CNRO-2012-00007, Arkansas Nuclear One, Units 1 & 2, River Bend Station, Grand Gulf Nuclear Station & Waterford 3 Steam Electric Station Status of Decommissioning Funding - Entergy Operations, Inc

Arkansas Nuclear One, Units 1 & 2, River Bend Station, Grand Gulf Nuclear Station & Waterford 3 Steam Electric Station Status of Decommissioning Funding - Entergy Operations, Inc

ML12292A283
Person / Time
Site:
Issue date:	10/15/2012
From:	John McCann Entergy Nuclear Operations, Entergy Operations
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CNRO-2012-00007
Download: ML12292A283 (297)

Text

'En tergy Entergy Operations, Inc Entergy Nuclear Operations, Inc.440 Hamilton Avenue White Plains, NY 10601 Tel 914 272 3370 John F. McCann Vice President

-Nuclear Safety, Emergency Planning and Licensing CNRO-2012-00007 October 15, 2012 U. S. Nuclear Regulatory Commission Attn: Document Control Desk 11555 Rockville Pike Rockville, MD 20852-2738

SUBJECT:

Status of Decommissioning Funding -Entergy Operations, Inc Arkansas Nuclear One, Units 1 & 2 Docket Nos. 50-313 & 50-368 Grand Gulf Nuclear Station Docket No. 50-416 River Bend Station Docket No. 50-458 Waterford 3 Steam Electric Station Docket No. 50-382

References:

1. Entergy letter CNRO-20112-00005, "Application for Order Approving Transfers of Licenses and Conforming License and ESP Amendments," September 27, 2012.2. Entergy letter CNRO-201 1-00001, "Status of Decommissioning Funding for Plants Operated by Entergy Operations, Inc," March 31, 2011.3. NUREG-1307, "Report on Waste Burial Charges," Revision 14, November 2010.4. NRC Regulatory Issue Summary 2001-07, "10 CFR 50.75(f)(1)

Reports on the Status of Decommissioning Funds," Revision 1 dated January 8, 2009.

Dear Sir or Madam:

NRC regulations regarding the reporting of decommissioning funding status requires that for plants involved in mergers or acquisitions, the status report shall be submitted annually instead of at the usual biennial frequency.

On September 27, 2012 Entergy Operations, Inc (Entergy)submitted a license application (Reference

1) to NRC regarding an indirect license transfer involving the subject plants. Entergy has determined that these proposed transactions satisfy the 'mergers or acquisitions' clause of 10 CFR 50.75(f)(1).

Therefore, on behalf of Entergy Arkansas, Inc. for Arkansas Nuclear One (ANO), System Entergy Resources, Inc. (SERI) and South Mississippi Electric Power Association (SMEPA) for CNRO-2012-00007 Page 2 of 4 Grand Gulf Nuclear Station (GGNS), Entergy Gulf States, L.L.C. for River Bend Station (RBS)and Entergy Louisiana, LLC for Waterford 3 Steam Electric Station (WF3), Entergy Operations, Inc. hereby submits the information requested in 10 CFR 50.75(f)(1) for power reactors operated by Entergy for the year ending December 31, 2011. The previous biennial status report (Reference

2) provided the funding status for the year ending December 31, 2010.The estimated minimum decommissioning fund values were determined using the methodology described in NUREG-1307, Revision 14 (Reference

3) and the information provided in Attachments 1 through 4 is based on RIS 2001-07, Revision 1 (Reference 4).Included with this submittal to supplement Attachments 1 through 4 is information consistent with NRC letter dated March 11, 2011 (ML1 10280410).

This information includes certain agreements providing for nuclear plant power sales (that may, from time to time, include decommissioning collections) between Entergy operating companies that invoke Federal Energy Regulatory Commission (FERC) Service Schedule MSS-4 in the FERC-approved Entergy System Agreement or other FERC tariffs. Entergy respectfully asserts that these rate-making tariffs should not be viewed as "contractual obligations" as used in 10 CFR 50.75(e)(1)(v).

These arrangements describe exchanges among regulated utilities that operate within the confines of a FERC-approved tariff, under the ratemaking jurisdiction of the FERC.As such, the various agreements are simply extensions of the FERC tariff and not the type of"contractual obligations" contemplated by 10 CFR 50.75(e)(1)(v), and Entergy's decommissioning funding is still provided by the external sinking fund method in accordance with 10 CFR 50.75(e)(1)(ii).

In an abundance of caution and in a spirit of cooperation, however, Entergy is providing the various tariff agreements for each affected plant. Footnotes associated with Line Item 5 in Attachmentsl through 4 (regarding contracts) further explain the relationships between the current ratepayer decommissioning funding assurance mechanisms and these system instruments.

Although not required by NRC regulations, Entergy is also providing the Minimum Funding Assurance calculation worksheets (Attachment

5) for the subject plants. These worksheets are derived from NRC Office Instruction LIC-205, Revision 4 and are provided to assist the reviewer in understanding the basis for figures reported elsewhere in this filing.This submittal contains no new commitments.

Please address any comments or questions to Mr. Bryan Ford, Senior Manager, Licensing at 601-368-5516.

J b ly, FM Ibsf 7ljs /krk cc: next page CNRO-2012-00007 Page 3 of 4 cc: NRC PM (ANO)NRC PM (GGNS)NRC PM (RBS)NRC PM (WF3)NRC Region IV (w/o att)Arkansas Department of Health Mississippi Department of Health Louisiana Department of Environmental Quality Mr. J. A. Aluise (ENT)Ms. W. C. Curry (ECH)Mr. L. J. Smith (ECH)Mr. B. F. Ford (ECH)

CNRO-2012-00007 Page 4 of 4 Attachments:

1 Entergy Arkansas, Inc. -ANO 1 & 2 Status Reports (2 pages)1-A Entergy Arkansas, Inc. -Calculation of Minimum Amount (1 page)1-B Changes to Trust Agreements, APSC Order in Docket No. 87-166-TF, Order Nos. 50 (19 pages)1-C APSC Order in Docket No. 87-166-TF, Order Nos. 55 (6 pages)1-D ANO Decommissioning Cost Rider NDCR Update and Rate Sch.37 Workpapers (64 pages)1-E Entergy Arkansas, Inc. Unit Power Purchase Agreements under Service Sch MSS-4 (53 pages)2 SERI & SMEPA -GGNS Status Report (1 page)2-A SERI & SMEPA -Calculation of Minimum Amount (1 page)2-B Schedule of Remaining Principle Payments -GGNS (1 page)2-C FERC Order in Docket No. ER95-1042 and Availability Agreement (39 pages)3 Entergy Gulf States Louisiana, LLC RBS Status Report -70% Regulated (1 page)3-A Entergy Gulf States Louisiana, LLC -Calculation of Minimum Amount (1 page)3-B Schedule of Remaining Principle Payments -RBS (1 page)3-C Entergy Gulf States Louisiana, LLC RBS Status Report -30% Non-Regulated (1 page)3-D LPSC Order in Docket No.U-31237 (20 pages)3-E PUCT Order in Docket No. 37744 (16 pages)3-F FERC Order in Docket Nos. ER86-558-002 (9 pages)3-G MSS-4 Agreement and FERC's acceptance (13 pages)4 Entergy Louisiana, LLC -WF3 Status Report (1 page)4-A Entergy Louisiana, LLC -Calculation of Minimum Amount (1 page)4-B Schedule of Remaining Principle Payments -WF3 (1 page)4-C LPSC Order in Docket No. U-31237 (20 pages)4-D CNO Resolution R-95-1081 in Docket UD-95-1 and IRS Schedule of Ruling Amounts (6 pages)5. Minimum Funding Assurance Calculation Worksheets (9 pages)

CNRO-2012-00007 SERIES 1 ATTACHMENTS 1 Entergy Arkansas, Inc. -ANO 1 & 2 Status Reports (2 pages)1-A Entergy Arkansas, Inc. -Calculation of Minimum Amount (1 page)1-B Changes to Trust Agreements, APSC Order in Docket No. 87-166-TF, Order Nos. 50 (19 pages)1-C APSC Order in Docket No. 87-166-TF, Order Nos. 55 (6 pages)1-D ANO Decommissioning Cost Rider NDCR Update and Rate Sch.37 Workpapers (64 pages)1-E Entergy Arkansas, Inc. Unit Power Purchase Agreements under Service Sch MSS-4 (53 pages)

Attachment 1 (2 pages)ENTERGY ARKANSAS, INC.Status Report of Decommissioning Funding For Year Ending December 31,2011 -10 CFR 50.75(f)(1)

Plant Name: Arkansas Nuclear One Unit 1 (ANO 1)1. Minimum Financial Assurance (MFA)Estimated per 10 CFR 50.75(b) and (c) (2011$): 2. Decommissioning Trust Fund Total As of 12/31/11: 3. Annual amounts remaining to be collected:

4. Assumptions used: Rate of Escalation of Decommissioning Costs: Rate of Earnings on Decommissioning Funds: Authority for use of Real Earnings Over 2%: 5. Contracts upon which licensee is relying For Decommissioning Funding: 6. Modifications to Method of Financial Assurance since Last Report: 7. Material Changes to Trust Agreements:

$440.9 million 1$303.9 million$02 Approx. 2.66%3 Approx. 5.78%3 APSC Order 3 See footnote 4 None None 1 See Attachment 1-A 2 Decommissioning funding has been suspended by the Arkansas Public Service Commission in Docket No. 87-166-TF.

The NRC has granted license renewal to 5/2034.Approved in APSC Docket No. 87-166-TF, Order Nos. 50 & 55 -See Attachments 1-B, 1-C and 1 -D.4 See the agreements in Attachment 1-E which are unit power purchase agreements under the MSS-4 Agreement, a FERC tariff. It is the licensee's position that these are not 10 CFR§50.75(e)(1

)(v) "contractual obligations", but rather cost of service tariffs which may appropriately be used to fund the external sinking fund in accordance with 10 CFR§50.75(e)(1

)(ii). Out of abundance of caution, the licensee identifies this information here.

Attachment 1 ENTERGY ARKANSAS, INC.Status Report of Decommissioning Funding For Year Ending December 31, 2011 -10 CFR 50.75(f)(1)

Plant Name: Arkansas Nuclear One Unit 2 (ANO 2)1. Minimum Financial Assurance (MFA)Estimated perlOCFR50.75(b) and (c) (2011$): 2. Decommissioning Fund Total As of 12/31/11: 3. Annual amounts remaining to be collected:

4. Assumptions used: Rate of Escalation of Decommissioning Costs: Rate of Eamings on Decommissioning Funds: Authority for use of Real Earnings Over 2%: 5. Contracts upon which licensee is relying For Decommissioning Funding: 6. Modifications to Method of Financial Assurance since Last Report: 7. Material Changes to Trust Agreements:

$459.1 million 1$237.7 million$o2 Approx. 2.66%3 Approx. 6.06% 3 APSC Order 3 See footnote 4 None None 1 2 3 4 See Attachment 1-A Decommissioning funding has been suspended by the Arkansas Public Service Commission in Docket No. 87-166-TF.

The NRC has granted license renewal to 7/2038.Approved in APSC Docket No. 87-166-TF,Order Nos. 50 & 55, see Attachments 1-B, 1-C and 1 -D.See the agreements in Attachment 1-E which are unit power purchase agreements under the MSS-4 Agreement, a FERC tariff. It is the licensee's position that these are not 10 CFR§50.75(e)(1)(v) "contractual obligations", but rather cost of service tariffs which may appropriately be used to fund the external sinking fund in accordance with 10 CFR§50.75(e)(1)(ii).

Out of abundance of caution, the licensee identifies this information here.

Attachment 1-A (1 page)ENTERGY ARKANSAS, INC.Calculation of Minimum Amount For Year Ending December 31, 2011 -10 CFR 50.75(f)(1)

Entergy Arkansas, Inc.: 100% ownership interest Plant Location:

Russellville, Arkansas Reactor Type: Pressurized Water Reactor ("PWR")ANO Unit 1 Power Level: <3,400 MWt (2,568 MWt)ANO Unit I PWR Base Year 1986$: $97,598,400 ANO Unit 2 Power Level: <3,400 MWt (3,026 MWt)ANO Unit 2 PWR Base Year 1986$: $101,628,800 Labor Region: South Waste Burial Facility:

Generic Disposal Site 10CFR50.75(c)(2)

Escalation Factor Formula: 0.65(L) +0.13(E) +0.22(B)L=Labor (South)E=Energy (PWR)B=Waste Burial-Vendor (PWR)PWR Escalation Factor: 0.65(L) +0.13(E) +0.22(B)=1986 PWR Base Year $ Escalated:

ANOI: $97,598,400

• Factor=Factor 2.281 2.582 12.283 4.51703$440,854,517 ANO2: $101,628,800

• Factor= $459,059.939 Bureau of Labor Statistics, Series Report ID: CIU2010000000220i (4 th Quarter 2011)Bureau of Labor Statistics, Series Report ID: wpu0543 and wpu0573 (December 2011)Nuclear Regulatory Commission:

NUREG-1307 Revision 14, Table 2.1 (2010)1 2 3 Attachment 1-B (19 pages)APSC Order in Docket No. 87-166-TF, Order No. 50 APK

'iF COLWU ARKANSAS PUBLIC SERVICE COMMISSION IN THE MATTER OF ARKANSAS POWER )FLED& LIGHT COMPANY'S PROPOSED ) DOCKET NO. 87-166-TF NUCLEAR DECOMMISSIONING ) ORDER NO. 5o COST RIDER M26 AND PROPOSED )DEPRECIATION RATE RIDER M41 )ORDER On March 31, 2009, Entergy Arkansas, Inc. ("EAI" or "Company")

filed its Motion for Approval of Revised Estimate ofArkwisas Nuclear One Decommissioning Costs and Certain Other Changes to the ANO Decommissioning Tnust Funds ("Motion")

with the supporting Second Supplemental Testimony of EM witness Michael A. Caruso, and the Direct Testimonies and Exhibits of EAM witnesses Rory L. Roberts, Rebecca L. Bowden and William A. Cloutier, Jr. In addition, EM previously filed the Supplemental Testimony and Exhibits of EAM witness Caruso on July 24, 2008, which, pursuant to Order No. 47 in this Docket, had been held in abeyance until such time that EAI filed its revised estimate of the Arkansas Nuclear One ("ANO") Decommissioning Costs.On April 23, 2oo9, the Arkansas Public Service Commission

("APSC" or "the Commission")

issued Order No. 48 in this Docket suspending EAI's Motion and establishing a procedural schedule.

Pursuant to Order No. 48, on July 24, 2oo9, the General Staff of the Commission

("Staff')

filed the Direct Testimony and Exhibits of its witness, Donna Gray, Director of the General Staff Financial Analysis.

On August 24, 2009, EAI filed the Rebuttal Testimonies and Exhibits of EM witnesses Steven K.Sttickland, Albert C. Xing, III, Caruso, Bowden, and Cloutier.

Staff filed the Surrebuttal I Preriously Arkansas Power and Light Company.

Testimony of Staff witness Gray on August 28, 2009. On September 4, 2009, EAT filed the Sur-Surrebuttal Testimony of EAI witness Strickland.

On September 11, 2009, EAI and Staff filed a Joint Motion to Adopt Stipulation of Erntergy Arkansas, Inc. and the General Staff of the Commission

("Joint Motion"), which included, as Attachment A, the Stipulation of Entergy Arkansas, Inc. and the General Staff of the Commission

("Stipulation")

proposing a settlement of all issues related to EAI's March 31, 2oog, Motion. In that Joint Motion, the parties asked that the Commission cancel the hearing set for September 15, 2oo9, and, after it had reviewed and considered the Stipulation, "enter an order approving the Stipulation without a hearing, or, if the Commission desires a hearing to consider the Stipulation or the full merits of the case, that the Commission set a hearing at a later time to accommodate the entry of an order no later than October, 15, 2oo9." (Joint Motion at i, Footnote Omitted).

On September 11, 2oog, the Commission issued Order No. 49 canceling the hearing subject to its being rescheduled by subsequent order.Background In 2007, EAI and the Staff agreed to postpone the 5-year ANO decommissioning cost study that was due to be filed on March 31, 2008, pursuant to Order No. 5 of this Docket Order No. 5 of this Docket provides that, if EAI and the Staff agree, the preparation of a new cost estimate may be deferred.

Order No. 46 directed EAT to continue to monitor ANO decommissioning costs and to notify the Staff when the Company believed that changes in conditions justified that a decommissioning cost study be performed.

On July 24, 2008, EAI filed the Supplemental Testimony and Exhibits of EAI witness Caruso introducing the asset allocation studies, completed by Callan Associates Docket No. 87-166-TF Order No. 5o Page 3 of 12 Inc. ("Callan")

on April io, 2oo8, ("Asset Allocation Studies")2 for the ANO decommissioning trust funds ("Funds")

requesting Commission approval of several proposed changes to the existing investment practices related to the Funds. Mr. Caruso reported that Callan felt it important to point out that, while the Funds are currently well funded, the future funded status is very sensitive to decommissioning cost escalation.

The cost escalation rate used in the studies, as required by ANO Nuclear Decommissioning Cost Rider ("Rider NDCR")3, was the Consumer Price Index -Urban ("CPI-U");

and Callan's estimate of future CPI-U is a 2.75 percent annual increase.

The Asset Allocation Studies pointed out that, if actual annual cost escalation exceeds CPI-U by just I percent for ANO Unit i and by just o.5 percent for ANO Unit 2, the Funds likely will be under-funded at the time of decommissioning.

By its Order No. 47, the Commission directed EM to file a new cost study by March 31, 2009, and held Mr. Caruso's July 24, 2oo8, Supplemental Testimony and Exhibits in abeyance, subject to subsequent Commission order. In compliance with Order 47, EAI filed its updated cost study ("2oo8 Cost Study")4 on March 31, 2oo9, and in its Motion requested certain considerations related to the Funds and Rider NDCR.2Exh. MAC-5 and Mac-6.a Rider NDCR, formerly Rider M26, recovers from ratepayers the expected cost to decommission the two ANO nuclear units. The amounts collected are invested in external trust funds until such time as decommissioning takes place. To calculate the annual recovery under the tariff, Rider NDCR measures the expected future costs to decommission the units compared to the expected future external fund balances available to pay those costs. Since 2ooi, recovery under Rider NDCR has been zero because expected fund balances have exceeded expected costs. (Gray Direct at 4-5).4 (Cloutier Exh. WAC-4).

Docket No. 87-166-TF Order No. 50 Page 4 of 12 2008 Cost Study By its Motion, RAI seeks Commission approval of its 2008 Cost Studys, which indicates expected cost of $1.265 billion in 2oo8 dollars to decommission both ANO Unit i and 2 which includes costs not previously defined as decommissioning costs for purposes of recovery under the tariff. (Motion: at 3-4, Cloutier Direct at 31-33, Cloutier Rebuttal at 5-6, Strickland Rebuttal at 4-5).EAI witness Cloutier explains that such newly-defined costs included post-shutdown spent fuel management

("Spent Fuel") costs and certain site restoration costs not related to removal of decontaminated material ("Site Restoration"). (Cloutier Direct at 31-33). Mr. Cloutier testifies that Spent Fuel costs are heretofore unanticipated costs BAI will now incur to manage spent fuel because the Department of Energy ("DOE") has breached its contract to timely remove that spent fuel. (Cloutier Rebuttal at 6-9). Mr.Cloutier explains that, pursuant to the Nuclear Waste Policy Act of 1982, DOE is required to contract with nuclear generation owners for disposal of high-level nuclear waste for which DOE assesses a fee. (Cloutier Direct at 28). In this regard, Mr. Cloutier further testifies that EAI has such a contract with the DOE under which DOE was to begin removing spent fuel in January 1998 and under which WA] has already paid $295.9 million in fees and remains obligated to pay an additional one-time fee for pre-April 7, 1983, spent fuel removal, currently measured at $180.4 million ("DOE Obligation").(Cloutier Direct at 28, Cloutier Rebuttal at 9). According to Mr. Cloutier, EA1 now estimates the earliest date DOE will commence removal is 202o and that EAT will now incur unexpected costs to manage the spent fuel until removal is complete. (Cloutier Rebuttal at 9).5The 2oo8 Cost Study was performed pursuant to requirements of Order No. 27 issued by the Commission in this Docket and updated to reflect license renewal for both ANO units. (Cloutier Direct at 12-15).

Docket No. 87-166-TF Order No. 5o Page 5 of 12 In support of including these costs, EM 'witness Strickland testifies that, because these costs will be incurred, they "will have to be addressed at some time, whether through the decommissioning funds or other means." Mr. Strickland, however, states that EAI will agree to defer this issue for later Commission determination.

Mr. Strickland testifies that EAI "reserves the right to seek a decision from the Commission on this issue prior to the next required decommissioning cost filing..." and asks that the Commission not foreclose EM's ability to file an interim update if changes in circumstances warrant.(Strickland Rebuttal at 7-8, Strickland Sur-Surrebuttal at 7-8). Mr. Strickland also clarifies EAI's position with regard to its cost escalation factor used in Rider NDCR, stating that EAI was not, in its current Motion, requesting a change to that factor "but believe[d]

it important to inform the Commission that experience is indicating actual decommissioning costs are escalating at a rate higher than the CPI factor...." (Strickland Rebuttal at 16).Staff witness Gray recommends the Commission deny EAI's request to include costs related to Spent Fuel and Site Restoration in the 2008 Cost Study and further recommends the Commission not defer making a finding on this issue. Ms. Gray recommends the Commission approve the 2008 Cost Study in the amount of $1,o49.8 million, exclusive of Spent Fuel and Site Restoration costs. She further recommends that this amount be used in each of the Rider NDCR November 1 filings until the next cost study is due 6.(Gray Direct at 9, Gray Surrebuttal at 6). Ms. Gray testifies that EMA has failed to substantiate the need to expand the scope of decommissioning costs to include Spent Fuel and Site Restoration costs. She notes that such costs are not recognized by the Nuclear Regulatory Commission

("NRC") as decommissioning costs for purposes of the 6 EAI's next cost study will be due March 31, 2014. (Gray Surrebuttal at 6).

Docket No. 87-i66-TF Order No. 50 Page 6 of 12 NRC Status of Decommissioning Funding Report ("NRC Funding Report")7 and that to include such costs "expands...

the scope of this proceeding and significantly lengthens the time frame over which the trust fund balances remain invested." (Gray Direct at 7-9).She concludes that there will be "ample opportunity" to address these costs as additional information becomes available. (rd.).Equity Investment in Funds By its Motion, EM also asks the Commission to approve certain changes in the equity investment currently allowed for the Funds. (Motion at 5-7). EAI witness Caruso testifies that, as recommended in the Asset Allocation Studies prepared by Callan, EAI asks the Commission to approve an increase in the equity allocation targets for the Funds from 50% to 6o%, with a plus or minus 5% rebalancing around that 6o%, and a general broadening of investment in the U. S. stock market for the Funds. (Caruso Supplemental at 11-12, Caruso Second Supplemental at 3-4, Caruso Exh. MAC-5 and MAC-6). EAI witness Bowden testifies that a change to a 60% equity target results in "greater growth" in the Fund balances than presently under the 50% target, estimating the projected balance in the Funds would be $222.4 million more using a 6o% equity target rather than 50%. (Bowden Direct at 7-8).Staff witness Gray testifies that, based on her review of the Asset Allocation Studies, supporting testimony and exhibits of EAI witnesses Caruso and Bowden, and EM response to discovery, EAI has substantiated its requests in this regard. Witness Gray recommends the Commission approve EAI's request for a 6o% equity allocation target with a +/- 5% rebalancing guideline, and its proposed broadening of equity exposure in the Funds. (Gray Direct at 17).7 EAI provides this report to the NRC pursuant to 10 CFR §50.75. (Gray Direct at 8).

Docket No. 87-166-TF Order No. so Page 7 of 12 Transfer, or "Pour-Over", of Non-Tax Qualified Funds toTax-Qualified Funds EM also asks in its Motion that the Commission approve a transfer of all funds currently invested in its Non-Tax Qualified Trust Fund to the Tax-Qualified Trust Funds.8 (Motion at 7-9). EAM witness Roberts testifies that prior limits9 on investment in tax-favorable trust funds have been lifted and that new IRS rules allow, upon IRS approval, a transfer, or "pour-over", of balances held in non-tax qualified funds to tax-qualified funds. (Roberts Direct at 4-6). EM witness Caruso testifies that allowing a pour-over into EAMs Tax-Qualified Funds will provide a benefit through lower taxes for the amounts transferred which will allow the Funds to grow faster than if held in the Non-Tax Qualified Fund. (Caruso Second Supplemental at 7). EAI witness Bowden projects that Fund balances would be $289.3 million greater as a result of the pour-over. (Bowden Direct at 9).Staff witness Gray testifies that the Company has substantiated the economic benefits of the pour-over of the amounts held in the Non-Tax Qualified Fund to the Tax-Qualified Funds and, based on those benefits, Ms. Gray recommends the Commission approve that pour-over. (Gray Direct at 18-19). In addition, Ms. Gray also recommends that EAM be required "to demonstrate in annual filings in this docket the actual net tax benefits for ratepayers, with full explanation of the variations from the annual estimates[EAI witness]...

Roberts determined in EAI Exhibit RLR-2." (Id. at 20).Revocation of Non-TaxOQualified Trust Agreement In conjunction with its approval of the pour-over, EAI asks in its Motion for Commission approval to revoke the currently approved Non-Tax Qualified Trust& Investments in tax-qualified funds enjoy tax bencfits not shared by investments in non-tax qualified funds, including tax deductibility and a lower tax rate applied to earnings. (Roberts Direct at 4).9 Limitations were set by rules under the Internal Revenue Service ("IRS") Code. (Id.).

Docket No. 87-166-TF Order No. 5o Page 8 of 12 Agreement.

The Motion states that the Non-Tax Qualified Trust Agreement will not be needed once the pour-over is complete. (Motion at 9). EAI witness Caruso testifies that the Non-Tax Qualified Trust Agreement is revocable and, pursuant to the Trust Agreement itself and the ANO Decommissioning Trust Fund Guidelines, Commission approval is needed prior to revocation. (Caruso Second Supplemental at 7-8).Responding to this request, Staff witness Gray asserts that revocation of the Non-Tax Qualified Trust Agreement may be premature absent assurance all funds will be approved by IRS to be transferred. (Gray Direct at 19-20). Ms. Gray, therefore, recommends that the Commission either withhold its approval of the revocation or, alternatively, condition Commission approval on EAI receiving IRS authorization to pour-over the full amount. Ms. Gray additionally recommends the Commission require EAI to file in this docket its request for that authorization and the IRS response. (Id.).EM witness Strickland testifies that EA1 agrees with Ms. Gray's recommendation that the Commission condition approval of the revocation on IRS authorization to pour-over the' entire Non-Tax Qualified Fund balance and, additionally, Mr. Stricldand states that EAI will, as Ms. Gray recommends, file its IRS request for that authorization in this docket, as well as the authorization itself. (Strickland Rebuttal at 9).NRC Funding Report and the DOE Obligation In addition to addressing the proposals EAM makes in its Motion, Staff witness Gray makes additional recommendations related respectively to the Funding Report EAI provides the NRC and with the status of EAI's DOE Obligation.

Ms. Gray recommends, first, that FAI be ordered to file in this docket its NRC Funding Reports, beginning with the next report which is due March 31, 2o11, and every two years thereafter or as required by the NRC. (Gray Direct at 8-9, 12).

Docket No. 87-166-TF Order No. 5o Pagc 9 of 12 Ms. Gray additionally recommends that EAM be ordered to proride substantiation that the DOE Obligation funds will be available when payment is due and that ratepayers will be insulated from any adverse impacts from that payment. Ms. Gray advises that ratepayers have provided funding of the DOE Obligation and continue to pay interest on the on-going obligation. (Gray Direct at 12).EAI witness Strickland proposes to work with Staff witness Gray in framing an appropriate analysis to address her recommendations regarding EAI's DOE Obligation and to provide that analysis to the Commission within 9o days after the Commission's order in this docket. (Strickland Sur-Surrebuttal at 4-5).Stipulation By their Joint Motion, Staff and EM propose a Stipulation (Attachment A hereto)to settle all issues addressed in this proceeding and ask that the Commission consider the Stipulation based upon the evidence of record and that the scheduled public hearing be cancelled.

By Order No. 49, issued on September 1i, 20o9, the Commission cancelled the hearing previously set for September 15, 2oog, and took this matter under advisement based upon the pre-filed testimony and exhibits of the parties.1o Further, EAM and Staff request that the Commission issue its final Order in this matter by October 15, 2o09.A summary" of the Stipulation terms follows: e The Commission should approve EAI's nuclear decommissioning cost estimate of $1,049.8 millioni2 for use in the annual November i tariff filings for the years 20o9 through 2013;,0 The only other party to this Docket, the Arkansas Electric Energy Consumers, Inc., has not participated in this specific phase of this Docket."1 This summary is not intended to supplant the actual language of the Stipulation.

2 The amount specifically excludes Spent Fuel costs.

Docket No. 87-166-TF Order No. 50 Page lO Of 12* EM will file its next scheduled nuclear decommissioning cost estimate by March 31, 2o14, unless EAI and Staff agree to an earlier filing;* EAI will not file to recover Spent Fuel costs in any proceeding without first providing Staff a reasonable opportunity to examine the proposal, and giving a good faith consideration of any questions, suggestions, or proposed modifications Staff may recommend;

• For the years 2009 through 2013, EAI will use the Annual CPI-U as the escalation rate in its Rider NDCR annual November 1 filings and, absent a Commission-approved change in the established process and methodology, EAI will continue to use the Annual CP -U as the escalation rate for the years 2014 and thereafter;

• .EAI's customers have provided and continue to provide funding,3 for the DOE Obligation and as a result no other amount is needed from EAI's retail customers;

• If the current DOE Obligation rate treatment14 continues until it is paid, EAM will not seek additional amounts from its retail customers for that obligation, except, as discussed below, for prudent costs incurred to provide the Commission with assurance that payment will be made;0 Within ninety (go) days of this Order, EAT will conduct a comprehensive analysis of the costs and benefits of identified options for providing assurance that funds to pay the DOE Obligation will be available when due and EAI and Staff will work cooperatively to jointly propose a recommendation to the Commission within i8o days;13 Ratepayers have provided this funding through 'the ratemaking treatment established in Order No. i6 in Docket No. U-2972 and in every generial rate case from that point through EAI's most recent rate case in Docket No. o6-ioi-U." (Settlement at 3).,4 (Id.).

Docket No. 87-166-TF Order No. 50 Page 11 of 12* The Commission should approve the "pour-over" as requested by EAI, with EM contributing both the funds in the Non-Tax Qualified Trust Fund and the cash benefit of the resulting tax deduction; 0 EAI will file in this docket both its request to IRS for approval of the pour-over and the IRS response to substantiate that approval;S EAM will demonstrate in annual filings in this docket the actual net tax benefits to ratepayers of the pour-over, with full explanation of variations in actual benefits from those reflected in EAI Exhibit RLR-2;* EAI shall identify the pour-over amounts and the timing thereof in the respective quarterly trust fund reports filed in Docket No. 96-341-U;a The Commission should condition its approval of the revocation of the Non-Tax Qualified Trust Fund on IRS authorization to pour-over the full amount in that fund;* The Commission should approve the change in the equity allocation targets for the Funds from 5o percent to 6o percent, maintaining re-balancing at +/- 5 percent around the 60 percent equity target and approve the broadening of the equity market exposure's in the funds, and;* EAI will file with this Commission the NRC Funding Report beginning with the report due March 31, 2011, and every two years thereafter or at such other interval as the NRC may require.Findings The Commission has considered the proposed Stipulation in conjunction with the parties' filed Testimony and Exhibits and finds that the Stipulation is fully supported by Is The Stipulation states that broadening should be accomplished by "increasing the exposure in the Wilshire 4500 Stock Index Fund, over a reasonable period of time, for both Units so that the ratio of investment in the Wilshire 4500 Stock Index Fund to the total equity in each fund is the same as the Wilshire 4500 Index is to the total U.S. stock market, or about 20 percent." (Stipulation at 5).

Docket No. 87-166-TF Order No. 50 Page 12 of 12 the record, settles all issues addressed herein in a reasonable manner, and is in the public interest.

Accordingly, the Commission hereby approves in its entirety the Stipulation attached hereto as Attachment A. EAI shall fully comply with the terms and conditions set forth in said Stipulation.

BY ORDER OF THE COMMISSION, This ____ of October, 2009.Colette D. Honorable, Commissioner Olan W. Reeves, Commissioner 6 fflceof the Secretary of the Corrmi~ssion I hweb osW OW~ the foot*Kg ordw "aod Vhasbeaosev on all parties of rsw~d eta dtgam%~U S. mail wrih postage prepakid using rBSof each party as indicatead in the Otficlal cdcckot f~itsý wc etar 7 ci Ih C c iss "o ,

Attachment A BEFORE THE ARKANSAS PUBLIC SERVICE COMMISSION IN THE MATTER OF ARKANSAS POWER & )LIGHT COMPANY'S PROPOSED NUCLEAR )DECOMMISSIONING COST RIDER M26 AND ) DOCKET NO. 87-166-TF PROPOSED DEPRECIATION RATE RIDER M41 )STIPULATION OF ENTERGY ARKANSAS, INC.AND THE GENERAL STAFF OF THE COMMISSION This Stipulation is made by Entergy Aikansas Inc. (EAI) and the General Staff of the Arkansas Public Service Commission (Staff). This Stipulation is voluntarily executed and intended to bind EAl and Staff. EA! and Staff believe that this Stipulation is in the public interest and recommend that the Commission approve and adopt it as the basis for concluding this portion of this Docket.On March 31, 2009, EAI filed a Motion for Approval of Revised Estimate of Arkansas Nuclear One (ANO) Decommissioning Costs, along with the supporting Second Supplemental Testimony of Michael A. Caruso, Direct Testimony and Exhibits of Rory L. Roberts, Direct Testimony and Exhibits of Rebecca L. Bowden and Direct Testimony and Exhibits of William A, Cloutier, Jr. EAI had also filed the Supplemental Testimony of Michael A. Caruso on July 24, 2008. Staff filed the Direct Testimony and Exhibits of Donna Gray on July 24, 2009. EAI -iled the Rebuttal Testimony of Steven K.Strickland, Michael A. Caruso, Rebecca L. Bowden, William A. Cloutier, Jr. and Albert C. King, IlI on August 14, 2009. On August 28, 2009, Staff filed the Surrebuttal Testimony of Donna Gray. On September 4, 2009, EAl filed the Sur-Surrebuttal Testimony of Steven K. Strickland.

The testimony filed In this Docket enabled Staff and EA1 to better understand the positions taken and the reasons supporting those positions.

Following their consideration of such testimony, Staff and EAI discussed their respective positions and sought to achieve a resolution of their differences in a manner which each believes serves the public Interest.

Staff and EAI now believe that they have achieved such a resolution and have agreed to urge the Commission to issue an order in this docket that Incorporates that resolution.

In order to resolve the issues in this docket, Staff and EAI have agreed, after discussions and thorough consideration of respective positions, to recommend the following to the Commission.

1. The Commission should approve the Company's nuclear decommissioning cost estimate bf $1,049.8 million, which specifically does not include projections of costs associated with post-shutdown spent fuel management, for use in the annual November I tariff filings for the years 2009 through 2013. EAI agrees its next scheduled nuclear decommissioning cost estimate filing Is due by March 31, 2014, unless EAI and Staff agree to an earlier filing should a significant change in relevant facts and circumstances warrant, which EAI could then propose for Commission consideration.

EAI agrees it will not file to recover projected costs associated with post-shutdown spent fuel management In any proceeding without first presenting its proposed method to Staff, providing Staff a reasonable opportunity to examine the proposal, and giving a good faith consideration of any questions, suggestions, or 2 proposed modifications Staff may recommend.

EAI and Staff agree to work cooperatively to comprehensively Identify the relevant issues and evaluate any need for and possible methods of recovery of projected costs associated with post-shutdown spent fuel management.

2. EAI agrees to use the required Annual CPl -Urban as the escalation rate in its annual November 1 filings for the ANO Decommissioning Cost Rider (Rider NDCR) for the years 2009 through 2013. EAI further agrees to use the Annual CPI -Urban as the escalation rate in its annual November 1 filings for 2014 and thereafter unless the Commission approves a change in the established process and methodology, including Rider NDCR, based upon a comprehensive reassessment

3. EAI acknowledges that its customers have provided and continue to provide funding for EArs obligation to the DOE for the one-time fee assessed for the disposal of spent nuclear fuel consumed prior to April 7, 1983 through the ratemaking treatment established In Order No. 16 in Docket No. U-2972 and In every general rate case from that point through EAI's most recent rate case In Docket No. 06-101-U.

As a result, no other amount Is needed from EAI's retail customers, and EAI will not seek, directly or indirectly, any additional amount from its retail customers for this DOE obligation, If this ratemaking treatment continues until EAI pays the DOE obligation pursuant to the contract between EAI and DOE. The exclusive exception for which EAI's retail ratepayers could be charged any additional amounts would be for the reasonable and prudent cost of a method of assurance developed pursuant to paragraph 4 below and approved by the Commission.

4. EAI agrees to conduct a comprehensive analysis within ninety (90) days 3 of the order approving this Stipulation of the costs and benefits of Identified options for providing assurance that the funds owed DOE and collected from ratepayers since 1985 are readily available when due. EAI and Staff agree to work cooperatively to jointly propose a recommendation to the Commission within 180 days of the order approving this Stipulation.

5. The Commission should approve the Company's requested "special transfer" or "pourover" of the balance from the non-tax qualified trust Into the tax qualified trust balance, with the Company contributing both the funds In the non-tax qualified trust fund and the cash benefit of the tax deduction for the special transfer to the qualified trust fund. EAI agrees to file in this docket its request to the Internal Revenue Service (IRS) and IRS response to substantiate this approval.

EAI agrees to demonstrate in annual firings in ihis docket the actual net tax benefits for ratepayers, with full explanation of variations from the annual estimates in EAI Exhibit RLR-2. The transferred amounts and the timing thereof shall also be Identified in the respective quarterly trust fund reports filed In Docket No. 96-341-U.The Commission should condition its approval of the revocation of the non-tax qualified fund on the IRS's approval of the pourover, and if the IRS approval is for any amount less than the full amount of the fund, the Commission should not allow revocation of the non-tax qualifieAfund.

6. The Commission should approve EAI's request to change the equity allocation targets for the ANO funds from the current 50 percent targets to 60 percent, and to maintain the current re-balancing ranges of +f- 5 percent around the 60 percent equity target. The Commission should also approve EAI's request to broaden the equity 4 market exposure in the funds by Increasing the exposure in the Wilshire 4500 Stock Index Fund, over a reasonable period of time, for both Units so that the ratio of investment in the Wilshire 4500 Stock Index Fund to the total equity in each fund is the same as the Wilshire 4500 Index is to the total U.S. stock market, or about 20 percent.7. EAI agrees to file with this Commission the Nuclear Regulatory Commission (NRC) Status of Decommissioning Funding report required by 10 CFR§50.75 beginning with the next required report due March 31, 2011 and every two years thereafter or at such other interval as the NRC may require.8. Nothing herein shall revise the current obligations of EAI to comply with any requirements previously established in this docket.9. Staff and EAI herby waive the need for a hearing as set forth in Order No.48 in this docket Staff and EAI hereby also agree to waive their respective rights to cross-examine any witness of either party who would have been called at the hearing scheduled In this docket to support the respective positions of Staff or EAI.10. In signing and submitting this Stipulation.

Staff and EAI recommend to the Commission a resolution of the issues in this docket. However, by signing and submitting this Stipulation, neither Staff nor EAI shall be deemed to have approved or acquiesced in any specific methodologies, procedures, calculation techniques, recommendations or conclusions set forth In the testimony of any party or approved in this Stipulation.

Further, none of the provisions in this Stipulation shall constitute an admission by Staff or EAL.11. This Stipulation sfail not have any precedential value in any other proceeding except to the extent necessary to give effect to the terms of this Stipulation, 5

12. In the event that the Commission does not approve and adopt the terms of this Stipulation In Its entirety, this Stipulation shall be void and neither Staff nor EAI shall be bound by any of the agreements or provisions hereof. None of the provisions of this Stipulation shall prejudice, bind, or otherwise affect any party executing this Stipulation should the Commission decide not to approve this Stipulation In its entirety without modification or condition.

13. EAI and Staff agree that this Stipulation is In the public Interest and recommend that the Commission adopt and approve this Stipulation.

Dated this 11 day of September, 2009.Respectfully submitted, General Staff of the Arkansas Public Service Commission By;Valerie F. Boyce Staff General Counsel 1000 Center Street P.O. Box 400 Uttle Rock, AR 72203-0400 (501) 682-5827 Entergy Arkansas, Inc.By: z-' a ZiýS'Jck-e FR; ney .. .Assistant General Counsel Entergy Arkansas, Inc.425 West Capitol P.O. Box 551 Utle Rock, AR 72201 (501) 3774372 6 Attachment 1-C (6 pages)APSC Order in Docket No. 87-166-TF, Order No. 55 AgK PUe,-IC SE"v. COUMA.eaG.CRETApV r" COMM.OnC 13 2 43 'I ARKANSAS PUBLIC SERVICE COMMISSION E)FILED IN THE MATTER OF ARKANSAS POWER & )LIGHT COMPANY'S PROPOSED NUCLEAR ) DOCKET NO. 87-166-TF DECOMMISSIONING COST RIDER M26 ) ORDER NO. 55 AND PROPOSED DEPRECIATION RATE )RIDER M41 )ORDER On November 1, 2o01, Entergy Arkansas, Inc., (EAI or the Company) filed in the above-styled Docket its required annual Arkansas Nuclear One (ANO)Decommissioning Cost Rider NDCR2 (Rider NDCR) update.3 Contemporaneous with the filing of its update EAI also filed the supporting Supplemental Testimony and Exhibits of its witness Rebecca L. Bowden.Attachment 1 to EAI's November 1, 2011, filing is EAI's proposed Revised Attachment A to Rider NDCR (Attachment A). Attachment A contains the ANO decommissioning rate adjustments to be effective from January 1, 2012 through December 31, 2o12; the supporting Revenue Requirement Summary page of the ANO decommissioning model; and a summary of the ANO decommissioning fund balances reflecting a 2o-year life extension for both ANO units. See Order No. 41, Scenario 2.Attachment A reflects that both the ANO decommissioning revenue requirement and the decommissioning rate will remain at the current zero level for 2012.As required by the Stipulation approved by Order No. 50, issued in this Docket U on October 13, 2009, EAI's current update incorporates the approved nuclear decommissioning cost estimate of approximately

$1,049,800,000, excluding Spent Fuel I Formerly Arkansas Power & Light Company.2 Previously known as Rider M26.3 Filed pursuant to Order Nos. 5, 27,32, 41, 45, 46 and 5o of this Docket.

Docket No. 87-166-TF Order No. 55 Page 2 of 5 costs, and the annual Consumer Price Index-Urban as the escalation rate. Also as required by Order No. 50, EM witness Bowden provides, in EAl Exhibit RLB-ii, the actual net tax benefits to ratepayers of the pour-over of the ANO non-tax qualified trust fund balances to the ANO tax qualified trust fund.4 On December 2, 2011, the General Staff of the Commission (Staff) filed the testimony of Staff witness Robert Daniel, Financial Analyst in the Financial Analysis Section, in response to EAI's November 1, 2011, Rider NDCR filing.Rider NDCR Rider NDCR is an exact recovery rider that recovers a levelized (inflation adjusted) revenue requirement necessary to fund the decommissioning trusts for ANO Units i and 2. Rider NDCR rate adjustments are redetermined annually in order to assure that sufficient funds exist to decommission both ANO Units at the end of their operating lives. The rate redetermination requires many inputs, including projected trust fund balances as of December 31 of the filing year, projected trust fund earnings and inflation rates, decommissioning cost estimates and the operating life of each unit.The annual Rider NDCR update is filed on or before November 1 each year with revised rates becoming effective for the first billing cycle of the following January.Addressing the current decommissioning fund balances, EAM witness Bowden testified that the pour-over of the ANO Non-Tax Qualified Trust Fund Balances to the ANO Tax Qualified Trust Fund "was completed in March 2011 ... [and that] ... EAI Exhibit RLB-n contains a schedule comparing the actual pour-over and net tax benefits 4 Pursuant to Order No. 5o, the Commission approved the pour-over and directed EAI to demonstrate in its annual filings the actual net tax benefits to ratepayers of the pour-over, with an explanation of any differences from those estimated in its March 31, 20o9, EM Exhibit RLR-2.

Docket No. 87-166-TF Order No. 55 Page 3 of 5 to the estimate provided in EM Exhibit RLR-2 attached to EAI witness Rory L. Roberts'Direct Testimony filed on March 31, 2oo9 in this docket. The schedule shows the amount of variation between the actual amount of the net tax benefits and the estimated amount. The schedule also provides an explanation of the variation for each line." Bowden Supplemental Testimony at 3-4.Ms. Bowden also testified that "[t]he decommissioning revenue requirement for 2011 is zero because the projected trust fund balances exceed the current escalated decommissioning cost estimate." Id. at 4. Based on the 2011 inputs, Ms. Bowden testified that "once the decommissioning process is complete which is currently estimated to be in 2046, the accumulated excess trust fund balance is estimated to be$570.0 million for Unit 1 and $298.4 million for Unit 2 (combined

$868.4 million)."s Id. Given that the current decommissioning revenue requirement is zero, the kWh rate under Rider NDCR will remain at zero for all rate classes for year 2012.Staff witness Daniel testified that EAI's November 1, 201o, Rider NDCR filing is in compliance with the Commission's directives in this Docket. Daniel Direct Testimony at 4. Mr. Daniel also testified that EAI provided, as required by Order No. 50, the actual net tax benefits as required by Order No. 5o. Mr. Daniel testified that "[a]s referenced on page 3 of Rebecca L. Bowden's Supplemental Testimony, the pour-over was completed in March of 2o11. Exhibit RLB-n identifies that for ANO 1, the tax benefit is$21,787,365 or $292,o6o higher than estimated.

For ANO 2, the tax benefit is$8,733,406 or $111,434 higher than estimated." Id. at 5-5 Pursuant to Orders No. 27 and 29, respectively issued in this Docket on October 3o, 1998 and June 25, 9ggg, any excess trust funds remaining after the decommissioning process has been completed will be refunded to EAI ratepayers.

Docket No. 87-166-TF Order No. 55 Page 4 Of 5 Regarding the adequacy of the ANO decommissioning trust funds, Mr. Daniel testified as follows: As reflected on [EAI's] Attachment 1 .-. the decommissioning trust fund balance for ANO Unit 1 continues to increase annually (from 2011 to 2033)until the current operating license expires in 2034 and decommissioning expenditures begin. Also, the trust fund balance for ANO Unit 2 continues to grow annually (2011 through 2038) until its current operating license expires in 2038 and decommissioning expenditures begin. As shown ..., without any further contributions from ratepayers and after decommissioning expenditures, the over-collection for ANO Units 1 and 2 is projected to be $569,991,00o and $298,416,0oo, respectively, for a total of$8 6 8Ao7,ooo.Id.Mr. Daniel further testified, that "[gliven the adequacy of decommissioning funding at this time, continued suspension

[of Rider NDCR collections) for 2012 is warranted

... [and, therefore,]

... [t]he Commission should approve a continued zero revenue requirement, and ... a continued zero rate for all classes for both ANO Unit 1 and ANO Unit 2 as reflected in attachment A to Rate Schedule No. 37 ... [of EAI's November i, 2o01 Rider NDCR update]. Id. at 7.Findings and Rulings Based upon the information contained in EAI's November 1, 2011, Rider NDCR update filing and the testimony of EAI witness Bowden and Staff witness Daniel, the Commission finds that the continuation of a zero rate for Rider NDCR for 2012 is in the public interest.

Accordingly, the Commission approves an ANO decommissioning revenue requirement of zero for 2012 and approves EAI's Rider NDCR -Attachment A as filed on November 1, 2011.

Docket No. 87-166-TF Order No. 55 Page 5 of 5 BY ORDER OF THE COMMISSION, This 1J3t4day of December, 2011.6U.Olan W. Reeves, Commissioner Elana C. Wills, Commissioner I teeby COWif tha the tcoiloi rder-Wby te AMwS PtSC Sw4IU Oomms~heiflhbW SWd OP S paulim of recod thbs d~af by elmctrci mai. usig to -ri addMS aef h party as in w in hn ot pfw docket file.Secrary of ti Jan Sanders, Secretary of th o6mmis or" Attachment 1-D (64 pages)ANO Decommissioning Cost Rider NDCR Update Rate Schedule No. 37 Workpapers 1 ENTERGY ARKANSAS, INC.II 2011 ANO DECOMMISSIONING COST RIDER NDCR UPDATE RATE SCHEDULE NO. 37 WORKPAPERS I-Entergy RATES EFFECTIVE JANUARY 2012 2 I Revenue Requirements

& Anal -yses<,

ENTERGY ARKANSAS, INC.2011 NUCLEAR DECOMMISSIONING RIDER (RIDER NDCR) UPDATE RATES EFFECTIVE JANUARY 2012 TABLE OF CONTENTS TAB DESCRIPTION A RIDER NDCR RATE DEVELOPMENT B REVENUE REQUIREMENT DEVELOPMENT C FINANCIAL WORKPAPERS D MISCELLANEOUS WORKPAPERS A Rate Development Entergy Arkansas, Inc.ANO Decommissioning Rider NDCR Rate Development For 2012 Line No.1 2 3 4 Rate Class ANO-1 Residential Small General Service Large General Service Lighting.Revenue Requirement 09-084-U ($000) [1]$453,127 232,421 250,660 21,042 Revenue Requirement

($000)0 0 0 0 Billing Units [2]7,831,730,441 kWh 4,555,064,986 kWh 16,567,856 kW 261,109,179 kWh Rate Adjustment 0.00000 $/kWh 0.00000 $/kWh 0.00 $/kW 0.00000 $/kWh 5 Arkansas Retail$957,250 0 [3]N/A N/A 6 7 8 9 ANO-2 Residential Small General Service Large General Service Lighting$453,127 232,421 250,660 21,042 0 0 0 0 7,831,730,441 kWh 4,555,064,986 kWh 16,567,856 kW 261,109,179 kWh 0.00000 S/kWh 0.00000 $/kWh 0.00 $/kW 0.00000 S/kWh 10 Arkansas Retail$957,250 0 [3]N/A N/A 11 12 13 14 Summary Residential Small General Service Large General Service Lighting$453,127 232,421 250,660 21,042 0 0 0 0 7,831,730,441 kWh 4,555,064,986 kWh 16,567,856 kW 261,109,179 kWh 0.00000 $/kWh 0.00000 $/kWh 0.00 $/kW 0.00000 $/kWh 15 Arkansas Retail$957,250 0 [3]N/A N/A Note[1]S: According to Rider NDCR the Arkansas jurisdictional revenue requirement shall be allocated to the same rate classes and in the same proportions as the Arkansas retail revenue requirement in EAI's most recent general rate filing in which a final order has been issued and which has resulted in non-appealable rates. See Workpapers D.1 -D.5 for excerpts from Order No. 20 in Docket No. 09-084-U issued June 23, 2010.See Workpaper D.6.See Workpaper B.1, Line 1.[2][3]A. 1 Entergy Arkansas, Inc.ANO Decommissioning Rider NDCR Wholesale Revenue Requirement and Summary 2012 Wholesale Contribution Line No.Annual Revenue Requirement

($000)Monthly Wholesale Contribution to Trust Funds ($)Rate Class ANO-1 1 Sales For Resale [1]ANO-2 2 Sales For Resale [1]0 0 0 0 Summary 3 Total Sales For Resale 4 Total Arkansas Retail [2]Total Decommissioning 5 Revenue Requirement

[3]0 0 0 0 Notes:[1] Total Revenue Requirement excluding Arkansas Retail.[2] See Workpaper A.1 Line 15.[3] See Workpaper B.1 Line 1.A.2 B Rev Rqmt Dev e Entergy Arkansas, Inc.ANO Decommissioning Model Revenue Requirement Summary ($000)Unit 1 Unit 2 Both Units Unit 1 Line No 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 Total Company [1]0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Arkansas Retail [2]0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Total Company [1]0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Arkansas Retail (2]0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Total Company 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Arkansas Retail [2]0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Notes:[1] See Workpaper B.2 for ANO Unit 1 Summary and B.4 for ANO Unit 2 Summary.[2] Total Company

• Retail Allocation Factor (0.8613).

See Workpaper B.7.B.1 Entergy Arkansas, Inc.ANO Decommissioning Model Unit 1 Summary ($000)Total Company Tax Qualified Trust [2]Line Revenue Net Trust Decomm.No. Year Rqmt. [1] Additions Balance Expend.[3]

1 Beginning Balance 306,406 2 2012 0 17,769 324,175 0 3 2013 0 18,967 343,142 0 4 2014 0 20,855 363,997 0 5 2015 0 23,325 387,322 0 6 2016 0 25,301 412,623 0 7 2017 0 27,040 439,663 0 8 2018 0 28,904 468,567 0 9 2019 0 30,903 499,470 0 10 2020 0 33,097 532,567 0 11 2021 0 35,402 567,969 0 12 2022 0 37,933 605,902 0 13 2023 0 40,593 646,495 0 14 2024 0 43,448 689,942 0 15 2025 0 46,583 736,525 0 16 2026 0 49,958 786,483 0 17 2027 0 53,592 840,076 0 18 2028 0 57,419 897,495 0 19 2029 0 61,716 959,211 0 20 2030 0 66,260 1,025,471 0 21 2031 0 71,156 1,096,627 0 22 2032 0 71,564 1,168,191 0 23 2033 0 66,488 1,234,679 0 24 2034 0 59,886 1,233,132 61,433 25 2035 0 55,017 1,097,872 190,277 26 2036 0 48,980 899,142 247,710 27 2037 0 40,110 772,521 166,730 28 2038 0 34,458 691,981 114,997 29 2039 0 30,863 604,983 117,861 30 2040 0 26,980 598,999 32,965 31 2041 0 26,713 618,015 7,697 32 2042 0 27,562 637,674 7,903.33 2043 0 28,439 658,001 8,112 34 2044 0 29,346 641,638 45,710*35 2045 0 28,616 624,953 45,301 36 2046 0 27,871 569,991 82,833 Notes:[1] The Revenue Requirements are set to zero for every year.[2] See Workpaper B.3[3] See Workpaper B.6 B.2 Entergy Arkansas, Inc.ANO Decommissioning Model Tax Qualified Trust Detail -Unit 1 ($000)Tax Qualified Trust Line No 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 Revenue Earning Transfer Year Rqmt. [1] Rate [2] To Trust [3] [9] Earnings [4]Beginning Balance 2012 0 5.81% 0 18,061 2013 0 5.86% 0 19,275 2014 0 6.08% 0 21,180 2015 0 6.40% 0 23,669 2016 0 6.52% 0 25,665 2017 0 6.54% 0 27,427 2018 0 6.56% 0 29,315 2019 0 6.58% 0 31,339 2020 0 6.61% 0 33,561 2021 0 6.63% 0 35,894 2022 0 6.66% 0 38,457 2023 0 6.68% 0 41,150 2024 0 6.70% 0 44,041 2025 0 6.73% 0 47,214 2026 0 6.76% 0 50,631 2027 0 6.79% 0 54,309 2028 0 6.81%. 0 58,183 2029 0 6.85% 0 62,531 2030 0 6.88% 0 67,129 2031 0 6.91% 0 72,084 2032 0 6.51% 0 72,552 2033 0 5.70% 0 67,536 2034 0 4.88% 0 60,987 2035 0 4.50% 0 56,115 2036 0 4.50% 0 49,960 2037 0 4.50% 0 40,917 2038 0 4.50% 0 35,155 2039 0 4.50% 0 31,489 2040 0 4.50% 0 27,531 2041 0 .4.50% 0 27,258 2042 0 4.50% 0 28,124 2043 0 4.50% 0 29,018 2044 0 4.50% 0 29,943 2045 0 4.50% 0 29,199 2046 0 4.50% 0 28,439 292 308 325 344 364 387 411 436 463 492 524 557 593 631 673 717 764 815 869 928 989 1,048 1,101 1,098 980 807 697 626 551 545 562 579 597 583 568 Mgmt. Net Decomm.Fee [5] Additions

[6] Expend. [7]17,769 18,967 20,855 23,325 25,301 27,040 28,904 30,903 33,097 35,402 37,933 40,593 43,448 46,583 49,958 53,592 57,419 61,716 66,260 71,156 71,564 66,488 59,886 55,017 48,980 40,110 34,458 30,863 26,980 26,713 27,562 28,439 29,346 28,616 27.871 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 61,433 190,277 247,710 166,730 114,997 117,861 32,965 7,697 7,903 8,112 45,710 45,301 82.833 Balance [8]306,406 324,175 343,142 363,997 387,322 412,623 439,663 468,567 499,470 532,567 567,969 605,902 646,495 689,942 736,525 786,483 840,076 897,495 959,211 1,025,471 1,096,627 1,168,191 1,234,679 1,233,132 1,097,872 899,142 772,521 691,981 604,983 598,999 618,015 637,674 658,001 641,638 624,953 569.991 Notes:[1] See Workpaper B.2[2] Projected After Tax Earnings Rates See Workpaper C.1.[3] Revenue Requirement

• (1 -Bad Debt Rate). See Workpaper B.7 for Bad Debt Rate.[4] Prior Year Balance Compounded Semiannually At Current Year Earning Rate + 1/2 Current Year Transfer

• Current Year Earning Rate.[5] Calculated on average balance according to the schedules on Workpaper B.7 multiplied by (1 -TQ Fund Tax Rate).[61 Transfer + Earnings -Management Fee.[7] Assumes that decommissioning expenditures are made at year end.See Workpaper B.6 for the total.[8] Prior Year Balance + Net Additions

-Decommissioning Expenditures.

For Beginning Balance see Workpaper C.4.[9] The percentage to be contributed to the Tax Qualified Trust Fund is 100%.B.3 Entergy Arkansas, Inc.ANO Decommissioning Model Unit 2 Summary ($000)Total Company Tax Qualified Trust [2]Line Revenue Net Trust Decomm.No Year Rqmt. [1] Additions Balance Expend.[3]

1 Beginning Balance 239,972 2 2012 0 13,911 253,883 0 3 2013 0 14,849 268,733 0 4 2014 0 16,328 285,061 0 5 2015 0 18,262 303,322 0 6 2016 0 19,809 323,131 0 7 2017 0 21,170 344,301 0 8 2018 0 22,630 366,931 0 9 2019 0 24,195 391,126 0 10 2020 0 25,913 417,038 0 11 2021 0 27,717 444,756 0 12 2022 0 29,699 474,454 0 13 2023 0 31,781 506,236 0 14 2024 0 34,016 540,252 0 15 2025 0 36,471 576,724 0 16 2026 0 39,114 615,837 0 17 2027 0 41,959 657,796 0.18 2028 0 44,955 702,751 0 19 2029 0 48,320 751,071 0 20 2030 0 51,877 802,948 0 21 2031 0 55,711 858,659 0 22 2032 0 59,578 918,236 0 23 2033 0 63,713 981,949 0 24 2034 0 68,135 1,050,084 0 25 2035 0 72,865 1,122,949 0 26 2036 0 73,282 1,196,231 0 27 2037 0 68,085 1,264,316 0 28 2038 0 61,324 1,282,401 43,239 29 2039 0 57,216 1,196,868 142,750 30 2040 0 53,399 968,406 281,860 31 2041 0 43,201 790,906 220,701 32 2042 0 35,279 669,760 156,425 33 2043 0 29,871 539,064 160,567 34 2044 0 24,038 470,397 92,705 35 2045 0 20,973 413,588 77,781 36 2046 0 18,437 298,416 133,609 Notes: (1] The Revenue Requirements are set to zero for every year.[2] See Workpaper B.5.[3] See Workpaper B.6.B.4 Entergy Arkansas, Inc.ANO Decommissioning Model Tax Qualified Trust Detail -Unit 2 ($000)Tax Qualified Trust Line Revenue Earning Transfer Mgmt. Net Decomm.No Year Rqmt. [1] Rate [2] To Trust [3] [9] Earnings [4] Fee [5] Additions

[6] Expend. [7] Balance [8]1 Beginning Balance 239,972 2 2012 0 5.81% 0 14,145 234 13,911 0 253,883 3 2013 0 5.86% 0 15,096 246 14,849 0 268,733 4 2014 0 6.08% 0 16,587 259 16,328 0 285,061 5 2015 0 6.40% 0 18,536 274 18,262 0 303,322 6 2016 0 6.52% 0 20,099 290 19,809 0 323,131 7 2017 0 6.54% 0 21,478 308 21,170 0 344,301 8 2018 0 6.56% 0 22,957 327 22,630 0 366,931 9 2019 0 6.58% 0 24,541 347 24,195 0 391,126 10 2020 0 6.61% 0 26,281 368 25,913 0 417,038 11 2021 0 6.63% 0 28,108 391 27,717 0 444,756 12 2022 0 6.66% 0 30,114 415 29,699 0 474,454 13 2023 0 6.68% 0 32,223 441 31,781 0 506,236 14 2024 0 6.70% 0 34,486 469 34,016 0 540,252 15 2025 0 6.73% 0 36,971 499 36,471 0 576,724 16 2026 0 6.76% 0 39,645 532 39,114 0 615,837 17 2027 0 6.79% 0 42,525 566 41,959 0 657,796 18 2028 0 6.81% 0 45,559 603 44,955 0 702,751 19 2029 0 6.85% 0 48,963 643 48,320 0 751,071 20 2030 0 6.88% 0 52,562 686 51,877 0 802,948 21 2031 0 6.91% 0 56,442 732 55,711 0 858,659 22 2032 0 6.91% 0 60,358 781 59,578 0 918,236 23 2033 0 6.91% 0 64,546 833 63,713 0 981,949 24 2034 0 6.91% 0 69,025 889 68,135 0 1,050,084 25 2035 0 6.91% 0 73,814 950 72,865 0 1,122,949 26 2036 0 6.51% 0 74,294 1,012 73,282 0 1,196,231 27 2037 0 5.70% 0 69,157 1,072 68,085 0 1,264,316 28 2038 0 4.88% 0 62,451 1,127 61,324 ý43,239 1,282,401 29 2039 0 4.50% 0 58,357 1,141 57,216 142,750 1,196,868 30 2040 0 4.50% 0 54,465 1,066 53,399 281,860 968,406 31 2041 0 4.50% 0 44,069 867 43,201 220,701 790,906 32 2042 0 4.50% 0 35,991 713 35,279 156,425 669,760 33 2043 0 4.50% 0 30,478 607 29,871 160,567 539,064 34 2044 0 4.50% 0 24,531 493 24,038 92,705 470,397 35 2045 0 4.50% 0 21,406 433 20,973 77,781 413,588 36 2046 0 4.50% 0 18,821 384 18,437 133,609 298,416 Notes:[1] See Workpaper B.4.[2] Projected After Tax Earnings Rates See Workpaper CA.[3] Revenue Requirement

• (1 -Bad Debt Rate). See Workpaper B.7 for Bad Debt Rate.[4] Prior Year Balance Compounded Semiannually At Current Year Earning Rate + 1/2 Current Year Transfer

• Current Year Earning Rate.[5] Calculated on average balance according to the schedules in Wqokpaper B.7 multiplied by (1 -TQ Fund Tax Rate).[6] Transfer + Earnings -Management Fee.[7] Assumes that decommissioning expenditures are made at year end.See Workpaper B.6 for the total.[8] Prior Year Balance + Net Additions

-Decommissioning Expenditures.

For Beginning Balance see Workpaper C.4.[9] The percentage to be contributed to the Tax Qualified Trust Fund is 100%.B.5 Entergy Arkansas, Inc.ANO Decommissioning Model CPIU and Decommissioning Expenditures

($000)Decommissioning Expenditures Cumulative Estimate [4] Escalated

[5]Line Cumulative Nuclear Cost No Year CPIU [1] CPIU [2] Escalator

[3] Unit 1 Unit 2 Unit 1 Unit 2-1 2008 2 2009 3 2010 4 2011 5 2012 6 2013 7 2014 8 2015 9 2016 10 2017 1.0215 1.0215 1.0218 1.0225 1.0228 1.0232 1.0237 1.0242 1.0248 1.0253 1.000 1.000 1.000 1.000 1.000 1.023 1.047 1.072 1.099 1.127 1.000 1.022 1.044 1.067 1.091 1.116 1.142 1.170 1.199 1.229 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 11 2018 12 2019 13 2020 14 2021 15 2022 16 2023 17 2024 18 2025 19 2026 20 2027 21 2028 22 2029 23 2030 24 2031 25 2032 26 2033 27 2034 28 2035 29 2036 30 2037 31 2038 32 2039 33 2040 34 2041 35 2042 36 2043 37 2044 38 2045 39 2046 1.0258 1.0262 1.0267 1.0272 1.0277 1.0282 1.0287 1.0293 1.0298 1.0304 1.0310 1.0317 1.0323 1.0330 1.0266 1.0266 1.0266 1.0266 1.0266 1.0266 1.0266 1.0266 1.0266 1.0266 1.0266 1.0266 1.0266 1.0266 1.0266 1.156 1.261 1.186 1.294 1.218 1.329 1.251 1.365 1.286 1.403 1.322 1.443 1.360 1.484 1.400 1.527 1.442 1.573 1.486 1.621 1.532 1.671 1.581 1.724 1.632 1.780 1.686 1.839 1.731 1.888 1.777 1.938 1.824 1.990 1.873 2.043 1.923 2.097 1.974 2.153 2.027 2.210 2.081 2.269 2.136 2.329 2.193 2.391 2.251 2.455 2.311 2.520 2.373 2.587 2.436 2.656 2.501 2.727 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 30,871 93,136 118,126 77,441 52,035 51,944 14,154 3,219 3,219 3,219 17,669 17,056 30,375 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 19,565 62,913 121,022 92,305 63,717 63,717 35,835 29,285 48,995 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 61,433 190,277 247,710 166,730 114,997 117,861 32,965 7,697 7,903 8,112 45,710 45,301 82,833 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 43,239 142,750 281,860 220,701 156,425 160,567 92,705 77,781 133,609 Total Decommissioning Expenditures 512,464 537,354 1,129,528 1,309,637 Notes:[1] See Workpaper C.32 for CPIU for years 2010-2031; the average for 2008 to 2031 is 2.66% and is used for 2032-2046.

[2] Cumulative CPIU from 2012 (Revision Year). Cumulative CPIU (Prior Year) CPIU (Current year).[3] Cumulative CPIU from 2008 (Estimate Year). Cumulative CPIU (Prior Year)

• CPIU (Current year).[4] Decommissioning Cost Estimate (2008 dollars) approved in Docket No. 87-166-TF Order 50.See Workpapers D.7 to D.1 1.[5] Decommissioning Cost Estimate

• Cumulative Nuclear Cost Escalator.

B.6 Entergy Arkansas, Inc.ANO Decommissioning Model Fees and Miscellaneous Input Data ($000)11.700 Fees f11 TQ Annual Fee [1]Trustee Fees TQ Investment Manager 0 20.23 7,100 18.98 14.363 14.363 8,000 18.21 1.708 16.072 10,000 16.96 3.642 19.714 16,000 15.81 10.176 29.890 17,750 13.31 2.767 32.656 20,000 12.15 2.995 35.651 25,000 9.65 6.075 41.726 Miscellaneous Input Data Arkansas Retail Bad Debt Rate [2] 0.5015% Nuclear Cost Escalator

[7] CPIU Revision Year [3] 2012 TQ Fund Federal Tax Rate [8] 20.00%Cost Estimate Year [4] 2008 End Date -ANO 1 5/20/2034 Retail Allocation Factor [5] 0.8613 End Date -ANO 2 7/17/2038 Wholesale Allocation Factor [6] 0.1387 Notes:[1] Investment Manager Fee is calculated as in the following example for a balance of $20 million: TQ Investor Management Fee = 35.651 which is 32.656 + (13.31 bp * (20,000-17,750))

/ 10,000.See Workpaper C.31.[2] Most recent five-year average. See Workpaper D.13.[3] First year showing impact of revised decommissioning revenue requirements.

[4] Year upon which the decommissioning cost estimate is based.[5] Production demand allocator for retail approved in Docket No. 09-084-U.

See Workpaper D.12.[6] Wholesale allocation factor equals 1 minus the Retail Allocation Factor.[7] Nuclear Cost Escalator is based on CPIU. See Workpaper B.6.[8] See Workpaper C.5.B.7 C Financial Workpapers ENTERGY ARKANSAS, INC.NUCLEAR DECOMMISSIONING FUNDS PROJECTED AFTER TAX RETURNS 2011 THROUGH 2046 ANO 1 -Tax Qualified Fund ANO 2 -Tax Qualified Fund ANO 1 -Tax Qualified Fund ANO 2 -Tax Qualified Fund ANO 1 -Tax Qualified Fund ANO 2 -Tax Qualified Fund ANO 1 -Tax Qualified Fund ANO 2 -Tax Qualified Fund 2011 2012 2013 2014 2015 2016 2017 2018 2019 6.04% 5.81% 5.86% 6.08% 6.40% 6.52% 6.54% 6.56% 6.58%6.01% 5.81% 5.86% 6.08% 6.40% 6.52% 6.54% 6.56% 6.58%2020 2021 2022 2023 2024 2025 2026 2027 2028 6.61% 6.63% 6.66% 6.68% 6.70% 6.73% 6.76% 6.79% 6.81%6.61% 6.63% 6.66% 6.68% 6.70% 6.73% 6.76% 6.79% 6.81%2029 2030 2031 2032 2033 2034 2035 2036 2037 6.85% 6.88% 6.91% 6.51% 5.70% 4.88% 4.50% 4.50% 4.50%6.85% 6.88% 6.91% 6.91% 6.91% 6.91% 6.91% 6.51% 5.70%2038 2039 2040 2041 2042 2043 2044 2045 2046 4.50% 4.50% 4.50% 4.50% 4.50% 4.50% 4.50% 4.50% 4.50%4.88% 4.50% 4.50% 4.50% 4.50% 4.50% 4.50% 4.50% 4.50%(')

ENTERGY ARKANSAS, INC.NUCLEAR DECOMMISSIONING FUNDS PROJECTED EARNINGS RATES 2011 THROUGH 2046 INDEX TO SUPPORTING SCHEDULES SCHEDULE:'

Attachment 1 Attachment 2 Attachment 3 Attachment 4 Attachment 5A Attachment 5B Attachment 6 Attachment 7 Attachment 8 Attachment 9 DESCRIPTION:

Portfolio Asset Allocations at June 30, 2011 Projected Portfolio Liquidation Values at December 31, 2011 Income Tax Rates Projected Before Tax Returns Projected After Tax Returns -ANO 1 Tax Qualified Projected After Tax Returns -ANO 2 Tax Qualified Trustee and Investment Manager Fees (Summary)Trustee and Investment Manager Fee Schedules CPIU and Interest Rates -Global Insight Forecasts Inflation Adjusted Total Equity Index and Average Compound Real Returns C.2 Attachment 1 ENTERGY ARKANSAS, INC. NUCLEAR DECOMMISSIONING FUNDS PORTFOLIO ASSET ALLOCATIONS JUNE 30, 2011 (In Thousands)

Description Cash Taxable Bonds -Corporates/Treasuries Municipal Bonds Equities Interest & Dividend Rec.Portfolio Market Value*ANO 1 TAX ANO 2 TAX QUALIFIED QUALIFIED$367 $148$113,937 $84,688$0 $8,437$193,234 $148,253$949 $990$308,487 $242,516* Includes final contributions made in 2010 and 2011 that represent the 2011 and 2012 tax benefit associated with the Non-Qualified Trust pourover in 2010.C.3 Attachment 2 ENTERGY ARKANSAS, INC.NUCLEAR DECOMMISSIONING FUNDS PROJECTED PORTFOLIO LIQUIDATION VALUES DECEMBER 31, 2011 (In Thousands)

ANO 1 Tax Qualified ANO 2 Tax Qualified Portfolio Market Value 6/30/11 (1)Estimated Accrued Taxes and Accrued Fees Estimated Liquidation Value 6/30/11 Estimated Contributions:

July 2011 August 2011 September 2011 October 2011 November 2011 December 2011 Subtotal Estimated after-tax earnings from 7/1/11 through 12/31/11 (2)Before Fee Liquidation Value Trustee/Manager Fees (After-tax)

Estimated 12/31/11 Liquidation Value$308,487$242,516 (10,925)$297,562 0 0 0 0 0 0$297,562 8,987$306,549 (9,433)$233,083 0 0 0 0 0 0$233,083 7,004$240,087 (143)(115)$306,406$239,972 Notes: 1. Includes final contributions made in 2010 and 2011 that represent the 2011 and 2012 tax benefit associated with the Non-Qualified Trust pourover in 2010.2. Estimated after-tax earnings from 7/1/11 through 12/31/11 were calculated using 2011 projected after tax returns on page C.1.C.4 ENTERGY ARKANSAS, INC.NUCLEAR DECOMMISSIONING FUNDS INCOME TAX RATES Attachment 3 TAX QUALIFIED FUNDS: Short Term Investment Funds Interest U.S. Treasury Notes -Interest Corporate Bond Interest Municipal Bond Interest Dividends Capital Gains 20.00%20.00%20.00%0.00%20.00%20.00%Explanation of Income Tax Rates: Tax Qualified Funds: The tax qualified funds are separate taxable entities for income tax purposes and Federal Income Tax Form 1120ND is required for all tax qualified funds. Arkansas state income tax rates do not apply. The trusts are located in Pennsylvania and exempt from Pennsylvania state taxes. Income tax rates reflect the 1992 Energy Policy Act provisions.

According to the Internal Revenue Code, as amended, qualified trust income is not subject to Alternative Minimum Tax.C.5 Attachment 4 ENTERGY ARKANSAS, INC. Page 1 of 3 NUCLEAR DECOMMISSIONING FUNDS PROJECTED BEFORE TAX RETURNS DESCRIPTION SHORT TERM RATE: Federal Funds Rate (1)Treasury Note, 2 -Year (1)MUNICIPAL BOND RATE: Bond Buyer 20 Municipals (1)TAXABLE BOND RATE: Moody's Corporate Composite (4)Moody's Aaa Corporate Bond (1)Moody's Baa Corporate Bond (1)EQUITY RETURN: Consumer Price Index -Urban (1)Percent Equities Historically Outperform CPIU (2)Total Equity Return Dividend Component (3)Capital Gain Component 2010 2011 2012 2013 2014 2015 2016 2017 2018 0.18% 0.11% 0.10% 0.11% 1.23% 3.27% 4.00% 4.00% 4.00%0.70% 0.44% 0.33% 0.52% 1.96% 3.76% 4.12% 4.12% 4.12%4.29% 4.55% 4.32% 4.48% 4.84% 5.49% 5.70% 5.70% 5.70%5.49% 5.23% 5.01% 5.14% 5.71% 6.54% 6.80% 6.80% 6.80%4.94% 4.78% 4.53% 4.60% 5.13% 5.96% 6.22% 6.22% 6.22%6.04% 5.68% 5.49% 5.68% 6.29% 7.12% 7.38% 7.38% 7.38%2.18% 2.25% 2.28% 2.32% 2.37% 2.42% 2.48% 2.53% 2.58%6.68% 6.68% 6.68% 6.68% 6.68% 6.68% 6.68% 6.68% 6.68%8.86% 8.93% 8.96% 9.00% 9.05% 9.10% 9.16% 9.21% 9.26%2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10%6.76% 6.83% 6.86% 6.90% 6.95% 7.00% 7.06% 7.11% 7.16%NOTES: 1. See Attachment 8 -Global Insight Forecasts 2. See Attachment 9 -Inflation Adjusted Total Equity Index and Average Compound Real Returns 3. Agrees with dividend assumptions in Callan 2008 asset allocation study for ANO 4. Average of Moody's Aaa & Baa Corporates

5. All years after 2031 are assumed to have the same before tax returns as 2031.C-)

Attachment 4 ENTERGY ARKANSAS, INC. Page 2 of 3 NUCLEAR DECOMMISSIONING FUNDS PROJECTED BEFORE TAX RETURNS DESCRIPTION SHORT TERM RATE: Federal Funds Rate (1)Treasury Note, 2 -Year (1)MUNICIPAL BOND RATE: Bond Buyer 20 Municipals (1)TAXABLE BOND RATE: Moody's Corporate Composite (4)Moody's Aaa Corporate Bond (1)Moody's Baa Corporate Bond (1)EQUITY RETURN: Consumer Price Index -Urban (1)Percent Equities Historically Outperform CPIU (2)Total Equity Return Dividend Component (3)Capital Gain Component 2019 2020 2021 2022 2023 2024 2025 2026 2027 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00%4.12% 4.12% 4.12% 4.12% 4.12% 4.12% 4.12% 4.12% 4.12%5.70% 5.70% 5.70% 5.70% 5.70% 5.70% 5.70% 5.70% 5.70%6.80% 6.80% 6.80% 6.80% 6.80% 6.80% 6.80% 6.80% 6.80%6.22% 6.22% 6.22% 6.22% 6.22% 6.22% 6.22% 6.22% 6.22%7.38% 7.38% 7.38% 7.38% 7.38% 7.38% 7.38% 7.38% 7.38%2.62% 2.67% 2.72% 2.77% 2.82% 2.87% 2.93% 2.98% 3.04%6.68% 6.68% 6.68% 6.68% 6.68% 6.68% 6.68% 6.68% 6.68%9.30% 9.35% 9.40% 9.45% 9.50% 9.55% 9.61% 9.66% 9.72%2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10%7.20% 7.25% 7.30% 7.35% 7.40% 7.45% 7.51% 7.56% 7.62%NOTES: 1. See Attachment 8 -Global Insight Forecasts 2. See Attachment 9 -Inflation Adjusted Total Equity Index and Average Compound Real Retums 3. Agrees with dividend assumptions in Callan 2008 asset allocation study for ANO 4. Average of Moody's Aaa & Baa Corporates

5. All years after 2031 are assumed to have the same before tax returns as 2031.0 Attachment 4 ENTERGY ARKANSAS, INC. Page 3 of 3 NUCLEAR DECOMMISSIONING FUNDS PROJECTED BEFORE TAX RETURNS DESCRIPTION SHORT TERM RATE: Federal Funds Rate (1)Treasury Note, 2 -Year (1)MUNICIPAL BOND RATE: Bond Buyer 20 Municipals (1)TAXABLE BOND RATE: Moody's Corporate Composite (4)Moody's Aaa Corporate Bond (1)Moody's Baa Corporate Bond (1)EQUITY RETURN: Consumer Price Index- Urban (1)Percent Equities Historically Outperform CPIU (2)Total Equity Return Dividend Component (3)Capital Gain Component 2028 2029 2030 2031 4.00% 4.00% 4.00% 4.00%4.12% 4.12% 4.12% 4.12%5.70% 5.70% 5.70% 5.70%6.80%. 6.80% 6.80% 6.80%6.22% 6.22% 6.22% 6.22%7.38% 7.38% 7.38% 7.38%3.10% 3.17% 3.23% 3.30%6.68% 6.68% 6.68% 6.68%9.78% 9.85% 9.91% 9.98%2.10% 2.10% 2.10% 2.10%7.68% 7.75% 7.81% 7.88%NOTES: 1. See Attachment 8 -Global Insight Forecasts 2. See Attachment 9 -Inflation Adjusted Total Equity Index and Average Compound Real Returns 3. Agrees with dividend assumptions in Callan 2008 asset allocation study for ANO 4. Average of Moody's Aaa & Baa Corporates

5. All years after 2031 are assumed to have the same before tax returns as 2031.C)bo

• ENTERGY ARKANSAS, INC. Attachment 5A NUCLEAR DECOMMISSIONING FUNDS Page 1 of 10 PROJECTED AFTER TAX RETURNS ANO 1 TAX QUALIFIED TRUST (2011-2046) 2011 2012 Market 2011 2011 Weighted 2012 2012 2012 Weighted Value Before Tax After Tax After Tax Estimated Before Tax After Tax After Tax 6/30/2011 Portfolio

% Return Return Return Portfolio

% Return Return Return (000's)Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds/(Corporate Composite)

$367 0.12% 0.11% 0.09% 0.00% 2.50% 0.10% 0.08% 0.00%$0 0.00% 0.44% 0.35% 0.00% 0.00% 0.33% 0.26% 0.00%$0 0.00% 4.55% 4.55% 0.00% 0.00% 4.32% 4.32% 0.00%$113,937 37.05% 5.23% 4.18% 1.55% 37.50% 5.01% 4.01% 1.50%Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return$193,234 62.83%60.00%6.83% 5.46% 3.43%2.10% 1.68% 1.06%8.93% 7.14% 4.49%6.86% 5.49% 3.29%2.10% 1.68% 1.01%8.96% 7.17% 4.30%Subtotal$307,538 100.00%100.00%Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. After Tax Return = Before Tax Return*(1 -tax rate)2. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)3. Weighted After Tax Return = (After Tax Retum*Portfolio

%)4. Portfolio percentages:

2013 to 2031 = 2012 5. Assume receivables are invested at same ratio as current funds 0$949$308,487 6.04%5.81%

ENTERGY ARKANSAS, INC. Attachment 5A NUCLEAR DECOMMISSIONING FUNDS Page 2 of 10 PROJECTED AFTER TAX RETURNS ANO 1 TAX QUALIFIED TRUST (2011-2046) 2013 2014 2013 2013 2013 Weighted 2014 2014 Weighted Estimated Before Tax After Tax After Tax Before Tax After Tax After Tax Portfolio

% Return Return Return Return Return Return 2015 2015 Before Tax After Tax Return Return Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds/(Corporate Composite) 2.50% 0.11% 0.09% 0.00% 1.23% 0.98% 0.02% 3.27% 2.62%0.00% 0.52% 0.42% 0.00% 1.96% 1.57% 0.00% 3.76% 3.01%0.00% 4.48% 4.48% 0.00% 4.84% 4.84% 0.00% 5.49% 5.49%37.50% 5.14%4.11% 1.54% 5.71% 4.57% 1.71% 6.54% 5.23%Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return Subtotal 60.00%6.90% 5.52% 3.31% 6.95% 5.56% 3.34%2.10% 1.68% 1.01% 2.10% 1.68% 1.01%9.00% 7.20% 4.32% 9.05% 7.24% 4.34%7.00% 5.60%2.10% 1.68%9.10% 7.28%100.00%Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. After Tax Return = Before Tax Retum*(1-tax rate)2. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)3. Weighted After Tax Return = (After Tax Retum*Portfolio

%)4. Portfolio percentages:

2013 to 2031 = 2012 5. Assume receivables are invested at same ratio as current funds C)5.86%6.08%

ENTERGY ARKANSAS, INC. Attachment 5A NUCLEAR DECOMMISSIONING FUNDS Page 3 of 10 PROJECTED AFTER TAX RETURNS ANO 1 TAX QUALIFIED TRUST (2011-2046) 2015 Weighted After Tax Return 2016 Before Tax Return 2016 2017 2016 Weighted 2017 2017 Weighted After Tax After Tax Before Tax After Tax After Tax Return Return Return Return Return 2018 2018 Before Tax After Tax Return Return Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds/(Corporate Composite)

Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 0.07% 4.00% 3.20% 0.08% 4.00% 3.20% 0.08% 4.00% 3.20%0.00% 4.12% 3.30% 0.00% 4.12% 3.30% 0.00% 4.12% 3.30%0.00% 5.70% 5.70% 0.00% 5.70% 5.70% 0.00% 5.70% 5.70%1.96% 6.80% 5.44% 2.04% 6.80% 5.44% 2.04% 6.80% 5.44%3.36% 7.06% 5.65% 3.39% 7.11% 5.69% 3.41% 7.16% 5.73%1.01% 2.10% 1.68% 1.01% 2.10% 1.68% 1.01% 2.10% 1.68%4.37% 9.16% 7.33% 4.40% 9.21% 7.37% 4.42% 9.26% 7.41%Subtotal Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. After Tax Return = Before Tax Return*(1-tax rate)2. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)3. Weighted After Tax Return = (After Tax Retum*Portfolio

%)4. Portfolio percentages:

2013 to 2031 = 2012 5. Assume receivables are invested at same ratio as current funds 03 6.40%6.52%6.54%

ENTERGY ARKANSAS, INC. Attachment 5A NUCLEAR DECOMMISSIONING FUNDS Page 4 of 10 PROJECTED AFTER TAX RETURNS ANO I TAX QUALIFIED TRUST (2011-2046) 2018 Weighted After Tax Return 2019 2020.201.9 2019 Before Tax After Tax.Return Return Weighted 2020 2020 Weighted 2021 2021 After Tax Before Tax After Tax After Tax Before Tax After Tax Return Return Return Return Return Return Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds/(Corporate Composite) 0.08% 4.00% 3.20% 0.08% 4.00% 3.20% 0.08% 4.00% 3.20%0.00% 4.12% 3.30% 0.00% 4.12% 3.30% 0.00% 4.12% 3.30%0.00% 5.70% 5.70% 0.00% 5.70% 5.70% 0.00% 5.70% 5.70%2.04% 6.80% 5.44% 2.04% 6.80% 5.44% 2.04% 6.80% 5.44%Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 3.44% 7.20% 5.76%1.01% 2.10% 1.68%4.44% 9.30% 7.44%3.46% 7.25% 5.80% 3.48% 7.30%1.01% 2.10% 1.68% 1.01% 2.10%4.46% 9.35% 7.48% 4.49% 9.40%5.84%1.68%7.52%Subtotal Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. After Tax Return = Before Tax Return*(1-tax rate)2. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)3. Weighted After Tax Return = (After Tax Retum*Portfolio

%)4. Portfolio percentages:

2013 to 2031 = 2012 5. Assume receivables are invested at same ratio as current funds P 6.56%6.58%6.61%

ENTERGY ARKANSAS, INC. Attachment 5A NUCLEAR DECOMMISSIONING FUNDS Page 5 of 10 PROJECTED AFTER TAX RETURNS ANO I TAX QUALIFIED TRUST (2011-2046) 2021 Weighted After Tax Return 2022 2023 2022 2022 Weighted 2023 2023 Weighted 2024 2024 Before Tax After Tax After Tax Before Tax After Tax After Tax Before Tax After Tax Return Return Return Return Return Return Return Return Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds/(Corporate Composite)

Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 0.08% 4.00% 3.20% 0.08% 4.00% 3.20% 0.08% 4.00% 3.20%0.00% 4.12% 3.30% 0.00% 4.12% 3.30% 0.00% 4.12% 3.30%0.00% 5.70% 5.70% 0.00% 5.70% 5.70% 0.00% 5.70% 5.70%2.04% 6.80% 5.44% 2.04% 6.80% 5.44% 2.04% 6.80% 5.44%3.50% 7.35% 5.88% 3.53% 7.40% 5.92% 3.55% 7.45% 5.96%1.01% 2.10% 1.68% 1.01% 2.10% 1.68% 1.01% 2.10% 1.68%4.51% 9.45% 7.56% 4.54% 9.50% 7.60% 4.56% 9.55% 7.64%Subtotal Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. After Tax Return = Before Tax Return*(1-tax rate)2. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)3. Weighted After Tax Return = (After Tax Retum*Portfolio

%)4. Portfolio percentages:

2013 to 2031 = 2012 5. Assume receivables are invested at same ratio as current funds 0 L.6.63%6.66%6.68%

ENTERGY ARKANSAS, INC. Attachment 5A NUCLEAR DECOMMISSIONING FUNDS Page 6 of 10 PROJECTED AFTER TAX RETURNS ANO 1 TAX QUALIFIED TRUST (2011-2046) 2024 Weighted After Tax Return 2025 Before Tax Return 2025 2026 2025 Weighted 2026 2026 Weighted 2027 2027 After Tax After Tax Before Tax After Tax After Tax Before Tax After Tax Return Return Return Return Return Return Return Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds/(Corporate Composite) 0.08% 4.00% 3.20% 0.08% 4.00% 3.20% 0.08% 4.00% 3.20%0.00% 4.12% 3.30% 0.00% 4.12% 3.30% 0.00% 4.12% 3.30%0.00% 5.70% 5.70% 0.00% 5.70% 5.70% 0.00% 5.70% 5.70%2.04% 6.80% 5.44% 2.04% 6.80% 5.44% 2.04% 6.80% 5.44%3.58% 7.51% 6.01% 3.60% 7.56% 6.05% 3.63% 7.62% 6.10%1.01% 2.10% 1.68% 1.01% 2.10% 1.68% 1.01% 2.10% 1.68%4.58% 9.61% 7.69% 4.61% 9.66% 7.73% 4.64% 9.72% 7.78%Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return Subtotal Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. After Tax Return = Before Tax Return*(1-tax rate)2. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)3. Weighted After Tax Return = (After Tax Return*Portfolio

%)4. Portfolio percentages:

2013 to 2031 = 2012 5. Assume receivables are invested at same ratio as current funds C)6.70%6.73%6.76%

ENTERGY ARKANSAS, INC.NUCLEAR DECOMMISSIONING FUNDS PROJECTED AFTER TAX RETURNS ANO 1 TAX QUALIFIED TRUST (2011-2046)

Attachment 5A Page 7 of 10 2027 Weighted After Tax Return 2028 2028 2028 Weighted 2029 2029 Before Tax After Tax After Tax Before Tax After Tax Return Return Return Return Return 2029 Weighted 2030 2030 After Tax Before Tax After Tax Return Return Return Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds/(Corporate Composite) 0.08% 4.00% 3.20% 0.08% 4.00% 3.20% 0.08% 4.00% 3.20%0.00% 4.12% 3.30% 0.00% 4.12% 3.30% 0.00% 4.12% 3.30%0.00% 5.70% 5.70% 0.00% 5.70% 5.70% 0.00% 5.70% 5.70%2.04% 6.80% 5.44% 2.04% 6.80% 5.44% 2.04% 6.80% 5.44%Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 3.66% 7.68% 6.14% 3.69% 7.75% 6.20%1.01% 2.10% 1.68% 1.01% 2.10% 1.68%4.67% 9.78% 7.82% 4.69% 9.85% 7.88%3.72% 7.81% 6.25%1.01% 2.10% 1.68%4.73% 9.91% 7.93%Subtotal Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. After Tax Return = Before Tax Return*(1 -tax rate)2. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)3. Weighted After Tax Return = (After Tax Retum*Portfolio

%)4. Portfolio percentages:

2013 to 2031 = 2012 5. Assume receivables are invested at same ratio as current funds P)0'1 6.79%6.81%6.85%

ENTERGY ARKANSAS, INC. Attachment 5A NUCLEAR DECOMMISSIONING FUNDS Page 8 of 10 PROJECTED AFTER TAX RETURNS ANO I TAX QUALIFIED TRUST (2011-2046) 2030 Weighted After Tax Return 2031 2032 2031 2031 Weighted 2032 2032 2032 Weighted 2033 Before Tax After Tax After Tax Estimated Before Tax After Tax After Tax Estimated I Return Return Return Portfolio

% Return Return Return Portfolio

%Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds/(Corporate Composite)

Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 0.08% 4.00% 3.20% 0.08% 2.50% 4.00% 3.20% 0.08% 2.50%0.00% 4.12% 3.30% 0.00% 8.00% 4.12% 3.30% 0.26% 24.00%0.00% 5.70% 5.70% 0.00% 8.50% 5.70% 5.70% 0.48% 25.00%2.04% 6.80% 5.44% 2.04% 31.00%50.00%6.80% 5.44% 1.69% 18.50%30.00%7.88% 6.30% 3.15%2.10% 1.68% 0.84%9.98% 7.98% 3.99%3.75% 7.88% 6.30% 3.78%1.01% 2.10% 1.68% 1.01%4.76% 9.98% 7.98% 4.79%Subtotal 100.00%100.00%Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. After Tax Return = Before Tax Return*(1-tax rate)2. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)3. Weighted After Tax Return = (After Tax Retum*Portfolio

%)4. Portfolio percentages:

2013 to 2031 = 2012 5. Assume receivables are invested at same ratio as current funds 03 6.88%6.91%6.51%

ENTERGY ARKANSAS, INC. Attachment 5A NUCLEAR DECOMMISSIONING FUNDS Page 9 of 10 PROJECTED AFTER TAX RETURNS ANO 1 TAX QUALIFIED TRUST (2011-2046) 2033 2034 2033 2033 Weighted 2034 2034 2034 Weighted 2035-2046 2035-2046 Before Tax After Tax After Tax Estimated Before Tax After Tax After Tax Estimated Before Tax Return Return Return Portfolio

% Return Return Return Portfolio

% Return Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)4.00% 3.20% 0.08% 2.50% 4.00% 3.20% 0.08% 2.50% 4.00%Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds/(Corporate Composite) 4.12% 3.30% 0.79% 40.50% 4.12%5.70% 5.70% 1.43% 41.00% 5.70%3.30% 1.33% 47.50% 4.12%5.70% 2.34% 50.00% 5.70%6.80% 5.44% 1.01% 6.00% 6.80% 5.44% 0.33% 0.00% 6.80%Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 10.00%0.00%7.88% 6.30% 1.89%2.10% 1.68% 0.50%9.98% 7.98% 2.40%7.88% 6.30% 0.63%2.10% 1.68% 0.17%9.98% 7.98% 0.80%7.88%2.10%9.98%Subtotal 100.00%100.00%Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. After Tax Return = Before Tax Return*(1-tax rate)2. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)3. Weighted After Tax Return = (After Tax Retum*Portfolio

%)4. Portfolio percentages:

2013 to 2031 = 2012 5. Assume receivables are invested at same ratio as current funds 04 5.70%4.88%

ENTERGY ARKANSAS, INC. Attachment 5A NUCLEAR DECOMMISSIONING FUNDS Page 10 of 10 PROJECTED AFTER TAX RETURNS ANO 1 TAX QUALIFIED TRUST (2011-2046) 2035-2046 2035-2046 Weighted After Tax After Tax Portfolio Assets/(Return Indices for Portfolio Assets) Return Return Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds/(Corporate Composite)

Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 3.20% 0.08%3.30% 1.57%5.70% 2.85%5.44% 0.00%6.30%1.68%7.98%0.00%0.00%0.00%Subtotal Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. After Tax Return = Before Tax Return*(1-tax rate)2. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)3. Weighted After Tax Return = (After Tax Retum*Portfolio

%)4. Portfolio percentages:

2013 to 2031 = 2012 5. Assume receivables are invested at same ratio as current funds co 4.50%

ENTERGY ARKANSAS, INC. Attachment 5B NUCLEAR DECOMMISSIONING FUNDS Page 1 of 10 PROJECTED AFTER TAX RETURNS ANO 2 TAX QUALIFIED TRUST (2011-2046)

Market Portfolio Assets/(Return Indices for Portfolio Assets)Value 6/30/2011 (000's)2011 2012 2011 2011 Weighted 2012 2012 2012 Weighted Before Tax After Tax After Tax Estimated Before Tax After Tax After Tax Portfolio

% Return Return Return Portfolio

% Return Return Return 1 0.06% 0.11% 0.09% 0.00% 2.50% 0.10% 0.08% 0.00%0.00% 0.44% 0.35% 0.00% 0.00% 0.33% 0.26% 0.00%3.49% 4.55% 4.55% 0.16% 0.00% 4.32% 4.32% 0.00%Cash/(Federal Funds Rate)$148 Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds -(Corporate Composite)

$8,437$84,688 35.06% 5.23% 4.18% 1.47% 37.50% 5.01%4.01% 1.50%Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return$148,253 61.38%60.00%6.83% 5.46% 3.35%2.10% 1.68% 1.03%8.93% 7.14% 4.39%6.86% 5.49% 3.29%2.10% 1.68% 1.01%8.96% 7.17% 4.30%Subtotal$241,526 100.00%100.00%Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)2. After Tax Return = Before Tax Retum*(1-tax rate)3. Weighted After Tax Return = (After Tax Return*Portfolio

%)4. Portfolio percentages:

2013 to 2035 = 2012 5. Assume receivables are invested at same ratio as current funds 0 (D.$990$242,516 6.01%5.81%

ENTERGY ARKANSAS, INC. Attachment 5B NUCLEAR DECOMMISSIONING FUNDS Page 2 of 10 PROJECTED AFTER TAX RETURNS ANO 2 TAX QUALIFIED TRUST (2011-2046) 2013 2014 2013 2013 2013 Estimated Before Tax After Tax Portfolio

% Return Return Weighted 2014 2014 Weighted 2015 2015 After Tax Before Tax After Tax After Tax Before Tax After Tax Return Return Return Return Return Return Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals) 2.50% 0.11% 0.09% 0.00% 1.23% 0.98% 0.02% 3.27% 2.62%0.00% 0.52% 0.42% 0.00% 1.96% 1.57% 0.00% 3.76% 3.01%0.00% 4.48% 4.48% 0.00% 4.84% 4.84% 0.00% 5.49% 5.49%Taxable Bonds -(Corporate Composite)

Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 37.50% 5.14%4.11% 1.54% 5.71% 4.57% 1.71% 6.54% 5.23%60.00%6.90% 5.52% 3.31% 6.95% 5.56% 3.34%2.10% 1.68% 1.01% 2.10% 1.68% 1.01%9.00% 7.20% 4.32% 9.05% 7.24% 4.34%7.00% 5.60%2.10% 1.68%9.10% 7.28%Subtotal 100.00%Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)2. After Tax Return = Before Tax Retum*(1-tax rate)3. Weighted After Tax Return = (After Tax Return*Portfolio

%)4. Portfolio percentages:

2013 to 2035 = 2012 5. Assume receivables are invested at same ratio as current funds p5.86%6.08%

ENTERGY ARKANSAS, INC.NUCLEAR DECOMMISSIONING FUNDS PROJECTED AFTER TAX RETURNS ANO 2 TAX QUALIFIED TRUST (2011-2046)

Attachment 5B Page 3 of 10 2015 2016 2017 Weighted 2016 2016 Weighted 2017 2017 Weighted 2018 2018 After Tax Before Tax After Tax After Tax Before Tax After Tax After Tax Before Tax After Tax Return Return Return Return Return Return Return Return Return Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds -(Corporate Composite)

Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 0.07%0.00%0.00%1.96%4.00%4.12%5.70%6.80%3.20%3.30%5.70%5.44%0.08%0.00%0.00%2.04%4.00%4.12%5.70%6.80%3.20%3.30%5.70%5.44%0.08%0.00%0.00%2.04%4.00%4.12%5.70%6.80%3.20%3.30%5.70%5.44%3.36% 7.06% 5.65% 3.39% 7.11%1.01% 2.10% 1.68% 1.01% 2.10%4.37% 9.16% 7.33% 4.40% 9.21%5.69% 3.41% 7.16% 5.73%1.68% 1.01% 2.10% 1.68%7.37% 4.42% 9.26% 7.41%Subtotal Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)2. After Tax Return = Before Tax Retum*(1-tax rate)3. Weighted After Tax Return = (After Tax Return*Portfolio

%)4. Portfolio percentages:

2013 to 2035 = 2012 5. Assume receivables are invested at same ratio as current funds 0 i'3 6.40%6.52%6.54%

ENTERGY ARKANSAS, INC.NUCLEAR DECOMMISSIONING FUNDS PROJECTED AFTER TAX RETURNS ANO 2 TAX QUALIFIED TRUST (2011-2046)

Attachment 5B Page 4 of 10 2018 Weighted After Tax Return 2019 2020 2019 2019 Before Tax After Tax Return Return Weighted 2020 2020 Weighted 2021 2021 After Tax Before Tax After Tax After Tax Before Tax After Tax Return Return Return Return Return Return Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)0.08% 4.00% 3.20% 0.08% 4.00% 3.20% 0.08%4.00% 3.20%Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds -(Corporate Composite) 0.00% 4.12% 3.30% 0.00% 4.12% 3.30% 0.00% 4.12% 3.30%0.00% 5.70% 5.70% 0.00% 5.70% 5.70% 0.00% 5.70% 5.70%2.04% 6.80% 5.44% 2.04% 6.80% 5.44% 2.04% 6.80% 5.44%3.44% 7.20% 5.76% 3.46% 7.25% 5.80% 3.48% 7.30% 5.84%1.01% 2.10% 1.68% 1.01% 2.10% 1.68% 1.01% 2.10% 1.68%4.44% 9.30% 7.44% 4.46% 9.35% 7.48% 4.49% 9.40% 7.52%Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return Subtotal Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)2. After Tax Return = Before Tax Retum*(1-tax rate)3. Weighted After Tax Return = (After Tax Return*Portfolio

%)4. Portfolio percentages:

2013 to 2035 = 2012 5. Assume receivables are invested at same ratio as current funds 0 N3 6.56%6.58%6.61%

ENTERGY ARKANSAS, INC. Attachment 5B NUCLEAR DECOMMISSIONING FUNDS Page 5 of 10 PROJECTED AFTER TAX RETURNS ANO 2 TAX QUALIFIED TRUST (2011-2046) 2021 Weighted After Tax Return 2022 2023 2022 2022 Weighted 2023 2023 Weighted 2024 2024 Before Tax After Tax After Tax Before Tax After Tax After Tax Before Tax After Tax Return Return Return Return Return Return Return Return Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds -(Corporate Composite)

Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 0.08% 4.00% 3.20% 0.08% 4.00% 3.20% 0.08% 4.00% 3.20%0.00% 4.12% 3.30% 0.00% 4.12% 3.30% 0.00% 4.12% 3.30%0.00% 5.70% 5.70% 0.00% 5.70% 5.70% 0.00% 5.70% 5.70%2.04% 6.80% 5.44% 2.04% 6.80% 5.44% 2.04% 6.80% 5.44%3.50% 7.35% 5.88% 3.53% 7.40% 5.92% 3.55% 7.45% 5.96%1.01% 2.10% 1.68% 1.01% 2.10% 1.68% 1.01% 2.10% 1.68%4.51% 9.45% 7.56% 4.54% 9.50% 7.60% 4.56% 9.55% 7.64%Subtotal Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)2. After Tax Return = Before Tax Retum*(1-tax rate)3. Weighted After Tax Return = (After Tax Return*Portfolio

%)4. Portfolio percentages:

2013 to 2035 = 2012 5. Assume receivables are invested at same ratio as current funds 6.63%6.66%6.68%

ENTERGY ARKANSAS, INC. Attachment 5B NUCLEAR DECOMMISSIONING FUNDS Page 6 of 10 PROJECTED AFTER TAX RETURNS ANO 2 TAX QUALIFIED TRUST (2011-2046)

Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds -(Corporate Composite)

Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 2024 2025 2026 Weighted 2025 2025 Weighted 2026 2026 Weighted 2027 2027 After Tax Before Tax After Tax After Tax Before Tax After Tax After Tax Before Tax After Tax Return Return Return Return Return Return Return Return Return 0.08% 4.00% 3.20% 0.08% 4.00% 3.20% 0.08% 4.00% 3.20%0.00% 4.12% 3.30% 0.00% 4.12% 3.30% 0.00% 4.12% 3.30%0.00% 5.70% 5.70% 0.00% 5.70% 5.70% 0.00% 5.70% 5.70%2.04% 6.80% 5.44% 2.04% 6.80% 5.44% 2.04% 6.80% 5.44%3.58% 7.51% 6.01% 3.60% 7.56% 6.05% 3.63% 7.62% 6.10%1.01% 2.10% 1.68% 1.01% 2.10% 1.68% 1.01% 2.10% 1.68%4.58% 9.61% 7.69% 4.61% 9.66% 7.73% 4.64% 9.72% 7.78%Subtotal Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)2. After Tax Return = Before Tax Return*(1-tax rate)3. Weighted After Tax Return = (After Tax Retum*Portfolio

%)4. Portfolio percentages:

2013 to 2035 = 2012 5. Assume receivables are invested at same ratio as current funds O.6.70%6.73%6.76%

ENTERGY ARKANSAS, INC. Attachment 5B NUCLEAR DECOMMISSIONING FUNDS Page 7 of 10 PROJECTED AFTER TAX RETURNS ANO 2 TAX QUALIFIED TRUST (2011-2046)

Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds -(Corporate Composite) 2027 2028 2029 Weighted 2028 2028 Weighted 2029 2029 Weighted 2030 2030 After Tax Before Tax After Tax After Tax Before Tax After Tax After Tax Before Tax After Tax Return Return Return Return Return Return Return Return Return 0.08% 4.00% 3.20% 0.08% 4.00% 3.20% 0.08% 4.00% 3.20%0.00% 4.12% 3.30% 0.00% 4.12% 3.30% 0.00% 4.12% 3.30%0.00% 5.70% 5.70% 0.00% 5.70% 5.70% 0.00% 5.70% 5.70%2.04% 6.80% 5.44% 2.04% 6.80% 5.44% 2.04% 6.80% 5.44%Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 3.66% 7.68% 6.14% 3.69% 7.75% 6.20% 3.72%1.01% 2.10% 1.68% 1.01% 2.10% 1.68% 1.01%4.67% 9.78% 7.82% 4.69% 9.85% 7.88% 4.73%7.81% 6.25%2.10% 1.68%9.91% 7.93%Subtotal Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)2. After Tax Return = Before Tax Retum*(1-tax rate)3. Weighted After Tax Return = (After Tax Return*Portfolio

%)4. Portfolio percentages:

2013 to 2035 = 2012 5. Assume receivables are invested at same ratio as current funds Cn)o)0, 6.79%6.81%6.85%

ENTERGY ARKANSAS, INC.NUCLEAR DECOMMISSIONING FUNDS PROJECTED AFTER TAX RETURNS ANO 2 TAX QUALIFIED TRUST (2011-2046)

Attachment 5B Page 8 of 10 2030 2031 Weighted 2031 2031 Weighted After Tax Before Tax After Tax After Tax Return Return Return Return 2032-2035 2032-2035 2032-2035 Weighted 2036 2036 Before Tax After Tax After Tax Estimated Before Tax Return Return Return Portfolio

% Return Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds -(Corporate Composite) 0.08% 4.00% 3.20% 0.08% 4.00% 3.20% 0.08% 2.50% 4.00%0.00% 4.12% 3.30% 0.00% 4.12% 3.30% 0.00% 8.00% 4.12%0.00% 5.70% 5.70% 0.00% 5.70% 5.70% 0.00% 8.50% 5.70%2.04% 6.80% 5.44% 2.04% 6.80% 5.44% 2.04% 31.00% 6.80%Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 50.00%3.75% 7.88% 6.30% 3.78%1.01% 2.10% 1.68% 1.01%4.76% 9.98% 7.98% 4.79%7.88% 6.30% 3.78%2.10% 1.68% 1.01%9.98% 7.98% 4.79%7.88%2.10%9.98%Subtotal 100.00%Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)2. After Tax Return = Before Tax Retum*(1-tax rate)3. Weighted After Tax Return = (After Tax Returm*Portfolio

%)4. Portfolio percentages:

2013 to 2035 = 2012 5. Assume receivables are invested at same ratio as current funds 0)6.88%6.91%6.91%

ENTERGY ARKANSAS, INC.NUCLEAR DECOMMISSIONING FUNDS PROJECTED AFTER TAX RETURNS ANO 2 TAX QUALIFIED TRUST (2011-2046)

Attachment 5B Page 9 of 10 2036 After Tax Return 2036 2037 Weighted 2037 2037 2037 Weighted 2038 2038 2038 After Tax Estimated Before Tax After Tax After Tax Estimated Before Tax After Tax Return Portfolio

% Return Return Return Portfolio

% Return Return Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)3.20% 0.08% 2.50% 4.00% 3.20% 0.08% 2.50% 4.00% 3.20%Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds -(Corporate Composite) 3.30% 0.26% 24.00% 4.12%5.70% 0.48% 25.00% 5.70%5.44% 1.69% 18.50% 6.80%3.30% 0.79% 40.50% 4.12%3.30%5.70% 1.43% 41.00%5.70% 5.70%5.44% 1.01% 6.00% 6.80% 5.44%Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 30.00%10.00%6.30% 3.15%1.68% 0.84%7.98% 3.99%7.88% 6.30% 1.89%2.10% 1.68% 0.50%9.98% 7.98% 2.40%7.88% 6.30%2.10% 1.68%9.98% 7.98%Subtotal 100.00%100.00%Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)2. After Tax Return = Before Tax Retum*(1-tax rate)3. Weighted After Tax Return = (After Tax Return*Portfolio

%)4. Portfolio percentages:

2013 to 2035 = 2012 5. Assume receivables are invested at same ratio as current funds-K)6.51%5.70%

ENTERGY ARKANSAS, INC. Attachment 5B NUCLEAR DECOMMISSIONING FUNDS Page 10 of 10 PROJECTED AFTER TAX RETURNS ANO 2 TAX QUALIFIED TRUST (2011-2046) 2038 Weighted After Tax Return 2039-2046 2039-2046 2039-2046 2039-2046 Weighted Estimated Before Tax After Tax After Tax Portfolio

% Return Return Return Portfolio Assets/(Return Indices for Portfolio Assets)Cash/(Federal Funds Rate)0.08% 2.50% 4.00% 3.20% 0.08%Treasuries/(Treasury Note, 2-Year)Municipal Bonds/(Bond Buyer-20 Municipals)

Taxable Bonds -(Corporate Composite).Equities Equity -Capital Gain Component Equity -Dividend Component Total Equity Return 1.33% 47.50% 4.12%2.34% 50.00% 5.70%3.30% 1.57%5.70% 2.85%0.33% 0.00% 6.80% 5.44% 0.00%0.00%0.63%0.17%0.80%7.88% 6.30% 0.00%2.10% 1.68% 0.00%9.98% 7.98% 0.00%Subtotal 100.00%Interest & Dividend Receivable Portfolio Totals NOTES:* See Attachment 1 1. Before Tax Returns (Attachment 4); Tax Rates (Attachment 3)2. After Tax Return = Before Tax Retum*(1-tax rate)3. Weighted After Tax Return = (After Tax Return*Portfolio

%)4. Portfolio percentages:

2013 to 2035 = 2012 5. Assume receivables are invested at same ratio as current funds o ki co 4.88%4.50%

Attachment 6 Entergy Arkansas, Inc.Arkansas Nuclear One Units I & 2 2011 Decommissioning Trustee and Investment Manager Fees Administrative Fees Paid to Trustee (1)Per Fund Trustee Fees (2)$11,700 Range$ Full amount Investment Manager Fees (3)Range ANO 1 TQ and ANO 2 TQ Basis Max. Rate for Cumulative Breakpoints

($) Points Breakpoint

($) Max. Rate ($)None 1.00 Tax Qualified Trust Basis Max. Rate for Points Breakpoint

($)Breakpoints

($)Cumulative Max. Rate ($)$ OMto$7.1M$ 7.1Mto$8M$ 8Mto$10M$10 Mto$ 16 M$ 16 M to $ 17.75 M$ 17.75 M to $ 20 M$ 20Mto$25M Over $25 M 7,100,000 8,000,000 10,000,000 16,000,000 17,750,000 20,000,000 25,000,000 20.23 18.98 18.21 16.96 15.81 13.31 12.15 9.65 14,363 1,708 3,642 10,176 2,767 2,995 6,075 14,363 16,072 19,714 29,890 32,656 35,651 41,726 Notes: (1) Refer to Attachment 7 section 1.A. Administrative Fees Paid to Trustee.(2) Refer to Attachment 7 section 1..B. Consolidated Funds Fee Structure.

(3) Refer to Attachment 7 section 2. Investment Manager Fees for breakdown of fees.C.29 ENTERGY ARKANSAS, INC.NUCLEAR DECOMMISSIONING FUNDS TRUSTEE & INVESTMENT MANAGER FEES 1. Trustee Fees: 1A. Administrative Fees Paid to Trustee Attachment 7 Page 1 of 2 Account Administration, Tax Return Preparation, Performance Reporting, and Report Production lB. Consolidated Funds$11,700 annually per fund Fee Structure I All funds lbp 2. Investment Manaaer Fees 2A. ANO 1 Tax Qualified Fund -Fixed Income$ 0 to $10 million$10 to $25 million over $25 million 30bp 25bp 15bp 2B. Assumed ANO 1 Tax Qualified

-Fixed Income Allocation*

$ 0 to $7.1 million$7.1 to $17.75 million over $17.75 million 30bp 25bp 15bp*Assume ANO 1 and Indian Point receive benefits of the declining rate structure in 2A. above, in the ratio of 71 -29, respectively.

2C. ANO 2 Tax Qualified Fund -Fixed Income$ 0 to $10 million$10 to $25 million over $25 million 30bp 25bp 15bp 2D. Averacie ANO 1 & 2 Tax Qualified Fund -Fixed Income*$ 0 to $7.1 million$7.1 to $10 million$10 to $17.75 million$17.75 to $25 million over $25 million*Average of B and C above.30bp 27.5bp 25bp 20bp 15bp C.30 ENTERGY ARKANSAS, INC. Attachment 7 NUCLEAR DECOMMISSIONING FUNDS Page 2 of 2 TRUSTEE & INVESTMENT MANAGER FEES 2E. Mellon Stock Index Fund$ 0 to $40 million 1Obp$40 to $80 million 8bp$80 to $100 million 5bp over $100 million 2bp 2F. Assumed Mellon Stock Index Allocation for ANO Funds*$ 0 to $8 million IObp$ 8 to $16 million 8bp$16 to $20 million 5bp over $20 million 2bp*Assume ANO Unit 1, ANO Unit 2, Grand Gulf, River Bend, and Waterford 3 funds receive equal benefits of the declining rate structure in 2E above.2G. Mellon Market Completion Fund$ 0 to $125 million 12bp 2H. Average ANO 1 & 2 Tax Qualified Fund -Equity$ 0 to $8 million 10.46bp$ 8 to $16 million 8.92bp$16 to $20 million 6.61bp over $20 million 4.30bp*Average of F and G above, weighted as follows: F -77% and G -23%.21. Assumed Average Investment Manager Fee for Each ANO Tax Qualified Fund*$ 0 to $ 7.1 million 20.23bp$ 7.1 to $ 8 milllion 18.98bp$ 8 to $10 million 18.21bp$10 to $16 million 16.96bp$16 to $17.75 million 15.81bp$17.75 to $20 million 13.31bp$20 to $25 million 12.15bp over $25 million 9.65bp* Assumes an average of each unit's tax qualified fund's investment management fees (average of 2D and 2H above)C.31 Attachment 8 INSIGOT Updated on Fri 30 Sep 2011, 1:06 AM EDT (06:06 GMT)SeriesTvype 201012011 2012 '201"3 201412015,2016

~2017'-R04 18ý 20-19 2020 U dated 9/30/ 2011 ........Consumer.Price IndexAll-Urban 1 2.18 2.25 2.281 2.32 2.37 2.42 8 2.53 2.58 2.62 2.67 Effective Rate On Federal Funds 0.18 0.11 0.10 0.11 1.23 3.27 4.00 4.00 4.00 4.00 4.00 Yield On 10-Year Treasury Notes j 3.21 2.90 2.69 2.91 3.58 4.60 4.91 4.91 4.91 4.91 4.91 Yield On 2-Year Treasury Notes 0.70 0.44 0.33 0.52 1.96 3.76 4.12 4.12 4.12 4.12 4.12 Yield On 5-YearTreasy Notes 1.93 1.58 1.39 1.64 2.66 4.18 4.50 4.50 4.50 4.50 4.50.~~~~ ~~~ ....... .... ... .: ...........

..................

Yield, On Aaa-Rated Corporate Bonds i 4.94 4.78 4.53 4.60 5.13 5.961 6.22 6.22 6.22 6.22 6.22 Yield On Baa-Rated Corporate Bonds' 6.04 5.68 5.49 5.68 6.29 7.12 7.381 7.38 7.38 7.38 Yield On Bond Buyer 20-Bond1Index 4.29 4.55 4.32 4.48 4.84 5.49 5.70 5.70 5.70 5.70 5.70 Serlesye __.22122 2023ý 1024!2 X025 2026 20257 20ý2 8 2 02-9 2 ..0-3" 0 ¶2-031 Updated 9/30/2011

~¶¶Consumer Price Index, All-Urban 1' 2.72 2.77 2.82 2.87 2.93 2.98 3.04 3.10 3.171 3.23 3.30 Effective Rate On Federal Funds 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 Yield On 10-Year Treasury Notes 4.91 4.91 4.91 4.91 4.91 4.91 4.91 4.91 4.91 4.91 4.91 Yield On 2-Year Treasury, Notes 4.12 4.12 4.12 4.12 4.12 4.12 4.12 4.12 4.12 4.12 4.12 Yield O n 5-Year Treasury Notes _ _ 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Yield On Aaa-Rated Corporate Bonds' 1 6.22 6.22 6.22 6.22 6.22 6.22 6.22 6.22 6.22 6.22" 6.2 2 Yield On Baa-Rated Corporate Bonds' 7.38 7.38 7.38 7.38 7.38 7.38 7.38 7.38 7.38 7.38 7.38 Yield, On Bond Buyer 20-Bond Index ' 5.70 5.70 5.70 5.70 5.70 5.70 5.70 5.70 5.70 5.70 5.70 C.32 Attachment 9 INFLATION ADJUSTED TOTAL EQUITY INDEX AND AVERAGE COMPOUND REAL RETURNS LARGE COMPANY STOCKS 1926 TO YEAR INDICATED 1926 To Year 1989 1990 1991 1992 1993 1994 1995 1996'1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Equity Index Net of Inflation (A)75.977 69.333 87.822 91.893 98.369 97.059 130.085 154.953 203.190 257.121 303.094 266.472 231.215 175.925 222.231 238.625 242.070 273.361 277.071 174.755 215.148 243.909 Average Annual Compound Real Returns 7.00%6.74%7.02%6.98%6.98%6.86%7.20%7.36%7.66%7.90%8.03%7.73%7.43%6.94%7.17%7.18%7.10%7.17%7.10%6.42%6.60%6.68%(A) The source for the 2010 equity index number is the Ibbotson (Morningstar) 2011 Yearbook.Data for all other years from prior lbbotson (Morningstar) yearbooks.(B) All average annual compound real returns are a geometric mean return.C.33 D Misc Workpapers Excerpt from Order No. 20 in APSC Docket No. 09-084-U issued June 23, 2010. ARK.'PUBLICSERV C044 CFETARY CFCMN ARKANSAS PUBLIC SERVICE COMMISSION 21'J JUN 23 P 4: 15 IN THE MATTER OF THE APPLICATION OF )ENTERGY ARKANSAS, INC. FOR APPROVAL OF ) DOCKET NO. 09-084-U CHANGES IN RATES FOR RETAIL ELECTRIC ) ORDER NO. 20 SERVICE )ORDER HISTORY On September 4, 2009, pursuant to Ark. Code Ann. § 23-4-401, et seq., Entergy Arkansas, Inc. (EAI) filed its Application For Approual Of Changes In Rates For Retail Elechtic Service (Application) claiming a retail revenue requirement of $1,137.2 million and resulting revenue deficiency of $223.2 million. See EAI's Minimum Filling Requirements (MFR) Schedule A-i (September 4, 20o9). EAM is a public utility as defined by Ark. Code Ann. § 23-1-101, et seq. and is subject to the jurisdiction of the Arkansas Public Service Commission (Commission).'

In support of its Application, EAM concurrently filed the Testimony and Exhibits of its witnesses as follows: John J.Spanos; Hugh T. McDonald; Myra L. Talkington; Gregory R. Zakrezewski; Gordon D.Meyer; Eric Fox; Samuel C. Hadaway; Kevin G. Gardner; Jay C. Hartzell; Lenoal R.Hartwick; Timothy G. Mitchell; Oscar D. Washington; Jeff D. Makholm; Kurtis W.Castleberry; Charles W. Long; S. Brady Aldy; and Jon A. Majewski.On October 2, 2009, the Commission issued its Order No. 3 by which it suspended the proposed rates and tariffs filed by EAI, set a public evidentiary hearing for May 24, 2olo, and directed the parties to propose a fully-developed procedural schedule for the Commission's consideration, with which the parties complied.E, EA provides service to approximately 687,ooo Arkansas retail customers.

D.

Excerpt from Order No. 20 in APSC Docket No. 09-084-U issued June 23, 2010. DocketNo.

og-o8 4-U Order No. P0 Page 13 of 24 THE AGREEMENT Filed May 10, 2aoo and Revised on May 25,2010 As discussed above, certain Parties filed an Agreement on May 10, which was revised and ultimately joined by all Parties to the Docket on May 25, 2010. To the extent the two differ, the Revised Agreement filed on May 25 controls, but the word"Agreement" as used in this order will refer to both Agreements in totality to the extent they represent the Parties' request for Commission approval.A. REVENUE REQUIREMENT

1. The Agreement proposes EAI's non-fuel rate schedule revenue requirement, Arkansas jurisdiction, is $967,361,325, with a resulting revenue deficiency of $73,781,76o, both of which are based on Staffs recommended amounts as reflected in Staffs Surrebuttal Testimonies and Exhibits with the following exceptions (May 1o, 2olo Agreement, Joint Exhibit at 2-5):* Increase in rate base by $18,838,802 to reflect the removal of Staff Adjustment RB-io, which adjusted rate base for historical capitalized incentive compensation.

Prospectively, beginning July 1, 2010, EAI will account for capitalized incentive compensation consistent with Staffs recommendation for retail ratemaking purposes.

The increase in retail revenue requirement resulting from this change is $1,114,792;

• Update retirements to include actual amounts through March 2010, which results in an increase in total company depreciation expense of $248,771.

The increase in retail revenue requirement resulting from this change is $196,537;D.2 Excerpt from Order No. 20 in APSC Docket No. 09-084-U issued June 23, 2010. DocketNo.

o9-o84-U Order No. 20 Page 22 of 24 In compliance with Order No. 18, all Parties to this Docket filed on June 3, 2010, the results of the new cost of service study reflecting the removal of $1o,111,517 in securitized storm costs and reflecting an adjusted revenue deficiency of $63,670,243.

See Joint Submission of Revised Cost of Service at 2 1 2 (June 3, 2aoo). With the removal of those costs, the revised revenue deficiency for each rate class results in an increase to base rates as depicted below: " CS oA....L-""-A'ON.BAE' NA $6,67 43 :RA TENCREASE By CLASS, RESIDENTIAL SGS LGS LIGHTING Rate Increase by Class $13,409,410

$24,264,652

$26,168,503

($172,322)

% Change in 3.05% 11.66% 1.66% -0.81%Base Rates 3.05% 11-66% n.66% 81%Id. at Joint Attachment 1, lines 7-8. Subsequently, on June 7, 201o, Entergy filed compliance tariffs to implement the proposed rate increase, which were amended on June ii, 2o0o. Staff, the only party to file a response to EAI's compliance tariff filing, filed the Compliance Testimony of Witness Kim 0. Davis on June ii, 2OlO. Staff Witness Davis' testimony recommended approval of EAI's compliance tariffs, as amended.CONCLUSION Having considered all of this Docket's pre-filed written testimonies and exhibits as delineated above, before settlement negotiations began, as well as the resulting Agreement and Revised Agreement and testimonies and exhibits in support of those agreements, the Commission finds that the evidence presented could support a non-fuel revenue requirement for EAI in the range of $995.422 Million (Staffs Surrebuttal case) to $1,13o.871 million (EAI's Rebuttal case) without the transfer of costs to be securitized.

The Agreement, as revised, proposes a revenue requirement of $1,020.170 million (Revised Agreement, Joint Attachment i) falling within the range supported by D.3 Exderpt from Order No. 20 in APSC Docket No. 09-084-U issued June 23, 2010. DocketNo.

o9-084-U Order No. 2o Page 24 of 24 June 11, 2010, the Commission finds that the Agreement, as filed on May 10 and revised on May 25, is just and reasonable and in the public interest.

As such the Commission directs and orders as follows: 1. The Agreement filed on May 25, 2010,'1 is hereby approved; and 2. The Compliance Tariffs filed on June 7, 2010, as amended on June ii, 2010, that were based on the Revised Agreement's mitigated cost of service and reduced by the 2009 storm costs, are approved hereby to be effective for all bills rendered on and after June 30, 2010.BY ORDER OF THE COMMISSION, This 2 3 rd day of June 2010.gaulS SeYfr I hereby certify that this order, Issued by the Arkansas Public Servica Commission, has been served on all parties of record on this data by the following method: thU.s dali withe postawinge pmetod. Colette D. Honorable, Commissioner-U.S. mall with postage prepaid using the rnaflng address of each party as icheed in the ofical docket file, or.ec nIc ma=l Using the emai address d eparty as indicated In the docket file.Olan W. Reeves, Commissioner Jan Sanders Secretary of the Commission 1 0 The May 25 Agreement incorporated by reference all provisions included in the May 1o Agreement not superseded by the revisions made in the May 25 filing.D.4 STORM SECIURITIZATION COST OF SERVICE RESULTS JOINT ATTACHNENT 2 Line No Total Company Total Totaw Pm Forma Wholesale Retail Residential 1 2 1 4 SGS iS LGS S Lighting 7 flanevlnhlnn No Descrift"o" 5 6 7 RATE EASE Gross Plant in Service $ 7,581,525.452

$ 817 Accumulated Depreciation

$ 3,579,342,588

$ 406 Total Not Plant $ 4.002,182,864

$412 Working Capital Assets $ 455.176,523

$ 4E TOTAL RATE BASE $ 4.457.359.387

$ 481 NLON-FUEL OPERATING REVENUES Present Rate Schedule Revenues $ 997,052.882

$ 103 System Sales amd Other Revenues $ 82,589,095

$TOTAL OPERA7lNG REVENUES $ 1,059,741,977

$ 113 Operations and Maintenance i 526.662.620 8 53 Depreciation and Amortlzatlon

$ 210,205.929

$ 21 Regulatory Debits $ 526,655 $Loss (Gains) from Dispostifon S (33.340) $Taxes Other Than lncome Taxes $ 44,723,087 S 4 Federal & State Income Taxes S 93.562.013

• 11 TOTAL EXPENSES 3 875.646.944

$ 90 OPERATING INCOME 3 184.095.033 8 22 EARNED RETURN ON RATE BASE 4.13%COST OF SERVICE REVENUE REQUiREMENT REQUIRED RETURN ON RATE BASE GIVEN EQUAL RATES OF RETURN REQUIRED OPERATING INCOME (LVLIS)OPERATING INCOME DEFICIENCY I [SURPLUS) (LO-1-171 REVENUE CONVERSION FACTOR REVEN UE DFIRCIENCY) (SURPLUSI (L211L22)RATE SCHEDULE REVENUE REQUIREMENT (L23+L7)TOTAL SYSTEM SALES AND OTHER REVENUES (LB)TOTAL NON-FUaL REVENUE REQUIREMENT (1240125)FUEL RIDER REVENUES GRAND GULF RIDER REVENUES PRODUCTION COST ALLOCATION RIDER REVENUES ENERGY EFFICIENCY COST RECOVERY RIDER REVENUES OTHER RIDER REVENUES TOTAL REVENUE REQUIREMENT (L2U+L27.L289L29+L30+L31)

..TAL BILL IMPACT REVISED SETTLEMENT COS REVENUE DEFICIENCY I (SURPLUS) (Attachment 3 L34)% INCREASE) (DECREASE)

ON BASE RATE REVENUES (L32L6)COST OF SERVICE IMPACT OF SECURITIZATION (L22-Attachment 3 1221% INCREASE (DECREASE)

ON BASE RATE REVENUES (134)L.)COMPLIANCE COST OF SERVICE REVENUE DEFICIENCY) (SURPLUS) (L32÷L34)% INCREASE) (DECREASE)

ON BASE RATE REVENUES (L36ILt)LESS RIDER CA REVENUES INCREASE (DECREASE)

TO REV. REQ. (Wi RIDER CA ELIMINATION) (L3-.38)% INCREASE) (DECREASE)

ON TOTAL REVENUE REQUIREMENT (L3SJ(L31-L39})

'1.88,506

$.135.358 $.763.148 8 5,998,635

$,751,784 $6.763,636.94a 3.174,207.230 3,589,429.715 406,177,888 3,995,807,604

$ 3.061.491.094

$$ 1,397,121.408

$$ 1,664,369,686

$$ 183.062.712 S$ 1.847.432.399 4 1,656,457,520

$763.160.981

$893,306,539

$99,337,613

$992,874,152

$1,892,327.158 919,409.766 972,917,392 116,479.877 1.089.397,289

$ 153.351,174 1 94.515,076

$ 56.836,098

$ 7,267,886 S. 85.103,784 1,473,317

$ 893,579,665

$ 439,717,619

$ 208,156,458

$ 224,491,339

$ 21.214149 1.621,518 S 53.067,577

$ 28,365,302 8 10.8U0.894

$ 13,008,594

$ 807.787 1.094,835

$ 948,647,142 S 468.082,921 8 219,042,352

$ 237,495,933

$ 22,021,936 3,941,790

$1,110,552 3 (0) $(,594) S.628,110 $1.278,026

$1,954,884

$2,139,951

$4.79%$$$$$8$*8 8 8 S$$$$$472.720,830 8 189.095,376

$526,655 $(29.747) $40,094,957

$82,248,986

$784.657,058

$161,990,083

$4.05%5.D4%201,378,623 39,388,540 1.81647 63.670.243 957,249.807 53,067,577 1,010,317,384 181,290,199 120,935,470 381,378,934 6,435,515 1,564,940 1.701,922.441 S$$$$$$$$$$219.217.,44 88,738,089 238,385 (13,323)18.230,482 49.372,836 375,792.312 92,290,609 5.00%6.04%93,110,593 819.984 1.61406 1,323,503 441,041,122 28,365.302 469,408,424 67.109.634 58.739.952 138.480,197 2,663.081 585.878 736,985.165 8 S S$$$$$$$$$$$$$$3 109,626,008

$46,247,163

$128,982 $(7.338) $9,623,944

$18,727.159

$184,339,918

$34,702,438

$3.50%5.04%50,030,777 15,328,342 1.61727 24.790.091 232,946,548 10,885m894 243,832.443 38.188,605 27,218.588 79,878,670 1,471,275 333,201 390,600,782

$8 8 8$$$$$S$8 5.04%54,805.622 26,899.800 1.61601 43,454.273 267,945,612 13,008,594 280,954.205 73,738,478 32.203,526 158.596,250 2.257,300 627,028 548,376.786 134,930,858

$50,222,695

$147.347 $(8,395) $11,341,478

$12,860.127

$209,484,110

$28,015,822

$2.57%$$$S$S S S$8$$8,952,121 3.867.430 11,941 (690)891,054 1,298,864 15,040,719 8,981,217 10.656%5.04%3,331,631 (3,849,588) 1.61597 (5,697.624) 15,316,525 807,797 16,124,312 2,275.481 2,773,404 4,723,817 43,858 18,833 25,959,706 0.00%(172,322)-0.81%(172,322)-0481%114,620 (286.942)-1,09%73,781,780

$8.26%(10,111,517)

$-1.13%63,670,243

$7.13%

3 45,374,515

$2.80%18.153.470 8 4.13%(4,744,060) 5-1.08%13,409,410

$3.05%7,129,168 8 6.280,242 8 0.86%28,758,704

$12.88%(2,494,052)

$-1.20%24.264.652

$11.66%4,006,387

$20,258,264

$5.47%28,869,586

$12.86%(2,701,083)

$-1.20%26,168,503 5 1. 1.68%G,045,552 5 20,122,952

$3.81%to 0U 0 0 a~(D cn' In accordance with the recovery of tie Investments and costs related to the Ouachita Plant through base rites rather than Rides CA.Approved Base Rate Schedule Revenue ($000) (L6+L36)957,250 453,127 232,421 250,660 21,042 p Note Added ENTERGY ARKANSAS, INC.BILLING DETERMINANT DEVELOPMENT 2011 GRAND GULF RIDER (GGR) & NUCLEAR DECOMMISSIONING COST RIDER (NDCR) UPDATE Development of Energy (kWh) Billing Determinant for all Rate Classes except LGS Ln No Residential Residential Lighting Total Residential Commercial Small GS Large GS 6 LG-NTOU 7 LG-TOU 8 Total Large GS 9 Lighting 10 Total Commercial Industrial 11 Small GS 12 Large GS 13 LG-NTOU 14 LG-TOU 15 Total Large GS 16 Lighting 17 Total Industrial Govt & Muni 18 Small GS 19 Large GS 20 LG-NTOU 21 LG-TOU 22 Total Large GS 23 Lighting 24 Total Govt & Muni 25 Total Retail Actual MWh (1)2010 2009 2008 Total Average 8,427,000 7,391,585 7,605,440 23,424,025 7,808,008 73,577 72,843 72,690 219,110 73,037 8,500,577 7,464,428 7,678,130 23,643,135 7,881,045 3,371,013 3,077,847 3,161,583 9,610,443 3,203,481 1,265,380 1,240,901 1,251,800 3,758,081 1,252,694 1,409,393 1,399,442 1,362,190 4,171,025 1,390,342 2,674,773 2,640,343 2,613,990 7,929,106 2,643,035 97,772 98,883 99,828 296,483 98,828 6,143,558 5,817,073 5,875,401 17,836,032 5,945,344 1,334,514 1,111,351 1,207,130 3,652,995 1,217,665 1,268,089 1,124,233 1,278,885 3,671,207 1,223,736 4,464,799 4,125,485 4,710,173 13,300,457 4,433,486 5,732,888 5,249,718 5,989,058 16,971,664 5,657,221 14,524 14,796 15,286 44,606 14,869 7,081,926 6,375,865 7,211,474 20,669,265 6,889,755 9,341 8,872 8,277 26,490 8,830 68,690 66,634 70,920 206,244 68,748 128,530 123,744 124,227 376,501 125,500 197,220 190,378 195,147 582,745 194,248 70,500 69,720 69,473 209,693 69,898 277,061 268,970 272,897 818,928 272,976 22,003,122 19,926,336 21,037,902 62,967,360 20,989,120 8,427,000 7,391,585 7,605,440 23,424,025 7,808,008 4,714,868 4,198,070 4,376,990 13,289,928 4,429,976 8,604,881 8,080,439 8,798,195 25,483,515 8,494,505 256,373 256,242 257,277 769,892 256,631 22,003,122 19,926,336 21,037,902 62,967,360 20,989,120 Ratios (%) Forecasted 2012 kWh 99.07% 7,831,730,441 0.93% 73,258,565 7,904,989,006 53.88% 3,286,669,961 44.46% 2,711,670,472 1.66% 101,394,053 6,099,734,487 17.67% 1,259,415,905 82.11% 5,851,194,317 0.22% 15,378,479 7,125,988,701 3.23% 8,979,119 71.16% 197,528,753 25.61% 71,078,082 277,585,953 21,408,298,147 kWh 7,831,730,441 4,555,064,986 8,760,393,542 261,109,179 21,408,298,147 26 27 28 29 30 TOTAL BY RATE CLASS Residential Small Gen. Service Large Gen. Service Lighting Total Retail 31 32 Large GS LGS kW (1)Total Development of Demand (kW) Billing Determinant for LGS Rate Class 2010 2009 2008 Total Average 16,959,852 15,256,699 15,978,455 48,195,006 16,065,002 16,959,852 15,256,699 15,978,455 48,195,006 16,065,002 Factor (4)kW (5)1.89 16,567,856 Notes: (1) All Historical Rate Class MWh and kW provided by Rate Administration.

(2) 3 year average ratio of Rate Class MWh to the Total MWh within the Revenue Class (3) Forecast provided on Revenue Class basis therefore converted to Rate Class based on 3 year Historical Average MWh (4) LGS 3 year average kW (L31) / 3 year average LGS MWh (L28)(5) Forecasted LGS MWh (L28)

• Factor derived from Historical results equals Forecasted kW for LGS Rate Class (L32)D.6 Afll

£,=j1.Excerpt from Order No. 50 in APSC Docket No. 87-166-TF issued Oct. 13, 2009 a týCBE1AA.

rjF COIMM.lST 13 1 21 PH '0ll'9 t ARKANSAS PUBLIC SERVICE COMMISSION IN THE MATTER OF ARKANSAS POWER ) ILED& LIGHT COMPANY'S PROPOSED ) DOCKET NO. 87-¶66-TF NUCLEAR DECOMMISSIONING ) ORDER NO. 50 COST RIDER M26 AND PROPOSED )DEPRECIATION RATE RIDER M41 )ORDER On March 31, 2009, Entergy Arkansas, Inc., ("EAI" or "Company")

filed its Motion for Approval of Revised Estimate of Arkansas Nuclear One Decommissioning Costs and Certain Other Changes to the ANO Decommissioning Trust Funds ("Motion")

with the supporting Second Supplemental Testimony of EAI witness Michael A. Caruso, and the Direct Testimonies and Exhibits of EAI witnesses Rory L. Roberts, Rebecca L. Bowden and William A. Cloutier, Jr. In addition, EAI previously filed the Supplemental Testimony and Exhibits of EAI witness Caruso on July 24, 2oo8, which, pursuant to Order No. 47 in this Docket, had been held in abeyance until such time that EAI filed its revised estimate of the Arkansas Nuclear One ("ANO") Decommissioning Costs.On April 23, 2oo9, the Arkansas Public Service Commission

("APSC" or "the Commission")

issued Order No. 48 in this Docket suspending EAr's Motion and establishing a procedural schedule.

Pursuant to Order No. 48, on July 24, 20o9, the General Staff of the Commission

("Staff")

filed the Direct Testimony and Exhibits of its witness, Donna Gray, Director of the General Staff Financial Analysis.

On August 24, 2009, EAI filed the Rebuttal Testimonies and Exhibits of EAI witnesses Steven K.Strickland, Albert C. King, III, Caruso, Bowden, and Cloutier.

Staff filed the Surrebuttal t Previously Arkansas Power and Light Company. L --D.7 Excerpt from Order No. 50 in APSC Docket No. 87-166-TF issued Oct. 13, 2009 Docket No. 87-166-TF Order No. 5o Page 9 of 12 Ms. Gray additionally recommends that EAM be ordered to provide substantiation that the DOE Obligation funds will be available when payment is due and that ratepayers will be insulated from any adverse impacts from that payment. Ms. Gray advises that ratepayers have provided funding of the DOE Obligation and continue to pay interest on the on-going obligation. (Gray Direct at 12).EAI witness Strickland proposes to work with Staff witness Gray in framing an appropriate analysis to address her recommendations regarding EAIs DOE Obligation and to provide that analysis to the Commission within 9o days after the Commission's order in this docket. (Strickland Sur-Surrebuttal at 4-5).Stipulation By their Joint Motion, Staff and EAT propose a Stipulation (Attachment A hereto)to settle all issues addressed in this proceeding and ask that the Commission consider the Stipulation based upon the evidence of record and that the scheduled public hearing be cancelled.

By Order No. 49, issued on September 11, 2009, the Commission cancelled the hearing previously set for September 15, 2-oo9, and took this matter under advisement based upon the pre-filed testimony and exhibits of the parties.1o Further, EAI and Staff request that the Commission issue its final Order in this matter by October 15, 2oo9.A summary 1' of the Stipulation terms follows:* The Commission should approve EAT's nuclear decommissioning cost estimate of $1,049.8 millionl2 for use in the annual November i tariff filings for the years 2009 through 2o13;1 0 The only other party to this Docket, the Arkansas Electric Energy Consumers, Inc., has not participated in this specific phase of this Docket.1 1 This summary is not intended to supplant the actual language of the Stipulation.

12 The amount specifically excludes Spent Fuel costs.D.8 Excerpt from Order No. 50 in APSC Docket No. 87-166-TF issued Oct. 13, 2009 Docket No. 87-i66-TF Order No. 50 Page 11 of 12* The Commission should approve the "pour-over" as requested by EAT, with EAI contributing both the funds in the Non-Tax Qualified Trust Fund and the cash benefit of the resulting tax deduction;

• EAI will file in this docket both its request to IRS for approval of the pour-over and the IRS response to substantiate that approval;* EAI will demonstrate in annual filings in this docket the actual net tax benefits to ratepayers of the pour-over, with full explanation of variations in actual benefits from those reflected in EAT Exhibit RLR-2;* EAI shall identify the pour-over amounts and the timing thereof in the respective quarterly trust fund reports filed in Docket No. 96-341-U;* The Commission should condition its approval of the revocation of the Non-Tax Qualified Trust Fund on IRS authorization to pour-over the full amount in that fund;* The Commission should approve the change in the equity allocation targets for the Funds from 50 percentto 6o percent, maintaining re-balancing at +/- 5 percent around the 6o percent equity target and approve the broadening of the equity market exposure's in the funds, and;* EAI will file with this Commission the NRC Funding Report beginning with the report due March 31, 2o0, and every two years thereafter or at such other interval as the NRC may require.Findings The Commission has considered the proposed Stipulation in conjunction with the parties' filed Testimony and Exhibits and finds that the Stipulation is fully supported by 15 The Stipulation states that broadening should be accomplished by "increasing the exposure in the Wilshire 4500 Stock Index Fund, over a reasonable period of time, for both Units so that the ratio of investment in the Wilshire 4500 Stock Index Fund to the total equity in each fund is the same as the Wilshire 4500 Index is to the total U.S. stock market, or about 2o percent." (Stipulation at 5).D.9 Excerpt from Order No. 50 in APSC Docket No. 87-166-TF issued Oct. 13, 2009 DocketNo.

87-166-TF Order No. 50 Page 12 of 12 the record, settles all issues addressed herein in a reasonable manner, and is in the public interest.

Accordingly, the Commission hereby approves in its entirety the Stipulation attached hereto as Attachment A. EAI shall fully comply with the terms and conditions set forth in said Stipulation.

BY ORDER OF THE COMMISSION, This /I -J of October, 2009.Colette D. Honorable, Commissioner Olan W. Reeves, Commissioner Office of the Secretary of the Co ssion I hsrby cat* th the -owr o.*r issue byt A* ue Pubic- service Commission ha bn served on all parties of record ti date U S. mail with postage pepaid, uwsig aess of each party as Indicated in the offtal adocket fire.-Secrsdarý Of the jiMnsn D.10 Entergy Arkansas, Inc.Approved Nuclear Decommissioning Cost Estimate For the annual November 1 tariff filings for the years 2009 through 2013 (1)($000)Approved Decommissioning Expenditures Line No Unit I License Site Year Termination Restoration Total ex Spent Fuel Unit 2 License Site Total ex Termination Restoration Spent Fuel Total Both Units (2)2 3 4.5 6 7 8 9 10 11 12 13 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 Total 30,497 92,023 117,755 77,094 51,702 51,651 14,154 3,219 3,219 3,219 17,669 5,281 13,017 480,500 374 1,113 371 347 333 293 0 0 0 0 0 11,775 17,358 31,964 30,871 93,136 118,126 77,441 52,035 51,944 14,154 3,219 3,219 3,219 17,669 17,056 30,375 512,464 19,414 62,322 119,903 89,660 59,626 59,626 35,667 5,488 13,913 465,619 0 0 151 591 1,119 2,645 4,091 4,091 168 23,797 35,082 71,735 0 0 19,565 62,913 121,022 92,305 63,717 63,717 35,835 29,285 48,995 537,354 1,049,818 Notes: (1) Decommissioning Cost Estimate (2008 dollars) as approved in APSC Order No. 50 in Docket No. 87-166-TF issued on October 13, 2009.See Workpapers D.7 -D.10 for excerpts from that Order.(2) Total ANO Decommissioning Cost Estimate as stated in APSC Order No. 50.D.11 ENTERGY ARKANSAS, INC.DOCKET NO. 09-084-U COMPLIANCE COST OF SERVICE -ALLOCATION FACTORS TEST YEAR ENDED JUNE 30, 2009 LINE NO. DESCRIPTION DEMAND ALLOCATION FACTORS 1 PRODUCTION DEMAND COMPUTER ALLOCATION CODE FACTOR TOTAL TOTAL COMPANY RETAIL TOTAL OF ALL FUNCTIONS RESID SGS LGS LIGHTING WHLSE 2-UNITIZED-*

PDAF 3 PRODUCTION DEMAND ARKANSAS RETAIL 4 -UNITIZED-5 PRODUCTION DEMAND ARKANSAS WHOLESALE 6 -UNITIZED-7 TRANSMISSION HIGH VOLTAGE DEMAND 8 -UNITIZED-9 TRANSMISSION HIGH VOLTAGE DEMAND ARKANSAS RETAIL 10 -UNITIZED-11 TRANSMISSION LOW VOLTAGE DEMAND 12 -UNITIZED-13 DISTRIBUTION SUBSTATIONS DEMAND 14 -UNITIZED-15 DISTRIBUTION LINES PRIMARY DEMAND 16 .-UNITIZED-17 DISTRIBUTION LINES SECONDARY DEMAND 18 -UNITIZED-19 DISTRIBUTION LINE TRANSFORMER DEMAND 20 -UNITIZED-PDAFAR PDAFW THDAF THDAFAR TLDAF DSDAF DLPDAF DLSDAF DLTDAF 1.000000 1.000000 1.000000 1.000000 0.138700 1.000000 1.000000 1.000000 0.717117 1.000000 1.000000 1.000000 1.000000 1.000000 1.000000 1.000000 1.000000 1.000000 1.000000 1.000000 0.861300 0.861300 1.000000 1.000000 0.717117 0.717117 0.717117 1.000000 0.763047 0.763047 0.979714 0.979714 0.987478 0.987478 0.999979 0.999979 0.999979 0.999979 0.353893 0.353893 0.410882 0.410882 0.315849 0.315849 0.315849 0.440443 0.336078 0.336078 0.428293 0.428293 0.431686 0.431686 0.573439 0.573439 0.573439 0.573439 0.204728 0.204728 0.237697 0.237697 0.163856 0.163856 0.163856 0.228493 0.174350 0.174350 0.259371 0.259371 0.261426 0.261426 0.277494 0.277494 0.277494 0.277494 0.296740 0.296740 0.344526 0.344526 0.237313 0.237313 0.237313 0.330926 0.252513 0.252513 0.277685 0.277685 0.279886 0.279886 0.136638 0.136638 0.136638 0.136638 0.005939 0.138700 0.005939 0.138700 0.006895 -0.006895 --0.138700 1.000000 0.000099 0.282883 0.000099 0.282883 0.000099 -0.000138 0.000106 0.236953 0.000106 0.236953 0.014365 0.020286 0.014365 0.020286 0.014480 0.012522 0.014480 0.012522 0.012408 0.000021 0.012408 0.000021 0.012408 0.000021 0.012408 0.000021 0 N_ Numbers may not add due to rounding.

ENTERGY ARKANSAS, INC.CALCULATION OF % OF UNCOLLECTIBLE ACCOUNTS YEARS 2006 THRU 2010 ($ooo's)5-YEAR TOTAL 5-YEAR TOTAL 5-YEAR JURISDICTIONAL JURISDICTIONAL AVERAGE OPERATING UNCOLLECTIBLES

%REVENUES WRITTEN OFF UNCOLLECTIBLES LINE NO YEAR RATE CLASSES 1 2 3 4 5 6 7 8 EAI APSC RETAIL RESIDENTIAL 3,633,458 SMALL GENERAL SVC 1,835,004 LARGE GENERAL SVC-NTOU 855,187 LARGE GEN SVC-TOU 1,669,209 SPECIAL CONTRACT 0 LIGHTING -ROADWAY 42,351 LIGHTING -NON-ROADWAY 112,748 TOTAL APSC RETAIL 8,147,957 35,135 2,923 290 1,858 0 0 659 40,865 0.9670%0.1593%0.0339%0.1113%0.0000%0.0000%0.5845%0.5015%D.13 Per the EAI 2011 ANO Decommissioning Cost Rider NDCR Update Rate Sch. No. 37 Workpapers Entergy Arkansas, Inc.ANO Decommissioning Model Tax Qualified Trust Detail -Unit 1 ($000)Tax Qualified Trust Line No 1 2 3 4 5 6 Revenue Year Rqmt. (1]Beginning Balance 2012 0 2013 0 2014 0 2015 0 2016 0 Earning Transfer Rate [2] To Trust [3] [9] Earnings [4]Mgmt. Net Fee [5] Additions

[6]Decomm.Expend. [7]5.81%5.86%6.08%6.40%6.52%0 0 0 0 0 18,061 19,275 292 308 325 21,180 23,669 25.665 17,769 18,967 20,855 23,325 25.301 0 0 0 0 0 Balance [8]306,406 324,175 343,142 363,997 387,322 412.623 344 364 7 2017 0 6.54% 0 27,427 387 27,040 0 439,663 8 2018 0 6.56% 0 29,315 411 28,904 0 468,567 9 2019 0 6.58% 0 31,339 436 30,903 0 499,470 10 2020 0 6.61% 0 33,561 463 33,097 0 532,567 11 2021 0 6.63% 0 35,894 492 35,402 0 567,969 12 2022 0 6.66% 0 38,457 524 37,933 0 605,902 13 2023 0 6.68% 0 41,150 557 40,593 0 646,495 14 2024 0 6.70% 0 44,041 593 43,448 0 689,942 15 2025 0 6.73% 0 47,214 631 46,583 0 736,525 16 2026 0 6.76% 0 50,631 673 49,958 0 786,483 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 2027 0 2028 0 2029 0 2030 0 2031 0 2032 0 2033 0 2034 0 2035 0 2036 0 2037 0 2038 0 2039 0 2040 0 2041 0 2042 0 2043 0 2044 0 2045 0 2046 0 Average 6.79%6.81%6.85%6.88%6.91%6.51%5.70%4.88%4.50%4.50%4.50%4.50%4.50%4.50%4.50%4.50%4.50%4.50%4.50%4.50%5.78%0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 54,309 58,183 62,531 67,129 72,084 72,552 67,536 60,987 56,115 49,960 40,917 35,155 31,489 27,531 27,258 28,124 29,018 29,943 29,199 28,439 717 764 815 869 928 989 1,048 1,101 1,098 980 807 697 626 551 545 562 579 597 583 568 53,592 57,419 61,716 66,260 71,156 71,564 66,488 59,886 55,017 48,980 40,110 34,458 30,863 26,980 26,713 27,562 28,439 29,346 28,616 27,871 0 0 0 0 0 0 0 61,433 190,277 247,710 166,730 114,997 117,861 32,965 7,697 7,903 8,112 45,710 45,301 82,833 840,076 897,495 959,211 1,025,471 1,096,627 1,168,191 1,234,679 1,233,132 1,097,872 899,142 772,521 691,981 604,983 598,999 618,015 637,674 658,001 641,638 624,953 569,991 Notes:[1] See Workpaper B.2[2] Projected After Tax Earnings Rates See Workpaper C.1.[3] Revenue Requirement

• (1 -Bad Debt Rate). See Workpaper B.7 for Bad Debt Rate.[4] Prior Year Balance Compounded Semiannually At Current Year Earning Rate + 1/2 Current Year Transfer

• Current Year Earning Rate.15] Calculated on average balance according to the schedules on Workpaper

6.7 multiplied

by (1 -TQ Fund Tax Rate).[6] Transfer + Earnings -Management Fee.[7] Assumes that decommissioning expenditures are made at year end.See Workpaper B.6 for the total.[8] Prior Year Balafice + Net Additions

-Decommissioning Expenditures.

For Beginning Balance see Workpaper C.4.[9] The percentage to be contributed to the Tax Qualified Trust Fund is 100%.

Per the EAI 2011 ANO Decommissioning Cost Rider NDCR Update Rate Sch. No. 37 Workpapers Entergy Arkansas, Inc.ANO Decommissioning Model Tax Qualified Trust Detail -Unit 2 ($000)Tax Qualified Trust Line No 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 Average Notes: Revenue Year Rqmt. [1]Beginning Balance 2012 0 2013 0 2014 0 2015 0 2016 0 2017 0 2018 0 2019 0 2020 0 2021 0 2022 0 2023 0 2024 0 2025 0 2026 0 2027 0 2028 0 2029 0 2030 0 2031 0 2032 0 2033 0 2034 0 2035 0 2036 0 2037 0 2038 0 2039 0 2040 0 2041 0 2042 0 2043 0 2044 0 2045 0 2046 0 Earning Transfer Rate [2] To Trust [3] [9] Earnings [4]5.81% 0 14,145 5.86% 0 15,096 6.08% 0 16,587 6.40% 0 18,536 6.52%- 0 20,099 6.54% 0 21,478 6.56% 0 22,957 6.58% 0 24,541 6.61% 0 26,281 6.63% 0 28,108 6.66% 0 30,114 6.68% 0 32,223 6.70% 0 34,486 6.73% 0 36,971 6.76% 0 39,645 6.79% 0 42,525 6.81% 0 45,559 6.85% 0 48,963 6.88% 0 52,562 6.91% 0 56,442 6.91% 0 60,358 6.91% 0 64,546 6.91% 0 69,025 6.91% 0 73,814 6.51% 0 74,294 5.70% 0 69,157 4.88% 0 62,451 4.50% 0 58,357 4.50% 0 54,465 4.50% 0 44,069'4.50% 0 35,991 4.50% 0 30,478 4.50% 0 24,531 4.50% 0 21,406 4.50% 0 18,821 6.06%Mgmt. Net Decomm.Fee (5] Additions

[6] Expend. [7]234 246 259 274 290 308 327 347 368 391 415 441 469 499 532 566 603 643 686 732 781 833 889 950 1,012 1,072 1,127 1,141 1,066 867 713 607 493 433 384 13,911 14,849 16,328 18,262 19,809 21,170 22,630 24,195 25,913 27,717 29,699 31,781 34,016 36,471 39,114 41,959 44,955 48,320 51,877 55,711 59,578 63,713 68,135 72,865 73,282 68,085 61,324 57,216 53,399 43,201 35,279 29,871 24,038 20,973 18.437 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 43,239 142,750 281,860 220,701 156,425 160,567 92,705 77,781 133.609 Balance [8]239,972 253,883 268,733 285,061 303,322 323,131 344,301 366,931 391,126 417,038 444,756 474,454 506,236 540,252 576,724 615,837 657,796 702,751 751,071 802.948 858,659 918,236 981,949 1,050,084 1,122,949 1,196,231 1,264,316 1,282,401 1,196,868 968,406 790,906 669,760 539,064 470,397 413,588 298,416[1] See Workpaper B.4.[21 Projected After Tax Earnings Rates See Workpaper C.1.[3] Revenue Requirement

• (1 -Bad Debt Rate). See Workpaper B.7 for Bad Debt Rate.[4] Prior Year Balance Compounded Semiannually At Current Year Earning Rate + 1/2 Current Year Transfer

• Current Year Earning Rate.[5] Calculated on average balance according to the schedules in Workpaper B.7 multiplied by (1 -TQ Fund Tax Rate).[6] Transfer + Earnings -Management Fee.[7] Assumes that decommissioning expenditures are made at year end.See Workpaper B.6 for the total.[8] Prior Year Balance + Net Additions

-Decommissioning Expenditures.

For Beginning Balance see Workpaper C.4.[9] The percentage to be contributed to the Tax Qualified Trust Fund is 100%.

Attachment 1-E (53 pages)Entergy Arkansas, Inc. Unit Power Purchase Agreements under Service Schedule MSS-4 Lega I Services Deportment Andrea J. Weinstein Octob' ., 13, 2009 The Honorable Kimberly Bose .-Secretary

., Federal Energy Regulatory Commission

__3 CD11 888 First Street, N:E.tashington, D.C. 20426 ri 7:--? J=. ':,r, Re: Entergy Services, Inc. --Docket No. ER 10- -000 .Dear Secretary Bose: Pursuant to section 205 of the Federal.Power Act ("FPA"), 16 U.S.C. § 824d (2004), and Part 35 or the regulations of the Federal Energy Regulatory Commission

("Commission")

IS C.F.R. Part 35t(e009), Energy Services, Inc."(ES["), on behalf of'0 Entergy Gulf Slates Louisiana, L.L.C. (.EGSL") as purchaser and Entergy Arkansas, Inc., ("EM") as seller with resp~ect to a three-year contract' for certain capacity iind associated energy fromn a portion of'EAL's Wholesale Bascload ("WBL") resouirces;2 (2) Entergy Texas, Inc. ('"ETI") as purchaser and EAI as seller with respect to a three- 'ear contract for certain capacity and associated energy from a portion of AI's WB3L resources, (3) Entergy Mississippi, Inc. ("EMIce) as purchaser and Al as seller with respect to a three-year contract 4 for certain capacity and associated energy Liroi a portion of EAGs WBL resources; and(4) Entergy Louisiana, LLC. ("ELL") as purchaser and EAI as seller with respect to a three-year contract 5 for certain capacity and associated energy from a portion of EAI's WBL resources hereby submit for filing six copies of the EAI-EGSL, EGS-ETI, EAI-EMI and EAI-ELL Contracts.

The EAI-EGSL, EAI-ETI, EAI-EMI and EAI-ELI. Contracts which are the subject of this filing are being priced at cost pursuant to the currently effective Service Schedule MSS-4 of the Entergy System Agreement.

6 The EAI-EGSL Hlccitkfler, the "PAti-EGSi.

Contract.'

LPAI s WBL resources include a "'slice" of EAl coal and mnclear baseload generating resources.

Phe specific resources are listed in Attachmnent A to the enclosed LBridge Contracts.

lercrinafter.

the ".Al-TI Conract."+ -!ereini ier, the "1A1- [NI I Contract.'" 11 h:rCinn1 fter. utie "EAt-EI. Contract.1'i'C SVOeniu Ag-rct2 ut is :1 I' .("-;nppr,:e:edl

t cheduile tiled with :nimd Itlhj,2ct to Hi e exclus+ivc jurisdiction Of this Conumissiotn.

Kimberly Bose October 13. 2009 PtAge 2 Contract is tor 101.4 MW of EAI WBL resources for the period January I, 20 10 through May 31, 2012 increasing to 104.8 MW from June, 1, 2012 through December 31, 2012. The EA1-ETI Contract is for 106.6 MW of EAI WBL resources for the period January 1, 2010 through May 31. 2012 increasing to 110. 1 MW from June I, 2012 through December 31, 2012. The EAI-EMI Contract is for 76.6 MW of EAI WBL resources for the period January 1, 2010 through May 3 I, 2012 increasing to 79.1 MW from June I, 2010 through December 31-12012.

The EAI-ELL Contract is for 51.4 MW of*EA.I WBL resources for the period January I. 2010 through May 31, 2012 increasing to 53.1 IMW from June 1, 2012 through December 31, 2012. These contracts reflect the same pricing provisions and fundamentally similar contractual provisions (but for the three-year term) as the previous contracts accepted by the Commission in Docket No. ER09-183-000.ESI hereby seeks acceptance of the EAI-EGSL, EAI-ETI, EAI-EMI and EAI-ELL Contracts as just and reasonable cost-based power sales pursuant to the Commission-approved formula rate in Service Schedule MSS-4. The EAI-EGSL, EAI-ETI, EAI-EMI and EAI-ELL Contracts:

(1) are expected to result in savings to EGSL, ETI, EMI and ELL customers as compared to other alternatives for meeting customer needs, (2) are expected to benefit customers by reducing the disparity in production cost responsibility among the Entergy Operating Companies in accordance with Opinion Nos. 480 and 480-A, and (3) will reduce the extent to which EGSL, ETI, EMI and ELL are dependent upon natural gas. a fuel source that has experienced substantial price volatility.

7 For these reasons, the Contracts are just and reasonable and the Commission should accept and approve these contracts as filed effective as of January 1, 2010, without further proceedings.

!. SUMIMARY OF FILING EAI, EGSL, ET7, EMI, ELL along with Entergy New Orleans, Inc. (collectively, the"Operating Companies"), are wholly-owned subsidiaries of Entergy Corporation.

Each Operating Company is a public utility within the meaning of the FPA and, in addition, provides retail electric services to native load customers within franchised service territories subject to regulation by State or local regulatory bodies. ESI, also a wholly-owned subsidiary of Entergy Corporation, acts as agent for the Operating Companies.

In January 2003, the Operating Companies adopted a Strategic Supply Resource Plan ("SSRP"), which represents a bailanced portlfolio method to generation resource planning, incorporatting short-term and long-term contracts in order to maintain price stability among the Entergy Operating Companies.

The SSRP outlines the long-termi view of the Openrting Colmpanies" planning needs for the 2003 through 2012 tinieframe and describes the Operating Companies' strategy tor obtaining the generation resources required to meet the needs of retail cutsto.)ners.

The principal goals of the SSRP include providing low cost base load resources to all of the F"titergy Operating Companies equivalent to their individual baseload requirements.

The:.'.A.I-ki(SL, EAI-ETI. IAI-EIM I and EAI-EL L Contracts are a continuation of'the SSRIP process..uNi Pn,/ 'ublic Service ("Ommi.si n I. bI?&rX), ScIi,"cs.

Inc., ()pinion No. 4kt). I I F RtC ,i.611 1 1 21)5). Opinion No. .480-A. I 13 FERC ¶ 61.2s2 (2(1.05)

K i [ivberly Bose October 13, 2009 lkn=' 3 In Opinion No. 480, the Commission, among other things, affirmed the presidingjudge's finding that the Elntergy System was no longer in rough prodLIctioh cost equalization and that a bandwidth remedy was a just and reasonable backstop if the SSRP proved to be an ineffective remedy for production cost disparities.

As discussed below, the EAI-EGSL,.EAI-ETI, EAL-EMI and EAI-ELL Contracts have been entered into pursuant to Service Schedu, le MSS-4 of the Entergy System Agreement.

Service Schedule MSS-4 was modified.

pursuant to a settlement and approved by the Commission in Docket No. ER03-753, vi al. Because the contracts are priced pursuant to MSS-4, the contracts are just and reasonable under a Commission-approved cost-based formula rate.Furthermore, the price terms reflected in the EAI-EGSL.

EA1-ETI, EAl-EMI and EAI-ELL Contracts are comparable to the price temis for similar EAI-WBL contracts that were accepted by the Commission in Docket Nos. ER06-342, ER07-135, ERO8-160 and ER09-183.Accordingly, approval of the subject PPAs is consistent with the Commission's standards for sales between affiliates, is in the public interest, and satisfies the requirements of section 205 of the FPA.II. INFORMIATION REQUIRED BY PART 35 Consistent with the requirements of Part 35 of the Commission's regulations, ESI states that in addition to this transmittal letter, this filing includes: A. Copies of the EAI-EMI (Attachment A), EAI-EGSL (Attachment B), EAI-ETI (Attachment C) and EAI-ELL Contracts (Attachment D); and B. Additional supporting evidence (NYMEX Henry Hub natural gas futures price fbr calendar years 2010, 2011 and 2012) (Attachment E).To the extent necessary, ESI requests a waiver of the information required by section 35.13. As these contracts are fundamentally identical to previously-approved Contracts and are being tiled pursuant to Service Schedule MSS-4, which is a Commission-approved cost-based forniula rate for cost-of-service sales among the Entergy Operating Companies, the cost inbrnnation required by that section is riot relevant.Ill. CO(AMUN[CAT[ONS The 6ollowhig persons are authorized to receive notices and communications with rcspect to the instant filing: Kimbcrly I1. I)Cspeaux Richard Armst rong*\V'1) and Associate General Counsel Director, Federal Regiul;,torv Al'fairs F-ntcrgy Services.

hIc. 1:nteryv Serx ices, Inc.639 Loyola .,\vciitsc It01 Conslitltion Ave., N.W.New Orleans. L.A 70113 Suite 200 fEast Kimblerly Bose October 13, 2009 Pagie 4 (504) 576-4267 Washington, DC 20001 kdespea.entergy.com (202) 530-7341 rarinstl C@entergy.com Andrea J. Weinstein*

Assistant General Counsel Entergy Services, Inc.101 Constitution Avenue, N.W.Suite 200 East Washington, DC 2000.1 (202) 530-7342 Fax: (202) 530-7350 aweinstCentergy.com

• persons designated to receive service in this proceeding.

IV. DISCUSSION A. The Contracts are Low Cost Transactions and Represent Cost Savings to Ratepayers, and thus are Just and Reasonable.

The Contracts are just and reasonable because they provide low cost baseload resources to EGSL,. ETI, EMI and ELL and represent significant savings to ratepayers as compared to alternatives available in the marketplace.

The EAI WBL resources reflect a slice of excess EAI solid fhul capacity.

As early as the Spring of 2002, ESI began to study the possibility of selling excess EA1 WBL resources from EAM to other Entergy Operating Companies, among other things, to allocate additional low-cost solid fuel baseload resources to Operating Companies with higher than System average total production costs. Moreover, the 2006 tranche of EAI-WBL resources was the subject of Docket No. ER06-342, the 201)7 tranche of EAI-WBL resources was the subject of Docket No. ER07-135, the 2008 tranche of EAI-WBL resources was the subject of Docket No. ER08-160, and the 2009 tranche of EAI-WBL resources was the subject of Docket No. ER09-183.The EAT WBL resources comprising the Contracts include two nuclear resources, EA,'s Arkansas Nuclear One Units I and 2 and EAI's share of the Grand Gulf nuclear facility, and two coal-fired resourccs, EAI's hIdepcndcnce Steam Electric Station Unit I and EAI's White B~luff Units I and 2. T'hese solid-fuel resources, priced at cosi pursuant to MSS-4, are expected to be tess costly over the three year horizon ot the Contracts when compared to the cost og gas-1ired rcsou'ccs at prevailing market prices.Typically, nuclear fuel costs on the Entergy System average approxiniaiely S6;M\Wh.while te ene~rgy cost of coal-fired generation averages approximately S2 I1.;Wh, In contrast, at I/"lfhiew C'cviC('S, hw.. Initial Decision.

II I F'RC !! 63,077 at P 41 (2005). Opinion No. 485. 116 ft:IXRC ¶." 6[.2 ..6 (2r1 ,6). o/r 1i r,.h 'g, Opinrion 485.A, 119 FZRC! 61,019 (200 7).

Kimberly Bose October 13, 2009 Page 5 current forward market data for the three-year horizon, natural gas prices are expected to be about 6.49/immgtu, the fuel cost of a modern fuel efficient, gas-tired resource operating at a 7000 Btu/kWh heat rate would be approxinmately

$45.43/MWh.'r This compares to the projected all-in price of the EAI WBL PPAs of S40.60iMWh, and hence, represents savings compared to the alternatives available to EGSL, ETI, EMI and ELL.The Contracts were market tested against a July 2009 Baseload Request for Proposalswhich was conducted by the ESI, under the supervision of an Independent Monitor.The RFPI was designed the.match the design of the products sought to correspond, to the extent possible, to the supply role that would be filled by the Contracts.

The levelized cost of the conforming proposals that were received in response to the RFP significantly exceeded the levelized cost of the Contracts.

In addition, the solid fuel resources offer numierous other benefits to EGSL, ETI, EMI and ELL ratepayers.

Among these benefits are fuel diversity, fuel security, and fuel and price stability.

Furthermore, the baseload resources in the Contracts match the load shape needs of EGSL, ETI, EMI and ELL. Finally, as in prior years, the Contracts are expected to continue to.reduce the disparity in production cost responsibility among the Entergy Operating Companies pursuant to Opinion No. 480.B. The Cost-Based Rates of the Contracts, Priced Pursuant to Commission-Approved Service Schedule MSS-4, are Just and Reasonable

1. Operation oj'MSS-4 Service Schedule MSS-4 of the Entergy System Agreement relates to a unit power purchase between Entergy Operating Companies and/or a sale of power purchased byan Operating Company. A unit power purchase is defined as the purchase of a portion of the capability of a generating resource sold pursuant to MSS-4 (the "Designated Generating Unit" or"DGU"), which entitles the purchaser to receive each hour, the same portion of the total energy generated by that resource.

MSS-4 prescribes a formula rate for calculating the payment by 6ne Operating Company to another Operating Company for a sale of the capability and associated energy of a DGU. By its terms, MSS-4 applies to capacity and associated energy owned by Operating Companies and otftrcd to other Operating Companies.

See System Agreement

§40.01. Section 2.02 of the System Agreement defines "Company" as one of tile Entergy Operating Companies.

As OtA.,uust t4, 2009, the tcvclizcd NY iMEX I lcnry I-ub niatulal gas f turIs price fOr calendar years 2010-212 is S6.49!rmnilliu.

See; tlachmcnt E. ESt notes that the NYMEX Henry hlub natural gas futures price has iecreased since August 14, 2009. As of September

30. 2009, thie lcvtlized NY %M I'X tHenry H-fub natural gas I'luurs price for calendar years 2010-2012 was S%.67h:IInlIj, which restilis in a geveralion fuel cost of $46.69iMWh.

Kiiinbezly B3ose October 13. 21009 Paue 6" 2. -.lIpwovcd Rcvisiows to MSS-4 On April 18, 2003, ES[ tiled fbr Commission approval of certain limited modifications to Service Schedule ?NISS-4. On June 10, 2003, the Commission issued an order accepting and suspending the amendments to Service Schedule MSS-4, subject to hearing, and establishing hearing procedures.")

The MSS-4 proceeding was coordinated with, but not consolidated with, the PPA. Proceeding, which involved the approval of eight PPAs among affiliated Entergy companies.

On August 13, 2004, following settlement discussions, ESJ filed an MSS-4 Settulicrnt Ofter on behalf of the Settling and FERC Trial Staff. On October 6, 2004, the Presiding Administrative Law Judge certified .the Settlement Offer to the Commission. Subsequently, on November 24, 2004, ESI filed a revised Service Schedule NISS-4 to incorporate two minor issues raised by FERC Trial Staff.On April 14, 2005, the Commission approved the MSS-4 Settlement, thus making the November 24, 2004 MSS-4 the currently effective MSS-4.1 As a condition in its order, the Commission required ESI to file a notice with the Commission within 30 days of any Operating Company's en tering into any long-term transaction pursuant to Service Schedule MSS-4.'"15 The Commission defined "long-term" transactions as"one year or more."' 6 According to the Commission, suchka notice condition "will provide interested parties with the ability to identify and the opportunity to challenge the transaction under section 206 of the FPA," and is therefore a reasonable resolution of the MSS-4 settlement.

1 7 In this instance, however, ESI is not making an informational filing regarding an MSS-4 transaction.

Rather, ESI is tiling these contracts under FPA section 205. Indeed, the reason ES[is making a section 205 filing here, as opposed to providing notice of long-term MSS-4 transactions within 30 days after Operating Companies enter into the transactions, stems from Section 40.09 of MSS-4. That section provides that a resale under MSS-4 of energy from the Grand Gulf nuclear facility shall be subject to the approval of the Commission.

It is important that the Comninission understand that the sole trigger fbr this particular filing requirement, is the presence of Grand Gulf energy in the transaction.

In other words, but for the inclusion of any Grand Gulf energy in the sale, there would not be and need not be a section 205 filing utnder the terms ot'the Commission approved settlement.

Ent.ig. Services.

hic., 103 FERC !161,322 (21)03).Docket Nos. -ItR03-5,3-(J00.

[R03-68 -()000, ER03-682-000, anrd ER03-744-)00, ct ,tl.The Sctttling Parties are -SI, the .,MISC, the L.I'SC'. mnd CNO,:' (.L'v'rtlith'aliu Docket No. ER03-7753-000 (October 6, 20.04).i4 Entcrgy Seirviecs.

hn., I I I FE RC 4,1 6 .035 42o05 ).I1d. it PPt I )0.hi. at 1' 20.hi1,. :it IP11-10,2-1

.

Kimberly Bose October' 13,-2009 Page 7 There is no dispute that the tbmrula rate reflected in the revised MSS-4 produces a just and reasonable cost-based rate. Indeed, as the Commission noted, even the non-settling parties do not object to any of the proposed revisions to Service Schedule MSS-4 set tbrth iII the settlement.

i Because these contracts are being filed pursuant to Service Schedule MSS-4, the 2009 contracts arejust and reasonable under a Commission-approved cost-based formula rate.V. EFFECTIVE DATE ESI requests that the Contracts be made effective as of January 1, 2010.VI. OTHER FILING REQUIREMENTS ESI knows of no costs included in the cost of service that have been alleged or judged in any administrative orjudicial proceeding to be illegal, duplicative, or unnecessary costs that are the product ofdiscriminatory practices.

The cost of service specifically is made subject to the Commission-approved Service Schedule MSS-4.VII. CONCLUSION Accordingly, ESI asks that the Commission accept the EAI-EGSL Contract, EAI-ETI Contract, EAI-EMI Contract and the EAI-ELL Contract for filing, and grant any waivers of the requirements in 18 C.F.R. Part 35 nt~cessary to allow the contracts to go into effect on January 1.2010.If you have any questions concerning this filing, please feel free to contact the undersigned.

Very truly yours, Andrea J. Weinstcin Attorney for EIitemry Services, Inc.,A\ttachrnerts cc: Service List in Docket No. ER13-583-000 l,/* at I' t ATTACHMENT A

Entergy Arkansas, Inc.. Third Revised Rate Schedule FERC No. 94 Foittrgy GulirStafes Louisiana, L.L.C., Rate Schedule FERC No, 181 Entcrgy Louisiana.

L.LC, Third Revised Rate Schedule FERC" No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 Entergy Operating Companies Service Agreement No. 564 Service Schedule MSS-4 Agreement by and between Entergy Arkansas, Inc., (Seller) and Entergy Mississippi, Inc. (Buyer)ISSIuLd hy: Kil 1 hrl y Des peaux VP mid .\5 sociltc (:Gicreml C.ounscl L- Ifecli e: imitluarv 1, i20)I0 ls.ujcd of): ()ctehcr 13. 2001)

AGREEMENT This Agreement is dated as of September 8, 2009 between Entergy Arkansas, Inc., ("EAT" or "Seller"), and Entergy Mississippi, Inc. ("EMI" or "Buyer").WHEREAS, EAI has agreed to make a unit power sale from the designated units set forth on Attachment A (individually a "Designated Unit" and collectively "Designated Units") to EMI; and WHEREAS, the Agreement among the Entergy Operating Companies (hereinafter referred to as the "System Agreement"), was filed with the FERC on April 30, 1982, and became effective on January 1, 1983, and amended to incorporate Entergy Gulf States, Inc. in 1993 and further amended in 2008 to split Entergy Gulf States, Inc, into Entergy Gulf States, Louisiana, L.L.C. and Entergy Texas, Inc.; and WHEREAS, the System Agreement contains a Service Schedule MSS-4 providing the basis for making a unit power purchase between the Companies that are participants in that Agreement; and WHEREAS, the parties herein wish to. execute this Agreement to provide for a unit power purchase by EMI under Service Schedule MSS-4 from the Designated Units.THEREFORE, the parties agree as follows: l. Designated Units. The designated generating units for purposes of this unit power purchase under Service Schedule MSS-4 of the System Agreement shall be those units set forth on Attachment A.2. Unit Power Purchase.

EAI agrees to sell and'EMI agrees to purchase that quantity of generating capacity and associated energy from the Designated Units equivalent to the percentage (the "Allocated Percentage")

of EAI's baseload capacity in each such Designated

-

Unit set forth on Attachment A, with such sale and purchase to become effective on January 1, 2010 and to continue thereafter until December 31, 2012.3. Pricing. The pricing of the capacity and energy to be sold and purchased pursuant to paragraph 2 above shall be as specified in Service Schedule MSS-4 of the System Agreement.

4. Energy Entitlement.

EMI is entitled to receive on an hourly basis the Allocated Percentage of the energy generated by each of the Designated Units.5. Termination.

Neither party shall have the right to terminate the unit power purchase and sale required by this Agreement without the express written consent of the other party.6. Condition Precedent.

This contract shall be conditioned upon Buyer receiving all regulatory approvals required for this Agreement no later than December 21, 2009.7. Notices. Unless specifically stated otherwise herein, any notice to be given hereunder shall be sent by Registered Mail, postage prepaid, to the party to be notified at the address set forth below, and shall be deemed given when so mailed.To EAI: Entergy Arkansas, Inc.425 West Capitol Avenue Little Rock, AR 72201 ATTN: Chief Executive Officer To EMI: Entergy Mississippi, Inc.P.O. Box 1640 Jackson, MS 39215 ATIN: Chief Executive Officer 8. Nonwaiver:

The failure of either party to insist upon or enforce, in any instance, strict performance by the other of any of the. terms of this Agreement or to exercise any rights herein conferred shall not be considered as a waiver or relinquishment to any extent of its rights to assert or rely upon any such terms or rights on any future occasion.

9. Amendments.

No waiver, alteration, amendment or modification of any of the provisions of this Agreement shall be binding unless in writing and signed by a duly authorized representation of both parties.10. Entir Agreement.

This Agreement, which is entered into in accordance with the authority of Service Schedule MSS-4 of the System Agreement, constitutes the entire agreement between the parties with respect to the subject matter hereof and supersedes all previous and collateral agreements or understandings with respect to the subject matter hereof.II. Severability.

It is agreed that if any clause or provision of this Agreement is held by the courts to be illegal or void, the validity of the remaining portions and provisions of the Agreement shall not be affected, and the rights and obligations of the parties shall be enforced as if the Agreement did not contain such illegal or void clauses or provisions.

ENTERGY4 SAC BY: TITLE: ý"ý 6" i ENTERGY MISSISSIPPI, INC.BY: TITLE:

N 9. Amendments.

No waiver, alteration, amendment or modification of any of the provisions of this Agreement shall be binding unless in writing and signed by a duly authorized representation of both parties.10. Entire Agreement.

This Agreement, which is entered into in accordance with the authority of Service Schedule MSS-4 of the System Agreement, constitutes the entire agreement between the parties with respect to the subject matter hereof and supersedes all previous and collateral agreements or understandings with respect to the subject matter hereof.11. Severability.

It is agreed that if any clause or provision of this Agreement is held by the courts to be illegal or void, the validity of the remaining portions and provisions of the Agreement shall not be affected, and the rights and obligationsof the parties shall be enforced as if the Agreement did not contain such illegal or void clauses or provisions.

ENTERGY ARKANSAS, INC.BY: TITLE: EINTERGY INC BY: TITLE: 5 -C 0 ATTACHMENT A SALE OF CAPACITY AND ENERGY BY ENTERGY ARKANSAS, INC. TO ENTERGY MISSISSIPPI, INC.During the period, January 1, 2010 through May 31, 2012, the capacity and energy amount is as follows: EAI's EAI's AVAILABLE BUYER'S BUYER'S BASELOAD BASELOAD ALLOCATED ALLOCATED CAPACITY*

CAPACITY*

CAPACITY*

PERCENTAGE DESIGNATED UNITS ANO Unit I 842.00 71.0 16.2 22.8%ANO Unit 2 997.00 84.2 19.2 22.8%White Bluff Unit I 465.00 39.3 8.9 22.8%White Bluff Unit 2 481.00 40.6 9.3 22.8%Independence Unit 1 263.00 22.2 5. I 22.8%Grand Gulf- No Retained Share 318.00 26.4 6.0 22.8%..Grand Gulf Retained Share 90.00 52.3 11.9 22.8%TOTAL 336.0 76.6 22.8%During the period, June I, 2012 through December 31, 2012 (including the Grand Gulf Uprate), the capacity and energy amount is as follows: EAI's EAI's AVAILABLE BUYER'S BUYER'S BASELOAD BASELOAD ALLOCATED ALLOCATED CAPACITY*

CAPACITY*

CAPACITY*

PERCENTAGE DESIGNATED UNITS ANO Unit 1 842.00 71.0 16.2 22.8%ANO Unit 2 997.00 84.2 19.2 22.8%White Bluff Unit I 465.00 39.3 8.9 22.8%White BluffUnit 2 481.00 40.6 9.3 22,8%Independence Unit I 263.00 22.2 5.1 22.8%Grand Gulf- No Retained Share 363.00 30.2 6.9 22.8%Grand Gulf Retained Share 102.00 59.7 13.6 22.8%TOTAL 347.1 79-L 22.8%*Expressed in megawatts.

To the extent EAI's Baseload Capacity increases or decreases, Buyer's Allocated Capacity shall adjust correspondingly based on Buyer's Allocated Percentage of EAI's Baseload Capacity..f ATTACHMENT B

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Eutergy Louisiana, LLC. Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. S Entergy Texas, Inc., Rate Schedule FERC No. 181 Entergy Operating Companies Service Agreement No. 565 Service Schedule MSS-4 Agreement by and between Entergy Arkansas, Inc., (Seller) and Entergy*Gulf States Louisiana, L.L.C. (Buyer)ks-.ticd h: Kin hcrl v lI')eS pt.'z, x%T m id A\ssoc im C1c ti enra Co(uu s c E fftictivc: .I;ILuar'v I., 201)1 kudonl: O.ciober 13, 2001)

.AGREEMENT This' Agreement is dated as of / between Entergy Arkansas, Inc., ("EAI" or "Seller"), and Entergy Gulf States Louisiana, L.L.C. ("EGSL" or "Buyer").WHEREAS, EA1 has agreed to make a unit power sale from the designated units set forth on Attachment A (individually a "Designated Unit" and collectively "Designated Units") to EGSL; and WHEREAS, the Agreement among EAM, Entergy Gulf States, Inc. ("EGS"), and Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc. and Entergy Services, Inc.(hereinafter referred to as the "System Agreement"), was filed with the FERC on April 30, 1982, and became effective on January 1, 1983, and amended to incorporate Entergy Gulf States, Inc.in 1993 and fuirther amended in 2008 to split Entergy Gulf States, mnc, into Entergy Gulf States, Louisiana, L.L.C. and Entergy Texas, Inc.; and WHEREAS, the System Agreement contains a Service Schedule MSS-4 providing the basis for making a unit power purchase between the Companies that are participants in that Agreement; and WHEREAS, the parties herein wish to execute this Agreement to provide for a unit power purchase by EGSL under Service Schedule MSS-4 from the Designated Units.THEREFORE, the parties agree as follows: I. Designatd Units. The designated generating units for purposes of this unit power purchase under Service Schedule MSS-4 of the System Agreement shall be those. units set forth on Attachment A.2. Unit Power Purchase.

EAI agrees to sell and EGSL agrees to purchase that quantity of generating capacity and associated energy from the Designated Units equivalent to the percentage (the "Allocated Percentage")

of EAI's baseload capacity in each such Designated Unit set forth on Attachment A, with such sale and purchase to become effective upon January 1, 2010 and to continue thereafter until December 31, 2012.3. PTrci. The pricing of the capacity and energy to be sold and purchased pursuant to paragraph 2 above shall be as specified in Service Schedule MSS-4 of the System Agreement.

.4. Energv Entitlement.

EGSL is entitled to receive on an hourly basis the Allocated Percentage of the energy generated by each of the Designated Units.5. Termination.

Neither party shall have the right to terminate the unit power purchase and sale required by this Agreement without the express written consent of the other party.6. Condition Precedent.

This contract shall be conditioned upon Buyer receiving all regulatory approvals required for this Agreement no later than December 21, 2009.7. Notices Unless specifically stated otherwise herein, any notice to be given hereunder shall be sent by Registered Mail, postage prepaid, to the party to be notified at the address set forth below, and shall be deemed giveti when so mailed.To EAI: Entergy Arkansas, Inc.425 West Capitol Avenue Little Rock, AR 72201 ATTN: Chief Executive Officer To EGS: Entergy Gulf States Louisiana, L.L.C.446 North Boulevard Baton Rouge, Louisiana 70802 ATTN: Chief Executive Officer 8. Nonwaiver:

The failure of either party to insist upon or enforce, in any instance, strict performance by the other of any of the terms of this Agreement or to exercise any rights herein conferred shall not be considered as a waiver or relinquishment to any extent of its rights to assert or rely upon any such terms or rights on any future occasion.

Amendments.

No waiver, alteration, amendment or modification of any of the provisions of this Agreement shall be binding unless in writing and signed by a duly authorized representation of both parties.10. Entire Agreement.

This Agreement, which is entered into in accordance with the authority of Service Schedule MSS-4 of the System Agreement, constitutes the entire agreement between the parties with respect to the subject matter hereof and supersedes all previous and collateral agreements of understandings with respect to the subject matter hereof.11. $everability.

It is agreed that if any clause or provision of this Agreement is held by the courts to be illegal or void, the validity of the remaining portions and provisions of the Agreement shall not be affected, and the rights and obligations of the parties shall be enforced as if the Agreement did not contain such illegal or void clauses or provisions.

ENTERGY ARKANSAS, INC.BY: ENTERGY GULF STATES LOUISIANA.

L.L.C.BY: TITLE:

ATTACHMENT A SALE OF CAPACITY AND ENERGY BY ENTERGY ARKANSAS, -INC. TO ENTERGY GULF STATES LOUISIANA, L.L.C.During the period, January 1, 2010 throiugh May 31, 2012, the capacity and energy amount is as follows: EAI's EA's AVAILABLE BUYER'S BUYER'S BASELOAD BASELOAD ALLOCATED ALLOCATED CAPACITY*

CAPACITY*

CAPACITY*

PERCENTAGE DESIGNATED UNITS ANO Unit 1 842.00 71.0 21.4 30.2%ANO Unit 2 997.00 84.2 25.4 30.26/6 White Bluff Unit 1 465.00 39.3 I 1.8 3.0.2%White Bluff Unit 2 481.00 40.6 12.3 30.2%Independence Unit I 263.00 22.2 6.7 30.2%Grand Gulf- No Retained Share 318.00 26.4 8.0 30.2%Grand Gulf Retained Share 90.00 52.3 15.8 30.2%TOTAL 336.0 101A4 30.2%During the period, June 1. 2012 through December 31, 2012 (including the Grand Gulf Uprate), the capacity and energy amount is as follows: EAI's EAI's AVAILABLE BUYER'S BUYER'S BASELOAD BASELOAD ALLOCATED ALLOCATED CAPACITYO CAPACITY*

CAPACITY*

PERCENTAGE DESIGNATED UNITS ANO Unit 1 842.00 71.0 21.4 30.2%ANO Unit 2 997.00 54.2 25.4 30.2%White BluffUnit I 465.00 39.3 11.8 30.2%White Bluff Unit 2 481.00 40.6 12.3 30.2%Independence Unit 1 263.00 22.2 6.7w 30.2%Grand Gulf- No Retained Share 363.00' 30.2 9. 1 30.2%Grand Gulf Retained Share 102.00 59.7 18.0 30.2%TOTAL 342.1 104.8 30.2%'Expressed in megawatts.

To the extent EAI's Baseload Capacity increases or decreases, Buyer's Allocated Capacity shall adjust correspondingly based on Buyer's Allocated Percentage of EAI's Baseload Capacity.

ATTACHMENT C

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Entergy Gulf States Louisiana.

L.L.C., Rate Schedule FERC No. 181 Entergy LoUisiana, LLC, Third Revised Rate Schedule FERC No. 69.ntcrgy Mississippi.

inc.. Third Revised Rate Schedule FERC No. 262 Elntergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Elntergy Texas, Inc., Rate Schedule FERC No. 181 Entergy Operating Companies Service Agreement No. 566 Service Schedule hISS-4 Agreement by and between Entergy Arkansas, Inc., (Seller) and Entergy Texas, Inc. (Buyer)Is ucic hy: Klmict-~ly De-,pcaux\'P and A,;soclate

('icnral Couns;el Fl'ctt.c1vc:

Jaluklrv I ( I k stlcd on: *..J)ciuber 13, 2001)

AGREEMIENT This Agreement is dated as of between Entergy Arkansas, [nc., ("EAt" or "Seller"), and Entergy Texas, Inc. ("ETI" or "Buyer'").

WHEREAS, EAI has agreed to make a unit power sale from the designated units set forth on Attachment A (individually a "Designated Unit" and collectively "Designated Units")to ETI; and WHEREAS, the Agreement among EAI, Entergy Gulf States, Inc. ("EGS"), and Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc. and Entergy Services, Inc. (hereinafter referred to as the "System Agreement"), was filed with the FERC on April 30, 1982, and became effective on January 1, 1983, and amended to incorporate Entergy Gulf States, Inc. in 1993 and further amended in 2008 to split Entergy Gulf States, Inc, into Entergy Gulf States, Louisiana, L.L.C. and Entergy Texas, Inc.; and WHEREAS,'

by Order dated July 20, 2007,'the FERC approved the addition of Entergy Gulf States Louisiana, L.L.C. and ETI as parties to the System Agreement; and WHEREAS, the System Agreement contains a Service Schedule MSS-4 providing the basis for making a unit power purchase between the Companies that are participants in that Agreement; and WHEREAS, the parties herein wish to execute this Agreement to provide for a unit power purchase by ETI under Service Schedule MSS-4 from the Designated Units.THEREFORE, th6 parties agree as follows: I. Designated Units. The designated generating units for purposes of this unit power purchase under Service Schedule MSS-4 of the System Agreement shall be those units set forth on Attachment A.

2. Unit Power Purchase.

EAI agrees to sell and ETI agrees to purchase that quantity of generating capacity and associated energy from the Designated Units'equivalent to the percentage (the "Allocated Percentage")

of EAI's baseload capacity in each such Designated Unit set forth on Attachment A, with such sale and purchase to become effective upon January 1; 2010 and to continue thereafter until December 31, 2012.3. Pr.cin. The pricing of the capacity and energy to be sold and purchased pursuant to paragraph 2 above shall be as specified in Service Schedule MSS-4 of the System Agreement.

4. Energy Entitlement.

ETI is entitled to receive on an hourly basis the Allocated Percentage of the energy generated by each of the Designated Units.5. T. Neither party shall have the right to terminate the unit power purchase and sale required by this Agreement without the express written consent of the other party.6. Condition Precedent.

This contract shall be conditioned upon Buyer receiving all regulatory approvals required for this Agreement no later than December 21, 2009.7. Notices. Unless specifically stated otherwise herein, any notice to be given hereunder shall be sent by Registered Mail, postage prepaid, to the party to be notified at the address set forth below, and shall be deemed given when so mailed.To EMA: Entergy Arkansas, Inc.425 West Capitol Avenue Little Rock, AR 72201 ATTN: Chief Executive Officer To ETI: Entergy Texas, Inc.350 Pine Street Beaumont, TX 77701 AT'TN: Chief Executive Officer

8. Nonwaiver:

The failure of either party to insist upon or enforce, in any instance, strict performance by the other of any of the terms of this Agreement or to exercise any rights herein conferred shall not be considered as a waiver or relinquishment to any extent of its rights to asseit or rely upon any such terms or rights on any future occasion.9. Amendments.

No waiver, alteration, amendment or modification of any of the provisions of this Agreement shall be binding unless in writing and signed by a duly authorized representation of both parties.10. EntimASrmment.

This Agreement, which is entered into in accordance with the authority of Service Schedule MSS-4 of the System Agreement, constitutes the entire agreement between the parties with respect to the subject matter hereof and supersedes all previous and collateral agreements of understandings with respect to the subject matter hereof I1. .Sevebilit

.it is agreed that if any clause or provision of this Agreement is held by the courts to be illegal or void, the validity of the remaining portions and provisions of the Agreement shall not be affected, and the rights and obligations of the parties shall be enforced as if the Agreement did not contain such illegal or void clauses or provisions.

ENTERGY WASS TITLE:I-i 9e e-'D ENTERGY TEXAS, INC.BY: TITLE:

8. Nonwaiver:

The failure of either party to insist upon or enforce, in any instance, strict performance by the other of any of the terms of this Agreement or to exercise any rights herein conferred shall not be considered as a waiver or relinquishment to any extent of its rights to assert or rely upon any such terms or rights on any future occasion.9. Amendments.

No waiver, alteration, amendment or modification of any of the provisions of this Agreement shall be binding unless in writing and signed by a duly authorized representation of both parties.10. Entire Agreement.

This Agreement, which is entered into in accordance with the authority of Service Schedule MSS-4 of the System Agreement, constitutes the entire agreement between the parties with respect to the subject matter hereof and supersedes all previous and collateral agreements of understandings with respect to the subject matter hereof.I1. Severability.

It is agreed that if any clause or provision of this Agreement is held by the courts to be illegal or void, the validity of the remaining portions and provisions of the Agreement shall not be affected, and the rights and obligations of the parties shall be enforced as if the Agreement did not contain such illegal or void clauses or provisions.

ENTERGY ARKANSAS, INC.BY: TITLE: ENTERGYT AS, INC., BY: TITLE: 4Om cn7 C-90 ATTACHMENT A SALE OF CAPACITY AND ENERGY BY ENTERGY ARKANSAS, INC. TO ENTERGY TEXAS, INC.During the period, January 1, 2010 through May 31, 2012, the capacity and energy amount is as follows: EAI's EAI's AVAILABLE BUYER'S BUYER'S BASELOAD BASELOAD ALLOCATED ALLOCATED CAPACITY9 CAPACITY0 CAPACITY*PERCENTAGE DESIGNATED UNITS ANO Unit I 842.00 71.0 22.5 31.70/6 ANO Unit 2 997.00 84.2 26.7 31.7%White Bluff Unit 1 465.00 39.3 12.4 31.7%/6 White Bluff Unit 2 481.00 40.6 12.9 31.7%Independence Unit 1 263.00 22.2 7.0 31.7%Grand Gulf- No Retained Share 318.00 26.4 8.4 31.7%h Grand Gulf Retained Share 90.00 52.3 16.6 31.7%o TOTAL 336.0 106.6 31.7%/6'During the period, June I, 2012 through December 31, 2012 (including the Grand Gulf Uprate), the capacity and energy amount is as follows: EAI's EAI's AVAILABLE BUYER'S BUYER'S BASELOAD BASELOAD ALLOCATED ALLOCATED CAPACITY*

CAPACITY*

CAPACITY*PERCENTAGE DESIGNATED UNITS ANO Unit 1 842.00 71.0 22.5 31.7%ANO Unit 2 997.00 84.2 26.7 31.7%White Bluff Unit I 465.00 39.3 12.4 31.7%White Bluff Unit 2 481.00 40.6' 12.9 31.7'/a Independence Unit 1 263.00 22.2 7.0 31.7%Grand Gulf- No Retained Share 363.00 30.2 9.6 31.7%Grand Gulf Retained Share 102.00 59.7 18.9 31.7%TOTAL 347A1 110.1 31.70%*Expressed in megawatts.

To the extent EAI's Baseload Capacity increases or decreases, Buyer's Allocated Capacity shall adjust correspondingly based on Buyer's Allocated Percentage of EAI's Baseload Capacity.

ATTACHMENT D

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 1Entcrgy Gulf States Louisiana, LL.C., Rate Schedule FERC No. 181 Entergy Louisiana.

LLC. Third Revised Rate Schedule FERC No. 69 EnLcrgy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Emergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 Entergy Operating Companies Service Agreement No. 567 Service Schedule MSS-4 Agreement by and between Entergy Arkansas, Inc., (Seller) and Entergy Louisiana, LLC (Buyer)Issucd I': li Iel epai VP' 11d A~ssoc~itc Gencrac~l Coulisel F.11'ectl\

k.: .1mmarv I .20 11.)ls~~1iccI" (n AK'~bc ; ~ 2t AGREEMENT This Agreement is dated as of 1/ 0 between Entergy Arkansas, Inc., ("EAI" or "Seller"), and Entergy Louisiana, LLC ("ELL" or "Buyer").WHEREAS, EAI has agreed to make a unit power sale from the designated units set forth on Attachment A (individually a "Designated Unit" and collectively "Designated Units")to ELL; and WHEREAS, the Agreement among the Entergy Operating Companies (hereinafter referred to as the "System Agreement"), was filed With the FERC on April 30, 1982, and became effective on January 1, 1983, and amended to incorporate Entergy Gulf States, Inc. in 1993 and further amended in 2008 to split Entergy Gulf States, Inc, into Entergy Gulf States, Louisiana, L.L.C. and Entergy Texas, Inc.; and WHEREAS, the System Agreement contains a Service Schedule MSS-4 providing the basis fbr making a unit power purchase between the Companies that are participants in that Agreement; and WHEREAS, the parties herein wish to execute this Agreement to provide for a unit power purchase by ELL under Service Schedule MSS-4 from the Designated Units.THEREFORE, the parties agree as follows: I. DeignatedL na. The designated generating units for purposes of this unit power purchase under Service Schedule MSS-4 of the System Agreement shall be those units set forth on Attachment A.2. Unit Power Purchasc.

EAI agrees to sell and ELL agrees to purchase that quantity of generating capacity and associated energy from the Designated Units equivalent to the percentage (the "Allocated Percentage")

of EAI's baseload capacity in each such Designated Unit set forth on Attachment A, with such sale and purchase to become effective on January 1, 2010 and to continue thereafter until December 31, 2012.3. The pricing of the capacity and energy to be sold and purchased pursuant to paragraph 2 above shall be as specified in Service Schedule MSS-4 of the System Agreement.

4. Energy Entitlement.

ELL is entitled to receive on an hourly basis the Allocated Percentage of the energy generated by each of the Designated Units.5. Termination.

Neither party shall have the right to terminate the unit power purchase and sale required by this Agreement without the express written consent of the other party.6. Condition Precedent.

This contract shall be conditioned upon Buyer receiving all regulatory approvals required for this Agreement no later than December 21, 2009.7. Notices. Unless specifically stated otherwise herein, any notice to be given hereunder shall be sent by Registered Mail, postage prepaid, to the party to be notified at the address set forth below, and shall be deemed given when so mailed.To EAI: Entergy Arkansas, Inc.425 West Capitol Avenue Little Rock, AR 72201 ATTN: Chief Executive Officer To ELL: Entergy Louisiana, LLC 4809 Jefferson Hwy Jefferson, LA 70121 ATTN: Chief Executive Officer 8. Nonwaiver:

The failure of either party to insist upon or enfbrce, in any instance, strict performance by the other of any of the terms of this Agreement or to exercise any rights herein conferred shall not be considered as a waiver or relinquishment to any extent of its rights to assert or rely upon any such terms or rights on any future occasion.

9. -Amendment.

No waiver, alteration, amendment or modification of any of the provisions of this Agreement shall be binding unless in writing and signed by a duly authorized representation of both parties.10. Entire- Agrement.

This Agreement, which is entered into in accordance with the authority of Service Schedule MSS-4 of the System Agreement, constitutes the entire agreement between the parties with respect to the subject matter hereof and supersedes all previous and collateral agreements or understandings with respect to the subject matter hereof.11. Sevkiit. It is agreed that if any clause or provision of this Agreement is held by the courts to be illegal or void, the validityof the remaining portions and provisions of the Agreement shall not be affected, and the rights and obligations of the parties shall be enforced as if the Agreement did not contain such illegal or void clauses or provisions.

EN;ERY A NSAS, INC BY: TITLE:rL J d)~ENTERGY LOUISIANA, LLC BY: TITLE:

ATTACHMENT A SALE OF CAPACITY AND ENERGY BY ENTERGY ARKANSAS, INC. TO ENTERGY LOUISIANA, LLC During the period, January 1, 2010 through May 31, 2012, the capacity and energy amount is as follows: EAI's EAI's AVAILABLE BUYER'S BUYER'S BASELOAD BASELOAD ALLOCATED ALLOCATED CAPACITY*

CAPACITY*

CAPACITY*PERCENTAGE DESIGNATED UNITS ANO Unit 1 842.00 71.0 10.9 15.3%ANO Unit 2 097.00 84.2 12.9 15.3%White Bluff Unit 1 465.00 39.3 6.0 15.3%White Bluff Unit 2 481.00 40.6 6.2 15.3%Independence Unit 1 263.00 22.2 3.4 15.3%Grand Gulf- No Rctained Share 318.00 26.4 4.0 15.3%Grand Gulf Retained Share 90.00 52.3 8.0 15.3%TOTAL 336.0 51.4 15.3%During the period, June I, 2012 through December 31, 2012 (including the Grand Gulf Uprate), the capacity and energy amount is as follows: EAI's EAI's AVAILABLE BUYER'S BUYER'S BASELOAD BASELOAD ALLOCATED ALLOCATED CAPACITY*

CAPACITY*

CAPACITY*PERCENTAGE DESIGNATED UNITS ANO Unit 1 842.00 71.0 10.9 15.3%ANO Unit 2 997.00 84.2 12.9 15.3%White Bluff Unit I 465.00 39.3 6.0 15.3%White Bluff Unit 2 481.00 40.6 6.2 15.3%Independence lrnit 1 263.00 22.2 3.4 15.3%Grand Gulf- No Retained Share 363.00 30.2 4.6 15.3%Grand Gulf Retained Share 102.00 59.7 9.1 15.3%TOTAL 347.1 53.1 15.3%'Expressed in megawatts.

To the extent EAI's Baseload Capacity increases or decreases, Buyer's Allocated Capacity shall adjust correspondingly based on Buyer's Allocated Percentage of EAI's Baseload Capacity.

ATTACHMENT E

NYMEX Natural Gas Futures$6.49 Levelzed Price Contract Jan.-2010 Ft-b-2010 Mar-2010 Apt-20,0 1lay-2O10 ju,.-2010 Jul-2010 Aug-2010 Sep.'20o Oct-2 0 10 Nov-2010 Dec-2 0 10 Jau-20I11 F'eb-2011 Mar-2011.Apr-2011 May-20 11 Jun-2011 Jul-2011 Aug-2011 Se0-2 011 0ct-2011 Nov-2011 Oec-2011 Ja.n-2012 Feb-2012 Mar-2012 Apr-2012 May-2012 Jun-2012 Jul-2012 Aug-2012 Sep-2012 Oci-2 0 1 2 tiov.2012 Dec-2012 Prior Settle ($ImrSliu) 5.616 5.650 5 602 5.550 5,605 8.70 5.817 5.912 5.975 6.095 6.480 6.850 7.075 7.070 6.890 6.405 6.375 6.455 6.545 8.615 8.645 6.725 6,970 7.255 7.465 7.460 7.235 6.535 6.490 6.570 6,665 6.730 6.760 6.840 7.065 7.340 H4191%(mmu)5.580' 5.590 5 570 5.810 5.920 6.4,50 6.395 7,240 6.50 Low lSimmBtju) 5.570 5.590 5.54 0 5.320 5915 6.450 6.395 7.240 6.50 Secttl ($/mnl~tu) 5.584 5,323 5,581 5,531 5.591 6 688 5.806" 5.901 5.964 6.084 6A474 6.849 7.074.7.069 6.889 6.404 6.374 6.454 6.544 6.614 6.644 6.7 24 6.969 7.254 ,7.464 7.459 7.234 6,534 6.489 6.569 6.664 6.729 6.759 6.039 7.064 7.339 Change ($)mnhl~tu)

-032-.027-021-019-.014-.012-011-011-.006-.001-.00-001-.001-.001-.001-.001-001-.001-.001.,001-.001-.001-.001-.001-.001-.001-.001-.001-.001-001-.001-.001-.001 Volurne 10020 1526 2315 2675 573 1597 2073 1720 653 363 127" 150 118 49 128 15 112 2 2 9 6 3 8 8 4 6 406 1 400 4 30 27 3 1 6 2 Changes in settlement price with zero volume mean t11e settlement price is implied. No actual trading took place for these contracts on the given day.Ptca is based on delivery at the Henry Hub in Louis~ana, wh.ch serves markets throughout

[he US East Coast. the Gull Coast, the Midwest. and up to the Catadion border.C q 12i 9. "'NL I'; ",,iLC NYMEX Natural Gas Futures$6.7 Levelized Price Contract Prior Settle High Low Settle Change Volume ($menBlu)

I/mnmtu) ($ImmBlu) (S/Immatu) (SImmBtu)Jan-2C10 5.954 5965 .Oil 16.549 Feb-2010 5.9s0 5.991 011 4,117 Mar-2010 5.)29 .5 937 .C08 5.406 Apr-201U 5.894 5,909 .015 6.455 May. 20110 5.928 5.912 5.912 5.944 .016 3.401 Jun-2010 5.996 5.960 5980 6.012 016 2.,04 Jul-2010 6.081 6.099 .018 6hi8 Aug-2C10 6.158 6.115 6.115 6. 179 .02 f 972 Sep-2010 6 225 6.i39 .014 174 Oct-2010 6.384 6.340 6340 6.396 .012 2.768 Nov.2010 6.329 -. 6.741 .012 300 Dec-2010 7.074 7.084 010 449 Jan-2011 7.299 7.311 .012 307 Feb-2011 7.284 7.201 .007 57 Mar-2011 7084 7.10 7.10 7.091 ..007 64 Apr-2011 6.519 6.530 6.530 6.526 .007 236 May-20 I1 6 464 6.480 6480 6.471 .007 2.tuin-201 I 6.534 6.540 6.540 6.536 .002 3 Jul-20? ? 6.614 6.635 6.635 6.616 .002 10 Aug-2011 6.684 6.690 6.690 8.686 002 0 Sep-2011 6.714 6.720 6.720 6.716 .002 2 Oct-20t1 6.809 6.811 .002 61 NOv-201 1 7,069 7.071 .002 5 Dec-2011 7.344 7.341 -.003 174 Jan-2012 7.554 7551 -.003 15 Feb-20t2 7.554 7.546 -008 3 Matr-2012 7.334 7.326 -.008 10 Apr-2012 6.639 6.626 -.013 60 May-2012 6.599 6.581 -.018 20 Jun-2 01 2 6.669 .6.051 ..018 19 Jul.2012 6.149 6.731 -.018 1 Aug-2012 6.809 6.791 -.018 17 Sep-2012 6.839 6.821 -.018 29 Oct-2012 6.919 6.901 -.018 1 Nov-2012 7 139 7.121 -.018 1 Doc-2012 7.409 7.391 -.018 100in ttlement prce with zero ,jolume mean the se(ttoment price is imled. No actual trading took place for these contracts on the given day.Prk-n is basrtd orl delivery at lhe Henry Hub in Louisiana, which serves matrets throughout the US East Coast. the Gull Coast, the Midwest and up'to the Canadian border.

AGREEMENT This Agreement is dated as of May , 2007 between Entergy Arkansas, Inc., ("EAl" or "Seller"), and Entergy Louisiana, LLC ("ELL" or "Buyer").WHEREAS, EAL has agreed to make a unit power sale from the designated unit set forth on Attacluhent A ("Designated Unit") to ELL; and WHEREAS, the Agreement among EAl, ELL, and Entergy New Orleans,'

Inc.("ENO"), Entergy Mississippi, Inc. ("EMI"), Entergy Gulf States, Inc. ("EGS") abnd Entergy Services, Inc. ("ESI") (hereinafter referred to as the "System Agreement"), was filed with the FERC on April 30, 1982, and became effective on January 1, 1983, and amended to incorporate EGS in 1993; and WHEREAS, the System Agreement contains a Service Schedule MSS-4 providing the basis for making a unit power purchase between theCompanies that are participants in that Agreement; and WHEREAS, the parties herein wish to execute this Agreement to provide for a unit power purchase by ELL under Service Schedule MSS-4 from the Designated Unit.THEREFORE, the parties agree as follows: I. Designated Unit. The designated generating unit for purposes of this unit power purchase under Service Schedule MSS-4 of the System Agreement shall be the unit set forth on Attachment A.2. Unit Power Purchase.

EAI agrees to sell and ELL agrees to purchase that quantity of generating capacity and associated energy from the Designated Unit equivalent to the percentage (the "Allocated Percentage")

of EAI's baseload capacity in such Designated Unit set forth on Attachment A, with such sale and purchase to become effective as of June 1, 2003., or as soon thereafter as deliveries may commence and to continue thereafter until the retirement date of Designated Unit set forth on Attachment A.3. Pricing. The pricing of the capacity and energy to be sold and purchased pursuant to paragraph 2 above shall be as specified in Service Schedule MSS-4 of the System Agreement.

4. Energy Entitlement.

ELL is entitled to receive on an hourly basis the Allocated Percentage of the energy generated by the Designated Unit.5. Termination.

Neither party shall have the right to terminate the unit power purchase and sale required by this Agreement without the express written consent of the other party.6. Condition Precedent.

This contract shall be conditioned upon Buyer receiving all regulatory approvals required for this Agreement.

7. Notices. Unless specifically stated otherwise herein, any notice to be given hereunder shall be sent by Registered Mail, postage prepaid, to the party to be notified at the address set forth below, and shall be deemed given when so mailed.To EAI: Entergy Arkansas, Inc.425 West Capitol Avenue Little Rock, AR 72201 ATTN: Chief Executive Officer To ELL: Entergy Louisiana, LLC 4809 Jefferson Hwy Jefferson, LA 70121 ATTN: Chief Executive Officer 8. Nonwaiver:

The failure of either party to insist upon or enforce, in any instance, strict performance by the other of any of the terms of this Agreement or to exercise any rights herein conferred shall not be considered as a waiver or relinquishment to any extent of its rights to assert or rely upon any such terms or rights on any future occasion.9. Amendments.

No. waiver, alteration, amendment or modification of any of the provisions of this Agreement shall be binding unless in writing and signed by a duly authorized representation of both parties.10. Entire Agreement.

This Agreement, which is entered into in accordance with the authority of Service Schedule MSS-4 of the System Agreement, constitutes the entire agreement between the parties with respect to the subject matter hereof and supersedes all previous and collateral agreements of understandings with respect to the subject matter hereof.11. Severability.

It is agreed that if any clause or provision of this Agreement is held by the courts to be illegal or void, the validity of the remaining portions and provisions of the Agreement shall not be affected, and the rights and obligations of the parties shall be enforced as if the Agreement did not contain such illegal or void clauses or provisions.

WITNESS OUR SIGNATURES as of May_, 2007.WITNESS: ENTERGY ARKANSAS, C.By.T T LE A 5, /4 /WITNESS: 4-ENTERGY LO SIANA, [LC BY:si&//44 ATTAC(2tMENT A SALE OF CAPACITY A-ND ENERGY BY ENTERGY ARKANSAS, INC. TO ENTERGY LOUISIANA, LLC This Attachment A is attached to and forms a part of the Agreement dated on May , 2007, between Entergy Louisiana, LLC ("ELL" or "Buyer") and Entergy Arkansas, Inc. ("EAI" or "Seller")

pursuant to the Service Schedule MSS-4 of the System Agreement.'

During the period, June 1, 2003 through the end of the term, the capacity and energy amount is as follows: EAI's BASELOAD CAPACITY*BUYER'S ALLOCATED CAPACITY*'19,00 BUYER'S ALLOCATED PERCENTAGE 20.88%DESIGNATED UNIT Grand Gulf Retained Share 91.00*Expressed in megawatts.

To the extent EAI's Baseload Capacity increases or decreases, Buyer's Allocated Capacity shall adjust correspondingly based on Buyer's Allocated Percentage of EAI's Baseload Capacity.

AGREEMENT This Agreement is.dated as of May , 2007 betwecn Entergy Arkansas, Inc., ("EAI" or "Seller"), and Entergy Louisiana, LLC ("ELL" or "Buyer").WHEREAS, EAI has agreed to make a unit power sale from the designated units set forth on Attachment A (individually a "Designated Unit" and collectively"Designated Units") to ELL; and WIHEREAS, the Agreement among EAI, ELL, and Entergy New Orleans, Inc.("ENO"), Entergy Mississippi, Inc. ("EMI"), Entergy Gulf States, Inc. ("EGS") and Entergy Services, Inc. ("ESI") (hereinafter referred to as the "System Agreement"), was filed with the FERC on April 30, 1982, and became effective on January 1, 1983, and amended to incorporate EGS in 1993; and WHEREAS, the System Agreement contains a Service Schedule MSS-4 providing.

the basis for making a unit power purchase, between the Companies that are participants in that Agreement; and WHEREAS, the parties herein wish to execute this Agreement to provide for a unit power purchase by ELL under Service Schedule MSS-4 from the Designated Units.THEREFORE, the parties agree as follows: I. Desimnated Units. The designated generating units for purposes of this unit power purchase under Service Schedule MSS-4 of the System Agreement shall he those units set forth on Attachment A.2. Unit Power Purchase.

EAt agrees to sell and ELL agrees to purchase that.quantity of generating capacity and associated energy from the Designated Units equivalent to the percentage (the.'Allocated Percentage")

o EAI's baseload capacity in each such D)esignated U(nit set fbrth on Attachment A, with such sale and purchase to become effective as of June 1, 2003, or as soon thereaflcr as deliveries may commence and to continue thereafter until the retirement date of Designated Units set forth on Attachment A.3. Pricing. The pricing of the capacity and energy to be sold and purchased pursuant to paragraph 2 above shall be as specified in Service Schedule MSS-4 of the System Agreement.

4. Energy Entitlement.

ELL is entitled to receive on an hourly basis the Allocated Percentage of the energy generated by each of the Designated Units.5. Termination.

Neither party shall have the right to terminate the unit power purchase and sale required by this Agreement without the express written consent of the other party.6. Condition Precedent.

This contract shall be conditioned upon Buyer receiving all regulatory approvals required for this Agreement.

7. Notices. Unless specifically stated otherwise herein, any notice to be given hereunder shall be sent by Registered Mail, postage prepaid, to the party to be notified at the address set forth below, and shall be deemed given when so mailed.To EAT: Entergy Arkansas, Inc.425 West Capitol Avenue Little Rock, AR 72201 ATTN: Chief Executive Officer To ELL: Entergy Louisiana, LLC 4809 Jefferson Hwy Jefferson, LA 70121 ATTN: Chief Executive Officer 8. Nonwaiver:

The failure of either party to insist upon or enforce, in any instance, strict performance by the other of any of the terms of this Agreement or to exercise any rights herein conferred shall not he considered as a Waiver or relinquishment to any extent of its rights to assert or rely upon any such terms or rights on any future occasion.9. Amendments.

No waiver, alteration, amendment or modification of any of the provisions of this Agreement shall be binding unless in writing and signed by a duly authorized representation of both parties.10. Entire Agreement.

This Agreement, which is entered into in accordance with the authority of Service Schedule MSS-4 of the System Agreement, constitutes the entire agreement between the parties with respect to the subject matter hereof and supersedes all previous and collateral agreements of understandings with respect to the subject matter hereof.11. Severability.

It is agreed that if any clause or provision of this Agreement.is held by the courts to be illegal or void, the validity of the remaining portions and provisions of the Agreement shall not be affected, and the rights and obligations of the parties shall be enforced as if the Agreement did not contain such illegal or void clauses or provisions.

WITNESS OUR SIGNATURES as of May__, 2007.WITNESS: ENTERGY ARKANSAS, INC.BY: _________TITLE: _ _ _'--WITNESS: ,ENTERGY LO N.

ATTACHMENT A SALE OF CAPACITY AND ENERGY BY ENTERGY ARKANSAS, INC. TO ENTERGY LOUISIANA, LLC This Attachment A is attached to and forms a part of the Agreement dated on May __, 2007, between Entergy Louisiana, LLC ("ELL" or "Buyer") and EnTergy Arkansas; Inc. ("EAr" or "Seller")

pursuant to the Service Schedule MSS-4 of the System Agreement.

During the period, June 1, 2003 through the end of the term, the capacity and energy amount is as follows: EAI's BUYER'S BUYER'S BASELOAD ALLOCATED ALLOCATED CAPACITY*

CAPACITY*

PERCENTAGE DESIGNATED UNITS ANO Unit 1 846.00 23.00 2.72%ANO Unit 2 998.00 27.00 2.71%White Bluff Unit 1 461.70 13.00 2.82%White BluffUnit 2 461.70 12.00 2.60%Independence Unit 1 257.00 7.00 2.72%Grand Gulf- EAI 324.00 9.00 2.78%TOTAL 3,348.40 91.00 2.72%* Expressed in megawatts.

To the extent EAI's Baseload Capacity increases.

or decreases, Buyer's Allocated Capacity shall adjust correspondingly based on Buyer's Allocated Percentage of EAI's Baseload Capacity.

AGREEMENT This Agreement is dated as of May _ , 2007 between Entergy Arkansas, Inc., ("EAI" or "Seller"), and Entergy New Orleans, Inc. ("ENO" or "Buyer").WHEREAS, EAI has agreed to make a unit power sale from the designated units set forth on Attachment A (individually a "Designated Unit" and collectively"Designated Units") to ENO; and WHEREAS, the Agreement among EAM, ENO, and Entergy Louisiana, LLC ("ELL"), Entergy Mississippi, Inc. ("EMI"), Entergy Gulf States, Inc. ("EGS") and Entergy Services, Tnc. ("ESr') (hereinafter referred to as the "System Agreement"), was filed with the FERC on April 30, 1982, and became effective on January 1, 1983, and amended to incorporate EGS in 1993; and WHEREAS, the System Agreement contains a Service Schedule MSS-4 providing the basis for making a unit power purchase between thie Companies that are participants in that Agreement; and WHEREAS, the parties herein wish to execute this Agreement to provide for a unit power purchase by ENO under Service Schedule MSS-4 from the Designated Units.THEREFORE, the parties agree as follows: L. Designated Units. The designated generating units for purposes of this unit power purchase under Service Schedule MSS-4 of the System Agreement shall be those ainits set forth on Attachment A.2. Unit Power Purchase.

EAI agrees to sell and ENO agrees to'purchase that quantity of generating capacity and associated energy from the Designated Units equivalent to the percentage (the "Akllocated Percentage")

of EAI's baseload capacity in each such Designated Unit set tbrth on Attachinent A, with such sale and purchase to become effective as of June 1, 2003 and to continue thereafter until the retirement date of Designated Units set forth on Attachment A.3. .Pricing.

The pricing of the capacity and energy to be sold and purchased pursuant to paragraph 2 above shall be as specified in Service Schedule MSS-4 of the System Agreement.

4. Energy Entitlement.

ENO is entitled to receive on an hourly basis the Allocated Percentage of the energy -generated by each of the Designated Units.5. Termination.

Neither party shall have the right to terminate the unit power purchase and sale required by this Agreement without the express written consent of the other party.6. Condition Precedent.

This contract shall be conditioned upon Buyer receiving all regulatory approvals required for this Agreement.

7. Notices. Unless specifically stated otherwise.

herein, any notice to be given hereunder shall be sent by Registered Mail, postage prepaid, to the party to be notified at the address set forth below, and shall be deemed given when so mailed.To EA: Entergy Arkansas, Inc.425 West Capitol Avenue Little Rock, AR 72201 ATTN: Chief Executive Officer To ENO: Entergy New Orleans, Inc.1600 Perdido Street Building 529 New Orleans, LA 70112 ATTN: Chief Executive Officer 8. Nonwaiver:

The failure of either party to insist upon or enforce, in any instance, strict performance by the other of any of the terms of this Agreement or to exercise any rights herein conterred shall not be considered as a waiver or relinquishment to any extent of its rights to assert or rely upon any such terms or rights on any future occasion.9. Amendments.

No waiver, alteration, amendment or modification of any of the provisions of this Agreement shall be binding unless in writing and signed by a duly authorized representation of both parties.10. Entire Agreement.

This Agreement, which is entered into in accordance with the authority of Service Schedule MSS-4 of the System Agreement, constitutes the entire agreement between the parties with respect to the subject matter hereof and supersedes all previous and collateral agreements of understandings with respect to the subject matter hereof.11. Severability.

It is agreed that if any clause or provision of this Agreement is held by-the courts to be illegal or void, the validity of the remaining portions and provisions of the Agreement shall not be affected, and the rights and obligations of the parties shall be enforced as if the Agreement did not contain such illegal or void clauses or provisions.

WITNESS OUR SIGNATURES as of May_, 2007.WITNESS: ENTERGY ARKANSAS,NC.

BI TITLENTER.Y WITNESS: ' ENTERGY NEW ORLEANS,,INC.

TITLE: ____________r____f AITACHMENT A SALE OF CAPACITY AND ENERGY BY ENTERGY ARKANSAS.

INC. TO ENTERGY NEW ORLEANS, INC.This Attachment A is attached to and forms a part of the Agreement dated on May 2007, between Entergy New Orleans, Inc. ("ENO" or "Buyer") and Entergy Arkansas, Inc. ("EAI" or "Seller")

pursuant to the Service Schedule MSS-4 of the System Agreement.

During the period, June 1, 2003 through the end of the term, the capacity and energy amount is as follows: EAI's BASELOAD CAPACITY*BUYER'S BUYER'S ALLOCATED ALLOCATED CAPACITY*

PERCENTAGE DESIGNATED UNITS ANO Unit I ANO Unit 2 White Bluff Unit I White Bluff Unit 2 Independence Unit 1 Grand Gulf- EAI 846.00 998.00 461.70 461.70 257.00 324.00 23.00 27.00 12.00 13.00 7.00 9.00 2.72%2.71%2.60%2.82%2.72%2.78%TOTAL 3.348.40 91.00 2.72%*Expressed in megawatts.

To the extent EAI's Baseload Capacity increases or decreases, Buyer's Allocated Capacity shall adjust correspondingly based on Buyer's Allocated Percentage of EAI's Baseloid Capacity.

AGREEMENT This Agreement is dated as of May _ , 2007 between Entergy Arkansas, Inc., ("EAr' or "Seller"), and Entergy New Orleans, .Inc. ("ENO" or "Buyer").WHEREAS, EAI has agreed to make a unit power sale from the designated unit set forth on Attachment A ("Designated Unit") to ENO; and WHEREAS, the Agreement among EAI, ENO, and Entergy Louisiana, LLC ("ELL"), Entergy Mississippi, Inc. ("EMI"), Entergy Gulf States, Inc. ("EGS") and Entergy Services, Inc. ("ESr') (hereinafter referred to as the "System Agreement"), was filed with the FERC on April 30, 1982, and became effective on January 1, 1983, and amended to incorporate EGS in 1993; and WHEREAS, the System Agreement contains a Service Schedule MSS-4 providing the basis for making a unit power purchase between the Companies that are participants-in that Agreement; and WHEREAS, the parties herein wish to execute this Agreement to provide for a unit power purchase by ENO under Service Schedule MSS-4 from the Designated Unit.THEREFORE, the parties agree as follows: 1. Designated Unit. The designated generating unit for purposes of this unit power purchase under Service Schedule MSS-4 of the System Agreement shall be the unit set forth on Attachment A.2. Unit Power Purchase.

EAr agrees to sell and ENO agrees to purchase that quantity of generating capacity and associated energy from the Designated Unit equivalent to the percentage (the "Allocated Percentage")

of EAI's baseload capacity in such Designated Unit set forth on Attachment A, with such sale and purchase to become effective as of June 1, 2003 and to continue thereafter until the retirement date of Designated Unit set forth on Attachment A.3. Pricing. The pricing of the capacity and energy to be sold and purchased pursuant to paragraph 2 above shall be as specified in Service Schedule MSS-4 of the System Agreement.

4. Energy Entitlement.

ENO is entitled to receive on an hourly basis the Allocated Percentage of the energy generated by the Designated Unit.5. Termination.

Neither party shall have the right to terminate the unit power purchase and sale required by this Agreement without the express written consent of the other party.6. Condition Precedent.

This contract shall be conditioned upon Buyer receiving all regulatory approvals required for this Agreement.

7. Notices. Unless specifically stated otherwise herein, any notice to be given hereunder shall be sent by Registered Mail, postage prepaid, to the party to be notified at the address set forth below, and shall be deemed given when so mailed.To EAI: Entergy Arkansas, Inc.425 West Capitol Avenue Little Rock, AR 72201 ATTN: Chief Executive Officer To ENO: Entergy New Orleans, Inc.1600 Perdido Street Building 529 New Orleans, LA 70112 ATTN: Chief Executive Officer 8. Nonwaiver:

The failure of either party to insist upon or enforce, in any instance, strict performance by the other of any of the terms of this Agreement or to exercise any rights herein conferred shall not be considered as a waiver or relinquishment to any extent of its rights to assert or rely upon any such terms or rights on any future occasion.9. Amendments.

No waiver, alteration, amendment or modification of any of the provisions of this Agreement shall be binding unless in writing and signed by a duly authorized representation of both parties.10. Entire Agreement.

This Agreement, which is entered into in accordance with the authority of Service Schedule MSS-4 of the System Agreement, constitutes the entire agreement between the parties with respect to the subject matter hereof and supersedes all previous and collateral agreements of understandings with respect to.the subject matter hereof.11. Severability' It is agreed that if any clause or provision of this Agreement is held by the courts to be illegal or void, the validity of the remaining portions and provisions of the Agreement shall not be affected, and the rights and obligations of the parties shall be enforced as if the Agreement did not contain such illegal or void clauses or provisions.

WITNESS OUR SIGNATURES as of May _, 2007.WITNESS: ENTERGY ARKANSAS INC.BY: TITLE:RG u N OREAS [NC WITNESS: ' -ENTERGY NEW ORLEANS, [NC, TITLE:

' ATTACHMENT A SALE OF CAPACITY AND ENERGY BY ENTERGY ARKANSAS, INC. TO ENTERGY NEW ORLEANS, INC.This Attachment A is attached to and forms a part of the Agreement dated on May____, 2007, between Entergy New Orleans, Inc. ("ENO" or "Buyer") and Entergy Arkansas, Inc. ("EAI" or "Seller")

pursuant to the Service Schedule MSS-4 of the System Agreement.

During the period, June 1, 2003 through the end of the term, the capacity and energy amount is as follows: EAI's BASELOAD CAPACITY*BUYER'S ALLOCATED CAPACITY*19.00 BUYER'S ALLOCATED PERCENTAGE 20.88%DESIGNATED UNIT Grand Gulf Retained Share 91.00*Expressed in megawa.tts.

To the extent EAI's Baseload Capacity increases or decreases, Buyer's Allocated Capacity shall adjust correspondingly based on Buyer's Allocated Percentage of EAI's Baseload Capacity.

CNRO-2012-00007 SERIES 2 ATTACHMENTS 2 SERI & SMEPA -GGNS Status Report (1 page)2-A SERI & SMEPA -Calculation of Minimum Amount (1 page)2-B Schedule of Remaining Principle Payments -GGNS (1 page)2-C FERC Order in Docket No. ER95-1042 and Availability Agreement (39 pages)

Attachment 2 (1 page)SYSTEM ENERGY RESOURCES, INC. and SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION Status Report of Decommissioning Funding For Year Ending December 31, 2011 -10 CFR 50.75(f)(1)

Plant Name: Grand Gulf Station (Owned & leased 90% by System Energy Resources, Inc (SERI) and 10% by South Mississippi Electric Power Association (SMEPA))1. Minimum Financial Assurance (MFA)Estimated per 10 CFR 50.75(b) and (c) (2011$): SERI (90% ownership share)SMEPA (10% ownership share)2. Decommissioning Fund Total as of 12/31/11: SERI SMEPA 3. Annual amounts remaining to be collected:

4. Assumptions used: Rate of Escalation of Decommissioning Costs: SERI SMEPA Rate of Earnings on Decommissioning Funds: SERI SMEPA Authority for use of Real Earnings Over 2%: SERI N/A SMEPA SMEPA Board 5. Contracts upon which licensee is relying For Decommissioning Funding: 6. Modifications to Method of Financial Assurance since Last Report: 7. Material Changes to Trust Agreements:

$557.0 million 1$61.9 million$423.4 million$39.4 million See Attachment 2-B See item below 3.0%2% real rate of return per 10 CFR 50.75(e)(1

)(i)Approx. 5.91%See footnote 2 None None 1 See Attachment 2-A 2 See the Unit Power Sales Agreement, a FERC tariff, in Attachment 2-C; and see also the Availability Agreement, in Attachment 2-C, which includes additional provisions related to decommissioning financial assurance.

It is the licensee's position that the Unit Power Sales Agreement is not a 10 CFR §50.75(e)(1)(v) "contractual obligation," but rather a cost of service tariff which may appropriately be used to fund the external sinking fund in accordance with 10 CFR §50.75(e)(1

)(ii). Out of abundance of caution, the licensee identifies this information here.

Attachment 2-A (1 page)SYSTEM ENERGY RESOURCES, INC. and SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION Calculation of Minimum Amount For Year Ending December 31, 2011 -10 CFR 50.75(f)(1)

System Energy Resources, Inc.: 90% ownership/leasehold interest South Mississippi Electric Power Association

("SMEPA"):

10% ownership interest Plant Location:

Port Gibson, Mississippi Reactor Type: Boiling Water Reactor ("BWR")Power Level: >3,400 MWt BWR Base Year 1986$: $135,000,000 Labor Region: South Waste Burial Facility:

Generic Disposal Site I OCFR50.75(c)(2)

Escalation Factor Formula: 0.65(L) +0.13(E) +0.22(B)L=Labor (South)E=Energy (BWR)B=Waste Burial-Vendor (BWR)BWR Escalation Factor: 0.65(L) +0.13(E) +0.22(B)=1986 BWR Base Year $ Escalated:

$135,000,000

• Factor=System Energy interest (90%)!SMEPA inteJrest'(10%):

Total Factor 2.281 2.662 12.543 4.58401$618,856,935

$556,956,813 611-,4&090

$618-840,903 1 2 3 Bureau of Labor Statistics, Series Report ID: CIU2010000000220i (4 th Quarter 2011)Bureau of Labor Statistics, Series Report ID: wpu0543 and wpu0573 (December 2011)Nuclear Regulatory Commission:

NUREG-1 307 Revision 14, Table 2.1 (2010)

Attachment 2-B (1 page)Schedule of Remaining Principal Payments into Grand Gulf Decommissioninq Fund ($ Thousands)

SERI Share SMEPA Share$0 Thereafter Total 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023$23,785$23,785$23,785$22,285$24,550$24,550$24,550$24,550$24,550$29,878$17,429$0 Thereafte$23,785$23,785$23,785$22,285$24,550$24,550$24,550$24,550$24,550$29,878$17,429$0 Thereafter Note: Approved in FERC Docket No. ER95-1042-004, see Attachment C in Attachment 2-C.

Attachment 2-C (39 pages)FERC Order in Docket No. ER95-1042-004 And Availability Agreement System Energy Resources, Inc.I SlV. Rate Schedule FERC No. 2 (5S onI na( ac, a&stAedkJe IERC t.J.2,asst.piplefenrenc)

Original Sheet No: I vockbt NM. bFJ~4OL/rr4.1 Rern X 601L. 4/(.1 A~FiligDateZ-L 1C~FILING PUBLIC UTILITY System Energy Resources, Inc.Rate Schedule FERC No. 2 PUBLIC UTILITIES RECEIVING SERVICE UNDER RATE SCHEDULE Entergy Arkansas, Inc.Entergy Louisiana, Inc.Entergy Mississippi, Inc.Entergy New Orleans, Inc.SERVICE TO BE PROVIDED'UNDER RATE SCHEDULE Wholesale Sale of Electric Power Issued by: Kimberly H, Despeaux Director, Federal Regulatory Affairs Issued on; August 29, 2001 Effective Date: December 12, 1995 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No, ER95-1042-000, issued July 31, 2000, 92 FERC 61,119, order denying rehearing, issued July 30, 2001, 96 FERC 61,165.& (?o'fl-do d-(

System Energy Resources, inc.1l'oV. Rate Schedule FERC No. 2 (5sr'.t gI. Rfate .& edA L)e ER2 Ja.2., as stPPfetrren&&c)

Original Sheet No. i 1- Rer4 El Rat So.N r#)g Date 1 L5-~FILING PUBLIC UTILITY System Energy Resources, Inc.Rate Schedule FERC.No. 2 PUBLIC UTILITIES RECEIVING SERVICE UNDER RATE SCHEDULE Entergy Arkansas, Inc.Entergy Louisiana, Inc.Entergy Mississippi, Inc.Entergy New Orleans, Inc.SERVICE TO BE PROVIDED UNDER RATE SCHEDULE Wholesale Sale of Electric Power Issued by: Kimbedy H. Despeaux Director, Federal Regulatory Affairs Issued on: August 29, 2001 Effective Date: December 12, 1995 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER95-1042-000, issued July 31, 2000, 92 FERC 61,119, order denying rehearing, issued July 30, 2001, 96 FERC 61,165.O Z r)') e ot System Energy Resources, Inc. Original Sheet No. 2 Rate Schedule FERC No. 2 Unit Power Sales Agreement THIS AGREEMENT, made, entered into, and effective as of this 1 0 th day of June, 1982, as amended from time to time thereafter, and as revised to comply with Federal Energy Regulatory Commission

("FERC") Opinion Nos. 446 and 446-A and FERC Order No.614, between and among Entergy Arkansas, Inc. ("EAI"), Entergy Louisiana, Inc. ("ELI"), Entergy Mississippi, Inc. ("EMI"), Entergy New Orleans, Inc. ("ENOI") and System Energy Resources, Inc. ("System Energy"), WITNESSETH THAT: WHEREAS, System Energy was incorporated on February I1, 1974 under the laws of the State of Arkansas to own certain future generating capacity for the Entergy System, of which EAI, ELI, EMI and ENOI.("System Companies")

are members; and WHEREAS, System Energy has accordingly undertaken the ownership and financing of an undivided interest in, and construction of, the Grand Gulf Generating Station, a one-unit, nuclear-fueled electric generating station on the east bankof the Mississippi River near Port Gibson, Mississippi

("Project");

and WHEREAS, the System Companies own and operate electric generating, transmission and distribution facilities in Arkansas, Louisiana and Mississippi and generate, transmit and sell electric energy both at retail and wholesale in such states; and WHEREAS, System Energy has agreed to sell to EAI, ELI, EMI and ENOI ("Purchasers")

specified percentages of all of the capacity and energy available to System Energy from the Project, and the System Companies have agreed to join with System Energy, before the date Unit I of the Project is placed in service, in executing an agreement which will set, forth in detail the terms and conditions for the sale of such capacity and energy by System Energy.10 the Systcm Companies; and WHEREAS, Unit I is expected to be placed in commercial operation in the first quarter of 1983;NOW. THEREFORE, System Energy and the System Companies mutually understand and agree as follows: Issued by: Kimberly H. Despeaux Effective Date: December 12, 1995 Director, Federal Regulatory Affairs Issued on: August 29, 2001.Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER95-1042-000, issued July 31. 2000, 92 FERC 61.119, order denying rehearing, issued July 30. 2001.96 FERC 61,165.

System Energy Resources, Inc. Original Sheet No. 3 Rate Schedule FERC No. 2 1.1 System Energy shall, subject to the terms and conditions of this Agreement, make available, or cause to be made available, to the Purchasers all of the capacity and energy which shall be available to System Energy at the Project, including test energy produced during the course of the construction and testing of Unit I of the Project ("Power").

1.2 The Purchasers shall, subject to the terms and conditions of this Agreement, be entitled to receive all of the Power which shall be available to System Energy at the Project in accordance with their respective Entitlement Percentages.

The Entitlement Percentages are as folldws: Entitlement Percentages Unit No. I EAI 36%ELI 14%EMI 33%ENOI 17%100%1.3 Commencing with the earlier of (a) the date of commercial operation of the Unit or (b) December 31, 1984 and continuing monthly thereafter until this Agreement is terminated pursuant to the provisions of Section 9 hereof, in consideration of the right to receive its Entitlement Percentage of such Power from the unit, each Purchaser will pay System Energy an amount determined pursuant to the Monthly Grand Gulf Power Charge Formula, which is attached hereto as Appendix 1.2. The performance of the obligations of System Energy hereunder shall be subject to the receipt and continued effectiveness of all authorizations of governmental regulatory authorities at the time necessary to permit System Energy to perform its duties and obligations hereunder, including the receipt and continued effectiveness of all authorizations by governmental regulatory authorities at the time necessary to permit the completion by System Energy of the construction of the Project, the.operation of the Project, and for System Energy to make available to the Purchakers all of the Power available to System Energy at the Project. System Energy shall use its best efforts to secure and maintain all such authorizations by governmental regulatory authorities.

Issued by: Kimberly H. Despeaux Effective Date: December 12, 1995 Director, Federal Regulatory Affairs Issued on: August 29, 2001 Filed tocomply with order of the Federal Energy Regulatory Commission, Docket No. ER95-1042-000, issued July 31, 2000, 92 FERC 61,119, order denying rehearing, issued July 30, 2001, 96 FERC 61,165.

System Energy Resources, Inc. Original Sheet No. 4 Rate Schedule FERC No. 2 3. System Energy shall operate and maintain the Project in accordance with good utility practice.

Outages for inspection, maintenance, refueling, repairs and replacements shall be scheduled in accordance with good utility practice and, insofar as practicable, shall be mutually agreed to by System Energy and the Purchasers.

4. Delivery of Power sold to the Purchasers pursuant to this Agreement shall occur at the Project's step-up transformer and shall be made in the form of three-phase, sixty hertz alternating current at a nominal voltage of 500 kilovolts.

System Energy will supply and maintain all necessary metering equipment for determining the quantity and conditions of delivery under this Agreement.

System Energy will furnish to the Purchasers such summaries of meter reading and other metering information as may reasonably be requested.

5. Monthly bills shall be calculated in accordance with the provisions of the Monthly Grand Gulf Power Charge Formula, attached hereto as Appendix 1.6. Nothing contained herein shall be construed as affecting in any way the right of System Energy to unilaterally make application to FERC for a change in the rates contained herein or any other term or condition of this Agreement under Section 205 of the Federal Power Act and pursuant to FERC Rules and Regulations promulgated thereunder.

7. No Purchaser shall be entitled to set off against any payment required to be made by it under this Agreement.(a) any amounts owed by System Energy to any Purchaser or (b) the amount of any claim by any Purchaser against System Energy. The foregoing, however, shall not affect in any other way the rights and remedies of any Purchaser with respect to any such amounts owed to any Purchaser by System Energy or any such claim by any Purchaser against System Energy.8. The invalidity and unenforceability of any provision of this Agreement shall not affect -the remaining provisions hereof.9. This Agreement shall continue until terminated by mutual agreement of all parties hereto.Issued by: Kimberly H. Despeaux Effective Date: December 12, 1995 Director, Federal Regulatory Affairs Issued on: August 29, 2001 Filed to comply with order of the Federal Energy Regulator/

Commission.

Docket No. ER95-1042-000, issued July 31, 2000. 92 FERC 61,119, order denying rehearing, issued July 30, 2001, 96 FERC 61,165.

System Energy Resources, Inc. Original Sheet No. 5 Rate Schedule FERC No. 2 10. This Agreement shall be binding upon the parties hereto and their successors and assigns, but no assignment hereof, or of any right to any funds due or to beconme due under this Agreement, shall in any event relieve either any Purchaser or System Energy of any of their respective obligations hereunder, or, in the case of the Purchasers, reduce to any extent their entitlement to receive all of the Power available to System Energy from time to time at the Project.11. The agreements herein set forth have been made for the benefit of the Purchasers and System Energy and their respective successors and assigns and n6 other person shall acquire or have any right under or by virtue of this Agreement.

12. The Purchasers and System Energy may, subject to the provisions of this Agreement, enter into a further agreement or agreements between the Purchasers and System Energy, setting forth detailed terms and provisions relating to the performance by the Purchasers and System Energy of their respective obligations under this Agreement.

No agreement entered into under this Section 12 shall, however, alter to any substantive degree the obligations of any party to this Agreement in any manner inconsistent with any of the foregoing sections of this Agreement.

13. Each of the Purchasers shall, at any time and from time to time, be entitled to assign all of its right, title and interest in and to all of the power. to which aný of them shall .be entitled under this Agreement, but no Purchaser shall, by such assignment, be relieved of any of its obligations and duties under this Agreement except through the payment to System Energy, by or on behalf of such Purchaser, of the amount or amounts which such Purchaser shall be obligated to pay pursuant to the terms of this Agreement.

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed as of the day and year first above written Issued by: Kimberly H. Despeaux Effective Date: December 12, 1995 Director, Federal Regulatory Affairs Issued on: August 29, 2001 Filed to comply with order of the Federal Energy Regulatory Commission, Dccket No. ER95-1042-000, issued July 31, 2000. 92 FERC 61,119, order denying rehearing, issued July 30, 2001. 96 FERC 61,165.

System Energy Resources, Inc.Rate Schedule FERC No. 2 Original Sheet No. 6 SYSTEM ENERGY RESOURCES, INC., fbr merly MIDDLE SOUTH ENERGY, INC.By. /S/ F W. Lewis ENTERGY ARKANSAS, INC., formerly ARKANSAS POWER & LIGHT COMPANY By: /S/ Jerry Maulden ENTERGY LOUISIANA, INC., formerly LOUISIANA POWER & LIGHT COMPANY By: /S/ J. Wyatt ENTERGY MISSISSIPPI.

INC., formerly MISSISSIPPI POWER & LIGHT COMPANY By: /S/ D. C. Lutkin ENTERGY NEW ORLEANS, INC., formerly NEW ORLEANS PUBLIC SERVICE INC.By: /Si James M. Cain Issued by: Kimberly.H.

Despeaux Director, Federal Regulatory Affairs Issued on: August 29. 2001 Effective Date: December 12, 1995 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER95-1 042-000.issued July 31:2000, 92 FERC 61,119. order denying rehearing, issued July 30, 2001, 96 FERC 61,165.

System Energy Resources, Inc.Rate Schedule FERC No. 2 Original Sheet No. 7 Appendix 1 Page 1 of 3 SYSTEM ENERGY RESOURCES, INC.MONTHLY GRAND GULF POWER CHARGE FORMULA 1. GENERAL This Grand Gulf Power Charge Formula ("PCF") sets out the procedures that shall be used to determine the monthly amounts which System Energy Resources, Inc. ("SERI) shall charge Entergy Arkansas, Inc.(CEAI"); Entergy Louisiana, Inc. ('ELI"); Entergy Mississippi, Inc. ("EMI"); and Entergy New Orleans, Inc.("ENOI") (referred to hereafter, collectively, as "Purchasers', or, individually, as 'Purchaser"), for capacity and. energy from the Grand Gulf Nuclear Station ("Grand Gulf) pursuant to the Unit Power Sales Agreement

("UPSA") between SERI and the Purchasers to which this document is attached as Appendix 1. The monthly charges for capacity ('Monthly Capacity Charges")

shall be determined in accordance with the provisions of Section 2 below.. The monthly charges for fuel ("Monthly Fuel Charges")

shall be determined in accordance with the provisions of Section 3 below. The Monthly Capacity Charges and the Monthly Fuel Charges determined in accordance with the provisions of this PCF shall be billed to the Purchasers monthly in accordance with the provisions of Section 4 below.J Issued by: Kimberly H. Despeaux Effective Date: December 12, 1995 Director, Federal Regulatory Affairs Issued on: August 29, 2001 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER95-1042-000, issuedJuly 31, 2000, 92 FERC 61,119, order denying rehearing, issued July 30, 2001, 96 FERC 61,165.

System Energy Resources.

Inc. Original Sheet No. 8 Rate Schedule FERC No. 2 Appendix 1 Page 2 of 3 2. MONTHLY CAPACITY CHARGE The Monthly Capacity Charge to be billed to each of the Purchasers for any service month shall be determined by applying the Monthly Capacity Charge Formula set-out in Attachment A to the applicable cost data.3. MONTHLY FUEL CHARGE The Monthly Fuel Charge to be billed to each of the Purchasers for any service month shall be determined by applying the Monthly Fuel Charge Formula set out in Attachment B to fuel cost data for the service month.4. BILLING On or before the fifth workday of each month SERI shall render a billing to .each of the Purchasers reflecting the Purchaser's Monthly Capacity Charge and Monthly Fuel Charge for the immediately, preceding service month, In addition, any applicable and appropriate adjustments shall be reflected in each of the monthly billings.

The monthly billings shall be payable in immediately available funds on or before the 15th day of such month. After the 15th day of such month, interest shall accrue on any balance due to SERI, or owed by SERI, at the rate required for refunds rendered pursuant to the requirements of Section 35.19.a of the Code of Federal Regulations.

Entergy Services Inc., acting as agent for SERI and the Purchasers, may prepare the necessary billings to the Purchasers and arrange for payment in accordance with the above requirements.

Issued by: Kimberly H. Despeaux Effective Date: December 12, 1995 Director, Federal. Regulatory Affairs Issued on: August 29, 2001 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER95-1042-000, issued July 31, 2000, 92 FERC 61,119, order denying rehearing, issued July 30, 2001. 96 FERC 61,165.

System Energy Resources, Inc.Rate Schedule FERC No. 2 Original Sheet NO. 9 Appendix 1 Page 3 of 3 5. EFFECTIVE DATE AND TERM This PCF shall be effective for service rendered on and after December 12, 1995 and shall continue in effect until modified or terminated in accordance with the provisions of this PCF or applicable regulations or laws.Issued by: Kimberly H. Despeaux Effective Date: December 12. 1995 Director, Federal Regutatory Affairs Issued on: August 29, 2001 Filed to comply with order of the Federal Energy Negulatory Commission, Docket No, ER95-1042-000.

issued July 31, 2000, 92 FERC 61,119, order denying rehearing, issued July 30, 2001, 96 FERC 61,165, System Energy Resources, Inc.Rate Schedule FERC No. 2 Original Sheet No. 10 Attachment A Page 1 of 5 SYSTEM ENERGY RESOURCES, INC.MONTHLY CAPACITY CHARGE FORMULA DETERMINATION OF MONTHLY CAPACITY CHARGES MONTH, XXXX LINE NO DESCRIPTION AMOUNT REFERENCE/SOURCE 1 CAPACITY REVENUE REQUIREMENT Page 3, Line 1 2 CREDIT, PER STIPULATION AND AGREEMENT SERI Rate Schedule FERC No. 6 IN DOCKET NO. FA89-28 3 ADJUSTED CAPACITY REVENUE REQUIREMENT Line I -Line 2 4 MONTHLY CAPACITY CHARGE FOR EAI 36% "Line 3 5 MONTHLY CAPACITY CHARGE FOR ELI 14% Line 3 6 MONTHLY CAPACITY CHARGE FOR EMI 33%

• Line 3 7 MONTHLY CAPACITY CHARGE FOR ENOI 17% Line 3 Issued by: Kimberly H. Despeaux Effective Date: December 12, 1995 Director, Federal Regulatory Affairs Issued on: August 29. 2001 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER95-1042o000, issued July 31, 2000, 92 FERC 61,119, order denying rehearing, issued July 30, 2001, 96 FERC 61,165.

System Energy Resources, Inc.Rate Schedule FERC No. 2 Original Sheet No, 11 Attachment A Page 2 of 5 SYSTEM ENERGY RESOURCES, INC.MONTHLY CAPACITY CHARGE FORMULA DEVELOPMENT OF RATE BASE (1)MONTH, XXXX LINE.NO DESCRIPTION AMOUNT REFERENCE/SOURCE 1 PLANT IN SERVICE FERC Accounts 101,106 2 ACCUMULATED DEPRECIATION

& AMORTIZATION FERC Accounts 108, 111 (2)3 NET UTILITY PLANT Linel1 Plus Line 2)4 NUCLEAR FUEL FERC Accounts 120.2-120.4

5. AMORTIZATION OF NUCLEAR FUEL FERC Account 120,5 6 MATERIALS

& SUPPLIES FERC Accounts 154, 163 7 PREPAYMENTS FERC Account 165 8 DEFERRED REFUELING OUTAGE COSTS FERC Account 182.3 9 ACCUMULATED DEFERRED INCOME TAXES FERC Accounts .190, 281, 282, 283 10 RATE BASE .. ..... Sum of Lines. 3 -9 NOTES: (1) TO BE DETERMINED BASED ON DATA AS OF THE END OF THE MONTH IMMEDIATELY PRECEDING THE CURRENT SERVICE MONTH.(2) THE BALANCE FOR ACCUMULATED DEPRECIATION AND AMORTIZATION IS TO BE REDUCED BY ANY DECOMMISSIONING RESERVE-AND RESERVE FOR DISPOSAL OF NUCLEAR FUEL INCLUDED IN FERC ACCOUNTS 108 AND 111 WHICH REPRESENT MONIES HELD BY THIRD PARTIES.Issued by: Kimberly H. Despeaux Director, Federal Regulatbry Affairs Issued on: August 29, 2001 Effective Date: December 12, 1995 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER95-1042-000, issued July 31. 2000, 92 FERC 61,119, orderdenying rehearing, issued July 30, 2001, 96 FERC 61,165.

System Energy Resources, Inc.Rate Schedule FERC No. 2 Original Sheet No. 12 Attachment A Page 3 of 5 SYSTEM ENERGY RESOURCES, INC.MONTHLY CAPACITY CHARGE FORMULA DEVELOPMENT OF CAPACITY REVENUE REQUIREMENT (1)MONTH, XXXX LINE NO DESCRIPTION AMOUNT REFERENCE/SOURCE I CAPACITY REVENUE REQUIREMENT

_Determined as described in Note 2 below.2 OPERATION

& MAINTENANCE EXPENSE (3) FERC Accounts 517, 519-525, 528-532, 556. 557, 560-573, 901-905.920-931.

935 3 DEPRECIATION EXPENSE FERC Account 403-Excluding Decommissioning Exp 4 DECOMMISSIONING EXPENSE (4) FERC Accounl 403-Decommissioning Expense 5 AMORTIZATION EXPENSE FERC Accounts 404, 407.3, 407.4 6 TAXES OTHER THAN INCOME TAXES FERC Account 405.1 7 CURRENT STATE INCOME TAX .Page 4, Line 16 8 CURRENT FEDERAL INCOME TAX Page 4, Line 25 9 PROVISION FOR DEFERRED INCOME TAX-STATE State Portion of FERC Accounts 410.1, 411.1(5)10 PROVISION FOR DEFERRED INCOME TAX-FEDERAL Federal Portion of FERC Accounts 410:1,411,11 (5)11 INVESTMENT TAX CREDIT-NET FERC Account 411.4 12 GAINSILOSSES ON DISPOSITION OF UTILITY PLANT FERC Accounts 411.6. 411.7 13 UTILITY OPERATING EXPENSES Sum of Lines 2- 1Z 14 UTILITY OPERATING INCOME Line I minus Line 13 15 VERIFICATION:

16 RATE BASE Page 2, Line 10 17 RATE OF RETURN ON RATE BASE :12"(Line 14 1 Line 16) (Must equal Line 1S)18 COST OF CAPITAL Weighted Cost Rate from Page 5. Line 6 NOTES I) ALL EXPENSES ARE TO BE THOSE FOR THE CURRENT SERVICE MONTH.2) THE CAPACITY REVENUE REQUIREMENT FOR THE SERVICE MONTH IS THE VALUE THAT RESULTS IN A UTILITY OPERATING INCOME WHICH, WHEN DIVIDED BY THE RATE BASE (DETERMINED IN ACCORDANCE WITH PAGE 2) AND MULTIPLIED BY 12 PRODUCES A RATE OF RETURN ON RATE BASE EQUAL TO THE COST OF CAPITAL (OETERMINEO IN ACCORDANCE WITH PAGE 5).3) EXCLUSIVE OF FUEL EXPFNSE IN FERC ACCOUNT 518.4) SHOULD THE FERC APPROVE A CHANGE IN SYSTEM ENERGY'S SCHEDULE OF ANNUAL DECOMMISSIONING EXPENSES DURING THE SERVICE MONTH, THE MONTHLY LEVEL IN EFFECT AS OF THE END OF THE MONTH SHALL BE UTILIZED OTHERWISE.

THE AMOUNT CHARGED TO FERC ACCOUNT 403 FOR THE SERVICE MONTH SHALL 8B UTILIZED.

AS SHOWN ON ATTACHMENT C.5) RESTRICTED TO THOSE ITEMS FOR WHICH CORRESPONDING rIMING DIFFERENCES ARE INCLUDED IN THE AOJUSTIENTS TO NET INCOME BEFORE INCOME TAX (SEE PAGE 4, LINE 101.Issued by: Kimberly H. Despeaux Director, Federal Regulatory Affairs Issued on: August 29, 2001 Effective Date: December 12. 1995 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER95-1042-000, issued July 31, 2000, 92 FERC 61,119, order denying rehearing, issued July 30. 2001. 96FERC 61,165.

System Energy Resources, Inc. Original Sheet No. 13 Rate Schedule FERC No. 2 Attachment A Page 4 of 5 SYSTEM ENERGY RESOURCES, INC, MONTHLY CAPACITY CHARGE FORMULA DEVELOPMENT OF CURRENT INCOME TAX EXPENSE MONTH, XXXX LINE NO DESCRIPTION

.AMUNTT REFERENCEISOURCE 2 3 4 5 8 7 10 12 13 14 15 16 17 18 19 20 21.22.23 24 25 CAPACITY REVENUE REQUIREMENT OPERATION

& MAINTENANCE EXPENSE DEPRECIATION EXPENSE DECOMMISSIONING EXPENSE AMORTIZATION EXPENSE TAXES OTHER THAN INCOME NET INCOME BEFORE INCOME TAXES ADJUSTMENTS TO NET INCOME BEFORE INCOME TAX: INTEREST SYNCHRONIZATION OTHER ADJUSTMENTS TOTAL A04USTMENTS TAXABLE INCOME Page 3, Line 1 Page 3, Line 2 Page 3, Line 3 Page 3. Line 4 Page 3. Line 5 Page 3, Line 6'Line 1 * (Surn of Lines 2-6)Rate Base (Page 2. Line 10) (.1) ° Total Debt Rate (Page 5, Line 4)012 See Note 1 Line 9 plus Line 10 Line 7 plus Line II Line 12 See Note I Line 13 plus Line 14 Line 15 Mississippi State Tax Rate(2)See Note II ttl I r UMrU AIION Or 3 1AI r~INCOME *#A STATE TAXABLE INCOME BEFORE ADJUSTMENTS NET ADJUSTMENT TO STATE TAXABLE INCOME STATE TAXABLE INCOME STATE INCOME TAX BEFORE ADJUSTMENTS 40JUSTMENTS TO STATE TAX CURRENT STATE INCOME TAX ...._._Sum of Lines 16- 17 COMPUTATION OF FEDERAL INCOME TAX FEDERAL TAXABLE INCOME BEFORE ADJUSTMENTS Line 12 CURRENT STATE INCOME TAX DEDUCTION Line 18 (Shcwn as deduction)

OTHER ADJUSTMENTS TO FEDERAL TAXABLE INCOME See Note I FEDERAL TAXABLE INCOME Sum of Lines 19-21 FEDERAL INCOME TAX BEFORE ADJUSTMENTS Line 22 ' Federal Tax Rate(2)ADJUSTMENTS TO FEDERAL TAX See Note I CURREN I FEDEIRAL INCOME TAX ISum of Lines 23 -24 NOTES 1) ITEMS FROM MONTHLY TAX DETERMINATION THAT ARE APPROPRIATE FOR RATEMAKING PURPOSES.2) RATE IN EFFECT AT THE END OF THE SERVICE MONTH.Issued by: Kimberly H. Despeaux Director, Federal Regulatory Affairs Issued on: August 29, 2001 Effective Date: December 12, 1995 Filed to comply with order of the Federal Energy Regulatory Commission.

Docket No, ER95-1042-000, issued July. 31, 2000, 92 FERC 61,119, order denying rehearing, issued July 30. 2001. 96. FERC 61,165.

System Energy Resources, Inc.Rate Schedule FERC No. 2 Original Sheet No. 14 Attachment A Page 5 of 5 SYSTEM ENERGY RESOURCES, INC.MONTHLY CAPACITY CHARGE FORMULA DEVELOPMENT OF COST OF CAPITAL (1)MONTH. XXXX LINE CAPITAL CAPITALIZATION " COST WEIGHTED NO CAPITAL SOURCE AMOUNT RATIO RATE COST RATE (2)(3) (4) (8)1 DEBT 2 LONG TERM FERC Accts 221, 224.225, 226, 181, (5)189 3 SHORT TERM _(6)4 TOTAL DEBT (7)5 COMMON EQUITY FERC Accts 201,208, 216 (SEE NOTE 9)6 TOTAL NA NOTES I1)(2)(3)(4)(sI (6)(7)(a)(91 TO BE DETERMINED BASED ON DATA AS OF THE END OF THE MONTH IMMEDIATELY PRECEDING THE CURRENT SERVICE MONTH, LONG TERM DEBT SHALL INCLUDEALL ISSUES AND REFLECT THE PRINCIPAL AMOUNT.SHORT TERM DEBT SHALL INCLUDE ONLY THAT PORTION NOT REFLECTED IN THE CALCULATION OF SERI'S RATE FOR ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION.

APPLICABLE CAPITAL AMOUNT OIVIOED BY THE TOTAL CAPITAL AMOUNT.AVERAGE COST RATE FOR ALL OUTSTANDING ISSUES INCLUDING APPLICABLE AMORTIZATION OF DEBT DISCOUNT, PREMIUM, AND EXPENSE TOGETHER WITH AMORTIZATION OF LOSS OR GAIN ON REACQUIRED DEBT.THE AVERAGE COST RATE FOR ELIGIBLE SHORT TERM DEBT.WEIGHTED AVERAGE COST RATE FOR LONG 1ERM DEBT AND SHORT TERM DEBT.CAPITALIZATION RATIO FOR THE APPLICABLE CAPITAL SOURCE MULTIPLIED BY THE CORRESPONDING COST RATE.THE COMMON EQUITY COST RATE SHALL BE AS FOLLOWS: A. FOR SERVICE FROM DECEMBER 12. 1995 THROUGH JULY 30. 2000 THE RATE SHALL BE 10.58%.B. FOR SERVICE AFTER JULY 30, 2000 THE RATE SHALL BE 10.G4%.Issued by: Kimberly H. Despeaux Direclor, Federal Regulatory Affairs Issued on: August 29, 2001 Effective Date: December 12, 1995 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER95-1042-000, issued July 31, 2000, 92 FERC 61,119, order denying rehearing, issued July 30, 200.1, 96 FERC 61,165.

System Energy Resources, Inc.Rate Schedule FERC No. 2 Original Sheet No. 15 Attachment B Page 1 of 1 SYSTEM ENERGY RESOURCE=MONTHLY FUEL CHARGE FOR MONTH, XXXX LINE NO DESCRIPTION I FUEL EXPENSE FOR APPLICABLE SERVICE MONTH 2 MONTHLY FUEL CHARGE FOR EAI 3 MONTHLY FUEL CHARGE FOR ELI 4 MONTHLY FUEL CHARGE FOR EMI 5 MONTHLY FUEL CHARGE FOR ENOI S, INC.MULA REFERENCE/SOURCE FERC Account 51B 36%

• Line 1 14%' Line 1 33%

• Line I 17%

• Line I Issued by: Kimberly H. Despeaux Effective Date: December 12. 1995 Director, Federal Regulatory Affairs Issued on: August 29, 2001 Filed to comply with order of the Federal Energy Regulator Commission, Docket No. ER95-1042-000, issued July 31, 2000. 92 FERC 61,119, order denying rehearing, issued July 30, 2001, 96 FERC 61.165.

System Energy Resources.

Inc. Original Sheet No. 16 Rate Schedule FERC No. 2 Attachment C Page 1 of I System Energy Resources, Inc.Grand Gulf Decommissioning Model Revenue Requirements Summary ($000)Revenue Requirements Line Owned Leased No Year Portion Portion Total 1 1995 6.813 1,208 8.021 2 1996 11,195 1,997 13,192 3 1997 11.195 1,997 13.192 4 1998 11,195 1,997 13.192 5 1999 11,195 1,997 13,192 6 2000 11,195 1,997 13,192 7 2001 13,624 2,431 16,055 8 2002 13,624 2,431 16,055 9 2003 13,624 2,431 16,055 10 2004 13,624 2,431 16,055 11 2005 13.624 2,431 16,055 12 2006 16,590 2,960 19,550 13 2007 16,590 2,960 19,550 14 2008 16,590 2,960 19,550 15 2009 16,590 2,960 19,550 16 2010 16,590 2.960 19,550 17 2011 20,184 3.'601 23,785 18 2012 20.184 3,601 2.3,785 19 2013 20,184 3,601 23,785 20 2014 20,184 3,601 23,785 21 2015 20,184 2,101 22.285 22 2016 24,550 0 24,550 23 2017 24.550 0 24,550 24 2018 24,550 0 24,550 25 2019 24.550 0 24.550 26 2020 24,550 0 24,550 27 2021 29,878 0 29,878 28 2022 17,429 0 17.429 29 2023 0 0 0 30 2024 0 0 0 31 2025 0 0 0 32 2026 0 0 0 33 2027 0 0 0 34 2028 0 0 0 35 2029 0 0 0.36 2030 0 0 0 37 2031 0 0 0 Issued by: Kimberly H. Despeaux Effective Date: December 30, 1994 Director, Federal Regulatory Affairs Issued on: August 29, 2001 Filed to comply with order of the Federal Energy Regulatory Commission.

Docket No. ER95-1042-000.

issued July 31, 2000, 92 FERC 61,119, order denying rehearing, issued July 30, 2001, 96 FERC 61.165.

. 2 AVAILABILITY AGREEMENT BETWEEN MIDDLE SOUTH ENERGY, INC.ARKANSAS POWER & LIGHT COMNPANY, ARKANSAS-MISSOURI POWER COMPANY, LOUISIANA POWER & LIGHT COMPANY, MISSISSIPPI POWER & LIGHT COMPANY, and NEW ORLEANS PUBLIC SERVICE INC."u!'S AGREEMENT, dated as of the 21st day of June, 1974, between MIroLF Sot1rtr E.NERGY. INC. (.MSEI) and ARKANSAS POWER & 1 1;,1r CoCMPNYv (AP&L..), ARKANSAS-NI1SSOURI POWER COMPANY (Ark-Mo), LOUISIANA PoWEn & LIGHT COMPANY (LP&L), MIssIsSIPPI PoWER& LIGLT COMPANY (MP&L) and NEW ORLEANS PUBLIC SEavIcE INC. (NOPSI), WVTzN~ss'rl THAT:%V1'CREAs, AP&L, Ark-Mo, [.IP&L, .[P&L and NOPSI (collectively, System operating companies and, singly, System operating company), all outstanding shares of whose common stock are wholly owned by Middle South Utilities, Inc., operate electric generating, transmission and distribution facilities in the states of Arkansas, Louisiana, Mississippi and Missouri and comprise the Middle South System; and WuER.As, the System operating conmpanies are parties to an agreement dated April 16, 1973 (as presently constituted and as amended in the future, System Agreement).

which provides the contractual basis for the continued planning, construction and operation of certain facilities owned by the System operating companies to achieve the purposes set forth therein; and WHEREAS, other entities may become parties to the Systemn Agreement';

and WHEREAS. MSEI has been organized as a subsidiary of Middle South Utilities, Inc. to finance and own certain generating units for the benefit of the Middle South System, including the Grand Gulf Nuclear Electric Statiun project (Project*, a two unit nuclear-fueled electric generating plant having an expected aggregate capacity of 2,500,000 KW and to be located near Port Gibson, Mississippi; and\VIIFRECAS.

\ISEI is. subject to the ternis hIereof, willing to undertake the construction and operation of the Project. to becomie a party to the. System Agreetment and to irake available to the sarties, :is h,:rcin1;t r hetindc , Ofl i tie pmw r h c ,

thur(a,.vith)

avail:hih "t any NtSE I Generating Unit, including the Project. under the ternis hereof atid of the SyStem Agreement; and WVIIE-EAs.

the Partie., ais hercinaitcr defined, are. subject to the terms hereof, willing to purchase power (and the energy associated therewith) available or to be available at any MSEI GeeratingUnit, including the Project, under the terms hereof atid o the System Agreement;, sac ~ ~7:jj ~ I Now, TnEREFOR, in consideration of the terms and conditions hereinafter set forth, the parties hereto agree with each other as follows: 1. For the purposes of this Agreement, the following definitions shall apply: (a) Party or Parties shall mean any entity or entities (other than MSEI) now or hereafter a party or parties to this Agreement.(b) MSEI GeneratiW Unit shall be that portion of any electric generator, together with its prime mover aid all auxiliary and appurtenant devices and equlipvment designed to be operated as a iinit for the prodluction of electric power and energy and all associated equipment and facilities, which is owned by MSEI and which MSEI and the Parties have designated

is being subject to this Agreement.(c) Power shall mnian both power and the energy associated therewith, including test power produced during construction or thereafter.

2. MSEI and the Parties hereby designate Unit No. I and Unit No. 2 of the Project as being subject to this Agreement and MSEI Generating Units hereunder, and MSEI hereby undertakes to ttse its best efforts to construct the Project.3. On or before the date on which Unit N'o. 1 of the Project is placed iin commercial operation, MSEI and the Parties wvill join in executing such dlocument or documents as may be necessary for MSET to become a party to the System Agreement.

MSEI and the Parties will also join in executing at an appropriate time such document or documents as may be necessary for others who become parties ti the System Agreement to join in and become parties to this Agreement. ,IJSEI shall, subject to the provisions of the then applicable requirements of Section 6 of this Agreement and the then applicable provisions of the System Agreement (or any agreement substituted therefor), make available, or cause to be made available, to the Parties all Power available from time to time at any MSEI Generating Unit.4. The Parties shall, subject to the provisions of the then applicable requirements of Section 7 of this Agreement anid the then applicable requirements of the System Agreement (or any 'agreement substituted therefor) be entitled to rcceive all Power available from time to time at any MSEI Generating Unit; provided, that (i) should any Party termiinate its participation in the System Agree-nient, then it is agreed that MSEI, such Party and the other Parties shall enter into a separate agreement whereby such Party shall continue to be entitled to receive Power, and obligated to take Power, available at any MSEI Generating Unit which has been designated as being subject to this Agreement at the time such Party shall exercise its right to terminate sutch participation, in such amounts and for such consideration calculated from time to time as if such Party had remained a party to the System Agreement, and (ii) should the System Agreement be cancelled or terminated, then it is agreed that MSEI and all such Parties shall enter into a separate agreement whereby such Parties shall continue to be entitled to receive Power, and obligated to take Power, available at any MSEI Generating Unit which has been designated as being subject to this Agreement at the time of catnc:eilA6tion or termn Iation ,,f the Sy,,teml : \greecient.

ill Such a'lvhluouvlts alid fur -u;ch colrsilcra!hinn Calculated from time to time as if thle System AgrLement had remained in effect and MSEJ and .uch P:'arties were partics thereto. Notwithstanding such withdrawal from, or cancullation or termination of. the System Agreezernt,'

each Party shalstl remain homud by the t:erms of this Agn-'etlcat.

with respet.to anly MS'I Geucrating Uvnit which has been designated as being subject to this Agreement at the t.imle of such withdrawal, cancellation or termination.

fn considheration of .fS F s co-mmitment to miiderviakcu:

ýrostrtt'tn of :dl.,! Projic:t and its other ,:,llations here'undcr awul of the right of ilhe Parties to receive Power available at any MSEI Generatinig Unit under the ternis of the System Agreement (or any separate agreement referred to above), the Parties agree to pay to MSEI , commencing on the dhate on which a particular MSEI Generating Unit is deemed to he in operation for the purposes of this Agreement.

such amounts from time to time as. when added to aunounts received by MSEI 2 4~72~A 'il' .- -..a r£ e', .*5f24.' ' .1, I ~, .4 -~

riom any other source, including, but not limited to, amounts (if any) received by MSEI with respect to such MSEI Generating Unit under the terms of the System Agreement, shall be at. least equal to MSEI's total operating expenses and interest charges with respect to such MSEl Generating Unit, inch:ling (with]out liilitation), for the purposes o. this Agreeenet. (i) all cxN)nles, di th'iois.charges and other lit-ms properly chargeable to the applicable Income Accounts 400 to 435, inclusive, of the Uniform System of Accounts prescribed by the Federal Power Commission for Class A and Class B Public Utilities and Licensees, as in effect on April 1, 1973, (Uniform System of Accounts)or. if such MSEI Generating Unit is not in service for any reason, all expenses, deductions, charges and other items which would he chargeable to the above Accounts if such MSEI Generating Unit were in service; it heing agreed that when a particular generating" unit is designated as being subject tn this Agreemnent by MSEI arid the Parties, then, solely for the purposes of. determining MSEI's total operating .xpen.,ies under this Section 4, such MSEI Generating Unit shall be deemed to be in operation on the date, and the accrial of depreciation as an operating expense with respect to the MSEI Generating Unit shall be deemed to commence on the date at the rate and in the manner and continue for the duration, as is specified in the d6cumuent so designating such generating unit as a MSEI Generating Unit subject to this Agreement, whether or not such MSEI Generating Unit is actually in operation on such date, and (ii) such expenses as might be incurred in connection with permanent shut-down of any MSEI Generating Unit which is nuclear-fueled and, in the event of any such shut-down, for perpetual maintenance and surveillance of any such facility in accordance with, and as required by, all applicable regulations established by any governmental authority having juris-diction. Payments to he made pursuant to this Section 4 shall he made monthly and shall be apportioned among the Parties whose Company Capability is less than its Capability Responsibility, as such terms are defined in the System Agreement and as determined in accordance with Section 10 of the System Agreement, in the ratio of each such Party's deficiency to tile stint of the deficiencies of all such deficient Parties; provided, however, that if in any month no Party has such a deficiency then the payments for such month shall be apportioned among the Parties in accordance with the ratio of their then respective Capability Responsibilities, as such term is defined in the System Agreement.

For the purpose of this Agreenent, the Capability of all MSET 'Generating Units shall be included in the System Capability, as such terms are defined in the System Agreement.

In the event the System Agreement is not then in effect, or has been amended or interpreted so that at least one or more of the Parties is not obligated to make the entire payment herein provided, then the Parties agree to make payments hereunder in accordance with the ratio of their then respective "Capability Respon-sibilities", as such term is defined in Appendix A attached hereto and made a part hereof and not as defitned in the System Agreement.

Payments made by any Party to MSEI pursuant to this Section 4 shall be applied as a credit to such Party's liability for payments to MSEI under the System Agreement.

5. For the purpose of determining MSEI's expenses and the Parties' obligations under Section 4 of this Agreement, it is hereby agreed that both Unit No. I and Unit No. 2 of the. Project shall be deemed to be in operation on the earlier of December 31, 1982 (whether or not such Units, or either of them, are then completed or in operation) or the date on which either of such Units is first placed in commercial operation as determined under the System Agreement (or any agreement substituted therefor).

and the accrual of depreciation anid amortization with respect to the Project shall be deemed to commence on the earlier of such dates; that such accrual of depreciation aid anortization shall be at'she rate of 3.657 per annum of the aggregate amiount properly chargeable (prior to the deduction therefrom of a-y depreciation or amortization) at the time with respect to the Pioject to fBalkui c Sheet Accounts i1)1. 102. R13, 104, 105, 06., 107 (the aforeentczionted accounts being exclusive of land and laml rights), 118, 120 (.1 through .5), 121,°'123, 123.1, 124, 1.51. 152, 153. 1.34, 155, H56, 157, 163, 182, 1..3, IiA0 185. 186, 187 and IMS of the Uniform System of Accounts and such other accounts as are properly subject to deprcciation or amortization at the time pursuant to such Uiiiform System of Accounts; anld that such accrual shall continue during each of the first 27.4 years after tile dlate of contlmlencerneut of such accrual hIercuilder whether or not such Unit3, or, either of them, sýhall ever commlence operation and/or remain in operation; provitled, however, that if Unit No. I is placed in commercial operation prior to December .31, 1982 and Unit No. 2 is not completed and ready for 3-. ...0-~

service at such time, then until December 31, 1982 or the date Unit No.' 2 is placed in commercial operation, whichever'date occ'rs earlier, expenditures included in Account 107 which are identified exCusiv'ely with the Construction of Unit No. 2 may he excluded from the calkulation of the aggregate afirAoit subject to the accrualof depreciation and amortization pursuant to this paragraph.

6. The performance of the obligations of MSE[ heretnder shall be subject to the receipt and continued effectiveness of all authorizations of go'ernmental regulatory authorities at the time necessary to permit MSEl to perform its duties :nd obligations hereunder.

in.cluding the receipt and continued effectiveness of all authorizations by. governmental reguLuory authorities

'at the time necessary to pertrit MSEI to finance, to construct or cause Jo be constructed, to operate or catuse th be operated, and/or to make available to'the Parties the Power available at any MSEI Generating Unit.MSEI ishall ise its hest efforts to SeL:ure and tiailltin

ill. such a11t11,o1rizations lb. governmental regulatory atithorities.

7. The performance by each Party of its obl-igations hereunder shall 'be subject to the receipt and continued effectiveness of all authorizations of governmental regulatory authorities necessary at the time to permit it to periorm' its duties and obligations lhereunder, including the receipt and couitinued effectiveness of all authorizations by governmental regulatory authorities necessary at the time to permit it to pay to YSEI, in consideration for the right to receive, its share of the Power available at any. MSEI Generating Unit, the amounts provided for in Section 4 oif this Agreement.

E1.ach Party shall use its. best efforts to secure and maintain all such authorizations by governmental regulatory authorities.

Each Party shall, to the extent permitted by'law, be obligated to perform. its duties anzid obligations hereundier.

subject to the then applicable provisions of this Section 7, (a)whether or not MSEI shall have received all. autthorizations of governmental regulatory atuthorities necessary to MSET to perform its dnties and obligations hereunder or under the System Agreement, (b) 'whether or not-such authorizations, or any such authorization, shall at any time in question be,mn effect, (c) whether or-not the System Agreement shill, from time to time, be amended, modified or supplemented or shall be cancelled or terminated or such Party shall have .withdrawn therefrom and (d) so long as MSEI and such Party shall continue'.to be subsidiary companies of N Mi,ldle South Utilities, Inc. (as said term is defined in Section 2(a) (8) of the Public Utility Holding Comnlpany Act of 19.35) or a snccessor thereto, whether or not. at any time ,in question, %-TSEf shall have performed its duties and obligations under this Agreement or the System Agreement.

In the event that MSEI or any Party shall cease to be such a subsidiary company, then a nd thereafter such Party shall not be relieved of its obligation to make payments pursuant to Section 4 of this Agreement by reason of the failure of MSEI to perform its duties and obligations hereunder or under the-System Agreement occasioned by act of Godi, fire, flood, explosion, strike. civil.or.,jailitary auth6o*"it

' .".insurrection, riot,, act of the elements, failure of equipment, or for aniy othei cause beyond the, control of MSEI.8. To the extent they may legally do so. each Party and MSEI hereby irrevocably waive any defense based on the adeutiacy of a remeoly at law which may be asserted as a lar to the remedy ot specific performance in any action brought against it for specific per'formance of this Agreement by.any other party to this Agreement, or by a trutstee twider any, r mortgaige or other debt instrunient ,hich :my sulch paits to this Agtreneit may.., nibject to rqttisit r-tcgnlatt'ry atitholritv, enter into, tV ;myv rc-eiver or trist'e appointed1 for any sýuch party neder 'the lanukruptcy or irisolvencv laws 1; an.y iuri!nti dtion to which, any such party roay he subiej. t! pruvidvd.

hownvever, that, notbir, g hireiji ,'ot:ud shall IX deailmed to constitutie a rpres:ntathn or w:irranty by any pirty to this Agreement that 1hei r re pcrt iVe o:bl igat ions xidtler this.'\grecnlent are, as t na ltter Of law, siubj ct t(o :he eqtiitallec rentedy o(f spcci fic performance.

9. No Party shall he entitled to set off againit any paymtcit reluired to be made by such['arty under this Agreement (i) any anmounts owedl by NISEF to such Party or (ii.,) the amount of any claim by sUcii Party against MSEI. The foregoing, however, shall tot affect in any other way 4,_ s~rv~vMA the rights and remedies of any Party with respect to anty such amounts owed to such Party by MSEI Pr any such claim by stich Party against MSEI.10. Tlie invalility or unentorceahility oi any prrvision of this Agreement shall not affect the remaining provisions hereof.tI. This Agreement shall becoime effective forthwith.

This Agreement ma-y, be amended. tmdifitcd or terminated o;nly with the consent ot .MSI"7[ and of the Parties then having respon sibility for 1wo-thire.s or more of the amounts to be paid under Section 4 hereof, and upon the receipt and conlilmued effectiveness of all authorizations of governmental regulatory atuthorities at thme Lilme necessary.

12. This Agreement shall be binding upon the Parties and MSEI and their respective successors a1nd usigns, but no assignment hereof, or of any right to any f'unds due or to becorne due under this Agreement, shall in any event relieve any Party or MSMI of any of their respective obligations here-under, or. in the case of the Parties, reduce to any extent their entitlement to receive Power available from time to time at any MSEI Generating Unit.tI .The agreements herein set forth have been mtade for the benefit of the Parties, MSEI'and their respective successors and assigns, and no other person shall acquire or have any right tinder or hy virtue of this Agreement..

IN WITNESS WitF.Rvor.

the parties hereto have caused this Agreement to be duly executed by their respective officers thereunto duly authorized as of the (lay and year first above written.ARKANSAS POWER & LItGHT COMPANY By ...................................

Witness: Title ARKANSAS-IMISSOURI

[PowIR COMPANY By............

................,Vitness:

Title l.ot)SI~.\.

'"vw!R & [init' CO(T ,AINY 1ly ...................................

Witess: Title................................... ". .p.-. k.r.. *~-.A ~- -.~s APPENDIX A Definition of "Capability Responsibility" As Used in Availability Agreement"Capability Responsibility" shall mean: with respect to any "Company", the "System Capability" mUltiplied by the "Responsibility Ratio" for that Company."Company" shall mean one of the Middle South Utilities, Inc.'s System operating companies, :Ls defined in the Availability Agreement; "System Capability" shall mean the arithmetical sum in megawatts of the individual "Company Capabilities"; "Company Capabilities" shall be the net output in megawatts that can be produced by all uf a Company's generating units, each unit of which consists of an electric generator, together with its prime mover and all auxiliary and appurtenant devices and equipment designed to he operated as a unit for the production of electric power and energy, under the coinditions specified by the administrative organization then having the authority to so specify, under either the System Agreement or any similar and succeeding agreement to which such Company is a party, or the input in meg'awatts available under contract to such Company from a supplying source; provided, however, that each Company shall be deemed to have at least one Kilowatt of Capability, whether or not it has atny such Capability; "Responsibility Ratio" shall mean the ratio obtained by dividing a "Company Load Responsibility" by the "System Load Responsibility"; "Company Load Responsibility" shall mean (a)the average of the four highest clock-hour demands in megawatts of a Company's system, each on a differeuit day, occurring during the twelve month period ending with the current month, but not less than 90%0 of the average of the four highest such demniands occurring during the twenty-four (24) month 'period ending with the current nmont~m, where each such demand shall represent the simultaneous hourly input from all sources into the system of a company, less the suni of the simultaneous hourly outputs to the system of other interconnected utilities (Company demands shall include firm power supplied to other systems fGr its.own account), (1) lesst6e power supplied to others as sales fur the joint account of all Companies.(c) less the contractual amount of firm purchases with reserves available during the month from other systems for its own account; provided, however,*

that each Company shall be deemed to have a Load Responsibility of at least one kilowatt, whether or not such Company has any such Load Responsibility;

"'System Load Responsibility" shall be the arithmetical sum in megawatts of the individual Company Load Responsibilities.

7- i". .;~4&~,'.' .' -'~ ~4 ,. 7-.. 4'.

FIRST AMENDMENT TO AVAILABILITY AGREEMENT.

MIDDLE SOUTH ENERGY, INC.AND ARKANSAS POWER & LIGHT COMPANY, ARKANSAS-MISSOURI POWER COMPANY,, LOUISIANA.POWER

& LIGHT COMPANY, MISSISSIPPI POWER & LIGHT.COMPANY., and NEW ORLEANS PUBLIC SERVICE INC.THIS FIRST AMENDMENT, .dated as of the 30th day of June, 1977,.between Middle South Energy, Inc. (MSE), and Arkansas Power & Light Company (AP&L); Arkansas-Missouri Power Company (Ark-Mo), Louisiana Power & Light Company (LP&L), Mississippi Power & Light Company (MP&L) and New Orleans Public Service Inc.(NOPS1.), to the Availability Agreement, dated- as of the 21st day of June, 1974, between MSE and AP&L, Ark-Mo, LP&L, MP&L and NOPSI (Availability Agree-ment), WITNESSETH THAT: WHEREAS, pursuant to the provisions of Section 5 of the Availability.

Agreement, it has been agreed that Unit No. 2 of the Project shall be deemed to be in operation no later than December 31;.1982 for purposes of calculating the date of commencement of the accrual of depreciation and amortization with respect to Unit No: 2 of the Project; and WHEREAS, the commencement of commercial operation of'Unit No. 2 has been deferred to a date subsequent to December 31, 1982 but is expected to occur not later than December 31, 1986; and WHEREAS, it is now appropriate and necessary to revise the provisions of Section 5 of the Availability Agreement accordingly.

2 Now, THEREFORE, in consideration of the terms and conditions here-inafter set forth, the panics hereto agree with each other as follows: i. For the purposes of this First Amendment to Availability Agreement, any term used herein which has a defined meaning in the Availability Agreement shall have the same meaning herein.2. Section 5 of the Availability Agreement is hereby deemed amended so that the last reference in Section 5 to "December 31, 1982" shall be chinged to read "December 31, 1986".3. All other provisions of the Availability Agreement shall be deemed to continue in full force and effect.IN WITNEss WHEREOF, the parties hereto have caused this First Amendment to Availability Agreement to be duly executed by their respective officers thereunto duly authorized as of the day and year first above written.ARKANSAS POWER & LIGHT COMPANY Mississippi x9'ip A NY BY ..... B.. ..y .........

... ..........................

President President ARKANIAS-MISSOURI POWER COMPANY NEW ORLEANS PUBLIC SERVICE INC.By .... By President Preside, i.LLoujSIAN WER & LIGHT COMPANY MIDDLE /SO/(H ENERG>By. .... ... .. .........

B y ... .....Z....President Vie Prsideflt, Fina~nce SECOND AMENDMENT TO AVAILABILITY.

AGREEMENT*

BETWEEN MIDDLE SOUTH ENERGY, INC...AND ARKANSAS POWER & LIGHT COMPANY, LOUISIANA POWER & LIGHT COMPANY, MISSISSIPPI POWER & LIGHT COMPANY, and NEW ORLEANS PUBLIC SERVICE INC.THIs SECOND AMENDMENT, dated as of the 15th day of June, 1981. be-tween Middle South Energy, Inc. (MSE) and Arkansas Power & Light Corn-pany (AP&L),'Louisiana Power & Light Company (LP&L),. Mississippi Power & Light Company (MP&L) and New Orleans Public Service Inc.(NOPSI), to the Availability Agreement, dated as of the 21st day of June, 1974, between MSE and AP&L, Arkansas-Missouri Power Company. (Ark-Mo), LP&L, MP&L and NOPSI, as amended by the First Amendment thereto dated as of June 30, 1977 (Availability Agreement), WrnESsETI THAT: WHEREAS, pursuant to the provisions of Section 3 of the Availability Agreement, it has been agreed that on or before the date on which Unit No. I of the Project is placed in commercial operation MSE and the Parties will join in executing such document or documents as-may be necessary for MSE to become a party to the System Agreement and that MSE will make available to the Parties under the then applicable provisions of the System Agreement (or any agreement substituted therefor) all Power available from time to time at any MSEI Generating Unit; and WHEREAS, pursuant to..the,,pA~visioms of -Section 4 of the ,'( Agreement, it has been.agree" that the Parties shall be entitled, then applicable requirements of the Syistem -Agreement (or an.ae " substituted.therefor.), to rectiveeall Power available from time to. 1a Ww MSEI Qenerating Unit and shall be responsible for certain ofO -.o, 10t.g expensc,.of.such Units apportioned in accordance with the forn6laksci forts in SectiontS, and.3:3Qo5-.Cooo:3-OUU02:

/2 WHEREAS, Unit No. I and Unit No. 2 of the Project are MSEI Generating Units, and MSE and the Parties desire to allocate the Power available to MSE from time to time from these MSEI Generating Units and the operating ex-penses associated therewith'on a fixed percentage basis rather than in accord-ance with the System Agreement; and WHEREAS, pursuant to the provisions of Section 5 of the Availability Agreement, it has been agreed that both Unit No. I and Unit No. 2 of the" Project shall be deemed to be in operation no later than December 31, 1982 for purposes of commencing the accrual of depreciation and amortization with respect to such Units and that, if Unit No. I of the Project has been placed in operation on or prior to December 31, 1982, Unit No. 2 of the Project shall be deemed to be in operation no later than December 31, 1986 for purposes of commencing the accrual of depreciation and amortization with respect to such Unit; and WHEREAS, the commencement of commercial operation of Unit No. I has been deferred to a date subsequent to December 31, 1981 but currently is expected to occur not later than December 31, 1982, and the commencement of commercial operation of Unit No. 2 has been deferred to a date subsequent to December 31, 1985 but currently is expected to occur not later than De-cember 31, 1986; and WHEREAS, MSE and the Parties deem it desirable that there be an approxi-mate two-year interval between the presently expected commercial operation dates of the Units and the dates on which the Units shall'be deemed to be in operation under the Availability Agreement for purposes of commencing the accrual of depreciation and amortization with respect to such Units; and WHEREAS, MSE and the Parties have determined that it would be prefer-able if Power available from any MSEI Generating Unit could be sold either pursuant to the then applicable provisions of the System Agreement or pursu-ant to the terms of another or other agreements; and WHEREAS, effective January 1, 1981, the electric properties of Ark-Mo were consolidated with those of AP&L and Ark-Mo was dissolved, and AP&L assumed all of the obligations of Ark-Mo under the Availability Agreement; and__:2305-000_-3_-0 3 WHEREAS, MSE, AP&L, Ark-Mo, LP&L, MP&L and NOPSI have entered into (i) a First and Fourth Assignment of Availability Agreement, Consent and Agreement, dated as of June 30, 1977 and March 20, 1980, respectively, with Manufacturers Hanover Trust Company, as agent for certain banks, and (ii) a Second and Third Assignment of Availability Agreement, Consent and Agreement, dated as of June 30, 1977 and January 1, 1980, respectively, with United States Trust Company of New York and Malcolm J. Hood, as trustees;and WHEREAS, it is now appropriate and necessary to revise the provisions of Sections 3, 4 and 5 of the Availability Agreement accordingly.

Now, THEREFORE, in consideration of the terms and conditions hereinafter set forth, the parties hereto agree with each other as follows:* 1. For the purposes of this Second Amendment to Availability Agree-ment, any term used herein which has a defined meaning in the Availability Agreement shall have the same meaning herein.2. Sections 3, 4 and 5 of the Availability Agreement are hereby amended to read as follows: "3. On or before the date on which Unit No. I of the Project is placed in commercial operation, AP&L, LP&L, MP&L and NOPSI (Participating Parties) will (a) join with MSEI in executing an agreement which will set forth in detail the terms and provisions for the sale by MSEI to the Partici-pating Parties of Power available to MSEI from Unit No. 1 and Unit No. 2 of the Project (Power Purchase Agreement), or (b) join (together with all other Parties) in executing such document or documents as may be neces-sary for MSEI to become a party to the System Agreement in such a man-iner as will cause the Power from the Project to be sold under the terms thereof. MSEI shall, subject to the provisions of this Agreement and the then applicable provisions of the Power Purchase Agreement (or, if applica-ble, the System Agreement), make available, or cause to be made available, to the Participating Parties all Power available to MSEI from time to time from the Project. On or before the date on which any MSEI Generating Unit other than Unit No. I and Unit No. 2 of the Project (Additional MSEI Generating Unit) is placed in commercial operation, MSEI and the Parties will either (a) join in executing such document or documents as may be necessary for MSEI to become a party to the System Agreement in such a manner as will cause the Power from such Additional MSEI Gener-ating Unit to be sold under the terms thereof or (b) enter into an agreement or agreements which will set forth in detail the terms and provisions for the 4 sale by MSEI to the Parties of Power available to MSEI from such Addi-tional MSEI Generating Unit (Other MSEI Power Agreement).

Notwith-standing (a) that MSEI may be a party to the System Agreement at the time it enters into an Other MSEI Power Agreement, or (b) that MSEI may be a party to the Power Purchase Agreement at such time as it joins in the System Agreement, neither MSEI nor the Parties shall have any rights or duties under the System Agreement with respect to the Additional MSEI Generating Units which are subject to any Other MSEI Power Agreement or with respect to Unit No. I and Unit No. 2 of the Project if they are then subject to the Power Purchase Agreement.

No generating unit or portion thereof owned by MSEI will become an "MSEI Generating Unit" for pur-poses of this Agreement until it has been designated as such hereunder.

MSEI and the Parties will also join in executing at an appropriate time such document or documents as may be necessary for others who become parties to (a) the Power Purchase Agreement, (b) the System Agreement or (c)any Other MSEI Power Agreement to join in and become parties to this Agreement.

MSEI shall, subject to the provisions of the then applicable requirements of Section 6 of this Agreement and (a) the Power Purchase Agreement, (b) the System Agreement (or any agreement substituted therefor), or (c) any Other MSEI Power Agreement, make available, or cause to be made available, to the Parties all Power available to MSEI from time to time at any MSEI Generating Unit."4. The Parties shall, subject to the provisions of the then applicable requirements of Section 7 of this Agreement and (a) the Power Purchase Agreement, (b) the then applicable requirements of the System Agreement (or any agreement substituted therefor) or (c) any Other MSEI Power Agreement be entitled to receive all Power available to MSEI from time to time at any MSEI Generating Unit: provided, that (i) should any Party terminate its participation in (a) the Power Purchase Agreement, (b) the System Agreement or (c) any Other MSEI Power Agreement, then it is agreed that MSEI, such Party and the other Parties shall enter into a sepa-rate agreement whereby such Party shall continue to be entitled to receive Power, and obligated to take Power, available to MSEI at any MSEI Gener-ating Unit which has been designated as being subject to this Agreement at the time such Party shal exercise its right to terminate such participation, in such amounts and for such consideration calculated from time to time as if such Party had remained a party to (a) the Power Purchase Agreement, (b) the System Agreement or (c) any Other MSEI Power Agreement, and (ii) should (a) the Power Purchase Agreement, (b) the System Agreement or (c) any Other MSEI Power Agreement be cancelled or terminated, then it is agreed that MSEI and all such Parties shall enter into a separate agreement whereby such Parties shall continue to be entitled to receive r ~

I Power, and obligated to take Power, available to MSEI at any MSEI Gener-ating Unit at the time of cancellation or termination of (a) the Power Purchase Agreement, (b) the System Agreement or (c) any Other MSEI Power Agreement, in such amounts and for such consideration calculated from time to time as if (a) the Power Purchase Agreement, (b) the System Agreement or (c) any Other MSEI Power Agreement had remained in effect and MSEI and such Parties were parties thereto.'

Notwithstanding such withdrawal from, or cancellation or termination of, (a) the Power Purchase Agreement, (b) the System Agreement or (c) any Other MSEI Power Agreement, each Party shall remain bound by the terms of this Agreement with respect to any MSEI Generating Unit which has been designated as being subject to this Agreement at the time of such with-drawal, cancellation or termination.

The Power available to MSEI from both Unit No. I and Unit No. 2 of the Project will be allocated to the Participating Parties according to the following percentages:

AP&L ........................................

17.1%LP&L .........................................

26.9%M P&L .........................................

31.3%NOPSI .........................................

24.7%The percentage applicable to any Participating Party is hereinafter called its"Allocable Share". Notwithstanding such fixed allocation, the Participating Parties may, pursuant to the Power Purchase Agreement or otherwise, freely assign and transfer all or any portion of their respective Allocable Shares. No such transfer or assignment will change the percentage Alloca-ble Share of any Participating Party hereunder.

In consideration of MSEI's commitment to undertake construction of the Project and its other obliga-tions hereunder and of the right of the Parties to receive Power available to MSEI at any MSEI Generating Unit under the terms of (a) the Power Purchase Agreement, (b) the System Agreement or (c) any Other MSEI Power Agreement.

the Parties agree to pay to MSEI, commencing on the date on which a particular MSEI Generating Unit is deemed to be in opera-tion for the purposes of this Agreement, such amounts from time to time as, when added to amounts received by MSEI from any other source, includ-ing, but not limited to, amounts (if any) received by MSEI with respect to such MSEI Generating Unit under the terms of (a) the Power Purchase Agreement, (b) the System Agreement or (c) any Other MSEI Power Agreement.

shall be at least equal to MSEI's total operating, expenses and interest charges with respect to such MSEI Generating Unit, including (without limitation), for the purposes of this Agreement, (i) all expenses, deductions, charges and other items properly chargeable to the applicable Income Accounts 400 to 435, inclusive, of the Uniform System of Accounts 4 ~ C 6 prescribed by the Federal Energy Regulatory Commission for Class A and Class B Public Utilities and Licensees, as in effect on April 1, 1980 (Uni-form System of Accounts), or, if such MSEI Generating Unit is not in service for any reason, all expenses, deductions, charges and other items which would be chargeable to the above Accounts if such MSEI Generating Unit were in service; it being agreed that when a particular generating unit is designated as being subject to this Agreement by MSEI and the Parties, then, solely for the purposes of determining MSEI's total operating ex-penses under this Section 4, such MSEI Generating Unit shall be deemed to be in operation on the date, and the accrual of depreciation as an operating expense with respect to the MSEI Generating Unit shall be deemed to commence on the date, at the rate and in the manner and continue for the duration, as is specified in the document so designating such generating unit as an MSEI Generating Unit subject to this Agreement, whether or not such MSEI Generating Unit is actually in operation on such date, and (ii)such expenses as might be incurred in connection with permanent shut-down of any MSEI Generating Unit which is nuclear-fueled and, in the event of any such shut-down, for perpetual maintenance and surveillance of any such facility in accordance with, and as required by, all applicable regulations established by any governmental authority having jurisdiction.

Payments of all such expenses, deductions, charges, and other items to be made pursuant to this Section 4 shall be made monthly and (a) with respect to Unit No. I and Unit No. 2 of the Project shall be apportioned severally and not jointly among the Participating Parties, in accordance with the Allocable Share of each Participating Party, and (b) with respect to any Additional MSEI Generating Unit shall be apportioned among the Parties whose Company Capability is less than their Capability Responsibility, as such terms are defined in the System Agreement and as determined in accordance with Section 10 of the System Agreement, in the ratio of each such Party's deficiency to the sum of the deficiencies of all such deficient Parties; provided, however, that if in any month no Party has such a defi-ciency then the payments for such month shall be apportioned among the Parties in accordance with the ratio of their then respective Capability Re-sponsibilities, as such term is defined in the System Agreement.

For the purpose of this Agreement, the Capability of all MSEI Generating Units shall be included in the System Capability, as such terms are defined in the System Agreement.

In the event the System Agreement is not then in effect, or has been amended or interpreted so that at least one or more of the Parties is not obligated to make the entire payment herein provided, then the Parties agree to make payments hereunder with respect to any Addi-tional MSEI Generating Unit in accordance with the ratio of their then respective "Capability Responsibilities", as such term is defined in Appen-I -'--__

7 dix A attached hereto and made a part hereof and not as defined in the System Agreement.

Payments made by any Participating Party to MSEI pursuant to this Section 4 with respect to Unit No. 1 and Unit No. 2 of the Project shall be applied as a credit to such Participating Party's liability for payments to MSEI under the Power Purchase Agreement or the System Agreement, as the case may be. Payments made by any Party to MSEI pursuant to this Section 4 with respect to any Additional MSEI Generating Unit shall be applied as a credit to such Party's liability for payments to MSEI under (a) the System Agreement or (b) any Other MSEI Power Agreement.

"5. For the purpose of determining MSEI's expenses and the Participat-ing Parties' obligations under Section 4 of this Agreement with respect to Unit No. I and Unit No. 2 of the Project, it is hereby agreed that both Unit No. 1 and Unit No. 2 of the Project shall be deemed to be in operation on the earlier of December 31. 1984 (whether or not such Units, or either of them, are then completed or in operation) or the date on which either of such Units is first placed in commercial operation as determined under the Power Purchase Agreement, and the, accrual of depreciation and amortiza-tion with respect to the Project shall be deemed to commence on the earlier of such dates; that such accrual of depreciation and amortization shall be at the rate of 3.65% per annum of the aggregate amount properly chargeable (prior to the deduction therefrom of any depreciation and amortization) at the time with respect to the Project to Balance Sheet Accounts 101, 102, 103, 104, 105, 106, 107 (the aforementioned accounts being exclusive of land and land rights), 118, 120 (.1 through .5), 121, 123, 123.1, 124, 151, 152, 153, 154, 155, 156, 157, 163, 182, 183, 184, 185, 186, 187, and 188 of the Uniform System of Accounts and such Other accounts as are properly subject to depreciation or amortization at the time pursuant to such Uni-form System of Accounts; and that such accrual shall continue during each of the first 27.4 years after the date of commencement of such accrual hereunder whether or not such Units, or either of them, shall ever com-mence operation and/or remain in operation; provided, however, that if Unit No. 1 is placed in commercial operation prior to December 31, 1984 and Unit No. 2 is not completed and ready for service at such time, then until December 31, 1988 or the date Unit No. 2 is placed in commercial operation, whichever date occurs earlier, expenditures included in Account 107 which are identified exclusively with the construction of Unit No. 2 may be excluded from the calculation of the aggregate amount subject to the accrual of depreciation and amortization pursuant to this paragraph." 3. All other provisions of the Availability Agreement shall be deemed to continue in full force and effect.-'05-0.~0C'_E; t:Co;ýo-Si IN WriNEss WHEREOF, the parties hereto have caused this Second Amend-ment to Availability Agreement to be duly executed by their respective officers thereunto duly authorized as of the day and year above written.MIDDLE SOUTH ENERGY, INC. LOUISIANA POWER & LIGHT By: Senior iW Presidek t t ident and Chi fExecutive Officer ARKANSAS POWER & LIGHT MISSISSIPPkPOW

& LIGHT COMPANY COMPA ..(By: y (/ esident and President and Chi Executive Officer Chief Fxecutive Officer NEW ORLEANS PUBLIC SERVICE INC.By: " z P Presdenti and Chief Executive Officerý171-I Exhibit B-13(a)THIRD AMENDMENT TO AVAILABILITY AGREEMENT Between MIDDLE SOUTH ENERGY. INC.And ARKANSAS POWER & LIGHT COMPANY.LOUISIANA POWER & LIGHT COMPANY.MISSISSIPPI POWER & LIGHT COMPANY, and NEW ORLEANS PUBLIC SERVICE INC.This Third AMENDMENT.

dated as of the 28th day of June, 1984. between Middle South Energy. Inc.(MSE), and Arkansas Power & Light Company (AP&L). Louisiana Power & Light Company (LP&L).Mississippi Power & Light Company (MP&L) and New Orleans Public Service Inc. (NOPSI), to the Availability Agreement, dated as of the 21st day of June. 1974. between MSE and AP&L, Arkansas-Missouri Power Company (Ark-Mo).

LP&L, MP&L and NOPSI, as amended by the First Amendment thereto dated as of June 30. 1977 and the Second Amendment thereto dated as of June 15, 1981 (Availability Agreement), Wr'NESSETH THAT.WHEREAS, pursuant to the provisions of Section 5 of the Availability Agreement, it has been agreed that both Unit No. I and Unit No. 2 of the Project shall be deemed to be in operation no later than December 31. 1984 for the purposes of commencing the accrual of depreciation and amortization with respect to such Units and that, if Unit No. I of the Project has been placed in operation on or prior to December 31, 1984, Unit No. 2 of the Project shall be deemed to be in operation no later than December 31. 1988 for purposes of commencing the accrual of depreciation and amortization with respect to such Unit. and WHEREAS, commercial operation of Unit No. I is currently scheduled to commence in the first quarter of 1985;.and WHEREAS, MSE and the Parties deem it desirable that there be a reasonable interval between the presently expected, commercial operation date of. Unit No. I and the date on which Unit No. I shall be deemed to be in operation under the Availability Agreement for purposes of commencing the accrual of depreciation and amortization with respect to Unit No. I and Unit No. 2 of the Project: and WHEREAS. effective January I, 1981, the electric properties of Ark-Mo were consolidated with those of AP&L and Ark-Mo was dissolved, and AP&L assumed all of the obligations of Ark-Mo under the Availability Agreement; and WHEREAS, MSE, AP&L. LP&L. MP&L and NOPS! have entered into (i) a First. Fourth. Fifth and J Eighth Assignment of Availability Agreement.

Consent and Agreement, dated as of June 30. 1977. March 20. 1980. June 15, 1981 and June 30; 1983. respectively, with Manufacturers Hanover Trust Company. as agent for certain banks, (ii) a Second and Third Assignment.of Availability Agreement.

Consent and Agreement, dated as of June 30. 1977 and January I. 1980. respectively, with United States' Trust Company of New York and Malcolm 1. Hood. as trustees. (iii) a Sixth and Seventh Assignment of Availability Agreement.

Consent and Agreement.

dated as of February 5. 1982 and February 18. 1983.respectively, with Credit Suisse First Boston Limited. as agent for certain banks, and (iv) a Ninth Assignment of Availability Agreement.

Consent and Agreement.

dated as of December 1, 1983. with Citibank, N.A. and Deposit Guaranty National Bank. as Trustee: and WHEREAS, it is now appropriate and necessary to revise Section 5 of the Availability Agreement accordingly, 6710al7`1111 Now. THEREFORE:

in consideration of the terms and conditions hereinafter set forth, the panics hereto agree with each other as follows: 1. For the purposes of this Third Amendment to Availability Agreement.

any term used herein which has a defined meaning in the Availability Agreement shall have the same meaning herein.2. Section 5 of the Availability Agreement is hereby deemed amended so that the two references in Section 5 to "December

31. 1984" shall be changed to read "December 31, 1985".3. All other provisions of the Availability Agreement shall be deemed to continue in full force and effect.IN WITNESS WHEREOF. the parties hereto have caused this Third Amendment to Availability Agreement to be duly executed by their respective officers thereunto duly authorized as of the day and year first above written.ARKANSAS POWER & LIGHT COMPANY/6eMaulden, President LOUISIANA POWER & LIGHT COMPANY By: t................

Aresidentcn' MISSISSIPPI PO D.. uken, ChairmanofteBa and Chief Executive Officer NEW ORLEANS PURLIC SERVICE INC.By .....M Cain, resident MIDDLE SOUTH ENERGY. INC.B .................................

F.W. Lewis, President 2_______ -I.' ~ ___

FOURTH AMENDMENT TO AVAILABILITY AGREEMENT Between SYSTEM ENERGY RESOURCES, INC.And ARMANSAS POWER & LIGHT COMPANY, LOUISIANA POWER & LIGHT COMPANY, MISSISSIPPI POWER & LIGHT COMPANY, and NEW ORLEANS PUBLIC SERVICE INC.This Fourth AMENDMENT, dated as of the 1st day of June, 1989, between System Energy Resources, Inc. (System Energy), and Arkansas Power & Light Corpany (A?&L)Louisiana Power & Light Company (LP&L), Mississippi Power.& Light Conpany (M?&L) and New Orleans, Public Service Inc.(NOPSI), to the Availability Agreement, dated as of the 21st day of June, 1974, between Middle South Energy, Inc.and AP&L, Arkansas-Missouri Power Company, LF&L, MP&L and NOPSI, as amended by the First Amendment thereto dated as of June 30, 1977, the Second Amendrment thereto dated as of June 15, 1981 and the Third Amendment thereto dated as of June 28, 1984. (Availability Agreement), WITNESSETH THAT: WHEREAS, a special group of officials have conducted an evaluation and review of Unit No. 2 of the Project; and WHEREAS, System Energy and the Parties deem it desirable that, for purposes of the Availability Agreement, any of System Energy's investment associated with Unit No. 2 which it will not be permitted to charge its customers in wholesale rates, and the obligations of the Parties to pay such investment to System Energy, be amortizable at the rate of 3.65% of such investment over a period of 27.4 years; and WHEREAS, effective December 20, 1986, System Energy's nrame was changed from Middle South Energy, Inc. to System Energy Resources, Inc.; and WHEREAS, System Energy, AP&L, LP&I., FP&L ard NOPSI have entered into (i) a sixteenth Assignment of the Availability Agreement, Consent and Agreement, dated as of May 1, 1986, with United States Trust Company of NJew York and Malcolm J. Hcod, as Trustees, (ii) a Fourteenth and Fifteenth Assignment of the Availability Agreement, Consent and Agreement, dated as of June 15, 1985 and May 1, 1986, respectively, with Deposit Giaranty National Bank, United States Trust Company of New York and Malcolm J. Hood, as Trustees, (iii) a Seventeenth, Eighteenth, Nineteenth, Twentieth and Twenty-first Assignment of the Availability Agreement, Consent and Agreement, dated as of September 1, 1986, September 1,.1986, September 1, 1986, November 15, 1987 and Decenber 1, 1987, respectively, with United States Trust Company of New York and Gerard F.Ganey, as Trustees, and (iv) a Twenty-second Assignient of the Availability Agreement, Consent and Agreement, dated as of December 1, 1988, with Chemical Bank as Agent, pursuant to which the following terms of this Fourth Amendment have been consented to; and WHEREAS, it is now appropriate and necessary to revise Section 4 of the Availability Agreement accordingly.

NOW, THEREFORE, in consideration of the terms and conditions hereinafter set forth, the parties hereto agree with each other as follows: 1. For the purposes of this Fourth Amendment to Availability Agreement, any term used herein, which has a defined meaning in the Availability Agreement shall have the same meaning herein.2. Section 4 of the Availability Agreement is hereby amended to add the following'to the end of such Section: Notwithstanding anything to the contrary in this Section 4, in the event that any portion of the Project is Abandoned prior to its Completion, the portion of System Energy's investment which It is not permitted to charge to its customers in wholesale rates ("disallowed investment")

and-the obligations of the Parties to pay such disallowed investment to System Energy, shall be amortizable from the date on which System Energy is obligated by applicable generally accepted accounting principles to eliminate the disallowed investment from the asset side of its balance sheet no less rapidly than at the rate of 3.65% of the disallowed investment per annum for a period of 27.4 years.Any portion of the Project that is Abandoned shall no longer be subject to this Availability Agreement except that Section 4 and 5 hereof.shall remain applicable to System Energy's investment (including the disallowed investment) in the Project."Abandoned" shall mean the good faith decision by System Energy to abandon any material portion of the Project as evidenced by a resolution of the Board of Directors of System Energy followed by a cessation of all operations (other than preservative maintenance) of such material portion for a period of ninety (90)days certified to in a certificate signed by the President or a Vice-President and the Treasurer or an Assistant Treasurer of System Energy (Officers' Certificate)."Completion", when applied to Unit No. 2, shall mean the first date on which all of the following have occurred:

the necessary permits and operating licenses have been issued; the critical tests for the major components have been completed; Unit No. 2 has been placed in the control of System Energy by the principal contractor; Unit No. 2 has been synchronized into the power grid of the Parties for its function in, the business of generating electric energy for the production of income; Unit No. 2 is -available for commercial operation; and an Officers' Certificate to such effect shall have been delivered to all necessary parties.3. All other provisions of the Availability Agreement shall be deemed to continue in full force and effect.IN WITNESS WHEREOF, the parties hereto have caused this Fourth Amendment to Availability Agreement to be duly executed by their respective officers thereunto duly authorized as of the day and year first above written.p .SYSTEM ENERGY RESOURCES,.

INC..,- ;illiam Cava I .Presidentt AR.KANSAS POWER & LIGHT COMPANY MISSISSIPPI POWER & LIGHT COMPANY" LOUISIANA POWER & LIGHT COMU'AY.-By: .__._____NEW ORLEANS PUBLIC SERVICE INC.By:__* II.

CNRO-2012-00007 SERIES 3 ATTACHMENTS 3 Entergy Gulf States Louisiana, LLC RBS Status Report -70% Regulated (1 page)3-A Entergy Gulf States Louisiana, LLC -Calculation of Minimum Amount (1 page)3-B Schedule of Remaining Principle Payments -RBS (1 page)3-C Entergy Gulf States Louisiana, LLC RBS Status Report -30% Non-Regulated (1 page)3-D LPSC Order in Docket No.U-31237 (20 pages)3-E PUCT Order in Docket No. 37744 (16 pages)3-F FERC Order in Docket Nos. ER86-558-002 (9 pages)3-G MSS-4 Agreement and FERC's acceptance (13 pages)

Attachment 3 (1 page)ENTERGY GULF STATES LOUISIANA, L.L.C.Status Report of Decommissioning Funding For Year Ending December 31, 2011 -10 CFR 50.75(f)(1)

Plant Name: River Bend Station (70% Regulated Interest)1. Minimum Financial Assurance (MFA)Estimated per 10 CFR 50.75(b) and (c) (2011$): 2. Decommissioning Fund Total As of 12/31/11: 3. Annual amounts remaining to be collected:

4. Assumptions used: Rate of Escalation of Decommissioning Costs: Rate of Earnings on Decommissioning Funds: Authority for use of Real Earnings Over 2%: 5. Contracts upon which licensee is relying For Decommissioning Funding: 6. Modifications to Method of Financial Assurance since Last Report: 7. Material Changes to Trust Agreements:

$423.0 million 1$192.3 million See Attachment 3-B See item below 2% real rate of return per 10 CFR 50.75(e)(1

)(i)N/A See footnote 2 See footnote 3 None See Attachment 3-A 2 See the agreement in attachment 3-G for the MSS-4 Agreement which is a unit power purchase agreement under the MSS-4 Agreement, a FERC tariff. The licensee had previously believed this arrangement would qualify as a contractual obligation, but upon further consideration, the licensee believes this arrangement is simply a cost of service recovery mechanism as defined in 10 CFR §50.75(e)(1)(ii)(A).

This MSS-4 Agreement is a FERC tariff, part of the larger Entergy System Agreement, which is itself a FERC tariff. The NRC reviewed this arrangement in a license transfer application in 2007 (see ADAMS Accession Nos. ML071560529 and ML072470715).

Accordingly, it is the licensee's position that this agreement' is not a 10 CFR§50.75(e)(1)(v) "contractual obligation," but rather a cost of service tariff which may appropriately be used to fund the external sinking fund in accordance with 10 CFR §50.75(e)(1)(ii).

Out of an abundance of caution, the licensee identifies this information here.3 Please see footnote 2 above. The MSS-4 Agreement was modified in 2010 in response to certain concerns raised by the NRC Staff. The modifications were accepted by the FERC on February 14, 2011. See attachment 3-G for the changes to the MSS-4 Agreement and the FERC's acceptance thereof.

Attachment 3-A (1 page)ENTERGY GULF STATES LOUISIANA, L.L.C.Calculation of Minimum Amount For Year Ending December 31, 2011 -10 CFR 50.75(f)(1)

I I Entergy Gulf States Louisiana, L.L.C.: Factors below used for all of ownership interests Plant Location:

West Feliciana Parish, Louisiana Reactor Type: Boiling Water Reactor ("BWR")Power Level: <3,400 MWt (3,091 MWt)BWR Base Year 1986$: $131,819,000 Labor Region: South Waste Burial Facility:

Generic Disposal Site 10CFR50.75(c)(2)

Escalation Factor Formula: 0.65(L) +0.13(E) +0.22(B)L=Labor (South)E=Energy (BWR)B=Waste Burial-Vendor (BWR)BWR Escalation Factor: 0.65(L) +0.13(E) +0.22(B)=1986 BWR Base Year $ Escalated:

$131,819,000

• Factor=River Bend 70% Regulated Interest: River Bend 30% Non-Regulated Interest: Total Factor 2.281 2.662 12.543 4.58401$604,259,178

$422,981,425 181,277,753

$604.259.178B 1 2 3 Bureau of Labor Statistics, Series Report ID: CIU2010000000220i (4 th Quarter 2011)Bureau of Labor Statistics, Series Report ID: wpu0543 and wpu0573 (December 2011)Nuclear Regulatory Commission:

NUREG-1307 Revision 14, Table 2.1 (2010)

Attachment 3-B (1 page)Schedule of Remainina Princioal Payments into River Bend Decommissioninq Fund ($ Thousands)

Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 LPSC$$$$$$$$7,843 7,843 7,843 8,996 8,996 8,995 8,995 8,996$10,195$10,195$10,195$10,195$10,195$11,693$11,693$11,693$11,693$11,693$13,513$0$0$0$0 PUCT$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019$ 2,019 FERC$ 113$ 113$ 113$ 113$ 113$ 113$ 113$ 113$ 113$ 113$ 113$ 113$ 113$ 165$0$0$0$0$0$0$0$0$0 Total$ 9,975$ 9,975$ 9,975$11,128$11,128$11,127$11,127$11,128$12,327$12,327$12,327$12,327$12,327$13,877$13,712$13,712$13,712$13,712$15,532$ 2,019$ 2,019$ 2,019$ 2,019 Note: Approved in LPSC Docket No.U-31237, see Attachment 3-D; PUCT Order in Docket No. 37744, See Attachment 3-E; FERC Order in Docket Nos. ER86-558-002, see Attachment 3-F.

Attachment 3-C (1 page)ENTERGY GULF STATES LOUISIANA, L.L.C.Status Report of Decommissioning Funding For Year Ending December 31, 2011 -10 CFR 50.75(f)(1)

Plant Name: River Bend Station (30% Non-Regulated Interest)1. Minimum Financial Assurance (MFA)Estimated per 10 CFR 50.75(b) and (c) (2011$): $181.3 2. Decommissioning Fund Total As of 12/31/11:

$228.7 3. Annual amounts remaining to be collected:

None 4. Assumptions used: Rate of Escalation of Decommissioning Costs: See ne)Rate of Earnings on Decommissioning Funds: 2% real million'millionitem rate of return Authority for use of Real Earnings Over 2%: 5. Contracts upon which licensee is relying For Decommissioning Funding: 6. Modifications to Method of Financial Assurance since Last Report: 7. Material Changes to Trust Agreements:

per 10 CFR 50.75(e)(1)(i)

N/A None None None 1 See Attachment 3-A Attachment 3-D (20 pages)LPSC Order in Docket No.U-31237 LOUISIANA PUBLIC SERVICE COMMISSION ORDER NO. U-31237 ENTERGY GULF STATES LOUISIANA, L.L.C.ENTERGY LOUISIANA, LLC EX PARTE Docket No. U1-31237 In re: Joint Application of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC for approval of an Increase in Funding for Decommissioning for River Bend and Waterford 3 Nuclear Facilities LPSC Docket No. U1-3123 7.(Decided at the Commission's July 28, 2010 Business and Executive Session.)Overview and Procedural History Entergy Gulf States Louisiana, L.L.C. ("EGSL") and Entergy Louisiana, LLC ("ELL") (collectively "the Companies")

filed a joint Application with supporting documentation and testimony on December 29, 2009 seeking approval from the Louisiana Public Service Commission

("LPSC" or "Commission")

to provide supplemental funding for the decommissioning trusts maintained for the LPSC-jurisdictional portions of ELL's Waterford 3 and EGSL's River Bend nuclear generation units.' The request to increase the amounts is the result of the Nuclear Regulatory Commission

("NRC") notifying the Companies of "a projected shortfall of decommissioning funding assurance" at both Waterford 3 and River Bend. The filings were published in the Commission's Official Bulletin on January 8, 2010. Interventions were filed by the Louisiana Energy Users Group ("LEUG"), Marathon Oil Company ("Marathon"), ArcelorMittal LaPlace, LLC ("ArcelorMittal")

and the Alliance for Affordable Energy ("the Alliance").

This matter was assigned to Administrative Law Judge Michelle Finnegan who presided over a status conference on February 22, 2010. At the status conference, Commission Staff requested that establishing a procedural schedule be postponed until after Commission hiring of an outside consultant to assist Staff in this matter. Staff advised that a Request for Proposals had been issued on February 5, 2010, and Staff anticipated the Commission's hiring decision would occur at the Commission's March 2010 Business and Executive

("B&E"). No party opposed Staff's request. A follow up conference was scheduled for April 5. At the Commission's March 10 B&E, the Commission voted to hire the firms of Exeter Associates, Inc. and Henderson Ridge Consulting, who submitted a joint proposal.

At a status conference held April 5, the parties established a procedural schedule with hearings set for early August 2010.On May 24, 2010 the Companies filed an Unopposed Motion to Modify and Amend Procedural Schedule to postpone the schedule while the parties worked to negotiate a possible settlement or narrow issues for hearing; the motion was granted. The Companies and Staff filed, on June 24, an Unopposed Joint Motion to Suspend the Procedural Schedule.

The motion was granted, and as requested in the motion, the I Waterford 3 is a single-unit 1,152 MW nuclear steam-electric gcnerating station located near Killona, Louisiana that was constructed by ELL's predecessor, Louisiana Power & Light Company, and began commercial operation in September 1985. Waterford 3 employs the pressurized-water-reactor design.River Bend is a single-unit 967 MW nuclear steam-electric generating station located near St.Francisville, Louisiana that was constructed by EGSL's predecessor, Gulf States Utilities Company, and began commercial operation in June 1986. River Bend employs the boiling-water-reactor design.Order No. U-31237 Page I parties were directed to file an update on the status of the case or an uncontested stipulation on or before July 9. On July 9, Staff and the Companies advised that a Settlement Term Sheet had been executed by all but one party, and that the parties planned to file the uncontested stipulation and request that a hearing be set so that this matter could be considered at the Commission's July B&E. On July 13, 2010 the parties filed a Joint Motion for the Scheduling of a Stipulation Hearing and Request for Expedited Hearing. The motion was granted and a Stipulation Hearing was convened on July 20, 2010.Commission Authority Louisiana Constitution and Statutes: The Commission exercises jurisdiction in this proceeding pursuant to Article IV, Sec. 21 of the Louisiana Constitution, and La. R.S. 45:1163(A)(1) and La. R.S. 45:1176.La. Const. Art. IV, Sec. 21 provides in pertinent part: The Commission shall regulate all common carriers and public utilities and have such other regulatory authority as provided by law. It shall adopt and enforce reasonable rules, regulations, and procedures necessary for the discharge of its duties, and perform other duties as provided by law.La. R.S. 45:1163 provides in pertinent part: A. (1) The Commission shall exercise all necessary power and authority over any street, railway, gas, electric light, heat, power, waterworks, or other local public utility for the purpose of fixing and regulation the rates charged or to be charged by and service furnished by such public utilities.

La. R.S. 45:1176 provides in pertinent part: The Commission...

shall investigate the reasonableness and justness of all contracts, agreements and charges entered into or paid by such public utilities with or to other persons, whether affiliated with such public utility or not.Companies' Application The Companies December 29, 2009 Joint Application requests an increase in revenues for ELL and EGSL to provide supplemental funding for the decommissioning trusts maintained for the LPSC-jurisdictional portions of ELL's Waterford 3 and EGSL's River Bend nuclear generation units. The request for increase is the result of the NRC's determination of a projected shortfall in the decommissioning funding at both Waterford 3 and River Bend.The Companies' Application proposes new revenue requirement amounts consistent with their revised decommissioning funding plans using a 40 year license and requests approval to include these revenue requirements in their 2009 Test Year Formula Rate Plan ("FRP") filings. ELL requests approximately

$10.336 million per year for its LPSC-jurisdictional revenue requirement in 2010 to meet the NRC minimum funding assurance of $400.2 million, which would be a $7.94 million increase over the $2.396 million in ELL's rates. For EGSL's portion of the regulated 70% share of River Bend, Order No. U-31237 Page 2 EGSL requests a revenue requirement of $9.671 million per year to meet its NRC minimum assurance of $378.8 million. Currently, EGSL has no funding in retail rates for decommissioning.

Staff's Review Commission Staff conducted a review of the Application, supporting documentation and testimony.

Commission Staff issued data requests, reviewed those responses and conducted a series of conferences with the Companies.

Staff proposed certain adjustments to the Companies' filed calculations of their revenue requirements to update the trust fund balances, extend the funding period and modify the investment portfolio allocations.

Commission Staff and the Companies reached a stipulated agreement, taking into account Commission Staff's adjustments, that resolves all issues in this docket.Uncontested Stipulated Settlement The Companies and Staff filed on July 13, pursuant to Rule 6 of the Commission's Rules of Practice and Procedure, a motion for stipulation hearing, Settlement Term Sheet signed by all parties, and supporting testimony from Kenneth Gallagher for the Companies and Thomas S. Catlin and William J. Barta for Commission Staff. A stipulation hearing was held July 20. At the stipulation hearing, the Companies presented the live testimony of Mr. Gallagher and Commission Staff presented the live testimony of Mr. Catlin. In addition to live testimony, the following documents were entered into the record: Joint Staff EGSLIELL Exhibit I -Settlement Term Sheet;Staff Exhibit I- Settlement Testimony of William J. Barta, dated July 2010;Staff Exhibit 2- Settlement Testimony of Thomas S. Catlin, dated July 2010;EGSLIELL Exhibit I- Settlement Testimony of Kenneth F. Gallagher, dated July 9, 2010;EGSL/ELL Exhibit 2- Direct Testimony of Kenneth F. Gallagher, redacted public version, dated December 2009; and EGSLJELL Exhibit 3- Direct Testimony of Kenneth F. Gallagher, confidential version, dated December 2009.Conclusion On motion of Commissioner Campbell, seconded by Commissioner Field, and unanimously adopted, the Commission voted to accept the Staff Recommendation and adopt the uncontested stipulated Settlement Term Sheet filed into the record on July 13, 2010. Therefore, IT IS ORDERED: 1. The Companies submitted a Joint Application seeking approval to provide supplemental funding for the decommissioning trusts maintained for the LPSC's jurisdictional portions of the Waterford 3 Steam Electric Station ("Waterford 3") owned by ELL and the River Bend Station ("River Bend") owned by EGSL.Order No. U-31237 Page 3 The Companies requested increases in their respective revenue requirements to address projected shortfalls found by the Nuclear Regulatory Commission

("NRC") in the decommissioning funding assurance required for each facility.2. The proposed revised revenue requirement amounts are a result of the NRC notifying the Companies of the referenced projected shortfall of decommissioning funding assurance at both Waterford 3 and River Bend.Under NRC financial assurance requirements regulations found in 10 CFR 50.75(a)-(O, ELL and EGSL, as holders of nuclear operating licenses, must certify through biennial filings that available decommissioning funds are not less than the NRC's prescribed minimum amount required to fund decommissioning costs. The projected shortfalls determined by the NRC are a result of several factors, including the NRC's requirement that only the currently approved license life of forty (40) years for each unit may be used in calculating the minimum financial assurance amount. The LPSC, in prior Orders, used a sixty (60) year license life to determine the appropriate level of funding for the decommissioning trusts, based on possible license extensions that the Companies are expected to apply for in the future.3. The Companies have proposed new revenue requirement amounts consistent with their revised decommissioning funding plans using a 40 year license and requested approval to include these revenue requirements in their 2009 Test Year Formula Rate Plan ("FRP") filings in the manner provided for in each Company's FRP.2 ELL has requested approximately

$10.336 million per year 3 for its LPSC-jurisdictional revenue requirement in 2010 to meet the NRC minimum funding assurance of $400.2 million, which would be a $7.94 million increase over the $2.396 million in ELL's rates. For EGSL's portion of the regulated 70% share of River Bend 4 , EGSL has requested a revenue requirement of $9.671 million per year to meet its NRC minimum assurance of$378.8 million.3 Currently, EGSL has no funding in retail rates for decommissioning.

4. The Commission has recognized in its prior rate Orders setting decommissioning accruals for both ELL and EGSL that the decommissioning accrual issue would be revisited if the NRC notified the Companies that decommissioning funding was inadequate.

Orders addressing both EGSL and ELL contain language substantially as follows: "In the event that the Nuclear Regulatory Commission

("NRC") formally notifies [EGSL or ELL] or [the River Bend or Waterford 3] licensee that the decommissioning funding for[River Bend or Waterford 31 is or would become inadequate, the Company would be permitted recognition in rates of decommissioning expense at a level sufficient to address reasonably the NRC's concern as expressed in the notification.'

6 2 Section 3.A.5 of the EGSL and ELL FRP Riders both contain identical language stating, in pertinent part that: "The effects of the changes in depreciation rates, and/or decommissioning accruals, increases and decreases, ordered by the LPSC, including as a result of changes in the requirement to fund the decommissioning trust that may be ordered by the Nuclear Regulatory Commission during the period that this FRP is in effect, shall be considered separately outside of the FRP mechanism." 3 The retail revenue requirement for ELL is $10.134 million.4 Thirty percent of the River Bend plant is unregulated and was acquired by EGSL from the former Cajun Electric Power Cooperative, Inc. as part of a bankruptcy reorganization.

See In Re Cajun Electric Power Cooperative, Inc., 238 B.R 319 (M.D. La. 1999) aff'd 119 F.3V 349 (5'" Cir. 1997). The decommissioning funding for this 30% share is separately funded and is not subject to the NRC's notice of projected shortfalls in the decommissioning funding assurance and, therefore, not subject to the review being undertaken in this proceeding.

5 The $378.8 million figure represents the combined total for the River Bend regulated plant, including the Louisiana, Texas and wholesale jurisdictions.

The Louisiana retail jurisdictional share of River Bend's NRC minimum is $217.76 million.6 For EGSL and River Bend, the provision comes from Item 8 of settlement term sheet for Consolidated Order Nos. U-22491, U-23358, U-24182, U-24993, U-25687 dated January 8, 2003. For ELL and Waterford 3, the provision comes from Item 4 of the settlement term sheet for Order No. U-20925 RRF 2004 dated May 25, 2005.Order No. U-31237 Page 4

5. After incorporating certain adjustments to the Companies' filed calculations of their revenue requirements to update the trust fund balances, extend the funding period and modify the investment portfolio allocations, the Staff and the Companies have agreed upon new decommissioning funding requirements for both Waterford 3 and River Bend. The agreed upon decommissioning funding is intended to serve only to meet the decommissioning funding requirements on an interim basis, and the Staff and Companies agree that both the Waterford 3 and River Bend funding requirements will be re-evaluated based on site specific cost studies after ELL and EGSL, respectively, have filed for and received the NRC's responses to requests for license extensions for the two nuclear facilities.

It is recognized that there is no certainty that either ELL or EGSL will receive license extensions for their respective plants and that the LPSC may have to re-evaluate and adjust revenue requirements based on a forty (40) year life for each plant.6. The initial funding requirement of $5.947 million ($5.831 million on a retail basis) per year is appropriate.

This amount will be included in ELL's revenue requirement for the Waterford 3 decommissioning funding plan, with collections to begin with the September 2010 billing cycle rate change scheduled to occur through the implementation of ELL's 2009 Test Year Formula Rate Plan and further finds that these costs are to be treated as"Extraordinary Costs" and recovered outside of the earnings sharing mechanism of the Formula Rate Plan. This calculation is based on the 5-year step funding plan historically used for Waterford 3 and reflects beginning fund balance, the investment portfolio allocations, escalation and earnings rates, 5-year funding increments, and other assumptions set forth in the Attached Exhibit A.7. For River Bend, an initial funding requirement of $7.843 million per year stepped up on a 5-year basis is appropriate 7.This amount will be included in EGSL's revenue requirement for the River Bend decommissioning funding plan, with collections to begin with the September 2010 billing cycle rate change scheduled to occur through the implementation of EGSL's 2009 Test Year Formula Rate Plan and further finds that these costs are to be treated as"Extraordinary Costs" and recovered outside of the earnings sharing mechanism of the Formula Rate Plan. This calculation is a 5-year step funding plan recommended by Staff and reflects the beginning fund balances, the investment portfolio allocations, escalation and earnings rates, 5-year funding increments, and other assumptions set forth in the Attached Exhibit B.8. The NRC financial assurance analysis is not a ratemaking adequacy test but is instead a financial adequacy test devised specifically and solely for that purpose. Thus, the financial adequacy test and the resulting implications for ratemaking can differ. Recognizing this fact, the Commission hereby allows contributions to the decommissioning trust fund during the decommissioning period to be considered for purposes of determining whether NRC financial assurance'requirements are met For Waterford 3, funding is assumed to occur for the first seven years of the expected ten-year decommissioning period, consistent with the NRC's own calculation of the Waterford 3 minimum decommissioning amount. Staff also assumed funding of the trust through ratepayer contributions during the first six years of the decommissioning period for River Bend.9. The Staffs decommissioning revenue requirement developed for the River Bend nuclear facility, which is hereby adopted by the Commission, reflects the amount to fully fund the Louisiana retail jurisdictional share of the regulated 70% portion of the unit, including the portion that comprises what is known as the Deregulated Asset Plan ("DAP"). Under the provisions of LPSC Order Nos.7 For EGSL the $7.843 million amount is on a retail basis.Order No. U-31237 Page 5 U-17282 D (1/26/88) and U-17282 K (1/12/92) establishing and modifying the River Bend DAP, EGSL has the following options: (1) selling the DAP capacity to customers at a rate of 4.6 cents per kWh ($46 per MWh), recovered through the Company's Fuel Adjustment Clause, (2) in response to a bona fide offer approved by the LPSC, selling the capacity into the market and sharing proceeds with customers on a 50/50 basis for amounts in excess of 4.6 cents per kWh, or (3) if EGSL requests approval by the LPSC to sell the capacity into the market in response to a bona fide offer, and the LPSC disapproves such off system sale, the purchase price by which the DAP capacity will be sold to customers and recovered through the Company's Fuel Adjustment Clause will be adjusted to 4.6 cents per kWh plus 50 percent of the increment above 4.6 cents per kWh offered by a third party. Seven years after the DAP was approved, in. Order U-19904-C (12/29/94), the Commission determined that nuclear decommissioning costs associated with the DAP capacity should be considered to be part of the 4.6 cents per kWh rate established by the DAP instead of separately recovered from customers.

The nuclear decommissioning costs for the DAP portion of River Bend should be returned to EGSL's revenue requirement consistent with the original DAP order and collected separately, and in addition to, the 4.6 cents per kWh. EGSL agrees that as long as~the DAP portion of the decommissioning revenue requirement is collected separately, and in addition to, the 4.6 cents per kWh, the Company will not sell the DAP capacity into the market and/or realize any amount in excess of 4.6 cents per kWh in the event it receives a bona fide offer by a third party, for the earlier of 1) a period of 5 years or 2) until EGSL receives a final ruling on its application for River Bend's license extension.

The LPSC and its Staff will review and re-examine allocating the DAP into rates within 5 years this Order.10. The increase in the 2010 decommissioning funding contributions of $3.5518 million for ELL and $7.843 million for EGSL will be allocated to and recovered from each applicable rate schedule, as identified in Statement A of Rider FRP-5 for ELL and Rider FRP-I for EGSL, in proportion to base revenues before the application of the monthly fuel adjustment.

11. This Commission finds that the Companies have complied with, or are not in conflict with, the provisions of all applicable LPSC Orders governing the Companies Joint Application filed December 29, 2009 in this matter.12. The proposed funding amounts of this Order must be accepted by the NRC. If for any reason the NRC does not accept the proposed funding amounts set forth, the LPSC will promptly undertake to re-examine and review the funding amounts and the related issues which are the subject of a NRC refusal.13. This Commission affirms the language of its prior Orders, namely Item 8 of settlement term sheet for Consolidated Order Nos. U-22491, U-23358, U-24182, U-24993, U-25687 dated January, 8 2003 and Item 4 of the settlement term sheet for Order No. U-20925 RRF 2004 dated May 25, 2005 that in the event that the NRC formally notifies EGSL or ELL or the River Bend or Waterford 3 licensee that the decommissioning funding for either River Bend or Waterford 3, individually or collectively, is or would become inadequate, then ELL or EGSL or both would be permitted recognition in rates of decommissioning expense at a level sufficient to address reasonably the NRC's concern as expressed in the notification.

14. For ratemaking purposes the amount of the decommissioning accrual to be reflected in rates shall track, on a prospective basis, for the rate effective period, the specific annual amounts set out in the agreed upon decommissioning funding plan or any subsequent Commission-approved decommission funding plan. on a monthly pro rata basis. Such derived amounts shall form the basis for 8 The retail increase is S 3.482 million.Order No. U-31237 Page 6 subsequent rate changes. To the extent that the Companies remain subject to Formula Rate Plans with scheduled rate implementations where rate changes do not occur on January 1, the Companies shall make pro forma adjustments to their Formula Rate Plan Filings reflecting any prospective changes to decommissioning accruals that would occur in the rate effective period, on a monthly pro rata basis. These pro forma adjustments shall be treated as Extraordinary Costs outside of any bandwidth sharing. In the event the Companies are no longer under Formula Rate Plans, the rate treatment of decommissioning costs will be determined by subsequent Commission Order.The Companies and the Staff reserve the right to modify this procedure upon mutual agreement if circumstances warrant.15, Except as stated herein and as set forth in prior Commission Orders, this Order, including the calculation methodology reflected in the Exhibits to this Order, shall have no precedential effect in any other proceedings involving issues similar to those resolved herein and shall be without prejudice to the right of any party to take any position on any such similar issue in future base rate proceedings, including Formula Rate Plan proceedings, or in other related regulatory proceedings or appeals.16. This Order is effective immediately.

BY ORDER OF THE COMMISSION BATON ROUGE, LOUISIANA August 27, 2010 IS/ LAMBERT C. BOISSIERE, III DISTRICT III CHAIRMAN LAMBERT C. BOISSIERE, III ISI JAMES M. FIELD DISTRICT II VICE CHAIRMAN JAMES M. FIELD IS/FOSTER L. CAMPBELL DISTRICT V COMMISSIONER FOSTER L. CAMPBELL ISI ERIC F. SKRMETTA DISTRICT I COMMISSIONER ERIC F. SKRMETTA EVE KAHAO GONZALEZ /SI CLYDE C. HOLLOWAY SECRETARY DISTRICT IV COMMISSIONER CLYDE C. HOLLOWAY Order No. U-31237 Page 7 ORDER NO. U-31237 EXHIBIT A Exhibit A Page I of 5 Egiw0, tLm~a. U.C Whlwftrd-3 E04MMWaisSot MOMa NO Yewn C-onp" 1) kndk ( 2) JW~ (3 1 2 3 4 5 8'7 8 9 10 I1 12 13 14 1s 2010 2011 2012 2013 2014 2015 2010 2017 2018 2019 2m2 2021 2022 2023 2m~5.94?3.947 5,947 8,947 0.821 6.821 8.821 6.821 7,731 7,731 7.731 7,731 7.731 5.831 5.831 5,831 5,831 5,831 8.8B8 7.580 7.580 7.880 7.m0 7.5w0 116 118 118 lie 11l 133 133 133 133 133 151 133 151 151 0 N~.e (1) Sm 2x10 A Pap.2Z (2) TOW Comapwwy

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Exhibit A Page 5 ofrS Entegy Louisianl, LLC WaVft ed.l-3 Deonaessioing Modal Fees m1 Other Data (S m Thousarki)

Tax Qualified Trultl aid klvasiant Msaiean" F.e Sc"Idul TO Annual Fees 19 500 Adder(5000)

Srealoo" P&A, U l s .WO t TO Trustee Fens L 1.00 TO MariaW e P 0 2170 6.000 17.70 11.350 11.350 6.000 16.90 5.310 16,660 16.000 15.70 13.520 30t80 20,000 950 u.200 30.480 Mlscelanooue ata Rovieb Year [31 2010 JuftdvfiWAlWAuca Fam [81 O Cost Eitimate Year [4) 2008 TO Furi Federal Tax Rate( 15 20W;%j tComposfte Tax Rate (51 38.48% End al Fundilg Period 12ri0:LL Fun id ._ .1 ... ... .. 10000%....

... .........(1) Calculated ss in tforotewg aexaripla;

.280 -1r1TQ * (20,00*16.000) 1"000 For blance i S2SM: TQ Maimgmt Fee -41.210 -36.460 * (9.6"bp (26.000 -20.000)) 110.00.[21 Bad Debts am asraed to be zMo.[3[ First year aisrhrig kroiac of revised decwmtriw

• Von revefue "aqtwmftle (41 Year u0o wich the decortClsrlrig zost eatGile is based.(51 State Invcome ra Rats it 800%. etoeov rate IS .36%.181 Entergy Louisan. LLC. lundirg Inltesi in Waltrotnl-3 is 100%.171 Nudsea Cost Escator is 4 25%a[8 production oernarid alloator for LosLmae Retai.

ORDER NO. U-31237 EXHIBIT B Exhibit B 5-Year Step Page Ilof 5 0 Exhibit B Page 2 of 5 ei 2 2t10y .8M SS / OW 82s L& % U.C Rivr Send ODommutl*

Mdd Non-Tax Oualtod Tnsal DOWl N^Tm.Iausille5d Inat Lift. Revenus Earnng Tranlss MP*t Nat Doconmm. NTo i to No Yewo rh I RAW. 121 To Tn,3 M3 OmnWo 414 FAA 151 Adtbans [6) M We..las 381 caOflftv 2 2010 1.843 &5%41 0 a2n 17 805 0 15.09f 0.00%3 2011 7.813 55S4% 0 861 1s 884 0 16555 000%4 2012 7.043 5.80% 0 974 18 G56 0 17.511 0.00%5 2013 7.043 5.81m 0 1.043 10 1,024 0 18.54 0.00%6 2014 7.843 5.97% 0 1.123 20 1.103 0 198637 0.00%7 2015 8.516 5,&"% 0 1,194 21 1.173 0 20.8m 0.00%a 2018 8.888 &01% 0 1.289 22 1,247 8 22.087 0.00%, 9 2017 8.96 68.02% 0 1.340 23 1.324 0 23.381 0.00%10 2018 8&096 &04% 0 1,434 25 1.409 0 24,710 5.00%I1i 2018 0.998 &6% 0 15= 28 1,4lA 0 28,280 0.0%12 2020 10,195 8.08% 0 ,¶23 27 1.566 0 27084 0.01%13 2021 i5.18s 6.00% 0 1,724 28 1.688 0 28.575 080%14 2022 10.19 6a02% 0 1.80? 20 l.m 0 S1.3 0.00(o%15 2023 10.100 &97% 0 1.900 32 Im8 0 33.225 0.00%le 2024 10,195 5.25% 0 1,.77 33 1.734 0 34.9W OrO%17 2025 11.693 &.10% 0 1.806 35 1,771 12.400 24.321 MO%to 2028 11.83 4.80 0 1,204 25 1.178 25,450 0 0.00%* 19 2027 11.5M3 4.8M% 0 a 0 8 0 0 0,00%2029 11. "3 4.M5% 0 0 0 0 0 0 0%2029 1 t"3 4.81% 0 0 0 0 0 0 0.00%22 2030 13.513 4.80% 0 0 0 0 0 0 0.00%23 2031 0 431% 0 0 0 0 0 0 0.00%24 203W 0 4.51% 0 0 0 0 0 0 0.00%25 2033 0 4.SI. 0 0 0 0 0 0 0.00%28 2034 0 4.51% 0 0 0 0 0 0 0.00%Notes: (It Sea ExhfA a Page I.(21 Projedod aft-"An o0"eals (31 Revenue Rooqko....

I (I. Ov30WN. pwaantegul 141 P Yo8r Saitnc CllMpoonder SiftflImfly at CQlint Yoe fte * -A CSO(M YeN Trwlw 'C~mm, You Ehun*i0 RawA IS) Cutol.,Wd

-. ---no b88mce (MV. 531 -P~o Yr. Bal.. -(riansule.o Emiikip) in wmoe~also

.10

• fog O00odM Wo Uu.li AMd m ..n.8rl IW aosIk leah tax Aah. SeIe 84*t 8 Page 5 181 T-aele -Eamigs- angea m~mon Fro.*M Assumens hat "~e Non-Tex Quol"d Oa& " Is .Utibnd to pay e dweemMiuonknV costs b,. "" gan Sao ESAU 6 Pao*4 for Me 102L.LII PO1W Yew Bilance

• Not Aidlftns.

Oocoenmfs-Joný ExpendiWrm Exhibit B Page 3 of 5 94ow~ Go 5Wu LGnl*IS LLC Mw6 6998 Dwm9891onli Ma"4 LoCUba eRaU Tax QuA*V4eA TrIUStA Tax Ouamed TrMA Ur. Remo Ewrng Trmw-w Up Net DOeeun QUO" I o *Balang c aJ t 3c1a 3ln* 32.940 2 2A00 7.A41 S.-0% W.84 1.431 31 4.014 0 39.984 100.00%3 2011 7.843 5,83% 7.643 2414 30 10.221 0 47.176 100.00%.4 2012 7.843 6.20% 7.943 3.213 42 11.014 0 58.18, 100,00%3 2013 7.843 6.29% 7,843 3.964 49 11,788 0 60.647 10.0o %a 2014 ?7.43 6.47% 7,643 4.8U3 7 1283$ a .82,886 100.0" 7 2015 9,95 6.50% &.996 1.748 68 ,4.675 0 97293 00.00%.8 2016 SA.W0 &.52% a8068 6.738 7s 15.065 0 112.922 10om0 2 2017 5.66 6..4% 8,99 7.803 88 1t, 11 0 128,833 1000%to 2018 8.996 8.57% 8.998 8.952 g6 17.852 0 147.486 100.00%I1 2018 0.58 , &898 10.176 107 19,064 0 16.549 1010.00%12 2020 10.85 6.619. 10.195 11.528 120 21,604 0 111.153 100.00%13 2021 10.195 6.639A 10,196 13.019 133 23.081 0 211.234 100.00%14 2022 0.18 8.65% 10.196 14.620 14$ 24.867 0 2 ,5m0 i.00%11" 2023 10198 8.39%A 10.195 15.641 194 25.672 0 201.513 100.00%18 2024 10.195 8.12% 1o0.s a1".58 180 26.581 0 208.154 00.00%" 17 2025 11&693 5.75% 11.093 17.143 197 28,839 0 316.793 100,00%18 2026 11U603 576% 11.693 19,847 218 30235 23.843. 3Z.575 100.00%10 2027 11.003 &76% 1l.603 10.243 230 30.717 t03.721 280.570 100.00%20 2028 19.693 5.78%, 11,891 14.977 173 26.48 7,774 17,294 100.00%21 2029 11.80 5&76% Ke,6w 10,813 12* 22,37X 67T07 134,169 100.00%22 200 13.513 5.76% 13513 8.229 100 21.82 70.378 ISA30 100.00%23 2031 0 4.88% 0 4.220 64 4.188 W0.108 8 .478 1 00,00%24 2032 0 4.8%16 0 1.960 35 1.915 24,701 184132 100.00%25 2033 0 4.88% 0 922 20 801 18,917 I$1.M 100.00%28 2034 0 4.88% 0 7s 7 67 1,544 0 t00.00%[I] See ExNVAO 6 Page I.121 Projecte aW-tdtax , nd t-,d9 .(13 Re"venue xeeffu, Oadgpim Pevoelt"&141 Pdio Yew BsIm ColomI*149d SewmwiV4u at Csang Year E59rn4519 R 8 1.* 14 %Cw' YeN T*fans9w

• Cwtd YeN ewl9 Rag.151 Clkete an evesuge .1951u.e (AS BaD v Pr4, Yr. Bal.

• K (lT79m48 easn* in ascwdap with " fee ,cI kv truslee U4. manage 9 4l.c W28 WL. See 6 8 POP 5.(8) ?,anmfe -Eav98ge- Managemeet Fee.(7) mm M e ma. t"8 NO,,Tax Ouaj~od ealane Is wlloed to pay ft, fesamn4ukiqalot sa before L~sa TO Salence See ExlIbl 9 Parge 4.183 PrW, Yew 0S* 98.- Not -Egped95e.

Exhibit B Page 4 of S Enr rtStm LOjlStAos.C Few a"~ Do58158b0.M mom (S006)LbIe CUnL Cum. m4,,8e8 R .E"GL Pa5imn of LA R*W -NO yew CPtU ll CPIU cod Om (21 70% 31 Ilomisla 70% 141 LA P.448(5 EwCattftd

[81 1 2008 IA WA I.0C0 0 0 0 0 2 A 1.000 1.0425 0 0 0 0 3 2010 1.0217 1.022 1.0m8 0 0 0 0.4 2011 10222 1.046 .1330 0 0 0 a 5 2012 1.022 1.068 1.1812 0 0 0 0 6 2013 1.0231 1.094 1.2314 0 0 0 0 7 2014 1.0m8 1.120 1.2837 0 a 0 0 a 2015 1.0240 1.147 1.3383 0 0 0 0 9 2018 1.0244 1.175 1.3252 0 0 0 0 10 2017 1.0240 1.2U4 IAS4, 0 0 0 0 ti 2018 1.0254 1.235 1.t163 0 0 0 0 12 2019 1.020 1.20? 1 .580 0 0 0 0 ts 2020 1.0283 1.300 1.6419 0 0 0 0 14 2021 1.428 1.336 1.7119 0 0 0 Is 2022 1.0272 1.371 1.7501 0 0 0 a 1e 2023 1.0277 1.400 1.8670 0 0 0 0 17 2024 1.0208 1.449 1,943 0 0 0 0 18 2025 1o0w8 1.491 2.0290 11.043 .6.350 6,116 12,408 S1 202m 1.0293 1.528 2.1152 41.M6 24.074 23.186 49,042 2 2027 1.020a 1.861 2.2051 64M938 4X.825 47,037 103,721 21 2028 i.0204 I.W 2.2388 M0804 44.162 42.022 P.M7 22 2029 1.0210 1.87n VM250S 50.o7 299 .28.189 87307 23 2030 1.0261 1.723 2.4914 50.66r 29,249 201.19 ?w.371 24 2021 1.0261 1.70m 2.048 34,740 1%976 19.228 50.108 25 2022 1.0281 1.814 .7163 10.467 D.4A8 %.112 24.701 26 20 .0281 1.881 2-807? 10.154 ka82 8.6 19.917 27 2034 1.0201 1.910 2,510 989 07 537 1.584 28 TOW5 Etp9 daw0e. 378.717 217,702 209.726 453,290 III CPIU pat UlcWa 155184. Forecas fom 2010- 20&tO. 2. 61% for2020234 is owl aroma, ftw 2010 la2M2.[21 Cwmr,wafa Nu7lclei 40, EW0 a 4.25% per yea.[3) Oecw~wnss5rrogf Coo 885,1189 pa 2008 MWC MIktmvm (2005 488.oý(41 0403.r.n-ong Cool 648rns4. ' ,nwgy OW Fwndk79 b t (t100%) f-TX PoW A~ocdwr pat PPA vwh 671T42.5%t

[51 -GSL FWXP69o S5., of Cost ES4, * (Lorfisa RMW8/ Pto 048. ronvind Agocal. (98.30941A) f8) Lorj0.n Rama -Caroriaho Ntrclta Ccn 05031*..

Exhibit B Pape 5 *F S B ntergy "ul States Louisiarm

.LC River ed0. m1oi Modal -Louisiana PC"e and COthe Data (Sin Thousands)

TAX 20.1(fled Trustee and low..lmeort Uammm~ Fe. SdieduWe, 111 TO Annual fees 6.320 Adder (S 000)Ile~piklnts t1000 Be.., Poirb Filied(I13 Cwnvwlei" TO Manager & ASSN Based Tnoda. Fe.NonTa 0 18350 1.333 170 .2.467 2.461 2.083 15.00 1313 2.867 ,3.0 08.75 46ON 3.333 12M f 0.900 5.514 4.167 9.50 1.000 .S54 1".333 .,00 ... I 7.750 t 4.312 d flVmey"nfnt Matlufer Fee 8W.aiduitm 0 NYC Annual Fe"e 5.000 Adder: (S WMo ore*kointe (SO000) sags Points Fixed (11 Cumultve N. Manager A. A. 0 18.50 Based Truste" Fee 1.000 17.30 1.960 1"85 1,560 1 600 0.1110 2.830 2.00. 132.30 060 ,.490 2.=0 12.00 0.615 4.165 3.130 9.50 0.756 4.ý921 9.250 7.00 &814 10.735 elaltrOul nMold O~af Bad 001:1 Rale 121 50.0% NuclearColt Escalator 37 4.23%~R~eviosaYearl3l 2010 18I 96.3094%i Cost Estkima* Year (43 2006 TO Fund Federal Tax Rate4 At6 & 1 20.00%s CoMroalte Effectie Tax Rate (51 38.48% End of Funding Period 124 t/2030f Entergy GClf States Ownersh Share 10000%Notes:[I) Calculated as In the folowing exanple: For tulanc8 ort 310h TO Management Fee -9.837 0.&54 -(7.Obp "( 10.OW- 4.167))/ 10.01M (213gBed Debts handled, in Cast of Servcte Study.(P3 First year saowantl kriapt of revised decornmssionlng revenue requitremen 141 Year upon whdch the coil alioiate i a baud.(53 Louisana income Tax Rite is 8.0%, however. in Louisiana Federal Inc0.l6 taxes are dductbile.

therefore If* affective Louisiana rate is 5.35%,. The eflect$ Fpeadea Rate is 33.13% resutling in a Comoposite Rate of 3848%.(53 Coal Extanate provided oir Regulated Portion (70%) W EW3L fu ding inerest is 100%.171 Nuclear Cost Esclela it A.25%181 Per t.me 2009 FRP based on 12/31108 Test Year. This LA Ralijl of 0GSL..191 Federal Tas Ram for Oviafifted Trustls. These trusts do not pay Istme taxes.

Attachment 3-E (16 pages)PUCT Order in Docket No. 37744 PUC DOCKET NO. 37744 SOAH DOCKET NO. 473-10-1962-APPLICATION OF ENTERGY TEXAS, §INC. FOR AUTHORITY TO CHANGE §RATES AND RECONCILE FUEL §COSTS §PUBLIC UTILITY COMMISSION OF TEXAS ORDER This Order addresses the application of Entergy Texas, Inc. (ETI) for authority to change rates and reconcile fuel costs. ETI, Commission Staff, the Office of Public Utility Counsel (OPUC), the Steering Committee of Cities Served by ETI (Cities),'

Texas Industrial Energy Consumers (TIEC), The Kroger Company (Kroger), and Wal-Mart Stores Texas, LLC and Sam's East, Inc. (collectively Wal-Mart), through their duly authorized representatives entered into and filed a stipulation and settlement agreement that resolves all of the issues in this proceeding except the issues related to ETI's proposal for competitive generation service.Cottonwood Energy, L.P. and the State of Texas agencies and institutions of higher education (State Agencies) did not join but do not oppose the stipulation.

The Commission severed the competitive generation service issues into Docket No. 389512 in Order No. 14.The Commission adopts the following findings of fact and conclusions of law: Steering Committee of Cities is comprised of the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange.2 Application ofEntergy Texas, Inc. for Approval of Competitive Generation Service Tariff(Issues Severed From Docket No. 37744), Docket No. 38951.

PUC Docket No. 37744 Order Page 2 of 15 SOAH Docket No. 473-10-1962 I. Findings of Fact Procedural History I. On December 30, 2009, ETI filed an application requesting approval of (1) base rate tariffs and riders designed to collect an overall revenue requirement of $1,758.4 million, which includes a total non-fuel retail revenue requirement of $838.3 million (base rate revenues of $486 million plus revenue from riders of $352.3 million);

(2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP) accompanying ETI's application; (3) a request for final reconciliation of ETI's fuel and purchased power costs for the reconciliation period from April i, 2007 to June 30, 2009; and (4) certain waivers to the instructions in RFP Schedule V accompanying ETI's application.

2. The 12-month test year employed in ETI's filing ended on June 30, 2009.3. ETI provided notice by publication for four consecutive weeks before the effective date of the proposed rate change in newspapers having general circulation in each county of ETI's Texas service territory.

ETI also mailed notice of its proposed rate change to all of its customers.

Additionally, ETI timely served notice of its statement of intent to change rates on all municipalities retaining original jurisdiction over its rates and services.

ETI also published one-time supplemental notice by publication in newspapers and by bill insert.4. The following parties were granted intervenor status in this docket: OPUC, Cities, Cottonwood, Kroger, State Agencies, TIEC, and Wal-Mart.

Commission Staff was also a participant in this docket.5. On January 4, 2010, the Commission referred this case to the State Office of Administrative Hearings (SOAH) for processing.

6. On February 19, 2010, the AUs issued Order No. 3, which approved an agreement between ETI, Staff, Cities, State Agencies, OPUC, TIEC, Kroger, and Wal-Mart, to (1) establish an interim rate increase of $17.5 million annually above ETI's then-existing base rates commencing with service rendered on and after May 1, 2010 subject to true-up and refund for service rendered prior to September 13, 2010 to the extent final PUC Docket No. 37744 Order Page 3 of 15 SOAHI Docket No. 473-10-1962 overall rates established by the Commission amounted to less than a $17.5 million rate increase; (2) extend the jurisdictional deadline by which the Commission must issue a final order on the Company's rate request from July 5, 2010 to November 1, 2010;(3) establish a September 13, 2010 effective date for rates such that, notwithstanding the extension of the jurisdictional deadline, the final overall rates established by the Commission would relate back to service rendered on and after September 13, 2010;(4) require ETI to publish supplemental notice, once in newspapers and by a bill insert, setting forth the effect of its proposed rate change in terms of the percentage increase in non-fuel revenues; and (5) establish a procedural schedule and discovery deadlines for this proceeding.

Order No. 3 also granted Mr. Kurt Boehmr's motion for admission pro hac vice as counsel for Kroger and ETI's February 3 and February 11, 2010 petitions for review of cities' ordinances and motions to consolidate with respect to the rate decisions adopted by the Cities of Ames, Anderson, Bedias, Bevil Oaks, Bremond, Caldwell, Calvert, Chester, China, Colmesneil, Corrigan, Cut and Shoot, Daisetta, Dayton, Devers, Franklin, Groveton, Hardin, Hearne, Iola, Kosse, Kountze, Liberty, Lumberton, Madisonville, Midway, New Waverly, Normangee, Nome, Patton Village, Plum Grove, Riverside, Rose Hill Acres, Somerville, Taylor Landing, Todd Mission, Trinity, and Woodville.

7. On June 14, 2010, the AL~s issued Order No. 6 granting Staff's June 1, 2010 motion and severing rate case expense issues to Docket No. 38346.3 Through Order No. 6, the AUs also granted ETI's March 12, April 29, and May 17 petitions for review and motions to consolidate with respect to the rate decisions adopted by the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Panorama Village, Pine Forest, Pinehurst, Port Arthur, Port Neches, Roman Forest, Rose City, Shenandoah, Shepard, Silsbee, Sour Lake, Splendora, Vidor, West Orange, Willis, Woodbranch Village, and Woodloch.3Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket No. 37744, Docket No. 38346.

PUC Docket No. 37744 Order Page 4 of 15 SOAH Docket No. 473-10-1962

8. The hearing on the merits commenced on July 13, 2010 and was immediately recessed in order to facilitate settlement negotiations.

The hearing was again convened on July 15, 2010, at which time the signatories announced their intent to continue settlement discussions to resolve all issues related to the Company's application with the exception of those related to ETI's proposal for competitive generation service (CGS) and associated riders.9. On August 6, 2010, the signatories submitted the stipulation resolving all outstanding issues regarding the Company's application with the exception of those related to ETI's CGS proposal.

Under the stipulation, ETI will be allowed to implement base rate tariffs and riders designed to collect an overall revenue requirement of $1,614.9 million, 4 which includes a total non-fuel retail revenue requirement of $694.9 million (base rate revenues of $599 million plus revenue from riders of $95.9 million).

The signatories also submitted, on August 6, 2010, an agreed motion to revise interim rates and to consolidate the severed rate-case expense docket. The interim rates requested in the agreed motion mirrored the final rates proposed for Commission approval in the stipulation.

The agreed motion further requested that the ALJs consolidate with the instant proceeding Docket No. 38346, related to severed Docket No. 37744 rate case expense issues, and admit the parties' pre-filed exhibits into evidence.10. On July 16 and July 20, 2010, the ALJs held the hearing on the merits with respect to ETI's CGS proposal.It. On August 9, 2010, the ALJs issued Order No. 12, granting approval of revised interim rates for usage on and after August 15, 2010.12. On October 5, 2010, the ALJs issued a proposal for decision regarding issues related to ETI's CGS proposal.13. On October 5, 2010, the Aids issued Order No. 13, ordering the consolidation of Docket No. 38346, related to severed rate-case expense issues, into the instant proceeding, 4 This figure includes fuel at test year prices. If current fuel prices are substituted for test year fuel prices, the overall revenue requirement figure would be $1,504.0 million.

PUC Docket No. 37744 Order Page 5 of 15 SOAH Docket No. 473-10-196%

admitting evidence, and returning this docket to the Commission consistent with the agreed motion filed on August 6, 2010.14. The Commission considered this Docket at the November 10, 2010 and December 1, 2010 open meetings.15. On November 30, 2010 ETI filed an unopposed motion to sever the competitive CGS issues from the settled issues in this docket. The Commission granted the motion at the December 1, 2010 open meeting and the Commission's decision was memorialized in Order No. 14 issued on December 3, 2010. The CGS issues were severed into Docket No. 38951 in Order No. 14.Descr'tion of the stipulation and Settlement Agreement 16. The signatories to the settlement stipulated that ETI should be allowed to implement an initial overall increase in base-rate revenues of $59 million for usage on and after August 15, 2010. The signatories further stipulated that they would request approval of interim rates by the ALJs presiding or by the Commission, as necessary, to ensure timely implementation of this initial rate increase.

The signatories further stipulated that ETI should be allowed to implement an additional overall increase in base-rate revenues of$9 million on an annualized basis effective for bills rendered on and after May 2, 2011, the first billing cycle for the revenue month of May.17. The signatories agreed that ETI's authorized return on equity shall be 10.125% and its weighted average cost of capital shall be 8.5209%.18. The signatories stipulated that the amount of rate increase authorized under finding of fact 16 includes rate-case expenses and contemplates their full amortization in 2010, and that this amount constitutes the full and final recovery of all rate-case expenses relating to Docket No. 37744.19. The signatories stipulated to the amount of transmission and distribution invested capital by function as of June 30, 2009 as set out in attachment I to the stipulation.

PUC Docket No. 37744 Order Page 6 of 15 SOAiI Docket No. 473-10-1962

20. The signatories stipulated that the Company's proposed purchased-power recovery rider will not be approved in this docket, and purchased capacity costs will be included in base rates.21. The signatories stipulated that the Company's proposed transmission cost recovery factor (TCRF) will not be approved in this docket. The signatories stipulated to the baseline values as shown in attachment 2 to the stipulation to be used in the Company's request, if any, for a TCRF in a separate proceeding.

22. The signatories agreed that ETI's proposed cost-of-service adjustment rider and formula rate plan will not be approved in this docket.23. The signatories stipulated that the Company's proposed renewable-energy-credit rider will not be approved in this docket, and the Company's renewable-energy-credit costs shall be recovered in base rates. The signatories further stipulated that a transmission customer that opts out pursuant to P.U.C. SuBsT. R. 25.173(0) shall receive a credit that offsets the amount of renewable-energy-credit costs that are recovered in base rates from the transmission customer.24. The signatories agreed that ETI's proposed remote-communications-link rider should be approved as filed by the Company.25. The signatories agreed that ETI's proposed market-valued-energy-reduction service rider will not be approved in this docket.26. The signatories reached the following specific agreements regarding rate design as a part of the overall resolution of this docket: a. Rate Schedule IS, Rate Schedule IS will be opened to new business.

In the Company's next base-rate case, the amount of interruptible credits recoverable from Texas retail customers shall be limited to an increase of $1 million more than the amount requested in this docket (or a total of $6.8 million);

provided, however, that in the next rate case, the Company may request an exception to this limitation upon a showing that the test-year credit amount in excess of the$6.8 million cap is both cost effective and necessary to meet the Company's generation reserve margin requirement.

The signatories further agreed that the PUC Docket No. 37744 Order Page 7 of 15 SOAH Docket No. 473-10-1962 Company will not offer additional interruptible service if the availability of total interruptible service supplied by the Company under all interruptible service riders exceeds 5% of the projected aggregate Company peak demand unless the additional level of interruptible service offered in excess of the 5% cap is both cost effective and necessary to meet the Company's generation reserve margin requirement.

To the extent that the credit amount or participation level exceeds the limitations described in this paragraph and the Company includes test-year credits over the $6.8 million credit-amount cap or additional participation in excess of the 5% participation-level cap in its next rate case, the Company shall have the burden to prove whether those test-year credits or participation levels meet the standards established in this paragraph for inclusion in the test year. The standards in this paragraph are in addition to any requirements in PURA for inclusion of costs in rates. The signatories further agreed to the Schedule IS revisions shown on attachment 3 to the stipulation.

b. Rate Schedule IHE. The signatories agreed that no change shall be made to rate schedule IHE in this docket.c. Lighting Class Rates. The signatories stipulated that the language under the paragraph relating to rate group C in rate schedule SHL will be revised to reflect that, where the Company agrees to install facilities other than its standard street light fixture and lamp as provided under Rate Group A, a lump sum payment will be required, based upon the installed cost of all facilities excluding the cost of the standard street light fixture and lamp, and the customer will be billed under rate group A.e. Electric Extension Policy. The signatories agreed to the line-extension terms and conditions as reflected in attachment 4 to the stipulation.

Life-of-Contract Demand Ratchet. The signatories agreed that the life-of-contract demand ratchet provision in rate schedules Large Industrial Power Service, Large Industrial Power Service-Time of Day, General Service, General Service-Time of Day, Large General Service, and Large General Service-Time of PUC Docket No. 37744 Order Page 8 of 15 SOAH Docket No. 473-10-1962 Day shall be excluded from rate schedules in ETI's next rate case. The signatories further stipulated that the foregoing rate schedules will be revised so that the life-of-contract demand ratchet provision shall not be applicable to new customers and shall not exceed the level in effect on August 15, 2010 for existing customers.

g. Residential Customer Charge. The signatories agreed that the residential customer charge shall be increased to $5.00.h. Non-Sufficient Funds Charge. The signatories agreed that the non-sufficient funds charge shall be increased to $15.00.27. The signatories agreed to the class cost allocation set forth in attachment 5 to the stipulation.

28. The signatories stipulated that the appropriate allocation between ETI's wholesale and retail jurisdictions of baseline values and costs to be included in a TCRF is to be addressed in the proceeding, if any, in which ETI seeks approval of a TCRF.29. The signatories stipulated that no party waives its right to address in any subsequent proceeding the appropriate treatment for Texas retail. ratemaking purposes of power sales between ETI and Entergy Gulf States Louisiana, L.L.C.30. The signatories reached the following specific agreements regarding fuel-related issues as part of the overall resolution of this docket: a. Agreed Fuel Disallowance.

The Company stipulated to a fuel disallowance of$3.25 million not associated with any particular issue raised by the signatories.

The disallowance will be allocated pro rata with interest over each month of the reconciliation period and reflected in the refund in Docket No. 38403.' The signatories stipulated that the Company's fuel costs shall be finally reconciled for the reconciliation period of April 1, 2007 through June 30, 2009.b. Rider IPCR. The signatories agreed that ETI's eligible Rider IPCR costs for the Application of Entergy Texas, Inc. to Implement an Interim Fuel Refund, Docket No. 38403, Order (Sept. 16,2010).

PUC Docket No. 37744 Order Page 9 of 15 SOAH Docket No. 473-10-1962 period April 1, 2007 through the date the rider terminated shall be finally reconciled with a disallowance of $300,000.

The signatories further agreed that the under-recovered balance of Rider IPCR costs shall be booked as fuel expense in the month in which the Commission issues an order adopting the stipulation; provided, however, that the under-recovered balance shall be allocated to customer classes using A&E4CP.c. Roubh Production Cost Equalization (RPCE) Payments.

The signatories agreed that ETI will credit an additional

$18.6 million to Texas fuel-factor customers, which the signatories stipulated represents the remaining portion of RPCE payments ETI received in 2007 that were at issue in Docket No. 35269.6 The R-PCE credit shall be allocated to rate classes based on loss-adjusted kilowatt hours at plant for calendar year 2006. For customers in the Large Industrial Power Service rate class, the credit will be refunded based on the customer's actual kWh usage during the billing months of January 2006 through December 2006. Upon issuance of a final order approving the stipulation, the RPCEs shall be credited to customers as a separate one-month bill credit in the same form as the RPCEA Rider last approved in Docket No. 38098." ETI agreed that it will terminate all appeals related to Docket No. 35269.31. The signatories agreed that ETI will continue its accrual of storm-cost reserves at the level of $3.65 million annually and that this amount shall be subsumed in the base-rate revenue increase described in finding of fact 16 above.32. The signatories agreed that ETI shall maintain River Bend depreciation rates at current levels, i.e., based on a 60-year life. River Bend decommissioning costs will be set at$2,019,000 annually, which is based upon a labor-factor escalation rate of 1.67%, an energy-factor escalation rate of 0.25%, and a waste-burial-factor-escalation rate of Compliance Filing of Entergy Texas, Inc. Regarding Jurisdictional Allocation of 2007 Svstem Agreement Payments, Docket No. 35269, Order (Jan. 7. 2009).Application of Entergy Texas, Inc. for Authority to Implement Mew RPCEA Rate, Docket No. 38098, Order (July 1, 2010).

PUC Docket No. 37744 SOAH Docket No. 473-10-1962 Order Page 10 of 15 1.71%, resulting in an overall escalation rate of 3.62%, and net investment yields as follows: Nuclear-Decommissioning-Trust Proiected Returns Tax-Oualified Investments 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026-2034 5.475%5.837%6.306%6.304%6.481%6.493%6.412%6.412%6.364%6.316%6.268%6.220%2.503%5.817%5.382%5.036%4.920%Non-Tax-Qualified Investment 5.057%5.236%5.567%5.607%5.896%5.909%5.826%5.830%5.790%5.748%5.712%5.670%5.458%5.055%4.628%4.516%4.409%33. The signatories stipulated that the Company's depreciation rates for non-River Bend production plant, transmission, distribution, and general plant will remain at current levels and the Company will maintain its accounting records on a prospective basis for purposes of depreciation accrual, depreciation reserve, retirements, additions, salvage, and cost of removal by FERC account.Consistency of the Agreement with PURA and the Commission Requirements

34. Considered in light of (1) the pre-filed testimony by the parties entered into evidence and (2) the additional evidence and testimony admitted during the course of the hearing on the merits on the Company's application, the stipulation is the result of compromise from each signatory, and these efforts, as well as the overall result of the stipulation viewed in light of the record evidence as a whole, support the reasonableness and benefits of the terms of the stipulation.

PUC Docket No. 37744 Order Page It of 15 SOAH Docket No. 473-10-t962

35. The evidence addressed in finding of fact 34 demonstrates that the rates, terms, and conditions resulting from the stipulation are just and reasonable and consistent with the public interest.36. The total level of the Texas retail revenue requirement contemplated by the stipulation will allow ETI the opportunity to earn a reasonable return over and above its reasonable and necessary operating expense.37. The stipulated revenue requirement is consistent with applicable provisions of PURA chapter 36 and the Commission's rules.38. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, they are reasonable and necessary for each class of affiliate costs presented in ETI's application.

39. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, the price charged to ETI is not higher than the prices charged by the supplying affiliate for the same item or class of items to its other affiliates or divisions, or a non-affiliated person within the same market area or having the same market conditions.

40. The retail revenue requirement in the stipulation does not, include any expenses prohibited from recovery under PURA.41. A return on equity of 10. 125% and a weighted average cost of capital of 8.5209% for ETI should be adopted consistent with the stipulation.

42. The agreed rate-design provisions and terms and conditions of service included in the stipulation are just and reasonable.

43. The treatment of rate-case expenses described in the stipulation is reasonable.

44. The Company's proposed remote-communications-link rider as filed by the Company is reasonable.

45. The depreciation rates agreed to in the stipulation are just and reasonable.

PUC Docket No. 37744 Order Page 12 of 15 SOAH Docket No. 473-10-1962

46. The recovery of $2,019,000 annually for decommissioning costs of nuclear production assets based on the factors agreed to in the stipulation is reasonable.

47. A $3.65 million annual storm cost accrual is reasonable.

48. The class allocation methodologies described in the stipulation are just and reasonable.

49. The fuel and IPCR-related provisions of the stipulation are reasonable.

[I. Conclusions of Law 1. ETI is a public utility as that term is defined in PURA § 11.004(1) and an electric utility as that term is defined in PURA § 31.002(6).

2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051, 36.001-.l 11, 36.203, 39.452, and 39.455.3. SOAH has jurisdiction over matters related to the conduct of the hearing and the preparation of a proposal for decision in this docket, pursuant to PURA § 14.053 and TEX. Gov'T CODE ANN. § 2003.049, 4. This docket was processed in accordance with the requirements of PURA, the Texas Administrative Procedure Act, 8 and Commission rules.5. ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PRoC.R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(l)-(3).

6. This docket contains no remaining contested issues of fact or law.7. The stipulation, taken as a whole, is a just and reasonable resolution of all issues it addresses; results in just and reasonable rates, terms, and conditions; is supported by a preponderance of the credible evidence in the record; is consistent with the relevant provisions of PURA; and is consistent with the public interest.8. ETI has properly accounted for the amount of fuel and IPCR-related revenues collected pursuant to the fuel factor and Rider IPCR.8 TEX. GoV'T CODE AN N. Chapter 2001 (Vernon 2007 and Supp. 2009).

PUC Docket No. 37744 Order Page 13 of 15 SOAH Docket No. 473-10-1962

9. The revenue requirement, cost allocation, revenue distribution, and rate design implementing the stipulation result in rates that are just and reasonable, comply with the ratemaking provisions in PURA, and are not unreasonably discriminatory, preferential, or prejudicial.

10. Based on the evidence in this docket, the overall total invested capital through the end of the test year meets the requirement in PURA § 36.053(a) that electric utility rates be based on the original cost, less depreciation, of property used by and useful to the utility in providing service.11. ETI has met its burden of proof in demonstrating that it is entitled to the level of retail base rate and rider revenue set out in the stipulation.

12. ETI has met its burden of proof in demonstrating that the rates resulting from the stipulation are just and reasonable, and consistent with PURA.III. Ordering Paragraphs

1. ETI's application seeking authority to change its rates; reconcile its fuel and purchased power costs for the Reconciliation Period from April 1, 2007 to June 30, 2009; and for other related relief is approved consistent with the above findings of fact and conclusions of law.2. Rates, terms, and conditions consistent with the stipulation are approved.3. The tariffs and riders consistent with the stipulation are approved for the initial and second step rate increases.

4. ETI's request for waivers of RFP instructions (RFP Schedule V) is granted.5. ETI shall adjust decommissioning expense related to the River Bend Nuclear Generating Station consistent with the terms of this Order.6. Neither the stipulation and settlement agreement nor this Order constitutes the Commission's agreement with, or consent to, the manner in which ETI, or any entity affiliated with ETI, has interacted with any decommissioning trust to which ETI or its ratepayers have made contributions or provided funds. Furthermore, this Order in no PUC Docket No. 37744 Order Page 14 of 15 SOAH Docket No. 473-10-1962 way constitutes a waiver or release of any conduct, whether or not such conduct occurred before the date of this Order, that may constitute a violation of any provision of state law, including, without limitation, the rules and regulations of this Commission relating to nuclear decommissioning trust funds; or prevents the Staff of the Commission from opening an investigation and taking enforcement action relating to violations of such rules and regulations.

7. Nothing contained in this Order constitutes the consent or approval, explicit or implied, of any modification, amendment or clarification of any power purchase agreement between ETI and any other Entergy entity relating to the River Bend Station. Without limiting the foregoing, nothing contained in this Order shall constitute the consent or approval of any modification, amendment, or clarification of any power purchase agreement between ETI and any other Entergy entity relating to the River Bend Station, which is made to address any concerns raised by the NRC in its Request for Additional Information regarding the River Bend Station dated March 11, 2010.8. The Rider IPCR costs and eligible fuel costs requested by ETI are, consistent with this Order, reconciled through June 30, 2009, and are approved consistent with the stipulation.

9. ETI shall adjust its fuel over/under recovery balance consistent with the findings in this Order.10. ETI shall file an RPCEA Rider consistent with the above findings of fact and conclusions of law to be effective with the first billing cycle of the billing month immediately following the effective date of this Order..If. Because the final approved rates are equal to or higher than the interim rates adopted in Order No. 3, no refund of the interim rates authorized by Order No. 3 is necessary.

12. The interim rates approved in Order No. 12 are herby approved for the initial step rate increase contemplated by the stipulation, and ETI shall implement the second step rates for bills rendered on and after May 2, 2011, the first billing cycle for the revenue month of May.

PUC Docket No. 37744 Order Page 15 of 15 SOAH Docket No. 473-10-1962

13. Within 30 days of the date of this Order, ETI shall file a clean copy of all of the tariffs and schedules approved in this docket and a clean copy of the attachments to the stipulation.

14. The entry of this Order consistent with the stipulation does not indicate the Commission's endorsement of any principle or method that may underlie the stipulation.

Neither should entry of this Order be regarded as a precedent as to the appropriateness of any principle or methodology underlying the stipulation.

15. All other motions, requests for entry of specific findings of fact, conclusions of law, and ordering paragraphs, and any other requests for general or specific relief, if not expressly granted in this order, are hereby denied.SIGNED AT AUSTIN, TEXAS the _____ day of December 2010 PUBLIC UTILITY COMMISSION OF TEXAS BAR .SMITHERMAN, CHAIRMAN DONNA L. NELSON, COMMISSIONER KEN TH W. ANDE ., COMMISSIONER q: \cadmkordqi na 1\3 7000137744 r.doc x Attachment 3-F (9 pages)FERC Order in Docket Nos. ER86-558-002 A UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION Before Commissioners:

Martha 0. Hess, Chairmani Anthony G. Sousa, Charles G. Stalon and Charles A. Trabandt.Gulf States Utilities company ) Docket Noas. ER86-558-002, ER86-558-01 and ER86-558-013 ORDER CLARIFYING PRVIOUS ORDERS (15suod May 18, 1988)On Fobruary 16,. 1988, Gulf States Utilities Company (Gulf States) filed a petition for clarification of certain letter orders approving settlements in this proceeding.

J/ The letter orders approved settlement rates reflecting decommissioning expenses funded through an external fund (River Bend Nuclear Decommissioning Fund) adjusted for a forty-year funding period.On March 2, 1988, Cajun Electric Power Cooperative, Inc.(Cajun) requested that the Cqmmission explicitly recognize.

that its contributions to Gulf Statas' docommissioning fund are, and have been, on the basis of unadjusted decommissioning expenses, and that the instant order will have no application to the rates being charged to Cajun.dulf States requests that the Comission expressly recognize the amount of yearly decommissioning costs which it is entitled to collect. Gulf States asserts that absent such express recognition, the Internal Revenue Service. (IRS) will not permit.its deduction of yearly cash contributions to the River Bend Nuclear Decommissioning Fund.Gulf'States contends that it must first receive a "schedule of ruling amounts", from the IRS in order to take this deduction.

Gulf States further maintains that the IRS will not provide a taxpayer with a schadule of rulihq atouns "UMIleds a pUblif utility conmission that Gstablishes or approves rates for electric energy generated by the nuclear power plant to which the V/ S Gulf States Utilities Company, 40 FrRC ! 61,081 (1987); Gulf States Utilities Company, 40 FERC ¶ 61,380 (1987)1 and Gulf States Utilities Company, 4. £ERC¶ 61,098 (1988).ILC 358016 Docket Nos. ER86-558-002 and -011 and -013 nuclear decommissioning fund relates has determined the amount of decommissioning costs of such nuclear power plant to be included in the taxpayer's cost of service for ratemaking purposes." 21 Gulf States maintains that the commission's letter orders approving the settlements do not expressly address decommissioning costs,'although the settlement rates which.the Commission has approved are expressly based upon specified decommissioning costs. Gulf States also claims that the IRS has determined that the Commission's letter orders approving the settlements do not satisfy the requirements of its regulations.

We are not convinced that the instant clarifications are necessary.

It appears that Gulf States has never submitted to the IRS'the letter orders approving the settlements that specified the amount of decommissioning costs that will be reflected in Gulf States' wholesale rates. Based on Gulf States, filing it appears that they requested approval from the IRS on June 24, 1987. 2/ The letter orders vere not issued until July 22 And September 25, 1987 and January 31, 1988, respectively.

We believe that had Gulf States properly submitted tha ltter orders that are tho subject of our order today to the IRS that no clarification of these orders would be necessary.

We shall nevertheless grant the requests of Gulf States and cajun. in approving the settldments reached in this docket the Commission has authorized Gulf Statj ,to rflac* in Its wholesale rates yearly decommissioning costs of $112,914.

We beiieve such acti1on to 5e in the public interest to allow Gulf States to receive the proper tax deduction for its yearly cash contributions to the River Bend Nuclear Decommissioning Fund.This order will also have no application to the rates being charged to Cajun.

orders: The Gulf states' and Cajun's requests for clarification arehereby granted.By the Commission.

Loi3 D. Cashel!, Acting Secretary.

2J Z-9_2 Petition for Clarification at 3-4, quctinq Tenp.Treas. Reg. I 1.468A-3T(g)

(1986).I/ a2 letter of September 22, 1987 of Willian J. Dwyer, Chief, Branch 6 Corporation Tax Divi3ion, :rRS at i.

C C ,- -.~BEFORE THE FEDERAL Ell- IS 4: REGULATORY COMMISSION Gulf States Utilities Company ) 'ýLD,:cket Nos. -.) ER86-558-000, ER86-558-002,) ER86-558-O11V) ER86-558-013,) ER86-558-015 FEB 22 1988 PETITION FOR CLARIFICATION OF ORDERS OF APPROVAL LEGAL SERVICES I. INTRODUCTION By this petition pursuant to Rule 207 (a) (2) of the Commission's Rules of Practice and Procedure, Gulf States Utilities Company ("Gulf States" or the "Company")

requests the Commission to clarify certain letter orders approving settlements which have been reached in this docket. The purpose of the clarification is to recognize expressly the amount of decommissioning costs reflected in the rates established by the settlements.

Absent this express recognition, Gulf States will be unable to deduct from its taxable income its yearly cash contributions to its decommissioning fund.II. BACKGROUND OF THE SETTLEMENT RATES On June 24, 1986, Gulf States filed a proposed three-phase increase in. rates and charges to fourteen wholesale customers.

The primary purpose of the filing was to establish rates reflecting the impact of the River Bend Unit I nuclear generating plant ("River Bend"), which went into commercial operation in June, 1986.

On March 20, 1987, Gulf States filed ý a settlement agreement with seven settling customers (the "Towns Agreement").

The Commission approved the Towns Agreement by a letter order dated July 22, 1987. On July 15, 1987, Gulf States filed a substantially similar settlement agreement with the Town of Welsh, Louisiana (the "Welsh Agreement").

The Commission approved the Welsh Agreement by a letter order dated September 25, 1987. On October 7, 1987, Gulf States filed a settlement agreement with Sam Rayburn Dam Electric Cooperative, Inc., Sam Rayburn G&T, Inc., and Sam Rayburn Municipal Power Agency (the "Sam Rayburn Agreement").

The Commission approved the Sam Rayburn Agreement by a letter order dated January 21, 1988. Also pending before the Commission is Gulf States'December 11, 1987, settlement agreement with Deep East Texas Electric Cooperative, Inc. ("Deep East Agreement")

and Gulf States' January 22, 1988, settlement agreement with Brazos Electric Power Cooperative, Inc. ("Brazos Agreement").

With respect to decommissioning costs, the settlement rates (which are the same for all customers) reflect the decommissioning expenses set forth in the Company's filing, adjusted for a 40-year funding period. The Sam Rayburn Agreement, for example, expressly provides: The settlement rates reflect the decommissioning expenses set forth in the Company's filing, adjusted for a 40-year funding period, which expenses are funded through an external fund.

C C Sam Rayburn Agreement, Art. III(H)(3);

Deep East Agreement, Art.III (G)(4); Brazos Agreement, Art. III (F)(4). Similarly, the Towns Agreement and the Welsh Agreement provide for settlement rates which incorporate the decommissioning expenses set forth in the Company's filing, funded over a 40-year period. See Towns Agreement, Art. III(K)(4) and Art. III(K)(l)

(40-year life);Welsh Agreement, Art. III(E)(4) and Art. III(E)(1)

(40-year life).The Deep East Agreement and Brazos Agreement specifically include a schedule reflecting the yearly decommissioning costs included in the settlement rates. Deep East Agreement, Exhibit D; Brazos Agreement, Exhibit C. As shown in the schedule, the settlement rates are based on a yearly decommissioning cost of $112,914.

While the other settlement agreements provided for the same specific decommissioning expenses, they did not include a separate schedule of the Company's actual yearly costs. Gulf States is attaching to this pleading as Attachment 1 the schedule reflecting the yearly decommissioning costs included in the settlement rates.III. THE IRS WILL NOT PERMIT GULF STATES TO DEDUCT ITS CONTRIBUTIONS TO ITS DECOMMISSIONING FUND UNLESS THE COMMISSION EXPRESSLY DETERMINES THE AMOUNT OF THE RIVER BEND DECOMMISSIONING COSTS TO BE REFLECTED IN RATES Section 468A of the Internal Revenue Code permits eligible taxpayers to deduct a portion of their cash contributions to a nuclear decommissioning fund. To take this deduction, the taxpayer must first obtain a "schedule of ruling C C amounts" from the Internal Revenue Service. Temp. Treas. Reg.Sl.468A-3T(a)(l)(1986).

The Internal Revenue Service will not provide a taxpayer with a schedule of ruling amounts "unless a-public utility commission that establishes or approves rates for electric energy generated by the nuclear power plant to which the nuclear decommissioning fund relates has determined the amount of decommissioning costs of such nuclear power plant to be included in the taxpayer's cost of service for ratemaking purposes." Temp. Treas. Reg. §l.468A-3T(g)

(1986). A copy of the commission's most recent determination must be included in the request for a schedule of ruling amounts. Temp. Treas. Reg.§1.468A-3T(h)

(2) (vi) (C) (1986).The Commission's letter orders approving the settlements in this docket do not expressly address decommissioning costs. Although the. settlement rates which the Commission has approved are expressly based upon specified decommissioning costs, see supra pp. 2-3, the Internal Revenue Service has determined that the Commission's letter orders approving the settlements do not satisfy the requirements of its regulations.

See letter from William J. Dwyer, Internal Revenue Service, to William A. Pinkerton, Manager -- Tax Services, Gulf States Utilities Company, September 22, 1987 (Attachment 2).According to the IRS, "a determination of the decommissioning cost tobe included in the cost of service must be made by [the Commission]

before the IRS can provide a schedule of ruling amounts." Id. at 2.

C C As a result, absent clarification by the Commission, Gulf States will be unable to obtain the schedule of ruling amounts it needs to take its tax deduction for decommissioning expenses.

That result would be detrimental both to Gulf States and its customers.

A simple order clarifying the Commission's earlier letter orders, however, will enable Gulf States to take V the deduction.

IV. CONCLUSION For the foregoing reasons, Gulf States respectfully asks the Commission (1) to amend each of its earlier letter orders in this docket to state expressly that yearly decommissioning costs of $112,914 are included in the settlement cost of service and (2) to include similar language in any future orders approving settlement agreements in this docket.Respectfully submitted, Cecil L. John on GULF STATES UTILITIES COMPANY 350 Pine Street Beaumont, Texas 77701 (409) 838-6631 George,, Avery Barry S. Spector CADWALADER, WICKERSHAM

& TAFT 1333 New Hampshire Ave., N.W.Washington, D.C. 20036 (202) 862-2200 Counsel for Gulf States Utilities Company Dated: February 16, 1988 J. .I A GULF STATES UTILITIES COMPANY RIVER BEND NUCLEAR DECOMIMISSIONING FUND FOR 704. CO-OHNERSHlIP BEGINNtNG YEAR BALANCE 1 q 0 6 $1 q07 60974 1988 179375 989 30345 990 e".9 106 q91 602439 9qz 7,9573 993 951748 jqq9 4 11sos2o 1q95 1 66763 1q96 1602685 997 1859841 1989" 41 2000 2778691 2001 3141688 2002 3537353 2001 39b8b29 200. 4430720 2005 4951119 2006 5509635 2007 6118414 0on8 6781986 2009 7505Z78 2010 8293667 2011 9153011 2011 70089696 014 1212123558 2015 3436593 zoiý 14758800 2011 16200006 2018 77709Z1 2019 19483217 020 21349621 021 23384001 022 25601475 2O02 2801852 St050Z4796 ANNUAL EARNINGS S487 16144 27;59 40419 51,220 6q261 85658 10352Q 125000 S4 4742 67306 192612 220110 250033 282751 318362 357177 3 9 948 85 4(45600 495867 550650 610S73 6 7575 746430 87.3771 9000 3 199196 1 I100121 209293 320292 450001 599382 753490 921466 Z104560 30413$521667 CUMULATIVE EARNINGS S487 21631 49390 89009 144029 213290 29891.0 40247?525405 669727 03?7115 029725 249855 1499918 17826f9 2101031 2458208 2857693 3303293*3799140 4349818 (260196 5 35671 6302101 7205872 0113945 9115106 0214027 1423320 2751612 4209611 5800995 7562481 9483951 21580511 230?26414 16414311;9173090 32190322 ANNUAL CONTRIBUTIONS

$ 60974 112914 112914 112914 I12914 11 291'f 112914 112914 11 29 I'.1 1 29 1'.11291', 112914 11 2914 12914 I 1291(1 112914 112914 1.1 2914 112914 11291 4 112914 11 Z 9 1it II914 11291 4 112914 112914 112914 112914 112914 112914 117914 112 914 512914$ 64854 C CONIRIBUTIONS 60974 17308Z 206800 399716 512630 625544 2 '1-450 05137Z')1,10236 1077200 1190114 1303020 110 15942 1520056 1641770 1754684 80 7598 930512 2093426 22063'.0 2319Z54 2,2168 25,15002 2657996 2770910 28182O4 2996738 3109652 3222566 33354800 3'. '.0394 35(.1300 674222 787136 900050 4012964 4125078 4238792 4351706 1 4516560 ENDING BALANCE$. 60974 179'75 30863S 449106 602'39 76957!915171411 1150320 1366763 602613!21401A4I 244566 7 2778691 M 141688 537353 3968629 44 38720 4951119 5509633 611041'4 6731986 75052713 829366W 9153011 1Q069b 111106,3 Z223551)4758800 6200006 1 7770921 29483217 2 349621 3384001 5601475 8018 22 306SS 03 J3524796$ 36706882/Th THE ANWUAL EARNINGS RATE IS 9.00 PERCENT This schedule is on a FERC jurisdictional basis..3 (1:11 1'I z I-.

Attachment 3-G (13 pages)MSS-4 Agreement and FERC's acceptance Entergy Services, Inc.101 Constitution Avenue, N.W.Suite 200 East Washington, DC 20001 Tel: 202 530 7342 Fax: 202 530 7350 e-mail: aweinst@entergy.com Andrea J. Weinstein Assistant General Counsel Federal Energy Regulatory Affairs December 29, 2010 The Honorable Kimberly Bose Secretary Federal Energy Regulatory Commission 888 First Street, N.E.Washington, D.C. 20426 Re: Entermy Services, Inc. Docket Nos. ER03-753-and ER11- -000 Dear Secretary Bose: Pursuant to section 205 of the Federal Power Act ("FPA"), 16 U.S.C. § 824d (2004), and Part 35 of the regulations of the Federal Energy Regulatory Commission

("Commission")

18 C.F.R. Part 35 (2007), Entergy Services, Inc. ("ESI"), on behalf of Entergy Gulf States Louisiana, L.L.C. ("EGSL"), and Entergy Texas, Inc. ("ETI")' hereby submit for filing a revision to the currently-effective Service Schedule MSS-4 Agreement relating to the River Bend nuclear generating station ("River Bend").I. BACKGROUND AND INTRODUCTION Service Schedule MSS-4 of the Entergy System Agreement relates to a unit power purchase between Entergy Operating Companies 2 and/or a sale of power purchased by an Operating Company. In an order issued on April 14, 2005, the Commission approved the current version of MSS-4.3 As a condition in its order, the Commission required ESI to file a notice with As described below, EGS-LA and ETI are expected to become public utilities on January 1, 2008 pursuant to EGS's proposed jurisdictional separation plan.2 The Operating Companies are Entergy Arkansas, Inc. ("EAI"), Entergy Gulf States Louisiana, L.L.C. ("EGSL"), Entergy Louisiana, LLC ("ELL"), Entergy Mississippi, Inc. ("EMI"), Entergy Texas, Inc. ("ETI") and Entergy New Orleans, Inc. .("ENO").

The generation and bulk transmission system of all of the Operating Companies is collectively referred to as the "Entergy System." Entergy Services', Inc., Ill FERC ¶ 61,035 (2005).

Hon. Kimberly Bose December 29, 2010 Page 2 the Commission within 30 days of any Operating Company's entering into any long-term transaction pursuant to Service Schedule MSS-4.'A The Commission defined "long-term" transactions as "one year or more." 5 According to the Commission, such a notice condition "will provide interested parties with the ability to identify and the opportunity to challenge the transaction under section 206 of the FPA," and is therefore a reasonable resolution of the MSS-4 settlement.

6 On March 13, 2007, in Docket Nos. EC07-66, ES07-26 and EL07-45, ESI, on behalf of Entergy Gulf States, Inc. ("EGS"), EGSL, and ETI requested authorization for EGS to implement a proposed jurisdictional separation plan ("JSP"). As a result of the JSP, EGS, a FERC-jurisdictional public utility, was restructured into two separate utilities, EGSL and ETI.By order dated July 20, 2007, the Commission authorized the JSP as consistent with the public interest under Section 203 of the Federal Power Act. See Entergy Gulf States, Inc., 120 FERC ¶61,079 (2007).River Bend was previously owned by EGS. As a result of the JSP, EGSL now owns the 70%7 regulated portion of the River Bend Station. EGSL sells a portion of this 70% regulated portion of River Bend to ETI pursuant to a MSS-4 Agreement

("River Bend MSS-4"). On October 5, 2007, in Docket No. ER08-3 1, ESI filed the River Bend MSS-4 at the Commission.

ESI originally filed the River Bend MSS-4 out of an abundance of caution because certain adjustments to the inputs into the Service Schedule MSS-4 rate were necessary to reflect the historical retail ratemaking treatment for River Bend. By unpublished letter order dated December 19, 2007, the Commission accepted the River Bend MSS-4 for filing.I1. INSTANT FILING As described above, the Commission has previously held that MSS-4 transactions need not be filed at the FERC prior to the commencement of such transactions.

8 Instead, "long-term" MSS-4 transactions must be filed at the Commission on an informational basis within 30 days of the commencement of such transactions.

In this instance, however, ESI is submitting the amended MSS-4 Agreement for River Bend between EGSL and ETI out of an abundance of 4 Id. at PP 1, 20.5 Id. at P 20.6 Id. at PP 20, 21.7. The remaining 30% share of the River Bend is not in retail rate base. This 30% share was formerly owned by Cajun Electric Power Cooperative

("Cajun").

EGSL owns this 30% share and currently sells the power associated with this share of River Bend to ELL and ENO in accordance with the Commission's order in Docket Nos. ER03-583, et al (Opinion No. 485 and 485-A).Entergy Services, Inc., Ill FERC ¶ 61,035 at P 31; Louisiana Pub. Serv. Comm 'n v. Arkansas Power & Light Co., 44 FERC ¶1 61,392, at 62,270 (1988).

Hon. Kimberly Bose December 29, 2010 Page 3 caution because the existing MSS-4 Agreement for River Bend is currently on file at the Commission.

On September 23, 2010, the U.S. Nuclear Regulatory Commission

("NRC") notified the operator of River Bend that it believed that certain language in the MSS-4 Agreement was not in compliance with NRC regulatory requirements.

Specifically, the NRC believed that the MSS-4 Agreement should contain express language that (1) payments for River Bend decommissioning costs should be made notwithstanding the operational status of River Bend, (2) payments for River Bend decommissioning costs should be made notwithstanding any force majeure provisions, and that (3) proceeds from decommissioning collections should be deposited into the external sinking fund. EGSL believes that items (1) and (2) are already addressed by the contract; and that item (3) is not an NRC regulatory requirement for the contract, and in any event is the intention of the contract and the current practice.

Nevertheless, in order to cooperate fully with the NRC, EGSL and ETI have revised the MSS-4 Agreement to incorporate provisions as suggested by the NRC.III. COMMUNICATIONS The following persons are authorized to receive notices and communications with respect to the instant filing: Andrea Weinstein Richard Armstrong Assistant General Counsel Director, Federal Regulatory Affairs Entergy Services, Inc. Entergy Services, Inc.101 Constitution Ave., N.W. 101 Constitution Ave., N.W.Suite 200 East Suite 200 East Washington, DC 20001 Washington, DC 20001 (202) 530-7342 (202) 530-7341 aweinst@entergy.com rarmst l @entergy.com IV. EFFECTIVE DATE To the extent the Commission determines it necessary to submit the revised River Bend MSS-4 Agreement between EGSL and ETI pursuant to FPA Section 205, ESI requests that the Commission grant an effective date of January 1, 2011. ESI requests waiver of the Commission's sixty day notice requirement to allow a January 1,2011 effective date. ESI believes that such waiver is appropriate because the River Bend MSS-4 Agreement is already on file, and because the revised River Bend MSS-4 Agreement only amends that agreement to reflect minor revisions requested by the NRC.

Hon. Kimberly Bose December 29, 2010 Page 4 V. OTHER FILING REQUIREMENTS ESI knows of no costs included in the cost of service that have been alleged or judged in any administrative or judicial proceeding to be illegal, duplicative, or unnecessary costs that are the product of discriminatory practices.

The cost of service specifically is made subject to the Commission-approved Service Schedule MSS-4.VI. CONCLUSION Accordingly, to the extent necessary, ESI requests that the Commission accept the revised River Bend MSS-4 between EGSL and ETI for filing, and grant any waivers of the requirements in 18 C.F.R. Part 35 necessary to allow the agreement to go into effect on January 1, 2011.If you have any questions concerning this filing, please feel free to contact the undersigned.

Very truly yours,/s/ Andrea Weinstein Andrea J. Weinstein Attorney for Entergy Services, Inc.

Entergy Operating Companies First Revised Service Agreement No. 472 Service Schedule MSS-4 Agreement by and between Entergy Texas, Inc. (Buyer) and Entergy Gulf States Louisiana, LLC (Seller)

MSS-4 AGREEMENT This Agreement is dated as of January 1, 2008, between Entergy Texas, Inc.("EGS-TX" or "Buyer"), and Entergy Gulf States Louisiana, LLC. ("EGS-LA" or"Seller").

WHEREAS, Seller has agreed to make a unit power sale from the designated units set forth on Attachment A (individually a "Designated Unit" and collectively"Designated Units") to Buyer; and WHEREAS, the agreement among Entergy Gulf States, Inc., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., and Entergy Arkansas, Inc., (collectively the "Companies"), and Entergy Services, Inc. ("ESI") was filed with the FERC on April 30, 1982, and became effective on January 1, 1983, and amended to incorporate Entergy Gulf States, Inc. in 1993 and its successor, EGS-LA in 2008 (hereinafter referred to as the "System Agreement");

and WHEREAS, the System Agreement contains a Service Schedule MSS-4 providing the basis for making a unit power purchase and sale between the Companies that arc participants in that Agreement; and WHEREAS, the parties herein wish to execute this Agreement to provide for a unit power purchase by Buyer under Service Schedule MSS-4 from the Designated Units.THEREFORE, the parties agree as follows: I. Designated Units. The designated generating units for purposes of this unit power sale under Service Schedule MSS-4 of the System Agreement shall be those units set forth on Attachment A.2. Unit Power Purchase.

Seller agrees to sell and Buyer agrees to purchase that quantity of generating capacity and associated energy from the Designated Units equivalent to the percentage (the "Allocated Percentage")

of Seller's capacity in each such Designated Unit set forth on Attachment A.3. Pricing. The pricing of the capacity and energy to be sold and purchased pursuant to paragraph 2 above shall be as specified in Service Schedule MSS-4 of the System Agreement, as clarified in the accompanying transmittal letter dated October 5, 2007. Should the trust funds set aside for Buyer's share of the responsibility for River Bend Station decommissioning be found to be insufficient to cover the aforesaid Buyer's share of the cost for such decommissioning, Buyer will promptly pay to Seller such deficit. The Buyer will fully pay for the Buyer's share of the decommissioning responsibility for River Bend notwithstanding the operational status of River Bend or any force majeure provisions.

All proceeds from decommissioning collections under Service Schedule MSS-4 pursuant to this Agreement will be deposited to the external sinking fund(s) that collect(s)

Buyer's decommissioning funding.4. Energy Entitlement.

Buyer is entitled to receive on an hourly basis the Allocated Percentage of the energy generated by each of the Designated Units.5. Term. The term of this Agreement shall be the operating life of the Designated Units, plus any time required to decommission the Designated Units.6. Termination.

Neither party shall have the right to terminate the unit power purchase and sale required by this Agreement without the express written consent of the other party.7. Assignment.

This Agreement is not assignable by Buyer without the consent of Seller, and Seller must consent to any transfer or assignment to any new or restructured entity resulting from any restructuring or business combination of Buyer, the effect of which would cause a successor to become a party hereto. Any assignment approved by Seller shall be on terms as then agreed.8. Condition Precedent.

This contract shall be conditioned upon Buyer receiving all regulatory approvals required for this Agreement.

9. Notices. Unless specifically stated otherwise herein, any notice to be given hereunder shall be sent by Registered Mail, postage prepaid, to the party to be notified at the address set forth below, and shall be deemed given when so mailed.To EGS-TX: Entergy Texas, Inc.350 Pine Street Beaumont, TX 77701 ATTN: Chief Executive Officer To EGS-LA: Entergy Gulf States Louisiana, L.L.C.4809 Jefferson Hwy Jefferson, LA 70121 ATTN: Chief Executive Officer 10. Nonwaiver:

The failure of either party to insist upon or enforce, in any instance, strict performance by the other of any of the terms of this Agreement or to exercise any rights herein conferred shall not be considered as a waiver or relinquishment to any extent of its rights to assert or rely upon any such terms or rights on any future occasion.11. Amendments.

No waiver, alteration, amendment or modification of any of the provisions of this Agreement shall be binding unless in writing and signed by a duly authorized representation of both parties.12. Entire Agreement.

This Agreement, which is entered into in accordance with the authority of Service Schedule MSS-4 of the System Agreement, constitutes the entire agreement between the parties with respect to the subject matter hereof and supersedes all previous and collateral agreements of understandings with respect to the subject matter hereof.13. Severability.

It is agreed that if any clause or provision of this Agreement is held by the courts to be illegal or void, the validity of the remaining portions and provisions of the Agreement shall not be affected, and the rights and obligations of the parties shall be enforced as if the Agreement did not contain such illegal or void clauses or provisions.

ENTERGY TEXAS, INC.BY: TITLE: ENTERGY GULF STATES LOUISIANA, L.L.C.BY: TITLE:

ATTACHMENT A SALE OF CAPACITY AND ENERGY BY ENTERGY GULF STATES LOUISIANA, L.L.C. TO ENTERGY TEXAS, INC.This Attachment A is attached to and forms a part of the Agreement dated January 1, 2008, between Entergy Gulf States Louisiana, L.L.C. ("Seller")

and Entergy Texas, Inc. ("Buye r") pursuant to the Service Schedule MSS--4 of the System Agreement.

SELLER'S BUYER'S CAPACITY*

ALLOCATED CAPACITY*BUYER'S ALLOCATED PERCENTAGE DESIGNATED UNITS River Bend Station 689 292.83 42.5%TOTAL 689 292.83 42.5%Expressed in megawatts.

To the extent Seller's Capacity increases or decreases as determined by the Entergy Operating Committee from time to time, Buyer's Allocated Capacity shall adjust correspondingly based on Buyer's Allocated Percentage of Seller's Capacity.

20110214-3037 FERC PDF (Unofficial) 02/14/2011 FEDERAL ENERGY REGULATORY COMMISSION WASHINGTON, D.C. 20426 OFFICE OF ENERGY MARKET REGULATION In Reply Refer To: Entergy Gulf States Louisiana, L.L.C.Docket No. ERI1-2562-000 February 14, 2011 Entergy Services, Inc.101 Constitution Avenue, N.W.Suite 200 East Washington, D.C. 20001 Attention:

Andrea J. Weinstein, Assistant General Counsel

Reference:

Filing of Revised Service Schedule MSS-4 Agreement Relating to River Bend Nuclear Generating Station

Dear Ms. Weinstein:

On December 29, 2010, Entergy Services, Inc. (Entergy) submitted for filing a revised Service Schedule MSS-4 Agreement between Entergy Gulf States Louisiana, L.L.C. (Entergy Gulf States) and Entergy Texas, Inc. (Entergy Texas). The agreement, First Revised Service Agreement No. 472, covers the sale of energy and capacity from the River Bend nuclear generator by Entergy Gulf States to Entergy Texas. Entergy explains that the agreement is being revised to incorporate new language requested by the Nuclear Regulatory Commission.

Waiver of the Commission's 60-day notice requirement is granted pursuant to section 35.11 of the Commission's regulations (18 C.F.R. § 35.11) and First Revised Service Agreement No. 472 is accepted for filing effective January 1, 2011, as requested.

This filing was noticed on December 29, 2010 with comments, protests, or motions to intervene due on or before January 19, 2011. No protests or adverse comments were filed. Notices of intervention and unopposed timely filed motions to intervene are granted pursuant to the operation of Rule 214 of the Commission's Rules of Practice and Procedure (18 C.F.R. § 385.214).

Any opposed or untimely filed motion to intervene is governed by the provisions of Rule 214.

20110214-3037 FERC PDF (Unofficial) 02/14/2011 Docket No. ERI 1-2562-000 This action does not constitute approval of any service, rate, charge, classification, or any rule, regulation, contract, or practice affecting such rate or service provided for in the filed documents; nor shall such action be deemed as recognition of any claimed contractual right or obligation affecting or relating to such service or rate; and such action is without prejudice to any findings or orders which have been or may hereafter be made by the Commission in any proceeding now pending or hereafter instituted by or against your Company.This action is taken pursuant to the authority delegated to the Director, Division of Electric Power Regulation

-- Central, under 18 C.F.R. § 375.307 of the Commission's Regulations.

This order constitutes final agency action. Requests for rehearing by the Commission may be filed within 30 days of the date of issuance of this order, pursuant to 18 C.F.R. § 385.713.Sincerely, Penny S. Murrell, Director Division of Electric Power Regulation

-.- Central CNRO-2012-00007 SERIES 4 ATTACHMENTS 4 Entergy Louisiana, LLC -WF3 Status Report (1 page)4-A Entergy Louisiana, LLC- Calculation of Minimum Amount (1 page)4-B Schedule of Remaining Principle Payments -WF3 (1 page)4-C LPSC Order in Docket No. U-31237 (20 pages)4-D CNO Resolution R-95-1081 in Docket UD-95-1 and IRS Schedule of Ruling Amounts (6 pgs)

Attachment 4 (1 page)ENTERGY LOUISIANA, LLC Status Report of Decommissioning Funding For Year Ending December 31, 2011 -10 CFR 50.75(f)(1)

Plant Name: Waterford 3 Steam Electric Station 1. Minimum Financial Assurance (MFA)Estimated per 10 CFR 50.75(b) and (c) (2011$): 2. Decommissioning Fund Total As of 12/31/11: 3. Annual amounts remaining to be collected:

4. Assumptions used: Rate of Escalation of Decommissioning Costs: Rate of Earnings on Decommissioning Funds: Authority for use of Real Earnings Over 2%: 5. Contracts upon which licensee is relying For Decommissioning Funding: 6. Modifications to Method of Financial Assurance since Last Report: 7. Material Changes to Trust Agreements:

$474.3 million 1$254.0 million See Attachment 4-B See item below 2% real rate of return per 10 CFR 50.75(e)(1)(i)

N/A None None None 1 See Attachment 4-A Attachment 4-A (1 page)ENTERGY LOUISIANA, LLC Calculation of Minimum Amount For Year Ending December 31, 2011 -10 CFR 50.75(f)(1)

Entergy Louisiana, LLC: 100% ownership interest Plant Location:

Taft, Louisiana Reactor Type: Pressurized Water Reactor ("PWR")Power Level: >3,400 MWt PWR Base Year 1986$: $105,000,000 Labor Region: South Waste Burial Facility:

Generic Disposal Site IOCFR50.75(c)(2)

Escalation Factor Formula: 0.65(L) +0.13(E) +0.22(B)L=Labor (South)E=Energy (PWR)B=Waste Burial-Vendor (PWR)PWR Escalation Factor: 0.65(L) +0.13(E) +0.22(B)=Factor 2.281 2.582 12.283 4.51703 1986 PWR Base Year $ Escalated:

$105,000,000

• Factor= $474.287.73Z 1 Bureau of Labor Statistics, Series Report ID: CIU2010000000220i (4 th Quarter 2011)2 Bureau of Labor Statistics, Series Report ID: wpu0543 and wpu0573 (December 2011)3 Nuclear Regulatory Commission:

NUREG-1307 Revision 14, Table 2.1 (2010)

Attachment 4-B (1 page)Schedule of Remaining Principal Payments into Waterford 3 Decommissioning Fund ($ Thousands)

Year LPSC City of New Orleans Total 2012 $5,831 $189 $6,020 2013 $5,831 $189 $6,020 2014 $5,831 $189 $6,020 2015 $6,688 $189 $6,877 2016 $6,688 $189 $6,877 2017 $6,688 $189 $6,877 2018 $6,688 $189 $6,877 2019 $6,688 $189 $6,877 2020 $7,580 $189 $7,769 2021 $7,580 $189 $7,769 2022 $7,580 $189 $7,769 2023 $7,580 $189 $7,769 2024 $7,580 $189 $7,769 2025 $8,694 $8,694 2026 $8,694 $8,694 2027 $8,694 $8,694 2028 $8,694 $8,694 2029 $8,694 $8,694 2030 $10,047 $10,047 Note: Approved in LPSC Docket No. U-31237 and CNO Resolution R-95-1081 in Docket UD-95-1, see Attachments 4-C and 4-D.

Attachment 4-C (20 pages)LPSC Order in Docket No. U-31237 LOUISIANA PUBLIC SERVICE COMMISSION ORDER NO. U-31237 ENTERGY GULF STATES LOUISIANA, L.L.C.ENTERGY LOUISIANA, LLC EXPARTE Docket No. U-3123 7 In re: Joint Application of Entergy Gulf States Louisiana, L.LC. and Entergy Louisiana, LLC for approval of an Increase in Funding for Decommissioning for River Bend and Waterford 3 Nuclear Facilities LPSC Docket No. U-31237.(Decided at the Commission's July 28, 2010 Business and Executive Session.)Overview and Procedural History Entergy Gulf States Louisiana, L.L.C. ("EGSL") and Entergy Louisiana, LLC ,("ELL") (collectively "the Companies")

filed a joint Application with supporting documentation and testimony on December 29, 2009 seeking approval from the Louisiana Public Service Commission

("LPSC" or "Commission")

to provide supplemental funding for the decommissioning trusts maintained for the LPSC-jurisdictional portions of ELL's Waterford 3 and EGSL's River Bend nuclear generation units.' The request to increase the amounts is the result of the Nuclear Rcgulatory Commission

("NRC") notifying the Companies of "a projected shortfall of decommissioning funding assurance" at both Waterford 3 and River Bend. The filings were published in the Commission's Official Bulletin on January 8, 2010. Interventions were filed by the Louisiana Energy Users Group ("LEUG"), Marathon Oil Company ("Marathon"), ArcelorMittal LaPlace, LLC ("ArcelorMittal")

and the Alliance for Affordable Energy ("the Alliance").

This matter was assigned to Administrative Law Judge Michelle Finnegan who presided over a status conference on February 22, 2010. At the status conference, Commission Staff requested that establishing a procedural schedule be postponed until after Commission hiring of an outside consultant to assist Staff in this matter. Staff advised that a Request for Proposals had been issued on February 5, 2010, and Staff anticipated the Commission's hiring decision would occur at the Commission's March 2010 Business and Executive

("B&E"). No party opposed Staff's request. A follow up conference was scheduled for April 5. At the Commission's March 10 B&E, the Commission voted to hire the firms of Exeter Associates, Inc. and Henderson Ridge Consulting, who submitted a joint proposal.

At a status conference held April 5, the parties established a procedural schedule with hearings set for early August 2010.On May 24, 2010 the Companies filed an Unopposed Motion to Modify and Amend Procedural Schedule to postpone the schedule while the parties worked to negotiate a possible settlement or narrow issues for hearing; the motion was granted. The Companies and Staff filed, on June 24, an Unopposed Joint Motion to Suspend the Procedural Schedule.

The motion was granted, and as requested in the motion, the I Waterford 3 is a single-unit 1,152 MW nuclear steam-electric generating station located near Killona, Louisiana that was constructed by ELL's predecessor, Louisiana Power & Light Company, and began commercial operation in September 1985. Waterford 3 employs the pressurized-water-reactor design.River Bend is a single-unit 967 MW nuclear steam-electric generating station located near St.Francisville, Louisiana that was constructed by EGSL's predecessor, Gulf States Utilities Company, and began commercial operation in June 1986. River Bend employs the boiling-water-reactor design.Order No. U-31237 Page I parties were directed to file an update on the status of the case or an uncontested stipulation on or before July 9. On July 9, Staff and the Companies advised that a Settlement Term Sheet had been executed by all but one party, and that the parties planned to file the uncontested stipulation and request that a hearing be set so that this matter could be considered at the Commission's July B&E. On July 13, 2010 the parties filed a Joint Motion for the Scheduling of a Stipulation Hearing and Request for Expedited Hearing. The motion was granted and a Stipulation Hearing was convened on July 20, 2010.Commission Authority Louisiana Constitution and Statutes: The Commission exercises jurisdiction in this proceeding pursuant to Article IV, Sec. 21 of the Louisiana Constitution, and La. R.S. 45:1 163(A)(1) and La. R.S. 45:1176.La. Const. Art. IV, Sec. 21 provides in pertinent part: The Commission shall regulate all common carriers and public utilities and have such other regulatory authority as provided by law. It shall adopt and enforce reasonable rules, regulations, and procedures necessary for the discharge of its duties, and perform other duties as provided by law.La. R.S. 45:1163 provides in pertinent part: A. (1) The Commission shall exercise all necessary power and authority over any street, railway, gas, electric light, heat, power, waterworks, or other local public utility for the purpose of fixing and regulation the rates charged or to be charged by and service furnished by such public utilities.

La. R.S. 45:11.76 provides in pertinent part: The Commission..

shall investigate the reasonableness and justness of all contracts, agreements and charges entered into or paid by such public utilities with or to other persons, whether affiliated with such public utility or not.Companies'Application The Companies December 29, 2009 Joint Application requests an increase in revenues for ELL and EGSL to provide supplemental funding for the decommissioning trusts maintained for the LPSC-jurisdictional portions of ELL's Waterford 3 and EGSL's River Bend nuclear generation units. The request for increase is the result of the NRC's determination of a projected shortfall in the decommissioning funding at both Waterford 3 and River Bend.The Companies' Application proposes new revenue requirement amounts consistent with their revised decommissioning funding plans using a 40 year license and requests approval to include these revenue requirements in their 2009 Test Year Formula Rate Plan ("FRP") filings. ELL requests approximately

$10.336 million per year for its LPSC-jurisdictional revenue requirement in 2010 to meet the NRC minimum funding assurance of $400.2 million, which would be a $7.94 million increase over the $2.396 million in ELL's rates. For EGSL's portion of the regulated 70% share of River Bend, Order No. U-31237 Page 2 EGSL requests a revenue requirement of $9.671 million per year to meet its NRC minimum assurance of $378.8 million. Currently, EGSL has no funding in retail rates for decommissioning.

Staffs Review Commission Staff conducted a review of the Application, supporting documentation and. testimony.

Commission Staff issued data requests, reviewed those responses and conducted a series of conferences with the Companies.

Staff proposed certain adjustments to the Companies' filed calculations of their revenue requirements to update the trust fund balances, extend the funding period and modify the investment portfolio allocations.

Commission Staff and the Companies reached a stipulated agreement, taking into account Commission Staff's adjustments, that resolves all issues in this docket.Uncontested Stipulated Settlement The Companies and Staff filed on July 13, pursuant to Rule 6 of the Commission's Rules of Practice and Procedure, a motion for stipulation hearing, Settlement Term Sheet signed by all parties, and supporting testimony from Kenneth Gallagher for the Companies and Thomas S. Catlin and William J. Barta for Commission Staff. A stipulation hearing was held July 20. At the stipulation hearing, the Companies presented the live testimony of Mr. Gallagher and Commission Staff presented the live testimony of Mr. Catlin. In addition to live testimony, the following documents were entered into the record: Joint Staff EGSLIELL Exhibit I -Settlement Term Sheet;Staff Exhibit I- Settlement Testimony of William J. Barta, dated July 2010;Staff Exhibit 2- Settlement Testimony of Thomas S. Catlin, dated July 2010;EGSL/ELL Exhibit 1- Settlement Testimony of Kenneth F. Gallagher, dated July 9, 2010;EGSL/ELL Exhibit 2- Direct Testimony of Kenneth F. Gallagher, redacted public version, dated December 2009; and EGSUiELL Exhibit 3- Direct Testimony of Kenneth F. Gallagher, confidential version, dated December 2009.Conclusion On motion of Commissioner Campbell, seconded by Commissioner Field, and unanimously adopted, the Commission voted to accept the Staff Recommendation and adopt the uncontested stipulated Settlement Term Sheet filed into the record on July 13, 2010. Therefore, IT IS ORDERED: I. The Companies submitted a Joint Application seeking approval to provide supp!emental funding for the decommissioning trusts maintained for the LPSC's jurisdictional portions of the Waterford 3 Steam Electric Station ("Waterford 3") owned by ELL and the River Bend Station ("River Bend") owned by EGSL.Order No. U-31237 Page 3 The Companies requested increases in their respective revenue requirements to address projected shortfalls found by the Nuclear Regulatory Commission

("NRC") in the decommissioning funding assurance required for each facility.2. The proposed revised revenue requirement amounts are a result of the NRC notifying the Companies of the referenced projected shortfall of decommissioning funding assurance at both Waterford 3 and River Bend.Under NRC financial assurance requirements regulations found in 10 CFR 50.75(a)-(f), ELL and EGSL, as holders of nuclear operating licenses, must certify through biennial filings that available decommissioning funds are not less than the NRC's prescribed minimum amount required to fund decommissioning costs. The projected shortfalls determined by the NRC are a result of several factors, including the NRC's requirement that only the currently approved license life of forty (40) years for each unit may be used in calculating the minimum financial assurance amount. The LPSC, in prior Orders, used a sixty (60) year license life to determine the appropriate level of funding for the decommissioning trusts, based on possible license extensions that the Companies are expected to apply for in the future.3. The Companies have proposed new revenue requirement amounts consistent with their revised decommissioning funding plans using a 40 year license and requested approval to include these revenue requirements in their 2009 Test Year Formula Rate Plan ("FRP") filings in the manner provided for in each Company's FRP.2 ELL has requested approximately

$10.336 million per year 3 for its LPSC-jurisdictional revenue requirement in 2010 to meet the NRC minimum funding assurance of $400.2 million, which would be a $7.94 million increase over the $2.396 million in ELL's rates. For EGSL's portion of the regulated 70% share of River Bend 4 , EGSL has requested a revenue requirement of $9.671 million per year to meet its NRC minimum assurance of$378.8 million.5 Currently, EGSL has no funding in retail rates for decommissioning.

4. The Commission has recognized in its prior rate Orders setting decommissioning accruals for both ELL and EGSL that the decommissioning accrual issue would be revisited if the NRC notified the Companies that decommissioning funding was inadequate, Orders addressing both EGSL and ELL contain language substantially as follows: "In the event that the Nuclear Regulatory Commission

("NRC") formally notifies [EGSL or ELL] or (the River Bend or Waterford 3] licensee that the decommissioning funding for[River Bend or Waterford 3] is or would become inadequate, the Company would be permitted recognition in rates of decommissioning expense at a level sufficient to address reasonably the NRC's concern as expressed in the notification." 6 2 Section 3.A.5 of the EGSL and ELL FRP Riders both contain identical language stating, in pertinent part that: "The effects of the changes in depreciation rates, and/or decommissioning accruals, increases and decreases, ordered by the LPSC, including as a result of changes in the requirement to fund the decommissioning trust that may be ordered by the Nuclear Regulatory Commission during the period that this FRP is in effect, shall be considered separately outside of the FRP mechanism." 3 The retail revenue requirement for ELL is $10.134 million.4 Thirty percent of the River Bend plant is unregulated and was acquired by EGSL from the former Cajun Electric Power Cooperative, Inc. as part of a bankruptcy reorganization.

See In Re Cajun Electric Power Cooperative, Inc., 238 B.R. 319 (M.D. La. 1999) aff'd 119 F.3" 349 (5 h Cir. 1997). The decommissioning funding for this 30% share is separately funded and is not subject to the NRC's notice of projected shortfalls in the decommissioning funding assurance and, therefore, not subject to the review being undertaken in this proceeding.

5 The $378.8 million figure represents the combined total for the River Bend regulated plant, including the Louisiana, Texas and wholesale jurisdictions.

The Louisiana retail jurisdictional share of River Bend's NRC minimum is $217.76 million.6 For EGSL and River Bend, the provision comes from Item 8 of settlement term sheet for Consolidated Order Nos. U-22491, U-23358, U-24182, U-24993, U-25687 dated January 8, 2003. For ELL and Waterford 3, the provision comes from Item 4 of the settlement term sheet for Order No. U-20925 RRF 2004 dated May 25, 2005.Order No. U-31237 Page 4

5. After incorporating certain adjustments to the Companies' filed calculations of their revenue requirements to update the trust fund balances, extend the funding period and modify the investment portfolio allocations, the Staff and the Companies have agreed upon new decommissioning funding requirements for both Waterford 3 and River Bend. The agreed upon decommissioning funding is intended to serve only to meet the decommissioning funding requirements on an interim basis, and the Staff and Companies agree that both the Waterford 3 and River Bend funding requirements will be re-evaluated based on site specific cost studies after ELL and EGSL, respectively, have filed for and received the NRC's responses to requests for license extensions for the two nuclear facilities.

It is recognized that there is no certainty that either ELL or EGSL will receive license extensions for their respective plants and that the LPSC may have to re-evaluate and adjust revenue requirements based on a forty (40) year life for each plant.6. The initial funding requirement of $5.947 million ($5.831 million on a retail basis) per year is appropriate.

This amount will be included in ELL's revenue requirement for the Waterford 3 decommissioning funding plan, with collections to begin with the September 2010 billing cycle rate change scheduled to occur through the implementation of ELL's 2009 Test Year Formula Rate Plan and further finds that these costs are to be treated as"Extraordinary Costs" and recovered outside of the earnings sharing mechanism of the Formula Rate Plan. This calculation is based on the 5-year step funding plan historically used for Waterford 3 and reflects beginning fund- balance, the investment portfolio allocations, escalation and earnings rates, 5-year funding increments, and other assumptions set forth in the Attached Exhibit A.7. For River Bend, an initial funding requirement of $7.843 million per year stepped up on a 5-year basis is appropriate7.

This amount will be included in EGSL's revenue requirement for the River Bend decommissioning funding plan, with collections to begin with the September 2010 billing cycle rate change scheduled to occur through the implementation of EGSL's 2009 Test Year Formula Rate Plan and further finds that these costs are to be treated as"Extraordinary Costs" and recovered outside of the earnings sharing mechanism of the Formula Rate Plan. This calculation is a 5-year step funding plan recommended by Staff and reflects the beginning fund balances, the investment portfolio allocations, escalation and earnings rates, 5-year funding increments, and other assumptions set forth in the Attached Exhibit B.8. The NRC financial assurance analysis is not a ratemaking adequacy test but is instead a financial adequacy test devised specifically and solely for that purpose. Thus, the financial adequacy test and the resulting implications for ratemaking can differ. Recognizing this fact, the Commission hereby allows contributions to the decommissioning trust fund during the decommissioning period to be considered for purposes of determining whether NRC financial assurance requirements are met For Waterford 3, funding is assumed to occur for the first seven years of the expected ten-year decommissioning period, consistent with the NRC's own calculation of the Waterford 3 minimum decommissioning amount. Staff also assumed funding of the trust through ratepayer contributions during the first six years of the decommissioning period for River Bend.9. The Staff's decommissioning revenue requirement developed for the River Bend nuclear facility, which is hereby adopted by the Commission, reflects the amount to fully fund the Louisiana retail jurisdictional share of the regulated 70% portion of the unit, including the portion that comprises what is known as the Deregulated Asset Plan ("DAP"). Under the provisions of LPSC Order Nos.7 For EGSL the $7.843 million amount is on a retail basis.Order No. U-31237 Page 5 U-17282 D (1/26/88) and U-17282 K (1/12/92) establishing and modifying the River Bend DAP, EGSL has the following options: (1) selling the DAP capacity to customers at a rate of 4.6 cents per kWh ($46 per MWh), recovered through the Company's Fuel Adjustment Clause, (2) in response to a bona fide offer approved by the LPSC, selling the capacity into the market and sharing proceeds with customers on a 50/50 basis for amounts in excess of 4.6 cents per kWh, or (3) if EGSL requests approval by the LPSC to sell the capacity into the market in response to a bona fide offer, ard the LPSC disapproves such off system sale, the purchase price by which the DAP capacity will be sold to customers and recovered through the Company's Fuel Adjustment Clause will be adjusted to 4.6 cents per kWh plus 50 percent of the increment above 4.6 cents per kWh offered by a third party. Seven years after the DAP was approved, in Order U-19904-C (12/29/94), the Commission determined that nuclear decommissioning costs associated with the DAP capacity should be considered to be part of the 4.6 cents per kWh rate established by the DAP instead of separately recovered from customers.

The nuclear decommissioning costs for the DAP portion of River Bend should be returned to EGSL's revenue requirement consistent with the original DAP order and collected separately, and in addition to, the 4.6 cents per kWh. EGSL agrees that as long as the DAP portion of the decommissioning revenue requirement is collected separately, and in addition to, the 4.6 cents per kWh, the Company will not sell the DAP capacity into the market and/or realize any amount in excess of 4.6 cents per kWh in the event it receives a bona fide offer by a third party, for the earlier of 1) a period of 5 years or 2) until EGSL receives a final ruling on its application for River Bend's license extension.

The LPSC and its Staff will review and re-examine allocating the DAP into rates within 5 years this Order.10. The increase in the 2010 decommissioning funding contributions of $3.55 18 million for ELL and $7.843 million for EGSL will be allocated to and recovered from each applicable rate schedule, as identified in Statement A of Rider FRP-5 for ELL and Rider FRP- I for EGSL, in proportion to base revenues before the application of the monthly fuel adjustment.

11. This Commission finds that the Companies have complied with, or are not in conflict with, the provisions of all applicable LPSC Orders governing the Companies Joint Application filed December 29, 2009 in this matter.12. The proposed funding amounts of this Order must be accepted by the NRC. If for any reason the NRC does not accept the proposed funding amounts set forth, the LPSC will promptly undertake to re-examine and review the funding amounts and the related issues which are the subject of a NRC refusal.13. This Commission affirms the language of its prior Orders, namely Item 8 of settlement term sheet for Consolidated Order Nos. U-22491, U-23358, U-24182, U-24993, U-25687 dated January, 8 2003 and Item 4 of the settlement term sheet for Order No. U-20925 RRF 2004 dated May 25, 2005 that in the event that the NRC formally notifies EGSL or ELL 'or the River Bend or Waterford 3 licensee that the decommissioning funding for either River Bend or Waterford 3, individually or collectively, is or would become inadequate, then ELL or EGSL or both would be permitted recognition in rates of decommissioning expense at a level sufficient to address reasonably the NRC's concern as expressed in the notification.

14. For ratemaking purposes the amount of the decommissioning accrual to be reflected in rates shall track, on a prospective basis, for the rate effective period, the specific annual amounts set out in the agreed upon decommissioning funding plan or any subsequent Commission-approved decommission funding plan on a monthly pro rata basis. Such derived amounts shall form the basis for 9 The retail increase is S 3.482 million.Order No. U-31237 Page 6 subsequent rate changes. To the extent that the Companies remain subject to Formula Rate Plans with scheduled rate implementations where rate changes do not occur on January 1, the Companies shall make pro forma adjustments to their Formula Rate Plan Filings reflecting any prospective changes to decommissioning accruals that would occur in the rate effective period, on a monthly pro rata basis. These pro forma adjustments shall be treated as Extraordinary Costs outside of any bandwidth sharing. In the event the Companies are no longer under Formula Rate Plans, the rate treatment of decommissioning costs will be determined by subsequent Commission Order.The Companies and the Staff reserve the right to modify this procedure upon mutual agreement if circumstances warrant.15. Except as stated herein and as set forth in prior Commission Orders, this Order, including the calculation methodology reflected in the Exhibits to this Order, shall have no precedential effect in any other proceedings involving issues similar to those resolved herein and shall be without prejudice to the right of any party to take any position on any such similar issue in future base rate proceedings, including Formula Rate Plan proceedings, or in other related regulatory proceedings or appeals.16. This Order is effective immediately.

BY ORDER OF THE COMMISSION BATON ROUGE, LOUISIANA August 27, 2010/S/ LAMBERT C. BOISSIERE, III DISTRICT III CHAIRMAN LAMBERT C. BOISSIERE, III IS/ JAMES M. FIELD DISTRICT II VICE CHAIRMAN JAMES M. FIELD ISI FOSTER L. CAMPBELL DISTRICT V COMMISSIONER FOSTER L. CAMPBELL/SI ERIC F. SKRMETTA DISTRICT I COMMISSIONER ERIC F. SKRMETTA EVE KAHAO GONZALEZ /SI CLYDE C. HOLLOWAY SECRETARY DISTRICT IV COMMISSIONER CLYDE C. HOLLOWAY Order No. U-3 1237 Page 7 ORDER NO. U-31237 EXHIBIT A Exhibit A Par0 I of 5 EF1Wov Laism. U.C Wastwed- Dow"wmnsI" model Raowoue ftequkemm

&mwnesy (OW00 Un. TOWa LPSC CNO No Yewr copw (1) 43 Jw 2 ~~i 3 1 2 3 4 5 B 7 8 10 11 12 13 14 15 2010 2011 2012 2013 2814 201s 2010 2017 2018 2010 2020 2021 2022 2023 2024 5.947&,947 5.947 5,947 '8.821 a.821 6.821 0.821 7.731 7,731 7.731 7.731 S.,03t 5.831 8,831 5.831 5.831 0.688 8.688 7.500 7.500 7.580 7.580?'88o 116 lie Its 118 133 133 133 133 133 151 151 151 151 0 (1) S" EXhWA Pap I (2) TOWe Crn'PWW* LPSC PrO&Etfan (D.rn~d Aloca~m ofl~eb 08.05%.(2) T~oW Com#.ny -LPSC Jwoi-dcom, 10 Exhibit A,,el Revlslon 2010 Page 2 of 5 Esrwladw 4.26%Fnowgy L09maa. LLC Walmillar-3 Oneamnmllomma mome Revenue Requhmaik Fund Balam a0 Exln40ue Smvnawy (S0M)Toa Una Revenue Tax Occfmm.No YO, Rqui. [I1 I [1 g L41 I 215,001 2 2010 5,947 227,329 0 3 2011 8.947 246,961 0 4 2012 6.9,7 26V.28, 0 5 2013 5.947 291.400 0 6 2014 8.947 318,413 0 7 2016 6,821 344.050 0 8 2016 6.821 37=6w0 0 9 2017 6,821 405,077 0 10 201 6.82A 438,799 0 11 2019 8.821 474,814 0 12 2020 7,731 5`14,25% a 13 2021 7.731 .M.427 0 14 2022 7,731 801516 0 is 2023 7,731 047.991 0 16 2024 7.731 892.624 U04 17 2026 8,867 M...323 8.fa3 18 2028 8.86? 7 09,8 1 193.388 19 2027 8,687 3A4.370 203.9 20 20=8 8.887 262.117 111.237 21 2029 8.887 1TO.T2? 15,650 22 2030 10.240 88,810 100.68m 23 2031 44.001 49.090 24 2032 542 45.564 25 2033 0 552 Notes (1) The anuat Revenue Requkemenwt (5.647) Is chosen that thUm 0econr Fund Balance Is mam In Ow last yeat of de ouvonlO.lo 121 See E~14, T A Pa"e 2Z r21 See EOM0 A Page 3.(41 54N.TSX OUS~led T,0.1 Balance +Taxo aahWe 7,0.1 BElnce.151 See Embbil A PaOW 4.

Exhibit A Pagec3of 5 To ~am~4 TmiDs Lkw ~ ~ ~ ~ ~ ~ 8 0e656e ThAITNW " F oaaf No Yew Exi ...sa2 roymma2 L.ML FwS Adb. 4 En~d. P~.I savmft sanm 21110310 2 _ 2010 S .947 (7% .06 .47 29 1.60 37) 00%3 i01l 5.947 9.90% 5.947 13.00 222 It=0 36.6 100.0016 6 201 5.947 82M% $.947 11AU9 265 25,01 0 316.41,i 100 J9-7 .. ....9 2017 6.821 6.54% Ole" 682 5 3.1 0 405.077 100.00 I1 26I 0DR 682 a 470.14 100 12 200 ~1.11 33196 446 39.446 0 64.66 1000 13 202 7.731 &M 1.7131 34017 476W 42.16m".14ý. , 7.731-M (63 -2 3.81 sit 4,0066 0 601.516 M00.00%(:22 V1 630% 1,731 36. 09 4.74 0 94.9 1(0 1 7,3 (2 .731 40.60 594 47.62.W10.0 3s 026 6.867 6,76% a.6 3066 433 46.46 9.16 15.2 O.0 2026 --.. 2!F. '. -19.9 90(011l 10; 9.067 30.098 474 38.489 203.62 344.370 10(0im 20 m 8.867 5.76% (99 20.446 1 ;S! 100 22 ~ ~ i 202 lm- MI 046 69 11 .A!... -..96 6....21223 0 -l 4i.37 106, n 4.23 4000 MAW .001g 10(00" 240 .113 67l WAG0 45D.066 942 100.00%28 2033 0 4.68% al 10 093 0a 1000%00 NOW 121 R.m- Raq*hwomt

• Ci..3l4" p4oomg (0%141 POW Y&W BSWM,0 COMP6W104d

8. 6IWAW A CwS6YVw g6e*qs Rig K CwUm Yew T,6,iM Cu1761 Yew Enlq RAW.33CabA4146 In acwmwm caNh be. u8&4M"s6 msmoww m udif t~Ies um Wpa=W Im ra*Le 64. UNA A PmpA.III Asa O 0,00m100601119 expowlOftSm naf Wl6yew and. Sm C A Pop 3.(a) Prim Ym eN 64601 Nol A4410,16 0.016114S1584 Empwod88b..

Exhibit A Page 4 of 5 EMW Uhdwlu% LLC W dmd-3 DamIMo Ma (2202)L"CWK cumo NoUCW Downrisawft 8lsffilE~NO vow MUM ON CII Cost £a. t21 Esas m .J Lm 4 1 208 WA NIA 1.0000 0 0 2 200 WA 1.000 1.042 0 0 3 2010 1.0217 1.022 I.0988 0 0 4 2011 1.022 1045 1.1320 0 0 5 2012 1.0m22 i.09 .1812 L 0 6 201Z 1.0231 1.004 1.2314 0 0 7 2014 I.228 1120 I .25$? 0 0 a 2018 1.0240 1,147 1.2202 0 0 2 20Me 1.0244 i1,2s 0 0 10 2017 1.024 1.204 1.450* 0 0 11 2018 1.0254 1.233 1.5163 0 0 12 2019 1.0256 1.267 1.5107 0 0 13 2020 1.m 1.2o00 1.64`9 a 0 14 2021 SAM25 1-323 1.7179 0 0 18 202 1.022' 1.371 1.7900 0 0 1t 2023 l.0o27 1.409 1.M70 0 0 17 2024 1.0292 1.440 1.9463 1,543 3W004 1i 2Q26 1,0267 1.491 20290 41.243 25.,13 to 2029 1.029 1.025 2.1152 91,426 1031.300 20 207 1.0298 1.541 2.2051 I2.441 233.920 21 2028 1.0304 2.2988 48.320 111..22 20290 1.0,O 1.979 63 48.236 115.24 2031 1.0260 1.768 2.110415 18,614 4904M 2 8 2 0 1,02 91 1 .014 2. 821 3 07'm 45.564 26t To1*3 IM 1.510.6 lie s 27 tow ENo)dWk8 4010.97 838284 I1) CP-U Ow Gaw, khoicti rvfwt 1+ 2010. 2m:. 6. 2.61% W 200.-2 is O ,w ,mmp IN 2010 %Q 2 0a0 r4I CoooWft Nummr coat Ef.alaw a 42s5% 9iv 1ar.M2 0 Veow-dIoEWft Cood E.uama o 2008 NRC Mimowbm O2N0 ftvmi.141 fo<comSlkAv Codl Es&mla CUmi*5N okw Coo 0 Exhibit A Page 5 of 5 EntWWy Loursfans.

LLC Wftwkd.3-0wr Mo4M Fes and Other Data (Sin Tia OQualifled Trtal.e and Inveaiant Mapa.er Fea Schedules TO Annual Feca 19.500 Adder is 000)ilrs(PObts

($000) 11831 PO 4At Fixed 31 Cumulative TO trusteeFews 1.00 T" Manager Fe. 0 22.70 5.000 17.70 11.350 11350&.000 16.90 5.30o 16.86 16.000 15,70 13.520 3010 20.000 9.50 6a20 38,40us Inut Oats, ,, " am0,00% NudeCo, -Ecala, m7 .-%1 Revwsion Yeaw [31 2010 Jwft~(aw Afj ca Factor MI8 100.00%Cost EaItante Year 141 2008 TQ Fund Fede",' Tax Rat 15 20.o0%j iComvosite Tax Rats (e3 38.48% End oi FunMd:n Peelod 12112030 Notes: I13 Calculated as zi ne foilea, n a.2o0 o8.70bp' (20o.0- 10.000),10.0oo For blanwc f 251i: TO QMangnt Fee -41.210- 36.460 + (9.6p (25,000.20.000))110.000.

121 Bad Debts arm assuined to be zero.131 Fit year show" krot of rvised deconondaaonlng reveana reqw Jmenle (41 Year upon wldch the decormnmis cost eslmate Is based 161 Stae Incme Tax Ra i 8.00We g te (at* Is 5.35%.101 Etwgy l.ouwans.

U.C. funding atemM in Waiwd.3 ia 100%.[7I Nuclear Coal Escalator Is 4 25%is1 Production dwemar allocator lot LOSian Rota.0 ORDER NO. U-31237 EXHIBIT B Exhibit B 5-Year Step Pagel ofs Exhibit B Page 2 of 5 EWAW GUN SWs LoIStaM. U.C Rfe s8w Owma486Wr MoW"Wl.Tfa Qual"ed ToA DOlW Nom.Tax Ttue Lif Rem. ET, i Tirv ee" Momt N"d Gecaf, fmto Wo Year Rn II Rt 12 'o Trust P)1 Samdlis (1~ 9.11 Mio* 0 ~ ! I~!.2 8.kws Be. 1 3031110 14.85 2 2010 7.543 5.45% 0 822 17 805 0 1S.MS1 5.00%3 2011 7.843 854% 0 581 10 864 0 14,556 0.00%4 2012 7.843 5&0% 0 874 18 ON 0 17,511 0.00%5 2013 7.843 t.87m 0 1.043 1 1,024 0 1&.534 0.00%6 2014 7,843 8.97% 0 1.123 20 1.103 0 19.L37 0.00%7 201$ 8.956 &,90% a 1,194 21 111,3 0 20,809 0.00%a 2010 8.8a 6 01%T 0 1SA 22 1,247 0 22.007 0.00%" 9 2017 8.895 6.02% 0 1.348 23 1,324 0 23.381 0.00%10 2018 8.986 8.04% 0 1.434 25 1.409 0 24.790 0.00%ii 2019 8.88i &.06% 0 1525 28 1.499 0 20,29 9100%12 2020 10.19S 6.08% 0 1,623 27 I.5 0 27,884 0.00%13 2021 6.08% 0 1,124 29 1.696 0 29.575 0.00%14 2022 MA.SS 64.02m 0 1,80? 10 I,'M1 0 11,358 000%IS 2023 10.196 5&7o, 0 1.m0 2 1.88A 0 332.5 000%18 2024 10.195 5.28% 0 1.767 33 1.734 0 34,888 000%17 2025 11.693 S.1016 0 1.808 35 1.771 S2.408 24.321 0.00%18 2028 11,53 488 0 1.204 25 1.17S 20.499 0 0.00%19 2027 11.693 4.898% 0 0 0 0 0 0 1100%20 2028 11,83 4.88% 0 0 0 0 0 0 1100%21 2028 1.883 4,89% 0 0 0 0 0 0 110016 22 2030 13.513 4.919 0 0 0 0 0 0 a00%23 2031 0 451% 0 0 0 0 0 0 11001 24 2032 0 4.51% 0 0 0 0 0 0 0.00%25 2033 0 4.51% 0 0 0 0 0 0 0.00%26 2034 0 4.51% 0 0 0 0 0 0 00%Momw ll saees i.h* a Pao. 1, 121 Pvrqeatod after-lu j~ e'a91te, (31 Rsvewru Re.enn (I 0l. QaiWq Pena 141 P-s Y-a B1ja-n Coonoowldso Smanrualiy wt CWurnt Yew Eamings

• CoeMl Yew Trwls

• C' r Year Earrkv8 Ral IS] CaICulated an1 WMIG bate' (Avg. 810 -Prlaf Y. 801.. + % (Tr&Awfws

-Ear&us~) In acmac .withn ftO Ife 18 hedules~ for m8u05 and Ms 9aMgare and 00 be lSa tab&e SBa E~bl a Psnp a 16I Ttsej -Eawlgvas

• lm6 laoel Fee.M7 Asaue "ta ,1 NnlTax Sle .IW Lized to Pay doe dowmelsinoll Cto e d TO 8.See EXnt 8 PaGe 4 W ft" (8) Prfin Yew Baloae

• Ne AMdbane. Oeanr ka g Experde, Exhibit B Page 3 of 5 Entow~ .MsW. LWWu.*u.LLC Louilase.

Reatil TAX OuWWd Trust 044 (s0oo)Tax Oee'az d Trust Line Revalue E6nkv TrmrW MO- Not Oaootm Quamov NO Yew R- t l atr To Trust M3 EmdP4 Fe t ILM Adil il x l.. M A ! Reiacef Prcn I 8e5g4*r Balance *1 3131110 32.940 2 2010 7.143 5.60% L814 1.431 31 4.014 0 36.964 10.00%3 2011 7.843 6.03% 7,843 2.414 38 10.221 0 4,1751 100.00%4 2012 7.843 6.20% 7.843 3,213 42 11,014 0 56.108 100.00" 5 2013 7.843 6.29% 7.843 3.964 49 11.758 0 69.947 100.00%a 2014 7.843 &.4T% 7.84 4.6= 67 12.631 0 S2,66S 10DA0%7 2015 8.9S 1150% &.M8 6.746 as 14,678 0 8.163 100.00%8 2016 8.68 8,52% 8.06 6.738 75 f5.659 0 112.M22 100.00m 9 2017 .86 6.64% 88,11 7.600 8a 16,711 0 129,633 110.00%10 2018 0.60 6.57% 6.5m L.052 as 17,852 0 147.466 100.00%I1 2016 L.O &"5% L596 10,178 107 19,064 0 1611,50 MOD%12 2020 10.19 0.61% 10.193 11.528 120 21.064 0 158.153 100.00%13 2021 10.195 &63% 10.196 13.019 133 23.061 0 211.234 100.00%14 202 10.166 8165% 10.156 14.620 146 24.86? 0 235.80 100.00%1s 2023 10.195 8.39% 10.195 15.641 164 Z5.672 0 241.573 100.00%1 2024 10.105 OL12% 10.105 *I0.563 160 38.51 0 288,154 I1O.0%17 202 8 863 5.75% 11.693 17.143 187 28.839 0 318.793 100.00%16 2= 11.653 &76% 11.693 18,847 215 30.325 23.543, 323.575 100.00%19 2027 11.693 5.70% 11.603 10.243 220 30.717 103.721 260.70 100.00%20 2028 14,693 V.71% 11.883 14.977 173 20,498 07.774 171.2"4 1o0.O00 21 2029 11,603 5.768A 11.693 10.653 128 22,378 67.507 134S166 22 2M0 A3.513 5.76% i3.13 66.23 150 21,642 70.178 R5,430 %00.00%23 2031 0 4.85% 0 4.230 64 4.100 50.108 39A78 100.0m%24 2D32 0 4.88% 0 1.950 35 1.915 24.761 18,632 100.00%25 2033 0 .4.6% 0 822 20 001 15.917 1.516 100.00%26 2034 0 4.14% 0 75 7 67 1,54 0 100.00%Not": Ill Se Exhibe 6 Page 1.12) Pr*oled aliar-to tograte,,.

13) Ae&~e"e Rwuirener.

-

PwownvW 141 Prior Yew 006,r0 CORIvPOilDed SaIi*umally a CWurt Yew Ewt~Ip Rooe3 Currentl Year Tretlalr 'Csuet6 Yewr Ea*149 4Raft.151 Cakulabted on "aeer. balance. (Avg. U1 m Prior Yr a. EW +. K Truntbi EamtiaspIn

• Icc4alalce -hsor fte e sdredu.elo tr 4n*.ese and ea~%a and applicable tax rates. SeaEft 0.64 Pap L.8] e -Earnngs. Mana5e4men4 Fed.(7) Ammes OW the N"o-Tux Qualled Galoeo is utailzed to pay the costs before 86 To 6ance.See E..ilt B Pop. 4.jal Prior Yaw DOW"ef Not A~dttiti.

De06onvOlaajont E~rpndw ee.b Fxhibit B Page 4 of 5&0oog G5SAS Uxdmia LLC m8w gem8 M0466.wmm mom Coca 11"Unit" ExpO.1400woS Lin Cumo. Ow. Nudew Rd -, EQSL Pamwo 41 LA RPA -NO year ci I cptl Cost 0w L21 0 70% IQcF LA RaWo)L E*CMIO PR I z008 OA WA 1.0=00 0 0 0 0 2 2000 NIA 1000 1.0423 0 0 0 0 3 2010 1.0217 1.022 1.0mB 0 0 0 0 4 2011 1 0222 1.0M 1.0330 0 0 0 0 5 2012 1.0228 1.068 1.1812 0 0 0 0 a 2013 ,.0231 1.004 1.2314 0 0 0 0 7 20M4 t.03 1.120 1.2937 0 0 0 0 8 2015 1.0240 1.147 0.383. 0 0 0 0 9 2014 1.0244 1.175 j.3"2 0 0 0 0 10 2017 t.0240 1.204 IA545 0 0 0 0 11 2018 I.025 1.235 1,.513 0 0 0 0 12 2018 1.0258 1.207 1.580w 0 0 0 0 f3 2020 0.0283 t.300 1.6478 0 0 0 0 14 2021 0.028 1.8 1.7170 0 0 0 0 1: 2022 1.0272 1.371 1.7m0 0 0 0 0 00 2023 1.0277 1.409 1,08670 0 0 1? 2024 0.0282 1.449 1.204 0 0 0 0 I8 202S 0.0247 .4si 2.0m8 11.043 &3wQ 6L.10 02,404 10 2026 1,0203 1.5135 21152 41,888 24,074 23.186 40.042 20 202? 1.0208 1.861 2.2"1 4.938 40,838 47.03? 103.721 21 2028 1.0304 1.028 2.2100 78.84 44.162 42.52 07,774 22 2020 1.0310 1.679 2 0,8 29,240 2Sfe6 6P50T 23 2030 1.0281 1.123 2.4084 10.867 29.240 28.M6N 73.378 24 2031 1.0261 1.768 2.6048 34.740 1.976 10,238 Ao.106 25 2022 1.0261 1.514 2.7163 14.467 9.46% 9.119 24,761 20 2032 1.0281 1.81a 2.8307 10.1.4 5.83' 6.623 15.917 27 2034 1.0261 1.910 2.1810 n8 65? 537 1."4 28 Ioal 378717 217.762 200.726 492,200 NOW.III CP1U Pff 01040 Ma/M FcOrcast for2010 -2029' ft. 2.81% Wc 2020-2034 is0 edw ms. kor20101 02028.M2 cuw0iaW NudarCO CM~ EscatOW 0 l4.25% PO O'W.131 0. mr/aolgwrtng cowl Es40io Pat 2008 NRC MWvmlo. (2008 948ot4 14) Oocow.asiO"L.g 0.ul gs9w.* , pj gy Gull swas4 Fundin0g hMwrec (I00%) -I.13 R" Ad omdo w. PPA with E70 (42.5%).(5) EGSL Funding Shw.of Cost Eadmi0m 0* (Lsoo to Re Prodoction 00mand Aftcaor (98. 0It%)(a] L(Oims Reba, e mAdl COw &csa.0 Exhibit 8 Page 5 ofS5 Entera5 Gulf fta6, Louisiana.

U.C River send Decormoninsang Model. Loulsana r7eam arml Othser oats (S in Thouoandse)

Tax Quattittet mIs.. sssd bWVstnse MIMI Post BOOM*%ndte fit TO Annual Fees 6.328 Adtter ($ 000)&eolkpoinfs 000O0) Basis Ponts Fixed ill Cianulafive TO Manager & Asset Based Trustee Fee To% Qalle 'rse.18.50 1.333 17.50 2.407 2,467 2.03 15.00 1313 3,779 2.807 13.50 0.878 4.854 3"333 12.00 0.9w0 5.554 4.167 9.50 1.000 6,554 12.333 7.00 7.158 14.312 and Maroar Fee fthedures 0.-II NTQ Annual Fe, 5.000

($000) Bals- Points Fixbd 1i Cumulase NTM Manager & Assail 0 18.50 Based Trustee Fe 1,000 17.50 I1.0 I 1.8" 1.5w0 %6.00 0.0"0 2.63 2.000 I 3o50 0680 3490 2.5W 12.00 0.I75 A. 16" 3.130 9.50 0.75 4.921 9.250 7.00 5,614 10.735 Mtscetteneos§ nod 160,6 01.Bad De4t Rae 121 .0.00% NuclearCoal Escalow [7 4.25%I Revisoro yae" [31 2010 EGS0.. LA Reteil 181 96.3094%t Cost Eafimate YaM (41 2008 TO Fund Federal Tax Ratl 006 After 353 20.00%j Compoasi Effective Tax Rate 153 38.48% End of Fwding Period 12/3I)2030J Entergy GuIf States Onetshifp Share i6t 100.00%Notes: If) Calculated as in the fatlawnlg example: For balance of $1016 TO Management Fees 9.637 8 0.554 -(7,Dbp * (10.00- 4.167))l 310.0.(23 Bad Oebs handsed in Cost of Service Study.(31 First year shOuing impact of revised decoarnmsloning revenue renuiremmnsn 141 Year upon Whtlch the coil estimate is based.(5I Louisiana Income Tra Rate is 8.0%. however. in LouisianM Federal Moore4 taxes ote therefore the effective Louisiana rate is 5.35%. The effective Federa Rate is 33.13% resulting in S Comrposie Rate of 38.48%.160 Cost Estimate provided far Regutated Posion 170%) no EGSL fundung ntresm is 100%.171 Nuclear Cost Encalatof is 4.25%8l3 Per mte 2009 FRP based on 12131,08 rtst Year. Thti it LA Retail Porbon of EGSIL (91 Eflectiv Fed¢srt Tax Rates for Qualified TVustf. These trusts do not pay State tax$s, Attachment 4-D (6 pages)CNO Resolution R-95-1081 in Docket UD-95-1 and IRS Schedule of Ruling Amounts RESOLUTION N-8S- 10611 CfrY HALL: August 8. 1915 BY: COUNCILMEMSERS SINGLETON.

GLAPION, HAZEUR-OISTANCE.

TERRELL. THOMAS AND WILSON RESOLUTION AND ORDER O1RECTING INVEST=11AION OP LOUSIANA POWER AND UGHIT COMPANY*$

I1MP1L) RATES AND CHARGES RATMIV TO ALGIERS AND EITAELISHING COUNCIL DOCKET NO. UQ-95-1 WHEREAS. pursuant to Section 4-1604 at the Home Rule Charter for the City of New Orleans O'Cy*'), the Council of the City of New Orlealn t'Counill has vested in it 8a powers of supervision.

re"tation, and control over the rates at electric, gas. heat, powe ... and otheir pubsic utultlts within the City, including the Now Orleans Public Service- Inc. VNOPWlj- and the Louisiana Power end Ught Company ILP&L): and WHEREAS. in 1986 LP&L applied to the Council for a rate increase related onmaridy to the construction costs associated with its Weterford 3 Nuclear Power Plant and LP&L's 14% share of Grand Gulf Unit No. I. which application was considered In Docket No. M11-I1S1; and WHEREAS. in 1989. during the Pendency of the Council's declion with respect: to LP&L's rate increase apliocation, the Council passed Resolution R-89-03 establishing Docket No. CO-894 to investigate (he allocation and esOrooriate disposition of the proceeds received by LP&L incident to litigation with United Gas P.oeline Coompany I'Unitedl:

and WHEREAS. after considesing all of the evidence in Oockaets No. CO-86-1 and CO-89-I, w,,rrch docket* -ere consoldated for trio purpose of Oroceduraily excediling tine cisposition of trie dockets. Council determined hat LP&L should be sbowed to incraise hte base electric rates apDlicable to customers in Algiers o01 a priase-im balsis provided It amortixzed 3.940.000 dollars of United proceeds allocable to Algiers over the soine period: and WHEREAS, the rate increase was furtlher conditioned on LP&L's agreement to not seek a base rate increase to be affective through May 14, 1994, i.e., rates were to be "cappid*l and WHEREAS, a slmilr rate cap was in place on that portion Ispptoximitsly 98%) of the LP&L system that Is subject to the Jurisdiction of the Louislana Public Service Cornmmission (IPSC'*. which also ended on May 14, 1994; and WHEREAS, In 1994 a rate making investigation was initlted by the LPSC to review the rates and operations of LP&L and hearings were held by the LPSC In March. 1991; and WHEREAS, following the hearings, the LPSC ordered that LP&L's base rates should be reduced by 44111.4 million; and WHEREAS. on July 5. 19"S. LP&L Md rates with the LPSC, which filing wil decrease the electric rates charged by LP'&L, outside Algiers (hereinafter, State levell. which filing implemented

• 34.7 mnllon of an ordered $49.4 miNlion decrease 1*14.7 million is to a temporary restraining order) mandalted by LPSC Orde No, U-20925; and WHEREAS, LP&L's filing of July 19. 1995 with the Council, seeks to decrease the currant Algiers rates to the State level rates as filed by LP&L with the LPSC on July 6, 1995. to expedite implementatIon of reduced rates for the benefit of Algiers customers laddilionallV, LP&L indicates that after issue reoating to the temporary restraining order is resolved, a filing for a revision to the Algiers rates will tbe made at the than resolved State pricing level); and WEI-IERAS, that portion of the LP&L system regulated by tie Council is aoProxtmatety 2%; arn WNHEREAS.

as detailed in rne LP&L filing, the typical summer residential bill for 1,000 kWh will decrease from 678.58 1to $76.78. a decrease of 11ý80, a tipicsl commercial bill for 10 kW and 1,825 kWh vill decrease from $207.88 to 2 e2o2.52. a decresse of 5136. end a typical industrial bil for 1,000 kW and 182.500 kWh will decrefais from $12.988665 to 112,709,40, a decriasil of 6279.21: end WHEREAS. the Council finds it in the Public Interest to establish an expedited schedule to consider the implementatlion of reduced rates for Algiers Ratepayurs; now, thwrefore BE IT RESOLVED BY THE COUNCIL OF THE CITY OF NEW CRJALE" that LP&L's filing tot deceasse of stoelet rates in the 15th Word of the City t*Alglers)j iS accepted for riling by the Council and the rates are hereby adopted and shall be placed into effect by LP&L for bills rendered on or after July 19, 1995.of IT FURTHER RESOLVED that the Council is hereby Initiating in investigation into the reosonableness of LP&L's rates and charges relative to Algiers under Docket No. U0 9W-1 which Docket is hsrebV established.

BE IT FURTHER RESOLVED that the following Procedural Schedule and Rules governing this proceeding are hereby estaebihghed:

August S. 1995 -Discovery commences by the Council's Advisors.August 11, 1991 -Publication of the Public Notice For Intseventionl.

August 21. 1991- Closing Date for the filing of Interventions and aM servIce " be fied In accordance with the Officla Service List established for this proceeding by the City Council Ujllities Regulatory Office.August 28. 1996 -Deadline for opposing Interventions.

Septemoenr

7. 1993 -City Council Action on any oppositions to Interventions.

September 18, 1995. Last Date for submisslon of Olscovery Requests by any party. All Discovery in this Docket is to be considered 15 Day *Rolling Oiscovery' (i.e. All Oiscovery responses are due within 15 days of the receipt of the Rsquest) and al parties are encouraged to commence discovery as soon as possible to expedite the Oiscovery process.Cclober 3, 1995 -Discoverv ClaSS.October 18, 1995 -Submission of statements of position WMim regard to the justness and reasonableness of the then effective rates by all Parties to the proceeding other t(an the Council's advisors.3 Attachment 4-D Exhibit A Page 1 of 5 Entergy Louisiana, LLC Waterford-3 Decommissioning Model Revenue Requirement Summary ($000)Line Total LPSC No Year Company (1) Jurisdiction (2)CNO Jurisdiction (3)1 2010 5,947 5,831 2 2011 5,947 5,831 3 2012 5,947 5,831 4 2013 5,947 5,831 5 2014 5,947 5,831 6 2015 6,821 6,688 7 2016 6,821 6,688 8 2017 6,821 6,688 9 2018 6,821 6,688 10 2019 6,821 6,688 11 2020 7,731 7,580 12 2021 7,731 7,580 13 2022 7,731 7,580 14 2023 7,731 7,580 15 2024 7,731 7,580 16 2025 8,867 8,694 17 2026 8,867 8,694 18 2027 8,867 8,694 19 2028 8,867 8,694 20 2029 8,867 8,694 21 2030 10,246 10,047 116 116 116 116 116 133 133 133 133 133 151 151 151 151 151 173 173.173 173 173 200 Notes: (1) See Exhibit A Page 2.(2) Total Company

• LPSC Production Demand Allocation Factor 98.05%.(3) Total Company -LPSC Jurisdiction.

Entergy Louisiana, LLC Nuclear Decommissioning Payment Schedule As of 11/15/2006 Per Sub.Sec. 468A(b) of the Internal Revenue Code The amount paid into decommisioning funds for any taxable year is limited to the lesser of the amount of nuclear decommissioning costs allocable to this fund which is included in the the taxpayers cost of service for ratemaking purposes for the tax year OR the ruling amounts applicable to this year.Payment Schedule LPSC Council Total 2005 4,231,513

.188,638 4,420,151 07 payment schedute 2006 2,230,896 188,638 2.419,534 2007 2,230,896 188,638 2,419,534

.1/2/2007 604,883.00 2008 2,230,896 188,638 2,419,534 04/02107 604,883.00 2009 2,230,896 188,638 2,419,534 07/02/07 604,884.00 2010 2,566,521 188,638 2,755,159 10/01/07 604,884.00 2011 2,566,521 188,638 2,755,159 2,419,534.00 2012 2,566,521

.188,638 2,755,159 2013 2,566,521 188,638 2,755,159 2014 2,566,521 188,638 2.755,159 2015 2,863,777 188,638 3,052,415 2016 2,863,777 188,638 3,052,415 2017 2,863,777 188,638 3,052,415 2018 2,863,777 188,638 3,052.415 2019 2,863.777 188,638 3,052,415 2020 3,194,524 188,638 3,383,162 2021 3,194,524 188,638 3,383,162 2022 3,194,524 188,638 3,383,162 2023 3,194,524 188,638 3,383,162 2024 3,194,524 188,638 3,383,162 2025 3,315,029 0 3,315,029 2026 3,315,029 0 3,315,029 2027 3,315,029 0 3,315,029 2028 3,315,029 0 3,315,029 2029 3,315.029 0 3,315,029 2030 3.315,029 0 3,315,029 2031 3,315,029 0 3,315,029 2032 3,315,029 0 3,315,029 2033 3,315,029 0 3,315,029 2034 3,315,029 0 3,315,029 2035 3,315,029 0 3,315.029 2036 3,315.029 0 3,315.029 2037 3,315,029 0 3,315,029 2038 3,315,029 0 3,315,029 2039 3,315,029 0 3,315,029 2040 3.315,029 0 3.315,029 2041 3,315.029 0 3,315,029 2042 3,315,029 0 3,315,029 2043 3,315,029 0 3,315,029 2044 3,315,029 0 3,315,029 CNRO-2012-00007 SERIES 5 ATTACHMENTS

5. Minimum Funding Assurance Calculation Worksheets (9 pages)

Attachment 5 Minimum Funding Aissurance Calculation Worksheets Plant name: Arkansas Nuclear One 1 Date of Operation:

Termination of Operations:

Month: 1 5 Day 1 20 Year: 2012 2034 I MWth I 1986$ ECI Base Lx$97,598,400 115.0 1.98 I 1A I Fx I I Ex I I Bx-Vendor 0.22 12.28! L PWR I 2568 r 0.65 j 2.28 r 3,671 I 0.13 r 2.58 I NRC Minimum:$440,854,517 Licensee: Entergy Step 1: Earnings Credit: Trust Fund Balance:$303,928,142

% Owned: Amount of NRC Minimum/Site Specific: 100.00% $440,854,517 Amount in Trust Fund:$303,928,142 I Real Rate of IYears Lefti Return per year2 in Licensel 3.12% 1 "-22.39 1 Total Real Total Earnings: Rate of 1.9892350031

$604,584,498 rotal Earnings = Trust Fund balance x (l+RRR)AYears left in license Step 2: Accumulation:

Value of Annuity per year$0 Real Rate of Return per year 3.12%Yer fAnnuity: Total Annuity:$0 I S Total$Step 2 Total Step 1 + Step 2$604,584,498 Step 3: Decom Period: Total Earnings:$604,584,498 1*IRelRato Reur pr ea Decom Period: 7 Total Real Rate of I Total Earnings for Decorn: 0.1486856681

$44,946,525 ITotal Earnings for Decom = (1/2) x Total Step 4+5 x [(l+RRR)^Decom period -1]]Total = Total Earnings + Accumulation

+ Total Earnings for Decom I-Accumulation during Decon I Total of Steps 1 -3:$649,531,023 I Excess (Shortfall)

$208,676,506 1

Attachment 5 Minimum Funding Assurance Calculation Worksheets Plant name: Date of Operation:

Termination of Operations:

Month: 1 7 Da'1 17 Arkansas Nuclear One 2 y Year: 2012 2038 MWth 1 986$ ECI I Base Lx PWR 3026 $101,628,800 115.0 1.98 Lx Px I Fx I- I I Bx-Ven-or 0.65 2.28 1.790 3.671 0.13 2.58 0.22 12.28 NRC Minimum:$459,059,939 F Licensee:

% Owned: Amount of NRC Minimum/Site Specific: Entergy 100.00% $459,059,939 Amount in Trust Fund:$237,729,232 I Step 1: Earnings Credit: Real Rate ofYears Leftj Total Real Total Earnings Trust Fund Balance: I Return per yearl in Licensel Rate of$237,729,232 3.40% 1 26.54 1 2.42901834

$577,448,664 Total Earnings = Trust Fund balance x (1+RRR)AYears left in license Step 2: Accumulation:

Real Rate of Value of Annuity per year Retum per yearl Years of Annuity:$0 1 3.40% 0 0 Total Annuity:$0 I Total Step 2 0 Total Step 1 + Step 2$577,448,664 Step 3: Decom Period: Real Rate of I Decorn Total Real Total Earnings:

Return per year Period: Rate of I Total Earnings for Decom:$577,448,664 1 2.00% 1 7 10.1486856681

$42,929,170 I Accumulation during Decon I Total of Steps 1 -3:.$620,377,835 iTotal Earnings for Decom = (1/2) x Total Step 4+5 x [(l+RRR)^Decom period -1]ITotal = Total Earnings + Accumulation

+ Total Earnings for Decom IExcess (Shortfall)

$161,317,896 Attachment 5 Minimum Funding Assurance Calculation Worksheets Plant name: Month: 1 Date of Operation:

Day I I Grand Gulf Year: 2012 2024 Termination of Operations:

11 MWth 1986$ ECI Base Lx BWR 3898 [ $135,000,000 115.0 1.98 Lx I Px Fx lo I IBx-Vendor 0.65 2.28 r 1790 3.671 0.13 r 2.66 0.22 12.54 NRC Minimum:$618,840,903 I..Licensee:

% Owned: Amount of NRC Minimum/Site Specific: Entergy 90.00% $556,956,813 Amount in Trust Fund:$423,409,202 I Step 1: Earnings Credit: Real Rate of Years Left Total Real Total Earnings: Trust Fund Balance:.I Return per year in License Rate of$423,409,202 1 2.00% 1 12.83 1 1.2893442

$545,920,199 Total Earnings = Trust Fund balance x (l+RRR)^Years left in license Step 2: Accumulation:

Real Rate of Value of Annuity per year Return per year Years of Annuity: See Annuity Sheet 2.00% 15 Total Annuity:$0 I I I Total Step 2 1$309,565,680 Comes from Annuity Sheet Total Step 1+ Step 2$855,45 79 Step 3: Decom Period: I Real Rate of Decom Total Real Total Earnings:

I Return per year Period: Rate of Total Eamings for Decom:$855,485,879 1 2.00% 7 0.148685668

$63,599,245 ITotal Earnings for Decom = (1/2) x Total Step 4+5 x [(I+RRR)^Decom period -1]I Accumulation during Decon I Total of Steps 1 -3: 1$919,085,124 Total = Total Earnings + Accumulation

+ Total Earnings for Decom Excess (Shortfall)

$362,128,311 Attachment 5 Minimum Funding Assurance Calculation Worksheets Plant name: Grand Gulf Termination of Operations:

2025 Real Total Year Annuity: Rate of Accumulatio 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025$0 2.00% $0$0 2.00% $0$0 2.00% $0$23,785,000 2.00% $30,768,434

$23,785,000 2.00% $30,165,131

$23,785,000 2.00% $29,573,658

$22,285,000 2.00% $27,165,291

$24,550,000 2.00% $29,339,523

$24,550,000 2.00% $28,764,238

$24,550,000 2.00% $28,200,233

$24,550,000 2.00% $27,647,287

$24,550,000 2.00% $27,105,184

$29,878,000 2.00% $32,340,908

$17,429,000 2.00% $18,495,794

$0 2.00% $0$0 2.00% $0$0 2.00% $0 Total Accumulation

= Annuity x (1+RRR)^Years left from Accum Total: $309,565,680 Attachment 5 Minimum Funding Assurance Calculation Worksheets Plant name: River Bend Station (Regulated 70%)Year of Biennial: Termination of Operation:

Month 1 8 Day 1 29 Year 2012 2025 IWMWth 1 1986$1 1 B3WR I3091 si~$3i,19,8 00 ECI 115,0 Base Lx 1.98 I Lx 0.65 2.28 PXl 1.790 01 1 0.13 r Ex Bx-e1nd. o 2.66 0.22 12.54/NRC Minimum:$604,259,178 F F Licensee: Entergy Step 1: Earnings Credit: Trust Fund Balance:$192,264,458

% Owned: 70.00%Amount of NRC Minimum/Site Specific:$422,981,425 Amount in Trust Fund:$192,264,458 I Real Rate of Years Left Return per in License 2.0% 13.66 Total Real Total Rate of Earnings: 1.31063 $251,986,774 ITotal Earnings = Trust Fund balance x (l+RRR)^Years left in license Step 2: Accumulation:

Value of Annuity per year See Annuity Sheet 4 Real Rate of Return per 20%Years of Annuity: 15 Total Annuity:$0 Total Step 2 d$182,481,679 Comes from Annuity Sheet Total Step 1 + Step 2$434,46845 F Step 3: Decom Period: Total Eamings:$434,468,453 I.Real Rate of Return per 20%Decomr Total Real Total Earnings for Period: Rate of Decom: 7 0.14869 $32,299,616 ITotal Earnings for Decom = (1/2) x Total Step 4+5 x [(l+RRR)ADecom period -1]Accumulation during Decon$78,456,000 Total of Steps 1 -3:$545,224,069 Total =,Total Earnings + Accumulation

+ Total Earnings for Decom I Excess (Shortfall)

$122,242,6441 Attachment 5 Minimum Funding Assurance Calculation Worksheets Plant name: River Bend Station (Regulated 70%)Termination of Operations:

2025 Year LPSC PUCT FERC Annuity: 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025$ -$ -$ -$7,843,000

$7,843,000

$7,843,000

$8,996,000

$8,996,000

$8,995,000

$8,995,000

$8,996,000

$10,195,000

$10,195,000

$10,195,000

$10,195,000

$10,195,000

$11,693,000

$ 2 $1,$ 2 $1,$ 2 $$2,019,000

$113,000$2,019,000

$113,000$2,019,000

$113,000$2,019,000

$113,000$2,019,000

$113,000$2,019,000

$113,000$2,019,000

$113,000$2,019,000

$113,000$2,019,000

$113,000$2,019,000

$113,000$2,019,000

$113,000$2,019,000

$113,000$2,019,000

$113,000$2,019,000

$165,000$$$$9,975,000

$9,975,000

$9,975,000

$11,128,000

$11,128,000

$11,127,000

$11,127,000

$11,128,000

$12,327,000

$12,327,000

$12,327,000

$12,327,000

$12,327,000

$13,877,000

$13,712,000

$13,712,000

$13,712,000

$13,712,000

$15,532,000

$2,019,000

$2,019,000

$2,019,000

$2,019,000 Real Total Rate of Accumulation 2.0% $0 2.0% $0 2.0% $12,903,726 2.0% $12,650,712 2.0% $12,402,659 2.0% $13,564,970 2.0% $13,298,990 2.0% $13,037,054 2.0% $12,781,425 2.0% $12,531,935 2.0% $13,610,004 2.0% $13,343,141 2.0% $13,081,511 2.0% $12,825,011 2.0% $12,573,540 2.0% $13,877,000 Total: $182,481,679

$13,712,000

$13,712,000

$13,712,000

$13,712,000

$15,532,000

$2,019,000

$2,019,000

$2,019,000

$2,019,000 Total: $78,456,000 Total Accumulation

= Annuity x (l+RRR)^Years left from Accum Accumulation During Decomm Period 2026 $11,693,000

$2,019,000 2027 $11,693,000

$2,019,000 2028 $11,693,000

$2,019,000 2029 $11,693,000

$2,019,000 2030 $13,513,000

$2,019,000 2031 $0 $2,019,000 2032 $0 $2,019,000 2033 $0 $2,019,000 2034 $0 $2,019,000

$0$0$0$0$0$0$0$0$0 Attachment 5 Minimum Funding Assurance Calculation Worksheets Plant name: River Bend Station (Regulated 30%)Month Day Year Year of Biennial:

1 1 2012 Termination of Operation:

8 29 2025 I~t 1~l x 196 lo ae xd BWR 3091 [S131.819,000 115.0 1 .98 0.65 2.28 1.790 3.671 0.13 2.66 0.22 12.54 NRC Minimum: $604,259,178 Amount of NRC Minimum/Site Licensee:

%Owned: Specific:

Amount in Trust Fu"nd: Entergy 30.00% $181,277,753

$228,652,703 I Step 1: Earnings Credit: Real Rate of IYears Leftl Total Real I Total I utFund Balance: Return per lin LicenseI Rate of Earnings: Trus$228,652,703 2.0% 1 13.66 1 1.31063 $299,678,150 Total Earnings=

Trust Fund balance x (1+RRR)^Years left in license Step 2: Accumulation:

Real Rate ofI Value of Annuity per year Return per Years of Annuity: Total Annuity:$0 2.0% 0 $0 Total Step 2$0 Total Step 1 + Step 2$299,678,150 Step 3: Decom Period: Real Rate of IDecorn ITotal Real Total Earnings for Total Earnings:

Return per Period: Rate of Decorn:$299,678,150 2.0% 7 0.14869 $22,278,923 Total Earnings for Decom = (1/2) x Total Step 4+5 x [(l+RRR)^Decom period -1]Total of Steps 1 -3: 1$321,957,073 ITotal = Total Earnings + Accumulation

+ Total Earnings for Decom Excess (Shortfall)

$140,679,319 Attachment 5 Minimum Funding Assurance Calculation Worksheets Plant name: Date of Operation:

Termination of Operations:

Month: 1 12 Waterford Generating Station, Unit 3 Day Year: 1 2012 18 2024 I MWth 1986$ ECI Base Lx PWR 3716 [$105,000,000 115.0 1.98 I L Px Fx I- I Bx-Vendo-r 0.65 2.28 1.790 3.671 0.13 2.58 0.22 12.28 NRC Minimum:$474,287,737 Licensee: Entergy Step 1: Earnings Credit: Trust Fund Balance:$253,967,667

%Owned: Amount of NRC Minimum/Site Specifi 100.00% $474,287,737 4 Amount in Trust Fund:$253,967,667 I Real Rate Years Left Total Real ITotal Earnings: Return per year in License Rate of 2.00% 1 12.96 1.292665351

$328,295,203 Total Earnings=

Trust Fund balance x (1+RRR)AYears left in license Step 2: Accumulation:

Value of Annuity Ier year See Annuity Sheet Real Rate of Return per year Years of Annuity: 2.00% 14 Total Annuity:$0 I Total Step 2 1$104,449,541 Comes from Annuity Sheet Total Step 1 + Step 2$432,744,744 Step 3: Decorn Period: Real Rateof Decom Total Real Total Earnings:

Return per year Period: Rate of Total Earnings for Decom:$432,744,744 2.00% 7 0.148685668

$32,171,471 I ITotal Earnings for Decom = (112) x Total Step 4+5 x [(l+RRR)^Decom period -1]I Accumulation during Decon$53,517,000 Toalof Steps 1- 3 Total = Total Earnings + Accumulation

+ Total Earnings for Decom I Excess (Shortfall)

$44,145,478 Attachment 5 Minimum Funding Assurance Calculation Worksheets Plant name: Waterford Generating Station, Unit 3 Termination of Operations:

2025 Real Year LPSC CNO Annuity: Rate of Tota I Accumulation

$0 Total Accumulation

= Annuity x (l+RRR)AYears left from 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024$0$0$0$5,831,000

$5,831,000

$5,831,000

$6,688,000

$6,688,000

$6,688,000

$6,688,000

$6,688,000

$7,580,000

$7,580,000

$7,580,000

$7,580,000

$7,580,000

$0$0$0$189,000$189,000$189,000$189,000$189,000$189,000$189,000$189,000$189,000$189,000$189,000$189,000$189,000$0$0$0$6,020,000

$6,020,000

$6,020,000

$6,877,000

$6,877,000

$6,877,000

$6,877,000

$6,877,000

$7,769,000

$7,769,000

$7,769,000

$7,769,000

$7,769,000 2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%$0$0$7,787,512

$7,634,816

$7,485,113

$8,383,025

$8,218,652

$8,057,502

$7,899,511

$7,744,619

$8,577,604

$8,409,415

$8,244,525

$8,082,868

$7,924,380 Accum Total: $104,449,541 Accumulation During Decomm Period 2025 $8,694,000

$0 $8,694,000 2026 $8,694,000

$0 $8,694,000 2027 $8,694,000

$0 $8,694,000 2028 $8,694,000

$0 $8,694,000 2029 $8,694,000

$0 $8,694,000 2030 $10,047,000

$0 $10,047,000 2031 0 $0 $0 Total: $53,517,000