BEFORE THE ARKANSAS PUBLIC SERVICE COMMISSION ) ) ) ) SETTLEMENT TESTIMONY MYRA L. TALKINGTON MANAGER, REGULATORY FILINGS ENTERGY SERVICES, INC.

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1 BEFORE THE ARKANSAS PUBLIC SERVICE COMMISSION IN THE MATTER OF THE APPLICATION OF FOR APPROVAL OF CHANGES IN FOR RETAIL ELECTRIC SERVICE SETTLEMENT TESTIMONY OF MYRA L. TALKINGTON MANAGER, REGULATORY FILINGS ENTERGY SERVICES, INC. ON BEHALF OF DECEMBER 31,

2 Entergy Arkansas, Inc. Settlement Testimony of Myra L. Talkington I. INTRODUCTION Q. PLEASE STATE YOUR NAME. A. My name is Myra L. Talkington Q. ARE YOU THE SAME MYRA L. TALKINGTON WHO PREVIOUSLY FILED TESTIMONY IN THIS DOCKET? A. Yes, I am Q. ON WHOSE BEHALF ARE YOU TESTIFYING? A. I am submitting this settlement testimony to the Arkansas Public Service Commission ( APSC or the Commission on behalf of Entergy Arkansas, Inc. ( EAI or the Company Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? A. My testimony supports the Settlement Agreement on behalf of EAI. Specifically, I address the derivation of the revenue deficiency, rate design, and resulting typical bill impacts. My testimony also addresses Rate Schedule No. 44, Formula Rate Plan Rider ( Rider FRP. 19 2

3 Entergy Arkansas, Inc. Settlement Testimony of Myra L. Talkington II. Q REVENUE REQUIREMENT HOW DID THE SETTLING PARTIES ARRIVE AT THE REVENUE DEFICIENCY STIPULATED IN THE SETTLEMENT AGREEMENT? A. The stipulated revenue deficiency, $225,141,542, is based upon Staff s cost-of-service study, which is summarized in the surrebuttal testimony of Karen L. Wheatley and provided as Staff Surrebuttal Exhibit KLW-1. Six adjustments were made to Staff s surrebuttal revenue requirement to arrive at the revenue requirement and resulting revenue deficiency set forth in Attachment No. 1 to the Settlement Agreement Q. PLEASE DESCRIBE THE SIX ADJUSTMENTS. A. The first adjustment was to increase the return on common equity ( ROE from 9.65 percent to 9.75 percent. This adjustment results in an increase to the before tax rate of return on rate base of 0.07 percent, increasing the retail revenue requirement by $3,845,215. The second adjustment increases the amortization period from five years to 10 years for AJ15 Fukushima. As explained in the Direct Testimony of EAI witness Michael A. Krupa, this adjustment includes all incremental operation and maintenance ( O&M costs associated with the Company s compliance with Nuclear Regulatory Commission ( NRC Orders, Nos. EA and EA , and related NRC requests for 22 information at Arkansas Nuclear One ( ANO. 1 The result of the 1 Krupa Direct Testimony at 4-12; See also, Zakrzewski Direct Testimony at 16. 3

4 Entergy Arkansas, Inc. Settlement Testimony of Myra L. Talkington increased amortization period reduces the annual amortization of these costs and decreases the retail revenue requirement by $763,581. The third adjustment increases the amortization period from five years to 10 years for AJ28 ANO Flood Barrier. This adjustment includes all incremental O&M costs associated with the Flood Barrier Restoration 6 project at ANO described by Mr. Krupa in his direct testimony. 2 The result of the increased amortization period reduces the retail revenue requirement by $992,033. The fourth adjustment removes 25 percent of short-term incentive compensation costs, and related payroll taxes, included in Staff s adjustment IS-35 for all plans except the Teamsharing plans. This adjustment reduces the retail revenue requirement by $5,465,884. The fifth adjustment removes $1,563,730 in non-qualified supplemental retirement plan costs from the revenue requirement. This amount is consistent with the sur-surrebuttal testimony of Company witness Jennifer A. Raeder. 3 The sixth and final adjustment reduces the revenue requirement by $3,639,903 to reflect changes in the storm reserve accrual. This adjustment holds the normalized level of the storm reserve accrual at Staff s recommendation of $28,881,440. However, the adjustment 2 Krupa Direct Testimony at 13; See, also, Zakrzewski Direct Testimony at Raeder Sur-Surrebuttal Testimony at

5 Entergy Arkansas, Inc. Settlement Testimony of Myra L. Talkington 1 2 increases the amortization period for the balance in the storm reserve account for settlement purposes Q. HAVE YOU VERIFIED THAT THESE ADJUSTMENTS ARE ACCURATELY REFLECTED IN ATTACHMENT NO. 1 TO THE SETTLEMENT AGREEMENT? A III. Yes, I have. REVENUE DISTRIBUTION AND RATE DESIGN Q. WERE ANY COST ALLOCATION AND/OR RATE DESIGN STIPULATIONS INCLUDED IN THE SETTLEMENT AGREEMENT? A. Yes. The class cost allocation and rate design included in the Settlement Agreement were developed consistent with the results of Staff s surrebuttal cost-of-service study, with the exception of the residential customer charge, which was capped at the system average increase in base rate revenue Q. HAVE YOU REVIEWED THE REVENUE DISTRIBUTION CALCULATIONS INCLUDED IN STAFF S SETTLEMENT TESTIMONY? A. Yes. Prior to filing the Settlement Agreement, I was afforded the opportunity to review Staff witness Matthew S. Klucher s revenue distribution calculations. 5

6 Entergy Arkansas, Inc. Settlement Testimony of Myra L. Talkington Q. DO YOU AGREE WITH MR. KLUCHER S RESULTS? A. Yes. Mr. Klucher s cost allocation is consistent with the results Staff proposed in its surrebuttal cost-of-service study, including mitigation to the Lighting class by allocating the revenue sufficiency in that class to the Residential and Small General Service ( SGS rate classes and then holding the Large General Service ( LGS rate class increase at 85 percent of the system average increase for all rate classes and distributing the remaining surplus to the Residential and SGS Q. PLEASE DESCRIBE THE LGS RATE DESIGN REFLECTED IN THE SETTLEMENT AGREEMENT. A. In designing rates for the LGS rate class, consideration was given to two factors. First, rates had to be designed to recover the LGS rate class revenue requirement. Second, consistent with Act 725 of 2015 (the 15 Act, 4 demand related costs are collected through demand charges subject to taking into consideration the 10 percent mitigation standard contemplated by the Act. To this end, I increased the demand charges for the LGS rate class such that approximately 79 percent of the LGS demand related costs identified within the cost of service study are being recovered through the demand charges for the LGS rate class. This required a larger increase than the class average to the demand charges for each LGS rate schedule and a smaller increase than the class average 4 Ark. Code Ann (f. 6

7 Entergy Arkansas, Inc. Settlement Testimony of Myra L. Talkington to the energy charge components in order to recover the class revenue requirement. Then, in order to ensure that no customers were impacted by much more than 10 percent due to the movement of demand related costs to the demand charges, I took a sample of the lowest load factor customers in each LGS rate schedule and calculated the bill impacts using the above rate design. I have attached the bill impacts for these customers as EAI Settlement Exhibit MLT Q. HAVE YOU PREPARED AN EXHIBIT WHICH DISPLAYS THE RESULTING FROM THE SETTLEMENT RATE DESIGN? A. Yes. EAI Settlement Exhibit MLT-2 attached to my settlement testimony shows both the currently effective base rates and the settlement base rates excluding Lighting rates. The Lighting rates are excluded from the exhibit because there will not be a change to them. 15 7

8 Entergy Arkansas, Inc. Settlement Testimony of Myra L. Talkington 1 IV. RIDER FRP Q. HAVE YOU REVIEWED THE RIDER FRP INCLUDED AS ATTACHMENT NO. 2 TO THE SETTLEMENT AGREEMENT? A. Yes. This version reflects all of the changes to the tariff that were reflected in Staff s Surrebuttal Exhibit DKB-1 and all of the changes stipulated to in the Settlement Agreement V. BILL IMPACTS Q. PLEASE SUMMARIZE THE BILL IMPACTS RESULTING FROM THE SUBSEQUENT RATE DESIGN. A. As shown in EAI Settlement Exhibit MLT-3 attached to my settlement testimony, the average increase in base rates for all customer classes is percent. However, because of the offsetting effects of riders that either reset with base rates or recognize costs/revenues that are not included in base rates, the net average bill effect to all customer classes is 7.62 percent. The residential customer class will see a percent base rate increase with a net 9.54 percent increase to a total bill. A typical residential customer using 1,000 kilowatt hours will see an $8.41 increase to his total monthly bill. This represents an 8.3 percent increase. The SGS customer class will see a percent base rate increase with a net 9.55 percent increase to a total bill. The LGS customer class will see an percent base rate increase with a net 8

9 Entergy Arkansas, Inc. Settlement Testimony of Myra L. Talkington percent increase to a total bill. For the SGS and LGS classes, actual bill impacts will depend on a customer s usage characteristics such as size, usage, and load factor. Lighting customers will actually see a decrease to their total bill. Since the Lighting class base rates are not changing, the total bill will decrease due to the effect of the reduction in rider rates Q. DO YOU SUPPORT THE IMPLEMENTATION OF NEW BASE EFFECTIVE WITH THE FIRST BILLING CYCLE OF APRIL 2016? A. Yes. Although the Settlement Agreement requests an order from the Commission by February 24, 2016, which is 10 months after EAI filed its Application, the Company requests additional time to file compliance tariffs for review by Staff and the Commission prior to implementing new rates. EAI anticipates that this can be accomplished by the first billing cycle of April, which is March 31, However, consistent with the treatment of new rates in EAI s previous rate case in Docket No U, EAI will file, commensurate with new rates taking effect, an Interim Base Rate Surcharge to collect the difference in new rates and current rates for all customers for the time between the effective date for rates in the Commission s order and the first billing cycle for compliance tariffs. In the above scenario, the Interim Base Rate Surcharge will collect a little over 1 month of revenue (February 24 to March 30. The rate for the surcharge will be calculated such that the 9

10 Entergy Arkansas, Inc. Settlement Testimony of Myra L. Talkington 1 2 surcharge is effective commensurate with new rates and billed through the last billing cycle of December 2016, which is December 29, Q. DOES THIS CONCLUDE YOUR SETTLEMENT TESTIMONY? A. Yes, it does. 10

11 CERTIFICATE OF SERVICE I, Laura R. Landreaux, do hereby certify that a copy of the foregoing has been served upon all parties of record by forwarding the same by electronic mail and/or first class mail, postage prepaid, this 31 st day of December, /s/ Laura R. Landreaux Laura R. Landreaux 11

12 BEFORE THE ARKANSAS PUBLIC SERVICE COMMISSION IN THE MATTER OF THE APPLICATION OF FOR APPROVAL OF CHANGES IN FOR RETAIL ELECTRIC SERVICE EAI SETTLEMENT EXHIBIT MLT-1 LGS BILL IMPACT ANALYSIS 12

13 EAI Settlement Exhibit MLT-1 Page 1 of 1 LGS BILL IMPACTS Customer Annual Current Rates Annual Equal Increase Rates % Equal Increase Rates EAI's Proposed Rates % Settlement Rates % Difference - Settlement Rates vs. Equal % Increase LGS #1 $62, $73, % $75, % 5% LGS #2 $105, $124, % $127, % 4% LGS #3 $28, $33, % $34, % 4% LGS #4 $97, $115, % $118, % 4% LGS #5 $51, $61, % $62, % 4% LGSTOU #1 $97, $115, % $127, % 7% LGSTOU #2 $60, $71, % $77, % 6% LGSTOU #3 $68, $81, % $87, % 6% LGSTOU #4 $74, $87, % $95, % 6% LGSTOU #5 $181, $214, % $232, % 6% LPS #1 $1,034, $1,221, % $1,242, % 4% LPS #2 $326, $385, % $391, % 4% LPS #3 $309, $366, % $370, % 4% LPS #4 $372, $439, % $443, % 3% LPS #5 $322, $381, % $384, % 3% LPSTOU #1 $570, $673, % $738, % 1% LPSTOU #2 $453, $535, % $593, % 1% LPSTOU #3 $610, $721, % $794, % 1% LPSTOU #4 $1,328, $1,569, % $1,717, % 1% LPSTOU #5 $902, $1,065, % $1,155, % 1% 13

14 BEFORE THE ARKANSAS PUBLIC SERVICE COMMISSION IN THE MATTER OF THE APPLICATION OF FOR APPROVAL OF CHANGES IN FOR RETAIL ELECTRIC SERVICE EAI SETTLEMENT EXHIBIT MLT-2 SCHEDULE OF SETTLEMENT 14

15 APSC FILED Time: 12/31/ :16:05 AM: Recvd 12/31/ :15:26 EAI AM: Settlement Docket U-Doc. Exhibit MLT Page 1 of 11 SCHEDULE OF SETTLEMENT PRESENT SETTLEMENT Ref. DESCRIPTION Rate $ Rate $ 1.0 GENERAL PURPOSE RESIDENTIAL SERVICE 1.4 NET MONTHLY RATE Customer Charge: $6.96 $8.43 Energy Charge per kwh: June-September 1st 1,500 kwh $ $ All additional kwh $ $ October-May 1st 1,000 kwh $ $ All additional kwh $ $ LOW/LEVEL USE PROVISION Customer Charge: $6.96 $8.43 Energy Charge per kwh: June-September 1st 1,500 kwh $ $ All additional kwh $ $ October-May 1st 1,000 kwh $ $ All additional kwh $ $ Three-Phase Service Charge per Month $2.71 $ OPTIONAL RESIDENTIAL TIME-OF-USE 2.4 NET MONTHLY RATE Customer Charge: $11.29 $13.87 Energy Charge per kwh: On-Peak Hours Use: $ $ Off-Peak Hours Use: $ $ Three-Phase Service Charge per Month $2.71 $ Residential Energy Management Time of Use Customer Charge $6.96 $8.43 Energy Charge per kwh On-Peak Hours $ Mid-Peak Hours $ Off-Peak Hours $ Three-Phase Service Charge per Month $2.71 $ NET METERING ***NO PRICES TO CHANGE*** 15

16 APSC FILED Time: 12/31/ :16:05 AM: Recvd 12/31/ :15:26 EAI AM: Settlement Docket U-Doc. Exhibit MLT Page 2 of 11 SCHEDULE OF SETTLEMENT PRESENT SETTLEMENT Ref. DESCRIPTION Rate $ Rate $ 4.0 SMALL GENERAL SERVICE 4.4 NET MONTHLY RATE Rate Customer Charge: $19.63 $24.35 Demand Charge per kw All kw over 6.0 kw $3.58 $4.44 Energy Charge: 1st 900 kwh plus 150 kwh/kw over 6.0 kw $ $ Additional kwh $ $ Minimum Customer Charge: $19.63 $24.35 Demand Charge per kw Highest kw over 6.0 kw established in the twelve $2.38 $2.95 months ending with the current month: 41.0 Optional Interruptible Service Rider (Optional Monthly Customer Charge $ $ Monthly Minimum Demand Charge per kw $2.90 $ Separately Metered Comm. Space and Water Htg. Rider (Optional Energy Charge per kwh: 1st 1000 kwh $ All additional kwh $ Minimum Charge per month $3.24 $ HIGHLY FLUCTUATING LOAD RIDER 23.3 Demand Charge per kva $0.22 $ Modification of General Service Minimum Rider (Optional Minimum Demand Charge Charge per kva or fraction thereof $1.47 $ VOLTAGE ADJUSTMENT RIDER 18.2 ADJUSTMENT TO NET MONTHLY RATE Service is delivered and metered at 0.0% 0.0% No reductions Service is delivered as secondary voltage but metered at primary voltage: Reduce Demand and Energy losses by: 1.0% 1.0% Service is delivered at primary voltage but metered at secondary voltage and customer owns and maintains all transformation facilities: Reduce Monthly Demand Charge per kw by: $0.97 $1.61 Reduce Daily Demand Charge per kw by: $ $ Service is delivered and metered at primary voltage and customer owns and maintains all transformation facilities: Reduce Demand and Energy for losses by: 1.0% 1.0% Reduce Monthly Demand Charge per kw by: $0.97 $1.61 Reduce Daily Demand Charge per kw by: $ $

17 APSC FILED Time: 12/31/ :16:05 AM: Recvd 12/31/ :15:26 EAI AM: Settlement Docket U-Doc. Exhibit MLT Page 3 of 11 SCHEDULE OF SETTLEMENT PRESENT SETTLEMENT Ref. DESCRIPTION Rate $ Rate $ Service is delivered at transmission voltage but metered at primary voltage: Reduce Demand and Energy for losses by: 1.0% 1.0% Reduce Monthly Demand Charge per kw by: $2.06 $3.43 Reduce Daily Demand Charge per kw by: $ $ Service is delivered and metered at transmission voltage: Reduce Demand and Energy for losses by: 2.0% 2.0% Reduce Monthly Demand Charge per kw by: $2.06 $3.43 Reduce Daily Demand Charge per kw by: $ $ GENERAL FARM SERVICE 5.4 NET MONTHLY RATE Rate Customer Charge: $16.36 $20.29 Demand Charge per kw: All kw over 6.0 kw $3.19 $3.96 Energy Charge per kwh All kwh $ $ Minimum A. Demand Charge per kva or fraction thereof of $1.24 $1.53 transformer capacity installed to serve the customer; or, Three-Phase Service Charge per Month $2.41 $ Separately Metered Comm. Space and Water Htg. Rider (Optional Energy Charge per kwh: 1st 1000 kwh $ $ All additional kwh $ $ Minimum Charge per month $3.24 $ MUNICIPAL PUMPING SERVICE 13.4 NET MONTHLY RATE Rate Charge per installed horsepower: $0.82 $ Minimum Charge per month $26.70 $ AGRICULTURAL PUMPING SERVICE 14.4 SEASONAL RATE (A Rate Energy Charge per kwh: 1st 268 kwh/kw of Billing Load $ $ All additional kwh $ $ Minimum Demand charge per kw of cumulative Billing Load per season: $8.44 $

18 APSC FILED Time: 12/31/ :16:05 AM: Recvd 12/31/ :15:26 EAI AM: Settlement Docket U-Doc. Exhibit MLT Page 4 of 11 SCHEDULE OF SETTLEMENT PRESENT SETTLEMENT Ref. DESCRIPTION Rate $ Rate $ 14.5 OPTIONAL MONTHLY RATE (B Rate Energy Charge per kwh: 1st 402 kwh/kw of Billing Load $ $ All additional kwh $ $ Minimum Demand Charge per kw All kw of Billing Load $4.96 $ COTTON GINNING SERVICE 15.5 SEASONAL RATE Rate Energy Charge per kwh: 1st 268 kwh/kw of Billing Load $ $ All additional kwh $ $ Minimum Demand Charge per kw of Billing Load: October $3.52 $4.37 November $7.04 $8.73 December $10.56 $ COMMUNITY ANTENNA TV POWER SUPPLY SERVICE 16.4 NET MONTHLY RATE Rate Energy Charge per kwh All kwh $ $ Minimum Charge per installation $1.38 $ TRAFFIC SIGNAL SERVICE 11.4 NET MONTHLY RATE Traffic Control Signals Each direction of traffic controlled at each intersection, or point of control, including three lenses per direction controlled: $3.18 $3.94 Each lens in excess of three per direction of traffic controlled at each intersection, or point of control: $0.96 $ Flashing or Warning Signals/Video Surveillance First 100 or less lamp Watts per signal $3.18 $3.94 Each additional 25 or major fraction thereof lamp Watts per signal: $0.49 $0.61 Monthly minimum charge per signal: $3.18 $ LARGE GENERAL SERVICE Rate Customer Charge: $90.53 $90.53 Demand Charge per kw All Summer Period kw $10.64 $13.91 All Other Period kw $9.01 $11.78 Energy Charge per kwh All Summer Period kwh $ $ All Other Period kwh $ $

19 APSC FILED Time: 12/31/ :16:05 AM: Recvd 12/31/ :15:26 EAI AM: Settlement Docket U-Doc. Exhibit MLT Page 5 of 11 SCHEDULE OF SETTLEMENT PRESENT SETTLEMENT Ref. DESCRIPTION Rate $ Rate $ Minimum Customer Charge: $90.53 $90.53 Demand Charge per kw Highest kw established in the twelve months $2.81 $4.68 ending with the current month: 41.0 Optional Interruptible Service Rider (Optional Monthly Customer Charge $ $ Monthly Minimum Demand Charge per kw $2.90 $ VOLTAGE ADJUSTMENT RIDER 18.2 ADJUSTMENT TO NET MONTHLY RATE Service is delivered and metered at 0.0% 0.0% No reductions Service is delivered as secondary voltage but metered at primary voltage: Reduce Demand and Energy losses by: 1.0% 1.0% Service is delivered at primary voltage but metered at secondary voltage and customer owns and maintains all transformation facilities: Reduce Monthly Demand Charge per kw by: $0.97 $1.61 Reduce Daily Demand Charge per kw by: $ $ Service is delivered and metered at primary voltage and customer owns and maintains all transformation facilities: Reduce Demand and Energy for losses by: 1.0% 1.0% Reduce Monthly Demand Charge per kw by: $0.97 $1.61 Reduce Daily Demand Charge per kw by: $ $ Service is delivered at transmission voltage but metered at primary voltage: Reduce Demand and Energy for losses by: 1.0% 1.0% Reduce Monthly Demand Charge per kw by: $2.06 $3.43 Reduce Daily Demand Charge per kw by: $ $ Service is delivered and metered at transmission voltage: Reduce Demand and Energy for losses by: 2.0% 2.0% Reduce Monthly Demand Charge per kw by: $2.06 $3.43 Reduce Daily Demand Charge per kw by: $ $ Separately Metered Comm. Space and Water Htg. Rider (Optional Energy Charge per kwh: 1st 1000 kwh $ $ All additional kwh $ $ Minimum Charge per month $3.24 $ LARGE GENERAL SERVICE TIME-OF-USE Rate Customer Charge: $90.53 $90.53 Demand Charge per kw Summer Period On-Peak kw $14.59 $18.69 All Excess kw $4.30 $5.51 Other Period On-Peak kw $12.30 $15.76 All Excess kw $3.73 $

20 APSC FILED Time: 12/31/ :16:05 AM: Recvd 12/31/ :15:26 EAI AM: Settlement Docket U-Doc. Exhibit MLT Page 6 of 11 SCHEDULE OF SETTLEMENT PRESENT SETTLEMENT Ref. DESCRIPTION Rate $ Rate $ Energy Charge per kwh Summer Period All On-Peak kwh $ $ All Off-Peak kwh $ $ Other Period All On-Peak kwh $ $ All Off-Peak kwh $ $ Minimum Customer Charge $90.53 $90.53 Demand Charge per kw: Highest kw established in the twelve months $2.81 $4.68 ending with the current month 41.0 Optional Interruptible Service Rider (Optional Monthly Customer Charge $ $ Monthly Minimum Demand Charge per kw $2.90 $ VOLTAGE ADJUSTMENT RIDER 18.2 ADJUSTMENT TO NET MONTHLY RATE Service is delivered and metered at 0.0% 0.0% No reductions Service is delivered as secondary voltage but metered at primary voltage: Reduce Demand and Energy losses by: 1.0% 1.0% Service is delivered at primary voltage but metered at secondary voltage and customer owns and maintains all transformation facilities: Reduce Monthly Demand Charge per kw by: $0.97 $1.61 Reduce Daily Demand Charge per kw by: $ $ Service is delivered and metered at primary voltage and customer owns and maintains all transformation facilities: Reduce Demand and Energy for losses by: 1.0% 1.0% Reduce Monthly Demand Charge per kw by: $0.97 $1.61 Reduce Daily Demand Charge per kw by: $ $ Service is delivered at transmission voltage but metered at primary voltage: Reduce Demand and Energy for losses by: 1.0% 1.0% Reduce Monthly Demand Charge per kw by: $2.06 $3.43 Reduce Daily Demand Charge per kw by: $ $ Service is delivered and metered at transmission voltage: Reduce Demand and Energy for losses by: 2.0% 2.0% Reduce Monthly Demand Charge per kw by: $2.06 $3.43 Reduce Daily Demand Charge per kw by: $ $ LARGE POWER SERVICE Rate Customer Charge: $ $ Demand Charge per kw All Summer period kw $10.30 $13.46 All Other period kw $8.66 $11.32 Energy Charge per kw All Summer period kwh $ $ All Other period kwh $ $

21 APSC FILED Time: 12/31/ :16:05 AM: Recvd 12/31/ :15:26 EAI AM: Settlement Docket U-Doc. Exhibit MLT Page 7 of 11 SCHEDULE OF SETTLEMENT PRESENT SETTLEMENT Ref. DESCRIPTION Rate $ Rate $ Minimum Customer Charge: $ $ Demand Charge per kw Highest kw established in the twelve months $2.81 $4.68 ending with the current month 41.0 Optional Interruptible Service Rider (Optional Monthly Customer Charge $ $ Monthly Minimum Demand Charge per kw $2.90 $ VOLTAGE ADJUSTMENT RIDER 18.2 ADJUSTMENT TO NET MONTHLY RATE Service is delivered and metered at 0.0% 0.0% No reductions Service is delivered as secondary voltage but metered at primary voltage: Reduce Demand and Energy losses by: 1.0% 1.0% Service is delivered at primary voltage but metered at secondary voltage and customer owns and maintains all transformation facilities: Reduce Monthly Demand Charge per kw by: $0.97 $1.61 Reduce Daily Demand Charge per kw by: $ $ Service is delivered and metered at primary voltage and customer owns and maintains all transformation facilities: Reduce Demand and Energy for losses by: 1.0% 1.0% Reduce Monthly Demand Charge per kw by: $0.97 $1.61 Reduce Daily Demand Charge per kw by: $ $ Service is delivered at transmission voltage but metered at primary voltage: Reduce Demand and Energy for losses by: 1.0% 1.0% Reduce Monthly Demand Charge per kw by: $2.06 $3.43 Reduce Daily Demand Charge per kw by: $ $ Service is delivered and metered at transmission voltage: Reduce Demand and Energy for losses by: 2.0% 2.0% Reduce Monthly Demand Charge per kw by: $2.06 $3.43 Reduce Daily Demand Charge per kw by: $ $ LARGE POWER SERVICE TIME-OF-USE Rate Customer Charge: $ $ Demand Charge per kw Energy Charge per kwh Summer Period On-Peak kw $15.08 $18.24 All Excess kw $4.42 $5.35 Other Period On-Peak kw $12.70 $15.37 All Excess kw $3.84 $4.65 Summer Period All On-Peak kwh $ $ All Off-Peak kwh $ $ Other Period All On-Peak kwh $ $ All Off-Peak kwh $ $

22 APSC FILED Time: 12/31/ :16:05 AM: Recvd 12/31/ :15:26 EAI AM: Settlement Docket U-Doc. Exhibit MLT Page 8 of 11 SCHEDULE OF SETTLEMENT PRESENT SETTLEMENT Ref. DESCRIPTION Rate $ Rate $ Minimum Customer Charge $ $ Demand Charge per kw: Highest kw established in the twelve months $2.81 $4.68 ending with the current month 41.0 Optional Interruptible Service Rider (Optional Monthly Customer Charge $ $ Monthly Minimum Demand Charge per kw $2.90 $ VOLTAGE ADJUSTMENT RIDER 18.2 ADJUSTMENT TO NET MONTHLY RATE Service is delivered and metered at 0.0% 0.0% No reductions Service is delivered as secondary voltage but metered at primary voltage: Reduce Demand and Energy losses by: 1.0% 1.0% Service is delivered at primary voltage but metered at secondary voltage and customer owns and maintains all transformation facilities: Reduce Monthly Demand Charge per kw by: $0.97 $1.61 Reduce Daily Demand Charge per kw by: $ $ Service is delivered and metered at primary voltage and customer owns and maintains all transformation facilities: Reduce Demand and Energy for losses by: 1.0% 1.0% Reduce Monthly Demand Charge per kw by: $0.97 $1.61 Reduce Daily Demand Charge per kw by: $ $ Service is delivered at transmission voltage but metered at primary voltage: Reduce Demand and Energy for losses by: 1.0% 1.0% Reduce Monthly Demand Charge per kw by: $2.06 $3.43 Reduce Daily Demand Charge per kw by: $ $ Service is delivered and metered at transmission voltage: Reduce Demand and Energy for losses by: 2.0% 2.0% Reduce Monthly Demand Charge per kw by: $2.06 $3.43 Reduce Daily Demand Charge per kw by: $ $ MUNICIPAL STREET LIGHTING SERVICE ****SEE LIGHTING PAGES FOR **** 12.0 MUNICIPAL PUMPING SERVICE ****SEE LIGHTING PAGES FOR **** 17.0 TABLE OF RIDERS APPLICABLE TO RATE SCHEDULES ***NO PRICES TO CHANGE*** 19.0 COLLECTIVE BILLING RIDER ***NO PRICES TO CHANGE*** 22

23 APSC FILED Time: 12/31/ :16:05 AM: Recvd 12/31/ :15:26 EAI AM: Settlement Docket U-Doc. Exhibit MLT Page 9 of 11 SCHEDULE OF SETTLEMENT PRESENT SETTLEMENT Ref. DESCRIPTION Rate $ Rate $ 20.0 STANDBY SERVICE RIDER 20.7 NET MONTHLY RATE Customer Charge Charge per month: $ $ Reservation Charges Rate per kw of Reserved Service Billing Demand: $3.17 $ Maintenance Demand Charges Demand Charge: Summer Period $/kw/day: $ $ Other Period $/kw/day: $ $ Backup Demand Charges Demand Charge: Summer Period $/kw/day: $ $ Other Period $/kw/day: $ $ Maintenance Energy Charges Energy Charge per kwh: Summer Period $ $ Other Period $ $ Backup Energy Charges Energy Charge per kwh: Summer Period $ $ Other Period $ $ MUNICIPAL SHIELDED STREET LIGHTING SERVICE ****SEE LIGHTING PAGES FOR **** 22.0 FIRE AND FLOOD LOADS RIDER ***NO PRICES TO CHANGE*** 24.0 Short Term, Temporary & Intermittent Service Rider (Optional ***NO PRICES TO CHANGE*** 25.0 Seasonal Service Rider (Optional Demand charge per kw for all kw $2.77 $ Additional Facilities Charge Rider 26.3 Option A Monthly Charge 0.870% 0.875% 26.4 Option B Selected Recovery Term % 8.939% Selected Recovery Term % 4.764% Selected Recovery Term % 3.374% Selected Recovery Term % 2.681% Selected Recovery Term % 2.266% Selected Recovery Term % 1.991% Selected Recovery Term % 1.795% Selected Recovery Term % 1.649% Selected Recovery Term % 1.537% Selected Recovery Term % 1.447% Monthly % Post-Recovery Term 0.272% 0.290% 26.5 Monthly O&M Charge customer owned 0.176% 0.199% 23

24 APSC FILED Time: 12/31/ :16:05 AM: Recvd 12/31/ :15:26 EAI AM: Settlement Docket U-Doc. Exhibit MLT Page 10 of 11 SCHEDULE OF SETTLEMENT PRESENT SETTLEMENT Ref. DESCRIPTION Rate $ Rate $ 29.0 Charges Related to Customer Activity (Mandatory ( Electronic Load Data Product Fees kva Analysis Report (Paper $0.00 $0.00 kva Analysis Report ( $6.00 $6.00 kva Peaks Summary Report ( $6.00 $6.00 Load Graph (Paper N/A N/A Time of Use Report (Paper N/A N/A Meter Test Fee Per Occurence $62.00 $ Trip Fee Per Occurence $17.00 $ During Normal Working Hours Reconnected at Customer's Meter $42.00 $42.00 Reconnected at Other $86.00 $ After Normal Working Hours Reconnected at Customer's Meter $62.00 $62.00 Reconnected at Other $ $ Charge for Datalink Subscription Charge Daily Viewing Option $39.50 $39.50 Hourly Viewing Option $ $ Installation of Interval Meter Monthly Payment Option $12.50 $12.50 Single Payment Option $ $ Optional Wireless Communication Link Daily Viewing Option $9.00 $9.00 Hourly Viewing Option $12.00 $12.00 Initial Setup/Activation - Single Payment $15.00 $ Optional Apartment Service Rider ***NO PRICES TO CHANGE*** 31.0 Commercial Space Heating Rider ***NO PRICES TO CHANGE*** 32.0 Economic Development Rider (Optional ***NO PRICES TO CHANGE*** 34.0 Small Cogeneration Rider 34.2 Monthly Customer Charge $19.06 $ Large Cogeneration Rider (Optional 35.2 Monthly Customer Charge $19.06 $ Agricultural Irrigation Load Control Service Rider 36.2 Credit Demand Credit per kw $4.16 $

25 APSC FILED Time: 12/31/ :16:05 AM: Recvd 12/31/ :15:26 EAI AM: Settlement Docket U-Doc. Exhibit MLT Page 11 of 11 SCHEDULE OF SETTLEMENT PRESENT SETTLEMENT Ref. DESCRIPTION Rate $ Rate $ 53.0 Additional Facilities Charge Rider - GOVERNMENTAL 53.3 Option A Monthly Charge 1.393% 1.428% 53.4 Option B Selected Recovery Term % 9.492% Selected Recovery Term % 5.317% Selected Recovery Term % 3.927% Selected Recovery Term % 3.234% Selected Recovery Term % 2.819% Selected Recovery Term % 2.544% Selected Recovery Term % 2.348% Selected Recovery Term % 2.202% Selected Recovery Term % 2.090% Selected Recovery Term % 2.000% Monthly % Post-Recovery Term 0.795% 0.843% 53.5 Monthly O&M Charge customer owned 0.699% 0.752% 41.0 Optional Interruptible Service Rider (Optional Nonfirm demand % reduction for NDCR, GGR & CCR 56.6% 57.2% 25

26 BEFORE THE ARKANSAS PUBLIC SERVICE COMMISSION IN THE MATTER OF THE APPLICATION OF FOR APPROVAL OF CHANGES IN FOR RETAIL ELECTRIC SERVICE EAI SETTLEMENT EXHIBIT MLT-3 RATE CLASS COST-OF-SERVICE SUMMARY 26

27 EAI Settlement Exhibit MLT-3 Page 1 of 1 SETTLEMENT COS SUMMARY PRESENT PROPOSED PROPOSED CHANGES Rate Fuel & Other Total Rate Fuel & Other Total Total Line Schedule Rider Retail Sales Schedule Rider Retail Sales Revenue % Revenues Sales % No. Rate Class Revenue Revenue Revenue Revenue Revenue Revenue Deficiency Increase Increase Increase [a] [b] [c] [d] [e] [f] [g] [h] [i] [j] [k] [l] 1 Residential $ 480,059,410 $ 274,445,881 $ 754,505,291 $ 590,124,997 $ 236,346,093 $ 826,471,090 $ 110,065, % $ 71,965, % 2 SGS $ 267,663,706 $ 159,326,560 $ 426,990,266 $ 330,817,737 $ 136,940,770 $ 467,758,507 $ 63,154, % $ 40,768, % 3 LGS $ 287,167,550 $ 251,639,156 $ 538,806,706 $ 339,089,475 $ 221,021,277 $ 560,110,752 $ 51,921, % $ 21,304, % 4 Lighting $ 23,532,030 $ 9,429,112 $ 32,961,142 $ 23,532,030 $ 9,012,883 $ 32,544,913 $ % $ (416, % 5 Total $ 1,058,422,696 $ 694,840,709 $ 1,753,263,405 $ 1,283,564,238 $ 603,321,023 $ 1,886,885,261 $ 225,141, % $ 133,621, % 27