The term of this Agreement, in accordance with AFCR, Rate Schedule No. 26, shall be from XXXXXXX, XXXX or the date said facilities are first made ready for use, whichever occurs earlier, and for a period of XXX years thereafter. This term shall be automatically extended for successive periods of one year each until terminated by written notice given by one party to the other not more than six months nor less than three months prior to the expiration date of the original term or any anniversary thereof.

H. Ownership of Facilities

Title to all such additional facilities shall remain in the Customer.

I. Other Provisions

Other Provisions to this Agreement are as listed on Attachment B.

J. Approval

This Agreement is contingent upon approval by Company's President, Vice President or Department Director.

CUSTOMER NAME

By: ____________________________________

Title: ___________________________________

Signature Date: __________________________

ATTEST: _________________________________ Customer's Secretary


By: ___________________________________

Title: __________________________________

Approved: ______________________________

Title: __________________________________

Signature Date:__________________________





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13.10.3.1. ATTACHMENT A – CUSTOMER FACILITIES SUBJECT TO OPERATION AND MAINTENANCE

A. The following facilities owned by the Customer are the subject of O&M services performed by the Company and Customer shall pay a monthly charge based on the estimated replacement cost of such facilities of $XXXXXXX. The monthly charge shall be calculated using the current rates from the provisions of § 26.5, Operation and Maintenance of Customer-Owned Facilities of Rate Schedule No. 26 (AFCR). The monthly charges shall become effective XXXXXXXXXXXXXXX.

B. The Customer Facilities subject to Company O&M services are as follows:

ITEM ESTIMATED REPLACEMENT COST

XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX $XXXXXXXXXXXXX

CUSTOMER NAME

By: ____________________________________

Title: ____________________________________

Signature Date:___________________________

ATTEST:________________________________ Customer's Secretary


By: _______________________________________

Title: ____________________________________

Approved: ________________________________

Title: ____________________________________

Signature Date:____________________________





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13.10.3.2. ATTACHMENT B - OTHER PROVISIONS TO AGREEMENT FOR OPERATION AND MAINTENANCE OF CUSTOMER FACILITIES

A. The following provisions are incorporated into and made a part of the Agreement for Operation and Maintenance of Customer Facilities as attached:

XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX

CUSTOMER NAME

By: _____________________________________

Title: __________________________________

Signature Date:__________________________



By: _____________________________________

Title: ____________________________________

Approved: _______________________________

Title: ____________________________________

Signature Date:____________________________





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Original Sheet No.: P13.11.1 Schedule Sheet 1 of 1



Kind of Service: Electric Class of Service: All Docket No: 18-073-TF Order No.:




13.11. Agreement Implementing Economic Development Rider (EDR)

In consideration of the agreement of ________________________________________ (“Customer”) to consider location or expansion of operations in Entergy Arkansas, LLC (“EAL” or the “Company”) service area at ______________________________________ EAL agrees to apply the terms of its Economic Development Rider (EDR) tariff (‘the Rider’),____________ (Option 1 or Option 2) on file with and approved by the Arkansas Public Service Commission (“APSC”), to such new or increased demand, so long as Customer qualifies for the application of the Rider pursuant to its terms. A copy of the Rider is attached hereto and incorporated herein by reference.

Customer estimates that a new or increased electric demand equal to or in excess of 500 kW will be installed and operational at the premises indicated above on or about_______ ________________ (date). Base Period Demand is currently estimated to be ________ kW but will be recalculated when the Rider becomes applicable.

Nothing herein obligates Customer to locate or expand in EAL’s service area. If, however, Customer has not caused demands sufficient to cause the Rider to apply within one year of the date Customer has designated in the previous paragraph, this contract shall terminate.

This contract is not effective until its approval by the Arkansas Public Service Commission in the manner set forth in the Rider. This contract is not assignable without the written consent of EAL.

CUSTOMER

By: ________________________________________

Title: ________________________________________


By: ________________________________________

COMPANY AGENT

Approved: ________________________________________

Title: ________________________________________

Date: ________________________ Date: ____________________

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Kind of Service: Electric Class of Service: Commercial/Industrial Docket No. 18-073-TF Order No.:




13.12. Amendment to Agreement for Electric Service for Interruptible Service

This Agreement, made and entered into on Month Day, Year, by and between Customer Name (“Customer”) and Entergy Arkansas, LLC (“EAL” or the “Company”), a corporation;

1. Agreement for Electric Service

Customer and Company have entered into an Agreement for Electric Service (“AES”)dated Month Day, Year whereby EAL provides Firm Electric Service to Customer for usein the operation of Customer’s type of operation located in or near City, Arkansas.

2. Purpose

Customer wishes to enter into an agreement with Company to allow Company tointerrupt a portion of Customer’s load that can from time to time be interrupted pursuantto the terms specified in this agreement and to the provisions of EAL’s Rate ScheduleNo. 41, Optional Interruptible Service Rider (OIS) (“Rider”) which is attached hereto andmade a part of this Agreement or such other effective superseding Rate Schedule asmay be authorized by duly constituted regulatory authority exercising lawful jurisdiction,or as may become effective in the manner provided by law.

3. Definitions

Firm Electric Service Requirements of Customer supplied under one of Company’s standard electric service schedules in accordance with the AES dated Month Day, Year.

Firm Contract Demand (“FCD”) Customer’s demand to be excluded from interruptions, for this Agreement Amount kW. Customer may change this FCD one time in a contract period upon giving 60 days written notice to the Company.

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3. Definitions (continued)

Nonfirm Demand Restrictions A. OIS without Standby Service: The sum of the FCD and Nonfirm demand shall not exceed the maximum amount of kVA specified in the ESA, Characteristics of Service. B. OIS with Standby Service: Nonfirm demand shall not exceed____________kW. The sum of the FCD, Reserved Service Contracted Demand, and Nonfirm demand shall not exceed the maximum amount of kVA specified in the AES, Characteristics of Service

4. Billing Provisions

Customer shall pay a Monthly Customer Charge and all other charges calculated inaccordance with Section 41.6 of the Rider.

5. Term Of Agreement

The term of this Agreement shall be from the date service is first made availablehereunder to Month Day, Year, and shall be automatically extended for successiveperiods of number year(s) each until terminated by written notice given by the Customerto the Company not less than three months prior to the expiration date of the original termor any anniversary thereof. The monthly minimum contained in Section 41.5.7 of theRider does not terminate with the initial term of this Agreement, but continues in effect aslong as service is provided hereunder.

6. Other Provisions

Except as modified herein or in the provisions of the Rider, all provisions of the applicableRate Schedules will apply.

7. Entirety Of Agreement

This constitutes the entire and only agreement between the Parties hereto with referenceto the subject matter hereof and supersedes all previous understandings whether writtenor oral.

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8. Notices

Any notice, consent or other communication concerning this Agreement shall be properlygiven when deposited in the United States Mail, postage prepaid, registered or certified,and addressed as follows:

(a) Customer Customer Attn:___________ Customer address

(b) Entergy Arkansas, LLC Entergy Arkansas, LLC Attn: President P.O. Box 551 Little Rock, Arkansas, 72203

9. Approval

This Agreement is contingent upon approval by Company's President, Vice President orDepartment Director.

Customer Name

By: ___________________________________ Signatory Title

ATTEST:_______________________________ Signatory Title

Date of Signature________________________


By: ___________________________________ Signatory Title

Approved: ______________________________

Title: __________________________________

Date of Signature





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13.17 Agreement For Datalink Service

This Agreement is made _________________, 20____ between_______________________ _____________________________(“Customer”) and Entergy Arkansas, LLC (“Company”), collectively, the Parties.

1. Rates For Service

Company currently provides electric service to Customer under Rate Schedule ______ at ornear (service location)________________________________________________________.Customer wishes to obtain web-based access to Customer’s interval load data throughCompany’s DataLink service, and Customer agrees to pay for such service pursuant to theprovisions of Company’s Rate Schedule No. 29, paragraph 29.18, attached hereto and madea part hereof, or such other superseding Schedules as may be authorized by applicableregulatory authority exercising lawful jurisdiction, or as may become effective in the mannerprovided by law and Company agrees to provide such service.

2. Data Viewing Options

DataLink is a service that provides web based viewing access to interval load data that hasbeen collected by Company. The service gives a subscribing Customer the option of viewingthe collected load data on an hourly or daily basis. The monthly Subscription Charges will bebilled based on the Customer’s choice of Viewing Option as Customer has indicated below.(Check applicable option)_____ Daily Viewing Option._____ Hourly Viewing Option.

3. Interval Metering Payment Options

Customers that do not have interval metering must have an interval meter installed byCompany to enable interval data collection. Customer may elect to pay for the interval meterinstallation by a one-time charge or by a recurring monthly charge.

Company will install and Customer agrees to pay for an interval meter indicated below.(Check applicable statement)_____ Customer has an existing interval meter. No additional charge._____ Installation of interval meter Monthly Payment Option._____ Installation of interval meter Single Payment Option.

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4. Communication Link Options

If the Customer elects the Customer Provided Telephone Line option below there will be noMonthly Communication Link Charge. If the Customer elects the Company ProvidedWireless option below a one-time Set-up/Activation fee will apply and the monthlyCommunication Link Charges will be billed based on the Customer’s choice of ViewingOption elected by the Customer and indicated in § 2 above. (Check applicable option)_____ Customer Provided Telephone Line_____ Company Provided Wireless

5. Term / Cancellation

The minimum term of this Agreement for DataLink Service is two (2) years and Customeragrees to take service under this Agreement for the minimum term. If Customer elects tocancel service before the completion of the minimum term, Customer will pay to Companyliquidated damages equal to the balance of the fees due, based on the current tariff, for theremainder of the minimum term of the Agreement. After the minimum term, this Agreementwill continue in effect until cancelled by either party, which may be done by one party giving aminimum of 30 (thirty) days notice of cancellation to the other party.

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6. Approvals

This Agreement is contingent upon approval by Company's President, Vice President orDepartment Director.

__________(Customer)_____________

By: ____________________________________

Signature Date:__________________________



By: ______________________________________

Approved: _________________________________

Title: _____________________________________

Signature Date:_____________________________




Commercial ________ Industrial _________

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13.20. Facilities Agreements - Governmental

13.20.1. Facilities Agreement - Governmental

This Agreement, made and entered into _________________, by and between ______________________________, ("Customer") and Entergy Arkansas, LLC, (“EAL” or the "Company");

A. Premise Location The Customer has contracted with the Company for the supply of electric power and energy for the operation of the Customer's _________________ located at or near ________________, Arkansas.

B. Additional Facilities Requested The Customer has requested the Company to additionally provide, install, operate and maintain the Additional Facilities listed on Attachment A to this Agreement which are over and above those facilities that the Company would normally install for the Customer's load and service requirements.

C. Rate Schedules The Company will provide said Additional Facilities in accordance with Additional Facilities Charge Rider - Governmental (AFCRG), Rate Schedule No. 53 and Company's Policy Schedule No. 9, Service Regulations, copies of which are attached and made a part hereof, or such other effective superseding rate schedule(s) and Service Regulations as may be authorized by duly constituted regulatory authority exercising lawful jurisdiction or as may become effective in the manner provided by law. The Customer agrees to promptly pay all charges for such additional facilities as provided in said schedule and regulations.

D. Monthly Charges The monthly charges under the Additional Facilities Charge Rider (AFCR), Rate Schedule No. 53 shall be based on the installed cost of such Additional Facilities as shown below in accordance with § 53.3, Option A or § 53.4, Option B whichever is applicable. Option A: The Customer’s monthly payment under Option A will be based on an installed cost of such additional facilities of XXXXXXXXXXXXXXXXX and will be calculated by multiplying such cost by the then current rate per month under Option A.

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Option B: The Customer’s monthly payment under Option B will be based on an installed cost of such additional facilities of XXXXXXXXXXXXXXXX and will be calculated by multiplying such installed cost by the “Monthly % During Recovery Term” applicable to the “Selected Recovery Term” selected by the Customer. Beginning with the first month after the end of the “Selected Recovery Term” and each month thereafter the Customer will pay an amount calculated by multiplying such installed cost by the “Monthly % Post Recovery Term”.

E. Control and Access to Facilities The Company shall have exclusive control of and access to said facilities and the Customer will not permit its employees or agents to come in contact with said facilities

F. Term The term of this Agreement shall be as follows in accordance with Additional Facilities Charge Rider - Governmental (AFCRG), Rate Schedule No. 53: Option A: The term of this Agreement shall be from Month Day, Year or the date said facilities are first made ready for use, whichever occurs earlier, and for a period of 10 years thereafter. This term shall be automatically extended for successive periods of one year each until terminated by written notice given by one party to the other not more than six months nor less than three months prior to the expiration date of the original term or any anniversary thereof. Option B: The term of this Agreement shall be from Month Day, Year or the date said facilities are first made ready for use, whichever occurs earlier, and for a period of ____ years thereafter.

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G. Termination Charges: If the Customer ceases to take electric service from the Company at the above Premise Location, the Company may remove said additional facilities and the Customer shall pay the Company the termination charges set forth in the Contract Term provisions of Rate Schedule No. 53. In the event the Customer does not require the additional facilities for the full term of the Contract and wishes to cancel this Contract prior to the expiration date, the Company reserves the right to remove such additional facilities and will consent to the cancellation of the Contract provided the Customer pays to the Company the applicable termination charges set forth in the Contract Term provisions of Rate Schedule No. 53.

H. Ownership of Facilities Title to all such additional facilities shall remain in the Company. Upon termination of this Agreement or in the event of non-payment of the applicable charges therefor, the Company shall have the right to remove all such facilities.

I. Approval This Agreement is contingent upon approval by the Company's President, Vice President or Department Director.

CUSTOMER

By: ____________________________________

Title: ___________________________________

Signature Date ____________________________

ATTEST:_________________________________ Witness

Signature Date ____________________________


By: _____________________________________

Title: ____________________________________

Approved: ________________________________

Title: ____________________________________

Signature Date ____________________________





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13.20.1.1. Attachment A to Facilities Agreement - Governmental

A. The following additional facilities requested by the Customer shall be installed by the Company and the Customer shall pay a monthly charge based on the estimated installed cost of such facilities of $________. The monthly charge shall be calculated using the then current rates from the provisions of Option A or Option B of Rate Schedule No. 53 as applicable. The monthly charge shall become effective Month Year.

B. The monthly charge shall be modified to reflect actual installed costs when such costs are available and the balance of the Facilities Agreement reflecting such actual costs shall be completed and signed by the Customer and the Company.

C. The Additional Facilities to be installed are as follows:

ITEM ESTIMATED INSTALLED COST

xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx $xxxxxxxxxxxx

CUSTOMER By: ___________________________________

Title: __________________________________

Signature Date __________________________

ATTEST: ______________________________ Witness

Signature Date __________________________

ENTERGY ARKANSAS, LLC By: ___________________________________

Title: __________________________________

Approved: ______________________________

Title: __________________________________

Signature Date __________________________





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Kind of Service: Electric Class of Service: Governmental Agencies Docket No: 18-073-TF Order No.:




13.20.2. AMENDMENT TO FACILITIES AGREEMENT FOR REMOVAL/RELOCATION OF FACILITIES - GOVERNMENTAL

Amendment No. XX To Facilities Agreement - Governmental Dated XXXXXXXXXXX

Pursuant To Additional Facilities Charge Rider (AFCRG) § 53.3 or § 53.4 (For Removal/Relocation of Facilities)

THIS AMENDMENT is made and entered into this XXX day of XXXXXX, XXXX, by and between XXXXXXXXXXXXX (“Customer”) and Entergy Arkansas, LLC (“Company).

A. Company and Customer are parties to a Facilities Agreement dated XXXXXXXXXXX (“Agreement”) in accordance with the provisions of Company’s Additional Facilities Charge Rider - Governmental, Rate Schedule No. 53, (“AFCRG”) whereby Company has installed facilities over and above those which Company would normally install for the Customer’s load and service requirements.

B. Pursuant to the provisions of § 53.3 or § 53.4 of AFCRG, the Customer requests the Amendment of said Agreement to reflect the removal or relocation of existing additional facilities as listed in Attachment A of this Amendment.

C. Company agrees to amend said Agreement and to remove or relocate such existing additional facilities.

D. Customer will pay the Company $XXXXXX, the cost of removing the existing facilities as listed in Attachment A of this Amendment.

E. The original installed cost of the remaining additional facilities shall be determined as the sum of the original installed cost of additional facilities before removals of $XXXXXX less the original installed cost of the additional facilities removed pursuant to this Amendment of $XXXXXX, and shall be the adjusted cost of $XXXXXX. The Customer’s revised monthly charge under AFCRG shall be based on such adjusted cost and shall be calculated by multiplying such adjusted cost by the then current rate per month from AFCRG § 53.3, Option A or the appropriate “Monthly % During Recovery Term” from § 53.4, Option B of AFCRG. Such monthly charge shall then prospectively replace the monthly charge under the Agreement dated XXXXXXXXXX including any and all amendments thereto.

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CUSTOMER NAME

By _____________________________________

Title: ___________________________________

Signature Date:___________________________

ATTEST:_______________________________ Witness


By: _____________________________________

Title: ____________________________________

Approved: _______________________________

Title: ____________________________________

Signature Date:___________________________





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Kind of Service Electric Class of Service: Governmental Agencies Docket No.: 18-073-TF Order No.:




13.20.2.1. ATTACHMENT A TO AMENDMENT TO FACILITIES AGREEMENT FOR REMOVAL/RELOCATION OF FACILITIES - GOVERNMENTAL

Attachment A To Facilities Agreement - Governmental Amendment No._______

Additional Facilities To Be Removed By Company

A. The Company shall remove the following additional facilities (Removals) as requested by the Customer and the Customer shall pay a revised monthly charge based on the revised installed cost determined as the current total original installed cost of the existing additional facilities of $XXXXX less the estimated installed cost of the Removals of $XXXXX. The revised monthly charge shall be calculated based on the revised installed cost using the then current rates from the provisions of § 53.3, Option A. of Rate Schedule No. 53. The revised monthly charge shall become effective XXXXXXXXX and will replace the monthly charge under the contract dated, XXXXXXXXX including any and all amendments thereto.

B. For those additional facilities removed, the Customer shall pay the Company a cancellation payment of $XXXXXX, if required, calculated pursuant to the lesser of parts 1 and 2 of § 53.6 of AFCRG plus any rearrangement costs associated with the removal of facilities.

C. The revised monthly charge shall be further modified and billed prospectively to reflect the remaining installed costs when the actual cost of Removals is available and the balance of this Amendment No. XXX reflecting such actual remaining installed costs shall be completed and signed by the Customer and the Company.

D. The following Additional Facilities shall be removed:

XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX

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CUSTOMER NAME

By: __________________________________

Title: _________________________________

Signature Date_________________________

ATTEST:______________________________ Witness


By: ___________________________________

Title: __________________________________

Approved: _____________________________

Title: __________________________________

Signature Date:__________________________





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Kind of Service: Electric Class of Service: Governmental Agencies Docket No: 18-073-TF Order No.:




13.20.3. AGREEMENT FOR OPERATION AND MAINTENANCE OF CUSTOMER FACILITIES - GOVERNMENTAL

This Agreement is made and entered into this date, XXXXXXXXXXXXXX, by and between XXXXXXXXXXXXXXXXX, ("Customer") and Entergy Arkansas, LLC, (“EAL” or the "Company"):

A. Premise Location

Customer has contracted with the Company for the supply of electric power and energy for the operation of the Customer's XXXXXXXXXXXXXX located at or near XXXXXXXXXXX, Arkansas.

B. Operation and Maintenance (“O&M”) Services

Customer has requested that the Company provide O&M services for the Customer-owned Facilities listed on Attachment A to this Agreement. The Company will provide O&M services as described below:

(1). O&M Service for Distribution Substation Facilities

EAL will inspect and service the Customer-owned substation facilities according to EAL standard practices for similar Company-owned substation facilities. Services provided will include but not necessarily be limited to: a. Emergency O&M services will be performed at the Company’s sole


b. Monthly ground level inspections of all facilities.c. Routine maintenance activities to include filtering transformer oil as

necessary, servicing substation batteries, and testing switches andbreakers. The Customer will receive a written report identifying theservices performed and any problems or needed repairs discovered byservice personnel.

d. Upon the Customer’s notification to the Company of a continuing serviceinterruption at Customer’s facilities, the Company will dispatch servicepersonnel to inspect the Customer’s facilities and determine the source(s)of trouble. The number of trouble cases and availability of Entergyresources will influence response time. If equipment damage is found andthe Company agrees to repair or replace the damaged equipment, theCompany will provide the Customer an estimated cost and schedule for thenecessary repairs.

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e. Equipment refurbishing, repair, and replacement of worn systems are notconsidered routine maintenance activities and are not provided as part ofthis Agreement, however, if the Company agrees, such activities may beperformed by the Company under Service Agreements for SpecificTasks or Activities below.

(2). O & M Service Agreements for Other Distribution Facilities

Company will inspect and service other Customer-owned distribution facilities according to standard practices for Company-owned distribution facilities. Services provided will include but not necessarily be limited to: a. Emergency O&M services will be performed at the Company’s sole


b. Company will perform an annual ground level distribution facilitiesinspection, limited to visual means from ground level, and provide a written report on the condition of the Customer-owned facilities covered by the agreement.

c. Company will tighten hardware found as a result of this annual inspectionand perform minor service work (re-fuse, re-splice overhead services, and photocell and/or bulb replacement) with Customer provided items.

d. Upon the Customer’s notification to the Company of a continuing serviceinterruption at Customer’s facilities, the Company will dispatch service personnel to inspect the Customer’s facilities and determine the source(s) of trouble. The number of trouble cases and availability of EAL resources will influence response time. If equipment damage is found and EAL agrees to repair or replace the damaged equipment, the Company will provide the Customer an estimated cost and schedule for the necessary repairs.

e. Refurbishing, repair, and replacement of poles, conductor, hardware,transformers, switches, capacitor banks, and lighting fixtures are not considered routine maintenance activities and are not provided as part of this service, however, if Company agrees, such activities may be performed under Service Agreements for Specific Tasks or Activities below.

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C. Service Agreements for Specific Tasks or Activities (Job Order Billing)

As described above, this O&M Service Agreement does not provide all possible service and repair activities for Customer-owned distribution facilities or substation facilities. When tasks or activities are in the Company’s sole judgment beyond the scope of routine O&M services, the Customer may request the Company to perform these specific tasks or activities for the Customer. In such cases if the Company agrees to do the work, the Customer will be assessed a charge that fully reimburses Company for the individual tasks or activities. The Customer is under no obligation to have the Company perform such tasks and may choose other vendors to provide such services. A Service Agreement for Specific Tasks or Activities will be required for all such tasks or activities including but not limited to detailed pole ground-line inspections, infrared inspections, and conductor termination cleaning and tightening.

D. Rate Schedules

Company will provide said O&M Services in accordance with AFCRG, and Company's Policy Schedule No. 9, Service Regulations, copies of which are attached hereto and made a part hereof, or such other effective superseding rate schedule(s) and Service Regulations as may be authorized by duly constituted regulatory authority exercising lawful jurisdiction or as may become effective in the manner provided by law. The Customer agrees to promptly pay all charges for such services as provided in said schedule and regulations.

E. Monthly Charges

The monthly charges under AFCRG, § 53.5, Operation and Maintenance of Customer-Owned Facilities (O&M Service) shall be based on the current estimated cost of replacement facilities as shown below. Customer’s monthly payment for O&M Service will be based on an estimated replacement cost of such facilities of XXXXXXXXXXXXXXXXX and will be calculated by multiplying such installed cost by the then current rate per month under § 53.5 of AFCRG.

F. Control and Access to Facilities

The Company shall have exclusive control of and access to said facilities and the Customer will not permit its employees or agents to come in contact with said facilities.

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G. Term

The term of this Agreement, in accordance with AFCRG, Rate Schedule No. 53, shall be from XXXXXXX, XXXX or the date said facilities are first made ready for use, whichever occurs earlier, and for a period of XXX years thereafter. This term shall be automatically extended for successive periods of one year each until terminated by written notice given by one party to the other not more than six months nor less than three months prior to the expiration date of the original term or any anniversary thereof.

H. Ownership of Facilities

Title to all such additional facilities shall remain in the Customer.

I. Other Provisions

Other Provisions to this Agreement are as listed on Attachment B.

J. Approval

This Agreement is contingent upon approval by the Company's President, Vice President or Department Director.

CUSTOMER NAME

By: ____________________________________

Title: ___________________________________

Signature Date: __________________________

ATTEST: _________________________________ Witness


By: ___________________________________

Title: __________________________________

Approved: ______________________________

Title: __________________________________

Signature Date:__________________________





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13.20.3.1. ATTACHMENT A – CUSTOMER FACILITIES SUBJECT TO OPERATION AND MAINTENANCE - GOVERNMENTAL

A. The following facilities owned by the Customer are the subject of O&M services performed by the Company and the Customer shall pay a monthly charge based on the estimated replacement cost of such facilities of $XXXXXXX. The monthly charge shall be calculated using the current rates from the provisions of § 53.5, Operation and Maintenance – Governmental of Customer-Owned Facilities of Rate Schedule No. 53. The monthly charges shall become effective XXXXXXXXXXXXXXX.

B. The Customer Facilities subject to Company O&M services are as follows:

ITEM ESTIMATED REPLACEMENT COST

XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX $XXXXXXXXXXXXX

CUSTOMER NAME

By: ____________________________________

Title: ____________________________________

Signature Date:___________________________

ATTEST:________________________________ Witness


By: _______________________________________

Title: ____________________________________

Approved: ________________________________

Title: ____________________________________

Signature Date:____________________________





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13.20.3.2. ATTACHMENT B - OTHER PROVISIONS TO AGREEMENT FOR OPERATION AND MAINTENANCE OF CUSTOMER FACILITIES - GOVERNMENTAL

A. The following provisions are incorporated into and made a part of the Agreement for Operation and Maintenance of Customer Facilities - Governmental as attached:

XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX

CUSTOMER NAME

By: _____________________________________

Title: __________________________________

Signature Date:__________________________

ATTEST:_______________________________ Witness


By: _____________________________________

Title: ____________________________________

Approved: _______________________________

Title: ____________________________________

Signature Date:____________________________





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13.21.0. AGREEMENT FOR SOLAR ENERGY PURCHASE OPTION

This Agreement is made _______________________, 20____ between ______________________________________ (“Customer”) and Entergy Arkansas, LLC (“Company”), collectively, the Parties.

1) Company currently provides electric service to Customer under Rate Schedule________ at or near (service location) ____________________________________under account number _________________.

2) Customer wishes to participate in the Solar Energy Purchase Option underCompany’s Rate Schedule No. 62 (SEPO). Customer agrees to comply with termsof the rate schedule attached hereto and made a part hereof, or such othersuperseding Schedules as may be authorized by applicable regulatory authorityexercising lawful jurisdiction, or as may become effective in the manner provided bylaw, and Company agrees to provide such offering subject to the terms set forth inSEPO.

3) Customer contracts for SEPO Capacity as described and defined in SEPO62.2 and 62.6 in the amount of ______ kW.

4) The term of this Agreement shall be from ________ 20__, to _______, 20__, or fromthe date service is first made available hereunder and continuing for a period oftwelve (12) months, and shall be automatically extended for successive periods ofone year each until terminated by written notice given by one party to the other notmore than six months nor less than two months prior to the expiration of the originalterm or any anniversary thereof.

5) If Customer discontinues service with EAL, the agreement under SEPO will beterminated except if 1) the Customer is relocating within the EAL service area, 2)initiates service at a new location at the time of discontinuing the original service,and 3) takes service at the new location under the same rate schedule as theoriginal service, then Customer may opt to transfer his SEPO agreement to the newaccount for service.


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6) All other provisions, prices and regulations of EAL’s standard rate scheduleseffective at the time service is provided shall apply and are not modified by thisAgreement.

CUSTOMER

By: ____________________________________

Title: ___________________________________

Signature Date ____________________________

Signature Date ____________________________


By: _____________________________________

Title: ____________________________________

Approved: ________________________________

Title: ____________________________________

Signature Date ____________________________


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Replacing Sheet No.






13.21. AGREEMENT FOR SOLAR ENERGY PURCHASE OPTION

13.21.1 AGREEMENT FOR SOLAR ENERGY PURCHASE OPTION A.


1) Company currently provides electric service to Customer under Rate Schedule________ at or near (service location) ____________________________________under account number _________________.

2) Customer wishes to participate in the Solar Energy Purchase Option underCompany’s Rate Schedule No. 62 (SEPO) Option A. Customer agrees to complywith terms of the rate schedule attached hereto and made a part hereof, or suchother superseding Schedules as may be authorized by applicable regulatoryauthority exercising lawful jurisdiction, or as may become effective in the mannerprovided by law, and Company agrees to provide such offering subject to the termsset forth in SEPO Option A.


4) The term of this Agreement shall be from ________ 20__, to _______, 20__, or fromthe date service is first made available hereunder and continuing for a period oftwelve (12) months, and shall be automatically extended for successive periods ofone year each until terminated by written notice given by one party to the other notmore than six months nor less than two months prior to the expiration of the originalterm or any anniversary thereof.

5) If Customer discontinues service with EAL, the agreement under SEPO Option A.will be terminated except if 1) the Customer is relocating within the EAL servicearea, 2) initiates service at a new location at the time of discontinuing the originalservice, and 3) takes service at the new location under the same rate schedule asthe original service, then Customer may opt to transfer his SEPO agreement to thenew account for service.

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Replacing Sheet No.






6) All other provisions, prices and regulations of EAL’s standard rate scheduleseffective at the time service is provided shall apply and are not modified by thisAgreement.

CUSTOMER

By: ____________________________________

Title: ___________________________________

Signature Date ____________________________

Signature Date ____________________________


By: _____________________________________

Title: ____________________________________

Approved: ________________________________

Title: ____________________________________

Signature Date ____________________________

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13.21. AGREEMENT FOR SOLAR ENERGY PURCHASE OPTION

13.21.2. AGREEMENT FOR SOLAR ENERGY PURCHASE OPTION B.


1) Company currently provides electric service to Customer under Rate Schedule________ at or near (service location) ______________________________ underaccount number _________________Or

2) for multiple accounts, complete Attachment A.

3) In order to have priority eligibility status to be considered for enrollment, Customercertifies that it has a Letter of Intent with the Company dated on or before June 15,2020.

4) Customer wishes to participate in the Solar Energy Purchase Option underCompany’s Rate Schedule No. 62 (“SEPO”) Option B. Customer agrees to complywith terms of the rate schedule attached hereto and made a part hereof, or suchother superseding Schedules as may be authorized by applicable regulatoryauthority exercising lawful jurisdiction, or as may become effective in the mannerprovided by law, and Company agrees to provide such offering subject to the termsset forth in SEPO Option B.


6) The term of this Agreement will begin ________ 20__, or from the date service isfirst made available hereunder and continue for the life of the Purchase PowerAgreement(s) associated with the Designated Resource listed here: Stuttgart Solar,LLC.

7) This Agreement may not be cancelled except in the case where the Customerpermanently discontinues electric service with the Company. In the event that theCustomer has multiple accounts for electric service included on this Agreement andchanges or cancels one or more accounts but not all of the accounts included in thisAgreement, this Agreement will not terminate and will remain in force for theremainder of accounts. The Company reserves the right to periodically review andadjust subscription levels to ensure the Customer’s SEPO energy does not exceedthe energy requirements for the remaining accounts.


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ARKANSAS PUBLIC SERVICE COMMISSION Original Sheet No. P13.21.2.2 Schedule Sheet 2 of 2 Replacing: Sheet No. Entergy Arkansas, LLC Name of Company Kind of Service: Electric Class of Service: As Applicable Docket No.: 19-042-TF Order No.: Part IV. Policy Schedule No. 13 Effective: Title: Contract Forms PSC File Mark Only


8) If the Customer discontinues service with the Company, this Agreement will be terminated and Customer will be ineligible to re-enroll in SEPO Option B, except that Customer may choose to transfer this Agreement to a new account for service if 1) the Customer is relocating within the EAL service area, 2) the Customer initiates service at a new location at the time of discontinuing the original service, and 3) the Customer takes service at the new location under the same rate schedule as the original service. In the event that a SEPO Option B customer elects to transfer a subscription to a new account under these circumstances, the subscription will be adjusted, if appropriate, to reflect the anticipated usage at the new location. In the event of termination, Company will compensate Customer for that account for any uncredited kWh as described in SEPO 62.5.D.

9) All other provisions, prices and regulations of EAL’s standard rate schedules

effective at the time service is provided shall apply and are not modified by this Agreement.

CUSTOMER

By: ____________________________________

Title: ___________________________________

Signature Date ____________________________


By: _____________________________________ Title: ____________________________________ Approved: ________________________________ Signature Date ____________________________


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ARKANSAS PUBLIC SERVICE COMMISSION Original Sheet No. P13.21.2.1.1 Schedule Sheet 1 of 2 Replacing: Sheet No. Entergy Arkansas, LLC Name of Company Kind of Service: Electric Class of Service: As Applicable Docket No.: 19-042-TF Order No.: Part IV. Policy Schedule No. 13 Effective: Title: Contract Forms PSC File Mark Only


13.21.2.1.1. ATTACHMENT A TO AGREEMENT FOR SOLAR ENERGY PURCHASE OPTION B

Account Number* Name on Account

Tax Identification

Number Service Location Rate

Schedule

SEPO Option B

Subscription kW

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15 *Must be Detail Account number if account is on Collective Billing


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ARKANSAS PUBLIC SERVICE COMMISSION Original Sheet No. P13.21.2.1.2 Schedule Sheet 2 of 2 Replacing: Sheet No. Entergy Arkansas, LLC Name of Company Kind of Service: Electric Class of Service: As Applicable Docket No.: 19-042-TF Order No.: Part IV. Policy Schedule No. 13 Effective: Title: Contract Forms PSC File Mark Only


Account Number* Name on Account

Tax Identification

Number Service Location Rate

Schedule

SEPO Option B

Subscription kW

16

17

18

19

20

21

22

23

24

*Must be Detail Account number if account is on Collective Billing Add additional pages for more accounts if necessary.

CUSTOMER

By: ____________________________________

Title: ___________________________________

Signature Date ____________________________


By: _____________________________________ Title: ____________________________________ Approved: ________________________________ Signature Date ____________________________


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EAL Appendix 1 Exhibit 3 Docket No. 18-037-TF Page 2 of 17 ...

Documents

Transcript of EAL Appendix 1 Exhibit 3 Docket No. 18-037-TF Page 2 of 17 ...