CNRO-2015-00011, Grand Gulf Nuclear Station Unit 1 and Waterford 3 Steam Electric Station Submittal of Decommssioning Funding Status Report for 2014

Grand Gulf Nuclear Station Unit 1 and Waterford 3 Steam Electric Station Submittal of Decommssioning Funding Status Report for 2014

ML15092A183
Person / Time
Site:	Grand Gulf, Arkansas Nuclear, River Bend, Waterford
Issue date:	03/27/2015
From:	Mccann J Entergy Operations
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CNRO-2015-00011
Download: ML15092A183 (226)

Text

{{#Wiki_filter:Entergy Operations, Inc ,Entergy 440 Hamilton Avenue White Plains, NY 10601 Tel 914 272 3370 John F. McCann Vice President - Nuclear Safety, Emergency Planning and Licensing CNRO-2015-00011 March 27, 2015 U.S. Nuclear Regulatory Commission Attn: Document Control Desk 11555 Rockville Pike Rockville, MD 20852-2738

SUBJECT:

Decommissioning Funding Status Report - Enteray Operations, Inc Arkansas Nuclear One, Units 1 & 2 River Bend Station Dockets 50-313 & 50-368 Docket 50-458 Grand Gulf Nuclear Station Waterford 3 Steam Electric Station Docket 50-416 Docket 50-382

References:

1. NUREG-1307, "Report on Waste Burial Charges," Revision 15, dated January 2013.

2. NRC Regulatory Issue Summary 2001-07, "10 CFR 50.75(f)(1) Reports on the Status of Decommissioning Funds (Due March 31, 2001)."

3. NRC Regulatory Issue Summary 2014-12, "Decommissioning Fund Status Report Calculations."

Dear Sir or Madam:

10 CFR 50.75(f)(1) requires each power reactor licensee to report to the NRC by March 31, 1999, and every two years thereafter, on the status of its decommissioning funding for each reactor, or share of a reactor, that it owns. On behalf of Entergy Arkansas, Inc. for Arkansas Nuclear One (ANO), System Entergy Resources, Inc. (SERI) and South Mississippi Electric Power Association (SMEPA) for Grand Gulf Nuclear Station (GGNS), Entergy Gulf States Louisiana, 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 for power reactors operated by Entergy Operations, Inc. The estimated minimum decommissioning fund values were determined using the NRC's methodology in NUREG-1307 Rev 15. Pursuant to NRC Regulatory Issue Summary 2014-12, Entergy Operations, Inc. understands that the NRC has directed licensees to use NUREG-1307 Rev. 15 for this filing. 1400( gib?-

CNRO-2015-00011 Page 2 of 5 The 70 percent regulated interest of RBS contains funds accumulated for separate rate regulatory jurisdictions. There are not separate trust funds for the individual jurisdictions responsible for decommissioning of the 70 percent regulated share of RBS. Balances in the nuclear decommissioning trust for the 70 percent regulated share of RBS attributable to the separate jurisdictions are accounted for by the Trustee, the Bank of New York Mellon. The following information provides the balances in the 70 percent regulated share trust attributable to each of the relevant jurisdictions as of December 31, 2014: Louisiana $120,969,107 Texas $174,851,163 FERC $ 9,130,481 The trust fund amounts reported for each facility in the responses to item 3 represent the market value of decommissioning trust funds as of December 31, 2014 net of any material current income tax liability on realized gains, interest, dividends and other income of the trusts. SMEPA is a not-for-profit electric cooperative, and is exempt from federal income tax. Accordingly, the amounts reported as of December 31, 2014 of funds separately accumulated by SMEPA for GGNS decommissioning were after-tax amounts. The trusts for the following plants had balances on their 2014 tax liabilities, not reflected in the trust fund balances, as follows (does not include SMEPA): ANO $ 0 GGNS $ 0 RBS $8,000 WF3 $ 0 In accordance with guidance provided by the NRC Staff in April 2014 requests for additional information (Accession No. ML14120A273) that "[fluture 10 CFR 50.75(f) reports should clearly delineate estimate reactor and ISFSI decommissioning costs," the information in Attachments 1-4 includes line item 2 identifying the ISFSI decommissioning obligation, escalated from the most recent 10 CFR 72.30 filing. This obligation is also accounted for in the Excess/Shortfall calculations for each plant in Attachment 5. The information provided in Attachments 1-4 is based on NRC Regulatory Issue Summary 2001-07. Consistent with your letter dated March 11,2011 (Accession No. ML110280410), we are providing with this submittal 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. Considering these agreements and the applicable NRC regulations, Entergy respectfully asserts that these rate-making tariffs should not be viewed as "contractual obligations" as that term is used within 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 the responses to item 6 further explain the relationships between the current ratepayer decommissioning funding assurance mechanisms and these system instruments.

CNRO-2015-00011 Page 3 of 5 Additionally, Attachment 5 includes Minimum Funding Assurance calculation worksheets (derived from LIC-205 Revision 4) for the plants, provided for the convenience of the reviewer. The aforementioned worksheets, using the December 31, 2014 trust fund balances, indicate that all of the plants covered by this submittal met or exceeded the NRC's funding requirements. This submittal contains no new commitments. Please address any comments or questions regarding this matter to Mr. Bryan Ford, Senior Manager, Fleet Regulatory Assurance at 601-368-5516. SF/ly,

    / BSF /LUS cc: next page

CNRO-2015-00011 Page 4 of 5 cc: Mr. J. A. Aluise (ENT) Mr. J. S. Forbes (ECH) Mr. B. F. Ford (ECH) Mr. L. Jager Smith (ECH) Mr. J. Browning (ANO) Mr. K. Mulligan (GGN) Mr. E. W. Olson (RBS) Mr. M. Chisum (WF3) USNRC Regional Administrator, Region IV USNRC Project Manager, ANO USNRC Project Manager, GGN USNRC Project Manager, RBS USNRC Project Manager, WF3 USNRC Resident Inspector, ANO USNRC Resident Inspector, GGN USNRC Resident Inspector, RBS USNRC Resident Inspector, WF3 Arkansas Department of Health Mississippi Department of Health Louisiana Department of Environmental Quality

CNRO-2015-00011 Page 5 of 5 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 No. 61 (6 pages) 1-C APSC Order in Docket No. 87-166-TF, Order No. 62 (3 pages) 1-D ANO Decommissioning Cost Rider NDCR Update (8 pages) 1-E Entergy Arkansas, Inc. Unit Power Purchase Agreements under Service Schedule MSS-4 (14 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 Resolution to Amend Rate of Earnings on Decommissioning Trust (1 pages) 2-D FERC Order in Docket No. ER95-1042 and Availability Agreement (38 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 (19 pages) 3-E PUCT Order in Docket No. 39896 (49 pages) 3-F FERC Order in Docket Nos. ER86-558-002 (8 pages) 3-G MSS-4 Agreement and FERC's Acceptance (12 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 (19 pages) 4-D CNO Resolution R-95-1081 in Docket UD-95-1 and IRS Schedule of Ruling Amounts (6 pages) 4-E CNO Resolution R-14-494 in Docket UD-13-01 (4 pages)

5. Minimum Funding Assurance Calculation Worksheets (10 pages)

Attachment 1 (Page 1 of 2) ENTERGY ARKANSAS, INC. Status Report of Decommissioning Funding For Year Ending December 31, 2014 - 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) (2014$): $480.5 million1

2. ISFSI Obligation as of 12/31/14 $1.97 million

3. Decommissioning Trust Fund Total As of 12/31/14: $429.5 million

                                                                            $W2

4. Annual amounts remaining to be collected:

5. Assumptions used:

Rate of Escalation of Decommissioning Costs: Approx. 3.24%3 Rate of Earnings on Decommissioning Funds: Approx. 5.59%3 Authority for use of Real Earnings Over 2%: APSC Order3

6. Contracts upon which licensee is relying 4 For Decommissioning Funding: See footnote

7. Modifications to Method of Financial Assurance since Last Report: None

8. Material Changes to Trust Agreements: None 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. 61 & 62 -See Attachments 1-B, i-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 (Page 2 of 2) ENTERGY ARKANSAS, INC. Status Report of Decommissioning Funding For Year Ending December 31, 2014 - 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) (2012$): $500.3 million 1

2. ISFSI Obligation as of 12/31/14 $1.97 million

3. Decommissioning Fund Total As of 12/31/12: $340.4 million

4. Annual amounts remaining to be collected: $W2

5. Assumptions used:

Rate of Escalation of Decommissioning Costs: Approx. 3.24%3 Rate of Earnings on Decommissioning Funds: Approx. 5.94% 3 Authority for use of Real Earnings Over 2%: APSC Order 3 4

6. Contracts upon which licensee is relying See footnote For Decommissioning Funding:

7. Modifications to Method of Financial Assurance since Last Report: None

8. Material Changes to Trust Agreements: 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 7/2038. 4 Approved in APSC Docket No. 87-166-TF, Order Nos. 61 & 62, 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-A (Page 1 of 1) ENTERGY ARKANSAS, INC. Calculation of Minimum Amount For Year Ending December 31, 2014 - 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 IOCFR50.75(c)(2) Escalation Factor Formula: 0.65(L) +0.13(E) +0.22(B) Factor L=Labor (South) 2.43' E=Energy (PWR) 2.222 B=Waste Burial-Vendor (PWR) 13.8853 PWR Escalation Factor: 0.65(L) +0.13(E) +0.22(B)= 4.92276 1986 PWR Base Year $ Escalated: ANOI: $97,598,400

• Factor= $480,453,236 ANO2: $101,628,800
• Factor= $500,293,91,7 1

Bureau of Labor Statistics, Series Report ID: CIU2010000000220i (4 " Quarter 2014) 2 Bureau of Labor Statistics, Series Report ID: wpu0543 and wpu0573 (December 2014) 3 Nuclear Regulatory Commission: NUREG-1307 Revision 15, Table 2.1 (2012)

Attachment 1-B (Page 1 of 7) APSC Order in Docket No. 87-166-TF, Order No. 61

APSC FILED Time: 11/10/2014 8:52:09 AM: Recvd 11/10/2014 8:52:06 AM: Docket 87-166-tf-Doc. 289 ARKANSAS PUBLIC SERVICE COMMISSION IN THE MATTER OF ARKANSAS POWER & ) LIGHT COMPANY'S PROPOSED NUCLEAR ) DOCKET NO. 87-166-TF DECOMMISSIONING COST RIDER M26 AND ) ORDER NO. 61 PROPOSED DEPRECIATION RATE ) REDUCTION RIDER M41. ) ORDER On March 31, 2014, Entergy Arkansas, Inc. (EAI) filed a motion and supporting testimony with the Arkansas Public Service Commission (Commission) seeking approval of its revised estimate of costs for the eventual decommissioning of Arkansas Nuclear One (ANO) Units 1 and 2 (Motion). EAM filed its Motion in accordance with Order No. 5 in this Docket, dated March 9, 1998, which provided that every five years EAI should submit an updated estimate of ANO decommissioning costs. In Order No. 50, entered on October 13, 2009, the Commission approved a stipulation among the parties adopting a cost estimate of $1.o498 billion, excluding spent fuel costs, and ordered that EAI's next estimate should be filed by March 31, 2014. EM_'s current Motion seeks approval of a revised estimate of $1.344 billion, excluding spent fuel costs. Motion at 2. EAI's cost estimate is used to determine the revenue requirement for its Nuclear Decommissioning Cost Recovery Rider (Rider NDCR). Order No. 27 at 12. Revenues from Rider NDCR are directed to an external trust fund established to ensure that EAI will have funds available to decommission ANO 1 and 2 after they cease operation. Order No. 5 at 2-3. In Order No. 32, dated October 3, 200o, the Commission found that EAI's accumulated trust fund balances, with anticipated investment earnings, appeared adequate and that, beginning on January 1, 2001, EA's revenue requirement for Rider

APSC FILED Time: 11/10/2014 8:52:09 AM: Recvd 11/10/2014 8:52:06 AM: fo6VfY*_0idgTF Order No. 61 Page 2 of 6 NDCR should be set at zero. Order No. 32 at 17. The Rider NDCR revenue requirement has remained at zero since January 2oo0. Order No. 57 at 3. In the current proceeding BAI filed the Direct Testimony of William A. Cloutier, Jr., the General Staff of the Commission (Staff) filed the Direct Testimony of Kim 0. Davis, and EAI filed the Rebuttal Testimony of Mr. Cloutier. No public comments were filed and no other party moved to intervene. Pursuant to a joint motion of EAI and Staff, the Commission entered Order No. 59 waiving additional testimony and canceling the hearing in this matter. Accordingly, EAI's Motion will be decided upon the written record compiled by the parties. Testimony of the Parties. William A. Cloutier, Jr., Manager of Decommissioning Services for TLG Services, Inc. (TLG), a subsidiary of EArs parent Entergy Corporation (Entergy), testifies that EAI's 2014 estimate uses the inventory of plant and equipment developed for EAI's 2009 filing updated to reflect intervening changes. Cloutier Direct at 8. In addition, the 2014 estimate uses labor and salary data provided by EAI's affiliate Entergy Operations, Inc. (EOI), and uses current EOI contract rates to estimate the costs of contracting for the processing and disposal of low level radioactive waste materials. Id. at 9. Mr. Cloutier testifies that TLG prepared estimates of the ANO 1 and 2 decommissioning costs using three alternative methods authorized by the Nuclear Regulatory Commission: DECON (prompt removal and decontamination of equipment, structures, and facilities containing radioactive contaminants at the cessation of normal plant operations), SAFSTOR (mothballing the nuclear facility for approximately 5o years before decontamination), and ENTOMB (encasing radioactive components in a

APSC FILED Time: 11/10/2014 8:52:09 AM: Recvd 11/10/2014 8:52:06 AM: ockt17e66-thDoc. 9 Order No. 61 Page 3 of 6 material such as concrete and storing them for up to 6o years). General Requirements for Decommissioning Nuclear Facilities, June 1988, 53 Fed. Reg. 24o18.1 Cloutier Direct at 9. Because ANO Units 1 and 2 share the same infrastructure, Mr. Cloutier testifies that it would not be practical to decommission one of the units while the other continues to operate. Thus, TLG's estimates assume coordinated decommissioning of both units, including dismantling, removal of contaminated materials, and grading of the site for future use. Id. at 13. According to Mr. Cloutier, TLG's 2014 decommissioning cost estimates, including disposing of spent fuel, are $1.676 billion using the DECON method, $1.876 billion using the SAFSTOR method, and $1.886 billion using the ENTOMB method. Id. at 21. Each estimate includes contingencies for delays and increased costs. Id. at 27. Mr. Cloutier testifies that changes from the 2oo9 estimate include: increased labor costs, increased costs for managing spent fuel, increased costs to contract with outside vendors for disposal of low level radioactive waste materials, and increased management, security, administration, and general costs. Id. at 22-25. Mr. Cloutier recommends that the Commission approve EAI's use of the DECON method for estimating decommissioning costs. The 2014 DECON estimate is $4. 3 4 4 , assuming spent fuel costs are excluded in accordance with Order No. 50. The DECON method is cheaper overall and avoids the long-term maintenance, security, and other costs associated with the SAFSTOR and ENTOMB methods. Mr. Cloutier also notes that dismantling and decontamination immediately upon cessation of commercial 'Although the ENTOMB method is authorized by the NRC, Mr. Cloutier testifies that method has limited practical application for a commercial nuclear reactor. Thus, TLG prepared only a conceptual estimate using the ENTOMB method but prepared more rigorous estimates for the DECON and SAFSTOR methods. Cloutier Direct at lo.

APSC FILED Time: 11/10/2014 8:52:09 AM: Recvd 11/10/2014 8:52:06 AM: ock 71,6-t Doi.-9? Order No. 61 Page 4 of 6 operations at the ANO Units would permit EAI to take advantage of available ANO operating staff still on the premises and would also allow EAI to use cranes, waste-processing equipment, and other machinery already on site. The DECON approach would also permit the site to be more quickly made available for another use. Id. at 35. Staff witness Kim 0. Davis testifies that the overall rise in EAI's 2014 cost estimate includes: increased labor costs; increased costs of managing spent fuels until United States Department of Energy disposal programs are implemented; increased vendor costs for off-site disposal of low-level radioactive waste; increased management costs; significantly increased site security costs due to changed NRC requirements; and increased administration and general expenses. Davis Direct at 8-9. Mr. Davis also testifies that, even with the increase in the cost estimate, EAI's nuclear decommissioning trust fund balance is projected to be adequate to cover anticipated decommissioning costs with Rider NDCR set at zero. Id. at 6-7. Mr. Davis recommends approval of EAI's DECON estimate of $1.344 billion for use in EAI's Rider NDCR filings in 2014 through 2018. Mr. Davis also recommends that the Commission impose certain conditions for future EAI filings in this Docket to assist the Commission in analyzing EAI's cost estimates and in determining the continuing adequacy of the trust fund. Id. at 12-14. In his rebuttal testimony, Mr. Cloutier responds that EAI can generally accept Mr. Davis's recommendations for future filings. Cloutier Rebuttal at 3-8. Commission Decision. Based upon EAI's Motion, the testimony of the witnesses, and review and analysis of the entire record, the Commission approves EAI's updated five-year estimate

APSC FILED Time: 11/1012014 8:52:09 AM: Recvd 11/10/2014 8:52:06 AM: ROL Order No. 61 Page 5 of 6 of the costs of eventual decommissioning of ANO Units 1 and 2 as filed on March 31, 2014. The Commission finds that it is reasonable for EAI to use the DECON method in calculating its estimated costs and that EAY's 2014 estimate is reasonable in all the circumstances. The Commission also finds that the recommendations of Staff Witness Rim 0. Davis should be approved to the extent set forth below. Accordingly, the Commission hereby finds and orders as follows: Wi) EAI's 2014 cost estimate of $1.344 billion, excluding spent fuel costs, is approved for use in BAI's Rider NDCR filings in years 2014 through 2018; (2) EAI's next five-year cost estimate shall be filed by March 31, 2019; (3) EAI shall file in this Docket within thirty days a copy of any NRC filing by EAI or an affiliate relating to ANO decommissioning; (4) In future five-year cost filings EAI shall provide a thorough explanation for any increase (among the 18 cost elements contained in the table on page xix of EAI Exhibit WAC-5) greater than the average annual inflation rate as measured by the Consumer Price Index for all Urban Consumers (CPI-U) over the same five-year period; (5) In future five-year cost filings EAI shall include the best available information comparing its cost estimates with actual decommissioning costs for United States nuclear plants that are already out of service; (6) EAI shall continue to monitor increases in estimated decommissioning costs and shall provide in its annual ANO Rider NDCR filings information

APSC FILED Time: 11/10/2014 8:52:09 AM: Recvd 11/10/2014 8:52:06 AM: Docket 87-166-tf-Doc. 289 Docket No. 87-166-TF Order No. 61 Page 6 of 6 regarding industry and site-specific factors that may cause costs to escalate at rates greater than the CPI-U; and (7) In its 2019 cost filing EAI shall include a recommendation, based on the best information available at the time, whether to discontinue evaluating the ENTOMB method in filings for 2024 and thereafter. BY ORDER OF THE COMMISSION, This j__7day of November, 2014. Colette D. Honorable, Chairman I hereby certify that this order, Issued by the Arkansas Public Service Commission, has been served on all parties of record on this date by the following method-

.- U.S. mail with postage prepaid using the mailing address of each party as                                                     a.

Indicated inthe official docket file, or

,.._.ectronlo mail using the emall address                          Olan W. Reeves, Commissioner of each party as Indicated Inthe official docket file.

Elana C. Wills, Commissioner ei ap ngton, Se ~tary of the Comm'issi

Attachment 1-C (Page 1 of 4) APSC Order in Docket No. 87-166-TF, Order No. 62

APSC FILED Time: 12/30/2014 1:01:25 PM: Recvd 12/30/2014 1:01:14 PM: Docket 87-166-tf-Doc. 293 ARKANSAS PUBLIC SERVICE COMMISSION IN THE MATTER OF ARKANSAS POWER & ) LIGHT COMPANY'S PROPOSED-NUCLEAR ) DOCKET NO. 87-166-TF DECOMMISSIONING COST RIDER M26 AND ) ORDER NO. 62 PROPOSED DEPRECIATION RATE ) REDUCTION RIDER M41. ) ORDER On November io, 2014, Entergy Arkansas, Inc. (EAI) filed an application and supporting testimony with the Arkansas Public Service Commission (Commission) seeking approval of the annual update to its Arkansas Nuclear One Decommissioning Cost Rider (Rider NDCR). Revenues from Rider NDCR flow to external trust funds to ensure that EAI will have sufficient resources available to decommission Arkansas Nuclear One (ANO) Units 1 and 2 after they cease operation. Order No. 5 at 2-3. Any excess trust fund balances not needed for decommissioning will be refunded to ratepayers. Order Nos. 27 and 29. In Order No. 32, dated October 3, 2000, the Commission found that EAI's accumulated trust fund balances, with anticipated investment earnings, appeared adequate to cover decommissioning costs and that, beginning on January 1, 2OOl, EAI's revenue requirement and rate for Rider NDCR should be set at zero. Order No. 32 at 17. The Rider NDCR revenue requirement and rate have remained at zero since January 2001. Order No. 57 at 3. In the current proceedings EAI submitted: (1) a revised Attachment A to Rider NDCR reflecting its decommissioning rate for 2015; (2) the associated decommissioning revenue requirement summary; and (3) a summary of the trust fund balances for ANO 1 and 2. EAI's filing proposed that the Rider NDCR revenue requirement and rate remain at zero for 2015.

APSC FILED Time: 12/30/2014 1:01:25 PM: Recvd 12/30/2014 1:01:14 PM: Docket 87-166-tf-Doc. 293 Docket No. 87-166-TF Order No. 62 Page 2 of 3 In support of its application EAI filed the testimony of Ina P. Laney and the General Staff of the Commission (Staff) filed the testimony of Kim 0. Davis. No public comments were filed and no other party moved to intervene. Testimony of the Parties. Ina P. Laney, Regulatory Project Coordinator for EAI, testifies that Rider NDCR is an exact recovery rider, which recovers a levelized, inflation-adjusted revenue requirement sufficient to fund the decommissioning trusts for ANO 1 and 2. Laney at 4-

5. The requested decommissioning revenue requirement for 2015 is zero, because the trust fund balances are currently projected to exceed the estimated decommissioning costs. Id. at 5. Under Rider NDCR as previously approved, decommissioning costs are assumed to increase at a rate equal to the Consumer Price Index - Urban (CPI). Ms.

Laney testifies that EAI is not aware of data or factors suggesting that decommissioning costs will rise at a rate faster than the CPI. Id. at 6. EAI proposes that both the revenue requirement and the rate for Rider NDCR remain at zero. Id. Staff witness Kim 0. Davis, Director of the Financial Analysis Section of the General Staff, testifies that he has analyzed EAI's application and supporting work papers. He states that, according to the data presented by EAI, the trust funds will be adequate to cover the anticipated costs of decommissioning ANO Units 1 and 2 after the end of their useful lives without any further contributions from ratepayers. Davis at 5. Mr. Davis recommends that the Commission approve EAI's proposal that the Rider NDCR revenue requirement and rate be set at zero for 2015. Id. at 6.

APSC FILED Time: 12/30/2014 1:01:25 PM: Recvd 12/30/2014 1:01:14 PM: Docket 87-166-tf-Doc. 293 Docket No. 87-166-TF Order No. 62 Page 3 of 3

                                                ..Commission Decision.

Based upon EAI's filing, the testimony of the witnesses, and review and analysis of the entire record, the Commission approves EAI's update of Rider as filed on November 10, 2014 as consistent with the public interest. The Commission finds that based on the available data it appears. that the trust fund balances will be adequate to cover the costs of the eventual decommissioning of ANO Units 1 and 2 and that, accordingly, it is reasonable for the revenue requirement and rate for Rider NDCR to continue to be set at zero for 2015. BY ORDER OF THE COMMISSION, This 3*0day of December, 2014. I hereby certify that this order, issued by the Colette D. Honorable, Chairman Arkansas Public Service Commission, has been served on all parties:of record on this date by the following method'

         - U.S. mail with postage prepaid using the mailing address of each party as indicated in the official docket file, or, Olan W. Reeves, Commissioner

_(Electronic mall using the email address of each party as indicated in the official Elana C. Wills, Commissioner Michael Sappington, Secetary of-Je Commission

Attachment 1-D (Page 1 of 8) ANO Decommissioning Cost Rider NDCR Update

APSC FILED Time: 11/10/2014 1:57:01 PM: Recvd 11/10/2014 1:56:00 PM: Docket 8 Avs, Inc. 4,01ves~t~apoiAvenue -- nLittle P. O. Box 551 Rock, AR 72203-0551 Tel 501 377 5876 Fax 501 377 4415 Laura Landreaux Vice President Regulatory Affairs November 10, 2014 Mr. Michael Sappington, Secretary Arkansas Public Service Commission P. 0. Box 400 Little Rock, AR 72203-0400 Re: APSC Docket No. 87-166-TF ANO Decommissioning Cost Rider NDCR Update

Dear Mr. Sappington:

In accordance with the requirements of ANO Decommissioning Cost Rider NDCR (Rider NDCR) and the Arkansas Public Service Commission's Order Nos. 5, 27, 32, 41, 45, 46, 50 and 61 in Docket No. 87-166-TF, please find attached for filing with the Commission the following: Attachment 1 Revised Attachment A to Rider NDCR containing decommissioning rate adjustments that are to be effective for the billing months from January 2015 through December 2015, the supporting Revenue Requirement Summary page of the decommissioning model, and a summary of the decommissioning fund balances reflecting a 20-year life extension for both ANO units. (Scenario 2 Order No. 41). Supplemental Testimony and Exhibits of Ina P. Laney in support of the Company's Rider NDCR Update. EAI did not include in this annual update the Scenario 1 analysis, previously provided as Attachment 2, pursuant to Order No. 45 issued in this Docket on December 20, 2006. Order No. 45 approved the Company's request to eliminate the Scenario 1 analysis and to provide only Attachment 1 in future annual updates unless the Attachment 1 analysis results in other than a zero revenue requirement. The revenue requirement and rate will remain at the zero level for 2015. In accordance with the Stipulation approved in Order No. 61 on November 10, 2014, this annual update to Rider NDCR incorporates the approved nuclear

Mr. Michael sý i tP Time: 11/10/2014 1:57:01 PM: Recvd 11/10/2014 1:56:00 PM: Docket 87-166-tf-Doc. 290 November 10, 2014 Page 2 decommissioning cost estimate of $1,344.2 million excluding Spent Fuel costs, and the annual CPI-U as the escalation rate. EAI submits the Supplemental Testimony of Ina P. Laney in support of the Company's Rider NDCR update. An electronic copy of this filing, with the above-listed attachments and testimony, is being served upon all parties of record to this docket. Copies of workpapers supporting the calculation of the revised Attachment A to Rider NDCR have been provided to the General Staff and will be provided to any other interested party upon request. Should you have any questions concerning this filing, please call me at (501) 377-5876 or Jeff McGee at (501) 377-3976. Sincerely,

   /s/ Laura Landreaux Laura Landreaux Vice President, EAI Regulatory Affairs Attachments c:             All Parties of Record

APSC FILED Time: 11/10/2014 1:57:01 PM: Recvd 11/10/2014 1:56:00 PM:,ftlqeW1f-Doc. 290 Docket No. 87-166-TF Page 1 of 3 Order No.: Effective: January 2015 Attachment A to Rate Schedule No. 37 Page 1 of 1 Schedule Sheet 1 of 1 ATTACHMENT A The Net Monthly Rates set forth in EAI's schedules identified below will be increased by the following Rate Adjustments amounts during the billing months of January 2015 through (CT) December 2015: (CT) Rate Class Rate Schedules Rate Adjustment ANO-1 Residential RS, RT, REMT $0.00000 per kWh Small General Service SGS, GFS, MP, AP, CTV, SMWHR, CGS, TSS $0.00000 per kWh Large General Service LGS, LPS, GST, PST $0.00 per kW Lighting L1, L4, LiSH $0.00000 per kWh ANO-2 Residential RS, RT, REMT $0.00000 per kWh Small General Service SGS, GFS, MP, AP, CTV, SMWHR, CGS, TSS $0.00000 per kWh Large General Service LGS, LPS, GST, PST $0.00 per kW Lighting L1, L4, L1SH $0.00000 per kWh

APSC FILED Time: 11/10/2014 1:57:01 PM: Recvd 11/10/2014 1:56:00 PM: Docket 87-166-tf-Doc. 290 Attachment 1 Docket No. 87-166-TF Page 2 of 3 Entergy Arkansas, Inc. ANO Decommissioning Model Revenue Requirement Summary ($000) Unit 1 Unit 2 Both Units Line Total Arkansas Total Arkansas Total Arkansas No Year Company [1] Retail [2] Company [1] Retail [2] Company Retail [2] 1 2015 0 0 0 0 0 0 2 2016 0 0 0 0 0 0 Total Company 3 2017 0 0 0 0 0 0 4 2018 0 0 0 0 0 0 5 2019 0 0 0 0 0 0 6 2020 0 0 0 0 0 0 7 2021 0 0 0 0 0 0 8 2022 0 0 0 0 0 0 9 2023 0 0 0 0 0 0 10 2024 0 0 0 0 0 0 11 2025 0 0 0 0 0 0 12 2026 0 0 13 2027 0 0 14 2028 0 0 15 2029 0 0 16 2030 0 0 17 2031 0 0 18 2032 0 0 19 2033 0 0 20 2034 0 0 21 2035 0 0 22 2036 0 0 23 2037 0 0 24 2038 0 0 25 2039 0 0 26 2040 0. 0 27 2041 0 0 28 2042 0 0 29 2043 0 0 30 2044 0 0 31 2045 0 0 32 2046 0 0 Notes: [1] See Workpaper B.2 for ANO Unit 1 and B.3 for ANO Unit 2. [2] Total Company

• Retail Allocation Factor. See Workpaper B.5.

APSC FILED Time: 11/10/2014 1:57:01 PM: Recvd 11/10/2014 1:56:00 PM: Docket 87-166-tf-Doc. 290 Attachment 1 Docket No. 87-166-TF Page 3 of 3 Entergy Arkansas, Inc. ANO Decommissioning Model Trust Balance Summary ($000) Line No Year ANO 1 ANO 2 Both Units 1 2014 397,723 311,423 709,146 2 2015 421,814 330,281 752,095 3 2016 448,323 351,031 799,354 4 2017 477,424 373,811 851,235 5 2018 508,564 398,186 906,750 6 2019 541 842 424,235 966,077 7 2020 577,467 452,122 1,029,589 8 2021 615,615 481,983 1,097,598 9 2022 656,412 513,918 1,170,330 10 2023 700,118 548,130 1,248,248 11 2024 746,953 584,792 1,331,745 12 2025 797,154 624,088 1,421,243 13 2026 850,978 666,221 1,517,199 14 2027 908,703 711,406 1,620,109 15 2028 970,626 759,879 1,730,505 16 2029 1,037,072 811,892 1,848,964 17 2030 1,108,390 867,718 1,976,109 18 2031 1,183,011 927,655 2,110,666 19 2032 1,253,143 992,021 2,245,164 20 2033 1,316,365 1,061,163 2,377,529 21 2034 1,301,085 1,135,456 2,436,541 22 2035 1,140,370 1,214,012 2,354,382 23 2036 910,592 1,289,233 2,199,825 24 2037 740,610 1,355,731 2,096,341 25 2038 630,312 1,358,654 1,988,966 26 2039 514,918 1,228,038 1,742,956 27 2040 504,208 959,306 1,463,513 28 2041 514,846 716,035 1,230,881 29 2042 525,488 541,660 1,067,148 30 2043 536,107 351,176 887,283 31 2044 502,728 264,339 767,067 32 2045 515,016 175,197 690,213 33 2046 388,339 6,709 395,048

Per the EAI 2014 ANO Decommissioning Cost Rider NDCR Update Rate Sch. No. 37 Workpapers Entergy Arkansas, Inc. ANO Decommissioning Model - Total Company Tax Qualified Trust Detail - Unit 1 ($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 397,723 2 2015 0 6.05% 0 24,426 335 24,091 0 421,814 3 2016 0 6.27% 0 26,862 354 26,509 0 448,323 4 2017 0 6.47% 0 29,476 374 29,101 0 477,424 5 2018 0 6.50% 0 31,537 397 31,140 0 508,564 6 2019 0 6.52% 0 33,699 421 33,278 0 541,842 2020 6.55% 36,072 447 35,625 0 577,467 2021 6.58% 38,622 474 38,148 0 615,615 2022 6.60% 41,301 504 40,797 0 656,412 2023 6.63% 44,241 535 43,706 0 700,118 2024 6.66% 47,404 569 46,835 0 746,953 2025 6.69% 50,807 606 50,201 0 797,154 2026 6.72% 54,469 645 53,824 0 850,978 2027 6.75% 58,410 686 57,724 0 908,703 2028 6.78% 62,654 731 61,923 0 970,626 2029 6.81% 67,225 779 66,446 0 1,037,072 2030 6.84% 72,149 830 71,318 0 1,108,390 2031 6.70% 75,506 885 74,621 0 1,183,011 2032 5.92% 71,071 939 70,132 0 1,253,143 2033 5.06% 64,211 989 63,222 0 1,316,365 2034 4.35% 57,885 1,034 56,851 72,131 1,301,085 2035 4.29% 56,415 1,022 55,393 216,108 1,140,370 2036 4.29% 49,447 899 48,547 278,325 910,592 2037 4.29% 39,483 724 38,760 208,742 740,610 2038 4.29% 32,113 594 31,519 141,817 630,312 2039 4.29% 27,330 510 26,821 142,215 514,918 2040 4.29% 22,327 422 21,905 32,615 504,208 2041 4.29% 21,863 413 21,449 10,811 514,848 2042 4.29% 22,324 422 21,902 11,260 525,488 2043 4.29% 22,785 430 22,356 11,737 536,107 2044 4.29% 23,246 438 22,808 56,187 502,728 2045 4.29% 21,798 412 21,386 9,098 515,016 2046 4.29% 22,331 422 21,910 148,587 388,339 Average 5.59%O Notes: [1] The annual Revenue Requirement (0) is chosen so that the Decommissioning Fund Balance is zero in the last year of decommissioning. The 2034 amount is through May. [2] Projected After Tax Earnings Rates See Workpaper C.1. [3] Revenue Requirement * (1 - Bad Debt Rate). See Workpaper B.5 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.5 multiplied by (1 - TO Fund Tax Rate). [6] Transfer + Earnings - Management Fee. [7] Assumes that decommissioning expenditures are made at year end. See Workpaper B.4 for the annual amounts. [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%.

Per the EAI 2014 ANO Decommissioning Cost Rider NDCR Update Rate Sch. No. 37 Workpapers Entergy Arkansas, Inc. ANO Decommissioning Model - Total Company 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 311,423 2 2015 0 6.05% 19,126 268 18,858 0 330,281 3 2016 0 6.27% 21,033 283 20,750 0 351,031 4 2017 0 6.47% 23,079 299 22,780 0 373.811 5 2018 0 6.50% 24,693 317 24,376 0 398,186 6 2019 0 6.52% 26,385 336 26,049 0 424,235 7 2020 0 6.55% 28,242 356 27,886 0 452,122 8 2021 0 6.58% 30,239 378 29,861 0 481.983 9 2022 0 6.60% 32,336 401 31,935 0 513,918 10 2023 0 6.63% 34,638 425 34,212 0 548,130 11 2024 0 6.66% 37,113 452 36,661 0 584,792 12 2025 0 6.69% 39,777 480 39,297 0 624,088 13 2026 0 6.72% 42,643 511 42,133 0 666,221 14 2027 0 6.75% 45,729 543 45,185 0 711 406 15 2028 0 6.78% 49,051 578 48,473 0 759,879 16 2029 0 6.81% 52,629 616 52,013 0 811,892 17 2030 0 6.84% 56,483 656 55,827 0 867,718 18 2031 0 6.87% 60,636 700 59,937 0 927,655 19 2032 0 6.90% 65,112 746 64,366 0 992,021 20 2033 0 6.93% 69,938 796 69,142 0 1,061,163 21 2034 0 6.96% 75,142 850 74,293 0 1,135,456 22 2035 0 6.88% 79,463 907 78,556 0 1,214,012 23 2036 0 6.18% 76,185 964 75,221 0 1,289,233 24 2037 0 5.17% 67,515 1,017 66,498 0 1,355,731 25 2038 0 4.47% 61,278 1,065 60,214 57,290 1,358,654 26 2039 0 4.29% 58,911 1,066 57,846 188,461 1,228,038 27 2040 0 4.29% 53,248 966 52,282 321,014 959,306 28 2041 0 4.29% 41,596 761 40,835 284,105 716,035 29 2042 0 4.29% 31,047 575 30,472 204,848 541,660 30 2043 0 4.29% 23,486 442 23,044 213,528 351,176 31 2044 0 4.29% 15,227 297 14,930 101,767 264,339 32 2045 0 4.29% 11,482 230 11,232 100,374 175,197 33 2046 0 4.29% 7,597 162 7,434 175,922 6,709 Average 5.94%1 Notes: [1] The annual Revenue Requirement (0) is chosen so that the Decommissioning Fund Balance is zero in the last year of decommissioning. The 2038 amount is through July. [2] Projected After Tax Earnings Rates See Workpaper C.1. [3] Revenue Requirement * (1 - Bad Debt Rate). See Workpaper B.5 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.5 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.4 for the annual amounts. [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%.

Per the EAI 2014 ANO Decommissioning Cost Rider NDCR Update Rate Sch. No. 37 Workpapers Entergy Arkansas, Inc. ANO Decommissioning Model - Total Company 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 2014 1.0237 1.000 1.000 0 0 0 0 2 2015 1.0241 1.000 1.024 0 0 0 0 3 2016 1.0245 1.024 1.049 0 0 0 0 4 2017 1.0250 1.050 1.075 0 0 0 0 5 2018 1.0255 1.077 1.102 0 0 0 0 6 2019 1.0260 1.105 1.131 0 0 0 0 7 2020 1.0265 1.134 1.161 0 0 0 0 8 2021 1.0271 1.165 1.192 0 0 0 0 9 2022 1.0276 1.197 1.225 0 0 0 0 10 2023 1.0282 1.231 1.260 0 0 0 0 11 2024 1.0289 1.267 1.296 0 0 0 0 12 2025 1.0295 1.304 1.334 0 0 0 0 13 2026 1.0301 1.343 1.374 0 0 0 0 14 2027 1.0307 1.384 1.416 0 0 0 0 15 2028 1.0313 1.427 1.460 0 0 0 0 16 2029 1.0319 1.472 1.507 0 0 0 0 17 2030 1.0325 1.520 1.556 0 0 0 0 18 2031 1.0331 1.570 1.608 0 0 0 0 19 2032 1.0338 1.623 1.662 0 0 0 0 20 2033 1.0345 1.679 1.719 0 0 0 0 21 2034 1.0351 1.738 1.779 40,546 0 72,131 0 22 2035 1.0359 1.800 1.843 117,259 0 216,108 0 23 2036 1.0366 1.866 1.910 145,720 0 278,325 0 24 2037 1.0373 1.936 1.981 105,372 0 208,742 0 25 2038 1.0381 2.010 2.056 68,977 27,865 141,817 57,290 26 2039 1.0389 2.088 2.136 66,580 88,231 142,215 188,461 27 2040 1.0397 2.171 2.221 14,685 144,536 32,615 321,014 28 2041 1.0405 2.259 2.311 4,678 122,936 10,811 284,105 29 2042 1.0414 2.352 2.407 4,678 85,105 11,260 204,848 30 2043 1.0422 2.451 2.509 4,678 85,105 11,737 213,528 31 2044 1.0431 2.557 2.617 21,470 38,887 56,187 101,767 32 2045 1.0324 2.640 2.702 3,367 37,148 9,098 100,374 33 2046 1.0324 2.725 2.789 53,276 63,077 148,587 175,922 Total Decommissioning Expenditures 651,286 692,890 1,339,633 1,647,311 Notes: [1] See Workpaper C.36 for CPIU for years 2014-2044; the average for 2014 to 2044 is 3.24% and is used for 2045-2046. [2] Cumulative CPIU from 2015 (Revision Year). Cumulative CPIU (Prior Year)

• CPIU (Current year).

[3] Cumulative CPIU from 2014 (Estimate Year). Cumulative CPIU (Prior Year)

• CPIU (Current year).

[4] Decommissioning Cost Estimate (2014 dollars) filed in Docket No. 87-166-TF on March 31, 2014. See Workpaper D.2 [5] Decommissioning Cost Estimate

• Cumulative Nuclear Cost Escalator.

Attachment 1-E (Page 1 of 15) Entergy Arkansas, Inc. Unit Power Purchase Agreements Under Service Schedule MSS-4

Entergy Operating Companies Service Agreement No. 670 Service Schedule MSS-4 Agreement by and between Entergy Mississippi, Inc. (Buyer) and Entergy Arkansas, Inc. (Seller) Effective: January 1, 2013

MSS-4 AGREEMENT This Agreement is dated as of November 6, 2012, between Entergy Mississippi, Inc. ("EMI" or "Buyer"), and Entergy Arkansas, Inc. ("EAI" or "Seller" and together with Buyer, each a "Party" and collectively the "Parties"). WHEREAS, Seller purchases a portion of the capacity and energy of the Grand Gulf Nuclear Power Station (the "Designated Unit" or "GGNS") from System Energy Resources, Inc. ("SERI") pursuant to a unit power sales agreement ("UPSA") dated June 10, 1982; 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 successors, Entergy Gulf States Louisiana and Entergy Texas, Inc., in 2008 (hereinafter referred to as the "System Agreement"); and WHEREAS, the System Agreement contains a Service Schedule MSS-4 (as modified from time to time, "Service Schedule MSS-4") that provides the basis for making a unit power purchase and sale between the Companies that are participants in that Agreement; and WHEREAS, GGNS is a nuclear power generation facility located near Port Gibson, Mississippi; and WHEREAS, through the UPSA, Seller has a fixed percentage interest in the capacity and energy output of GGNS, including an approximately 30 MW share of such capacity and energy output from what is known as the "Non-Retained Share"; and WHEREAS, Seller has given notice of its intent to withdraw from and terminate its participation in the System Agreement effective as of December 19, 2013; and WHEREAS, the Parties wish to execute this Agreement to provide for a power sale by Seller and a power purchase by Buyer ("Designated Power Purchase") under Section 40.09 of Service Schedule MSS-4 from the Designated Unit; and WHEREAS, the Entergy Operating Committee has considered and approved the terms of this Agreement;

THEREFORE, the Parties agree as follows:

1. Designated Unit. The designated generating unit for purposes of this unit power sale under Service Schedule MSS-4 of the System Agreement is GGNS.

2. Unit Power Purchase. Seller agrees to sell and Buyer agrees to purchase that quantity of generating capacity and associated energy from the Designated Unit equivalent to the percentage (the "Buyer's Allocated Percentage") set forth on Attachment A.

3. Pricing. The pricing of the capacity and energy sold and purchased pursuant to paragraph 2 above shall be as specified in Service Schedule MSS-4 of the System Agreement, including particularly Section 40.09(c) of Service Schedule MSS-4.

4. Energy Entitlement. Buyer is entitled to receive on an hourly basis the Buyer's Allocated Percentage of the energy generated by the Designated Unit.

5. Term. Subject to paragraph 8 below, the term of this Agreement shall be the operating life of the Designated Unit, but shall commence no earlier than 00:00 January 1, 2013.

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 Agreement shall be conditioned upon Seller and Buyer receiving all regulatory approvals required, and all Entergy internal (e.g., board) approvals as necessary, 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 EMI: Entergy Mississippi, Inc. P.O. Box 1640 Jackson, MS 39215 ATTN: Chief Executive Officer To EA: Entergy Arkansas, Inc. 425 West Capitol Street Little Rock, AR 72201 ATTN: Chief Executive Officer

10. Non-waiver. 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.

a. Future Changes. EMI and EAI recognize that in the future, EAI and EMI will exit from the System Agreement, including Service Schedule MSS-4. EMI and EAI agree that, at the time of EAI's exit, this Agreement will continue under a successor tariff, as similar as reasonably practical to the terms of Service Schedule MSS-4, to continue to permit EAI to sell and EMI to receive the Allocated Percentage of generating capacity and associated energy from of the Designated Unit.

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.

BY: TITLE: f ENTERGY ARKANSAS, INC. BY: TITLE:

ENTERGY MISSISSIPPI, INC. BY: TITLE: ENTERGY ARKANSAS, INC. TITLE:

ATTACHMENT A SALE OF CAPACITY AND ENERGY BY ENTERGY ARKANSAS, INC. TO ENTERGY MISSISSIPPI, INC. This Attachment A is attached to and forms a part of the Agreement dated January 1, 2013, between Entergy Arkansas, Inc. ("Seller") and Entergy Mississippi, Inc. ("Buyer") pursuant to the Service Schedule MSS-4 of the System Agreement. SELLER'S BUYER'S BUYER'S CAPACITY* ALLOCATED ALLOCATED CAPACITY* PERCENTAGE Grand Gulf Nuclear Station 364.67 30.3 8.31% EAI Non-Retained Share** TOTAL 364.67 30.3 8.31%

• Expressed in megawatts for illustration. To the extent Seller's Capacity increases or decreases as determined in accordance with the UPSA, Buyer's Allocated Capacity shall adjust correspondingly based on Buyer's Allocated Percentage of Seller's Capacity.

   ** Under the UPSA, Seller purchases 36% of SERI's 90% entitlement to the capacity and associated energy of the Grand Gulf Nuclear Station. Seller's Non-Retained Share is 78% of its 36%

entitlement to capacity and associated energy of the Grand Gulf Nuclear Station.

Entergy Operating Company Service Agreement No. 668 Service Schedule MSS-4 Agreement by and between Entergy Mississippi, Inc. (Buyer) and Entergy Arkansas, Inc. (Seller) Effective: January 1, 2013

MSS-4 AGREEMENT This Agreement is dated as of November 2, 2012, between Entergy Mississippi, Inc. ("EMI" or "Buyer"), and Entergy Arkansas, Inc. ("EAI" or "Seller" and together withBuyer, each a "Party" and collectively the "Parties"). WHEREAS, Seller purchases a portion of the capacity and energy of the Grand Gulf Nuclear Power Station (the "Designated Unit" or "GGNS") from System Energy Resources, Inc. ("SERI") pursuant to a unit power sales agreement ("UPSA") dated June 10, 1982; 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 successors, Entergy Gulf States Louisiana and Entergy Texas, Inc., in 2008 (hereinafter referred to as the "System Agreement"); and WHEREAS, the System Agreement contains a Service Schedule MSS-4 (as modified from time to time, "Service Schedule MSS-4") that provides the basis for making a unit power purchase and sale between the Companies that are participants in that Agreement; and WHEREAS, GGNS is a nuclear power generation facility located near Port Gibson, Mississippi; and WHEREAS, through the UPSA, Seller has a fixed percentage interest in the capacity and energy output of GGNS, including an approximately 59 MW share of such capacity and energy output from what is known as the "Retained Share"; and WHEREAS, Seller has given notice of its intent to withdraw from and terminate its participation in the System Agreement effective as of December 19, 2013; and WHEREAS, the Parties wish to execute this Agreement to provide for a power sale by Seller and a power purchase by Buyer ("Designated Power Purchase") under Section 40.09 of Service Schedule MSS-4 from the Designated Unit; and WHEREAS, the Entergy Operating Committee has considered and approved the terms of this Agreement;

THEREFORE, the Parties agree as follows:

1. Designated Unit. The designated generating unit for purposes of this unit power sale under Service Schedule MSS-4 of the System Agreement is GGNS.

2. Unit Power Purchase. Seller agrees to sell and Buyer agrees to purchase that quantity of generating capacity and associated energy from the Designated Unit equivalent to the percentage (the "Buyer's Allocated Percentage") set forth on Attachment A.

3. Pricing. The pricing of the capacity and energy sold and purchased pursuant to paragraph 2 above shall be as specified in Service Schedule MSS-4 of the System Agreement, including particularly Section 40.09(c) of Service Schedule MSS-4.

4. Energy Entitlement. Buyer is entitled to receive on an hourly basis the Buyer's Allocated Percentage of the energy generated by the Designated Unit.

5. Term. Subject to paragraph 8 below, the term of this Agreement shall be the operating life of the Designated Unit, but shall commence no earlier than 00:00 January 1, 2013.

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 Agreement shall be conditioned upon Buyer receiving all regulatory approvals required, and all Entergy internal (e.g., board) approvals as necessary, 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 EMI: Entergy Mississippi, Inc. P.O. Box 1640 Jackson, MS 39215 ATTN: Chief Executive Officer To EAI: Entergy Arkansas, Inc. 425 West Capitol Street Little Rock, AR 72201 ATTN: Chief Executive Officer

10. Non-waiver. 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.

a. Future Changes. EMI and EAI recognize that in the future, EAI and EMI will exit from the System Agreement, including Service Schedule MSS-4. EMI and EAI agree that, at the time of EAI's exit, this Agreement will continue under a successor tariff, as similar as reasonably practical to the terms of Service Schedule MSS-4, to continue to permit EAI to sell and EMI to receive the Allocated Percentage of generating capacity and associated energy from of the Designated Unit.

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.

ETRGY MI S ,%IPPI jC. 1* *¢' TITLE: 4~2OCiv ENTERGY ARKANSAS, INC. BY: TITLE:

ENTERGY MISSISSIPPI, INC. BY: TITLE: ENTERGY ARKANSAS INC. TITLE: O

ATTACHMENT A SALE OF CAPACITY AND ENERGY BY ENTERGY ARKANSAS, INC. TO ENTERGY MISSISSIPPI, INC. This Attachment A is attached to and forms a part of the Agreement dated January 1, 2013, between Entergy Arkansas, Inc. ("Seller") and Entergy Mississippi, Inc. ("Buyer") pursuant to the Service Schedule MSS-4 of the System Agreement. SELLER'S BUYER'S BUYER'S CAPACITY* ALLOCATED ALLOCATED CAPACITY* PERCENTAGE Grand Gulf Nuclear Station 102.86 59.9 58.24% EAI Retained Share** TOTAL 102.86 59.9 58.24%

• Expressed in megawatts for illustration. To the extent Seller's Capacity increases or decreases as determined in accordance with the UPSA, Buyer's Allocated Capacity shall adjust correspondingly based on Buyer's Allocated Percentage of Seller's Capacity.

    ** Under the UPSA, Seller purchases 36% of SERI's 90% entitlement to the capacity and associated energy of the Grand Gulf Nuclear Station. Seller's Retained Share is 22% of its 36% entitlement to capacity and associated energy of the Grand Gulf Nuclear Station.

Attachment 2 (Page 1 of 1) SYSTEM ENERGY RESOURCES, INC. and SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION Status Report of Decommissioning Funding For Year Ending December 31, 2014 - 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) (2014$): SERI (90% ownership share) $606.0 million1 SMEPA (10% ownership share) $67.3 million

2. ISFSI Obligation as of 12/31/14 SERI $3.34 million SMEPA $0.37 million

3. Decommissioning Fund Total as of 12/31/14:

SERI $679.8 million SMEPA $55.2 million

4. Annual amounts remaining to be collected: See Attachment 2-B

5. Assumptions used:

Rate of Escalation of Decommissioning Costs: SERI See item below SMEPA 3.0% Rate of Earnings on Decommissioning Funds: SERI 2% real rate of return per 10 CFR 50.75(e)(1)(i) SMEPA Approx. 5.91%2 Authority for use of Real Earnings Over 2%: SERI N/A SMEPA SMEPA Board

6. Contracts upon which licensee is relying 3

For Decommissioning Funding: See footnote

7. Modifications to Method of Financial Assurance since Last Report: None

8. Material Changes to Trust Agreements:

SERI None SMEPA None 1 See Attachment 2-A 2 See Attachment 2-C 3 See the Unit Power Sales Agreement, a FERC tariff, in Attachment 2-D; and see also the Availability Agreement, in Attachment 2-D, 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 (Page 1 of 1) SYSTEM ENERGY RESOURCES, INC. and SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION Calculation of Minimum Amount For Year Ending December 31, 2014 - 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 IOCFR50.75(c)(2) Escalation Factor Formula: 0.65(L) +0.13(E) +0.22(B) Factor L=Labor (South) 2.431 E=Energy (BWR) 2.252 B=Waste Burial-Vendor (BWR) 14.1603 BWR Escalation Factor: 0.65(L) +0.13(E) +0.22(B)= 4.98750 1986 BWR Base Year $ Escalated:

   $135,000,000

• Factor= $673,311,926 System Energy interest (90%): $605,980,734 SMEPA interest (10%): $ 67,331,193 Total $673.311.926 1

Bureau of Labor Statistics, Series Report ID: CILU2010000000220i ( 4 "' Quarter 2014) 2 Bureau of Labor Statistics, Series Report ID: wpu0543 and wpu0573 (December 2014) 3 Nuclear Regulatory Commission: NUREG-1307 Revision 15, Table 2.1 (2012)

Attachment 2-B (Page 1 of 1) Schedule of Remaining Principal Payments into Grand Gulf Decommissioning Fund ($ Thousands) SERI Share SMEPA Share Total 2015 $22,285 $0 Thereafter $22,285 2016 $24,550 $24,550 2017 $24,550 $24,550 2018 $24,550 $24,550 2019 $24,550 $24,550 2020 $24,550 $24,550 2021 $29,878 $29,878 2022 $17,429 $17,429 2023 $0 Thereafte $0 Thereafter Note: Approved in FERC Docket No. ER95-1042-004, see Attachment 2-C.

Attachment 2-C (Page 1 of 2) Resolution to Amend Rate of Earnings on Decommissioning Trust

RESOLUTION WHEREAS, the Nuclear Regulatory Commission (NRC) requires nuclear plant operators to establish a fund for future decommissioning costs of nuclear facilities; and WHEREAS, biennially, the NRC reviews calculations and assumptions supporting the forecasted decommissioning costs for each nuclear facility; and WHEREAS, the NRC likewise biennially reviews adequacy of funds deposited to cover the future decommissioning costs, including projected future fund deposits, and projected rate of fund earnings; and WVHEREAS, in October 2011 the NRC received a License Renewal Application (LRA) pursuant to 10 CFR Part 54 to extend the operating license of the Grand Gulf Nuclear Station for an additional twenty years to an expiry date of 2044, NOW, THEREFORE, BE IT RESOLVED that based on an assumed operating license extension to Year 2044, and historic earnings data, supplied by the South Mississippi Electric Grand Gulf Decommissioning Trust Fund manager, Trustmark National Bank, the assumed projected rate of fund earnings will be 5.9 1%per annum. Certificate of Secretary I, Mack J. Mauldin, do hereby certify that I am the duly elected, qualified, and acting Secretary of South Mississippi Electric Power Association and keeper of its regular meeting of the Board of Directors of said Association duly convened and held in accordance with its Bylaws of the 213" day of December 2011, at which time a quorum was present and acting throughout. I further certify that said resolution is still in force and effect and has not been rescinded. IN WITNESS WHEREOF, I have hereunto subscribed my name and affixed the corporate seal of said Association on this 2 1st day of December 2011. 0.

           % o*'" "C*,,,"

Ee ESEA-L hi, O 0...  !'L-'e~ Exhibit B - December 21, 2011

Attachment 2-D (Page 1 of 39) FERC Order in Docket No. ER95-1042-004 And Availability Agreement

System Energy Resources, Inc. Original Sheet No. i

   $ av, Rate Schedule FERC No. 2 sE*n nal.Rate
                *.           5cr.pple r'ER2 iJa. 2)as .su-ppefeien#&d)

F/r4 EC- E.aU ft fl~hig Date7L'- 9ffiv *Dilte"/1.3~i 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 Effective Date: December .12, 1995 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, o tza0od-"(

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 l10" 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 11, 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 ENOl.("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-flueled 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 System 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 foilc6ws: Entitlement Percentages Unit No. I EAI 36% ELI 14% EMI 33% ENO] 17% 100% 1.3 Commencingwith 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 topermit 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 Purcha~ers 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 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. 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 I.

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 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.

                                                                                                         -I 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 successor. and assigns, but no assignment hereof, or of any right to any funds due or to become 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 no 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 any 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, Decket 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. 6 Rate Schedule FERC No. 2 SYSTEM ENERGY RESOURCES, INC., formerly 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., ormierly MISSISSIPPI POWER & I.IGHT COMPANY By: /S/ D. C. Lutkin ENTERGY NEW ORLEANS, INC., formerly NEW ORLEANS PUBLIC SERVICE INC. By: /S/ James M. Cain 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. 7 Rate Schedule FERC No. 2 Appindix 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.

('EAI"); Entergy Louisiana, Inc. ("ELI"); Entergy Mississippi, Inc. ("EMI); and Entergy New Orleans, Inc. ("ENOr) (referred to hereafter, collectively, as "Purchasers", or, individually, as "Purchaser¶), for capacity and. energy from the Grand Gulf Nuclear Station ("Grand Guir) 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.

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. 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. Original Sheet No. 9 Rate Schedule FERC No. 2 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 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 61,105,

System Energy Resources. Inc. Original Sheet No. 10 Rate Schedule FERC No. 2 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 EM! 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. ER95-1042-000, issued July 31, 2000, 92 FERC 1

61,119, order denying rehearing, issued July 30, 2001, 96 FERC 61,165

System Energy Resources, Inc. Original Sheet No. II Rate Schedule FERC No. 2 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 Line 1 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 1II WHICH REPRESENT MONIES HELD BY THIRD PARTIES. Issued by: Kimberly H. Despeaux Effective Date; December 12, 1995 Director, Federal Regulatbry 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, orderdenying rehearing, issued July 30, 2001, 96 FERC 61,165.

System Energy Resources, Inc. Original Sheet No. 12 Rate Schedule FERC No. 2 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 Account 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 18 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. 411.1 (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- 12 14 =UTILITY OPERATING INCOME Line 1 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 18) 18 COST OF CAPITAL Weighted Cost Rate from Page 5. Line 6 NOTES

1) 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 (DETERMINED IN ACCORDANCE WITH PAGE 51.

3) EXCLUSIVE OF FUEL EXPENSE IN FERk 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 INEFFECT AS OF THE END OF THE MONTH SHALL BE UTILIZED OTHERWISE. THE AMOUNT CHARGED TO FERC ACCOUNT 403 FOR THE SERVICE MONTH SHALL BE UTILIZED. AS SHOWN ON ATTACHMENT C.

5) RESTRICTED TO THOSE ITEMS FOR WHICH CORRESPONDING FIMING DIFFERENCES ARE INCLUDED IN THE ADJUSTM1ENTS TO NET INCOME BEFORE INCOME TAX (SEE PAGE 4. LINE 101.

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-Q00, 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 D NO .,DESCRIPTION AMOUNT REFERENCE/SOURCE. 1 CAPACITY REVENUE REQUIREMENT Page 3, Line 1 2 OPERATION &MAINTENANCE EXPENSE Page 3, Line 2 3 DEPRECIATION EXPENSE Page 3. Line 3 4 DECOMMISSIONING EXPENSE Page 3. Line 4 5 AMORTIZATION EXPENSE Page 3. Line 5 TAXES OTHER THAN INCOME Page 3. Line 6 7 NET INCOME BEFORE INCOME TAXES Line 1 * (Sum of Lines 2-6) 8 ADJUSTMENTS TO NET INCOME BEFORE INCOME TAX: INTEREST SYNCHRONIZATION Rate Base (Page 2. Line 10)° (o1) Total Debt Rate (Page s, Line 4)112 10 OTHER ADJUSTMENTS See Note I 11 TOTAL ADJUSTMENTS Line 9 plus Line 10 12 TAXABLE INCOME Line 7 plus Line I I VPAUDI ITAltIAM ng **TATI IM(*IrnUU TAW 13 COMPUTATION OF QTATO INCO Wf: Tr- V 5 TATE AXABLE INCOUME BEOcREUcUJUO IvMiN

• Line 12 14 NET ADJUSTMENT TO STATE TAXABtE INCOME See Note I 1s STATE TAXABLE INCOME Line .13plus Line 14 16 STATE INCOME TAX BEFORE ADJUSTMENTS Line 15* Mississippi State Tax Rate(2) 17 ADJUSTMENTS TO STATE TAX See Note I 18 CURRENT STATE INCOME TAX Sum of Lines 16- 17 COMPUTATION OF FEDERAL INCOME TAX 19 FEOERAL TAXABLE INCOME BEFORE ADJUSTMENTS Line 12 20 CURRENT STATE INCOME TAX DEDUCTION Line 18 (Shown as deduction) 21 OTHER ADJUSTMENTS TO FEDERAL TAXABLE INCOME See Note I

22. FEDERAL TAXABLE INCOME Sum of Lines 19-21 23 FEDERAL INCOME TAX BEFORE ADJUSTMENTS Line 22 *Federal Tax Rate(2) 24 ADJUSTMENTS TO FEDERAL TAX See Note 1 tA~ffl~li rU~fflLflNLJM~Ifl 25 CURREN i FEDERAL INCOME i AX !Sum Of Lines 24 . 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 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. 14 Rate Schedule FERC No. 2 Attachrfient 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) I DEBT 2 LONG TERM FERC Accts 221,224,225, 226,181, (5) 189 3 SHORT TERM (61 4 TOTAL DEBT (7) 5 COMMON EQUITY FERC Acets 201, 208, 216 (SEE NOTE 9) 6 TOTAL NA 7'

NOTES, (1) TO BE DETERMINED BASED ON DATA AS OF THE END OF THE MONTH IMMEDIATELY PRECEDING THE CURRENT SERVICE MONTH.

(2) LONG TERM DEBT SHALL INCLUDE.ALL ISSUES AND REFLECT THE-PRINCIPAL AMOUNT. (3) SHORT TERM DEBT SHALL INCLUDE ONLY THAT PORTION NOT REFLECTED IN THE CALCULATION OF SERI'S RATE FOR ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION. (4) 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. (6) THE AVERAGE COST RATE FOR ELIGIBLE SHORT TERM DEBT. (7) WEIGHTED AVERAGE COST RATE FOR LONG TERM DEBT AND SHORT TERM DEBT. (a) CAPITALIZATION RATIO FOR THE APPLICABLE CAPITAL SOURCE MULTIPLIED BY THE CORRESPONDING COST RATE. (9) 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. 2C00 THE RATE SHALL BE 10.94%. 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. 1.5 Rate Schedule FERC No. 2 Attachment B Page 1 of 1 SYSTEM ENERGY RESOURCE:S, INC. MONTHLY FUEL CHARGE FORIMULA MONTH, XXXX LINE NO DESCRIPTION REFERENCE/SOURCE I FUEL EXPENSE FOR APPLICABLE SERVICE MONTH FERC Account 51B 2 MONTHLY FUEL CHARGE FOR EAI 36%

• Line 1 3 MONTHLY FUEL CHARGE FOR ELI 14%
• Line 1 4 MONTHLY FUEL CHARGE FOR EMI 33%
• Line 1 5 'MONTHLY FUEL CHARGE FOR ENOI 17% Line 1 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. 16 Rate Schedule FERC No. 2 Attachment C Page 1 of I System Energy Resources, Inc. Grand Gulf Decommissioning Model Revenue Requirements Summary (S0o0) 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 21o0 16.590 2.960 19,550 17 2011 20,184 3.601 23,785 18 2012 20.184 3,601 23,785 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.

AVAILABILITY AGREEMENT BETWEEN 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. T'I[S AGREEMENT, dated as of the 2lt day of June, 1974, between MIDDLF SOUTIU ENF.R*A,. INC. (.MSEI) and ARKANSAS POWER & l-IIT C(O'A, (AI:P&L), ARKASAS-ArISSUtE.T7I POWER COMPANY (Ark-Mo). LouIsIANA POWER & LIGHT COMPANY (LP&L), Mississippi PowEx

  & LIGILT COMPANY (MP&L) and NEw OaLEANS PUBLIC SERVICE INC. (NOPSI), WiTNESSLTrn THAT:

Wi AP&L, Ark-Mo, [.P&L, MFP&L and NOPSI (collectively, System operating companies

                .EREA*s, 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 Wiipitp.As. the System operating companies are parties to an agreement dated April 16, 1973 (as presently constituted and as amended in the ftuture. System Agreement), which provides the contractual basis for the continued planning, construction and operation of certain facilities owned by thie System operating companies to achieve the purposes set forth therein; and WHEREAS, other entities may become parties to the System Agreement; and WrEmatzis, 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 Ghull Nuclear Electric Station 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 WrFIPRCAS. MSEI is. iubjhect to the terms hereof, willing to undertake the construction and operation of the Project, to beconme a party to the. System Agreement and to make available to the Parties, :is h:'rcinadt;-r ct1.'med, all #t i      ,e
                                                    .w,'r    :*til Olc (Ie- rp' asscialtcd  hth rc.with) :avail:abhh It
 ,ny'MS      EI Gnerating Unit, including the [:roject. under the ternis hereof and of the System Agrcenecnt; and WWEREascS. the Partie.s. as hereinaitcr decined, are. subject to the terms hereof, willing to pturchase power (and the energy associated therewith) available or to be available at any MSEE Generating Unit, including the Project, under the terms lhteof and u( the Syiitarn Agreement; U V

- '4 5 I- .. .

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 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) AISEI Gcnerating Unit shall be that portion of any electric generator, together with its prime mover and all auxiliary and appurtenant devices and equipment designed to be operated as a unit for the production of electric power and energy and all associated equipment and facilities. which is owned by MSEI and which MSEI and the Parties have designated as being subject to this Agreement. (c) Poiver shall rni.arn both power and thie 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 MSE1 hereby undertakes to use its best efforts to construct the Project.

3. On or before the date on which Unit N'o. 1 of the Project is placed in commercial operation, MSEI and the Partiec. will join in executing such document or documents as may be necessary for MSEI to become a party to the System Agreement. MSEI and the Parties will also join in exe 'uting at an appropriate time such document or documents as may be necessary for others who become parties ti tihe System 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 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 and the then applicable requirements of the System Agreement (or any 'agreement subhstituted therefor) be entitled to receive all Power available from time to time at any MSET Generating Unit: provided, that (i) should any Party terminate its participation in the System Agree-ment, 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 such 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 he 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

'at'cellmion or ter-niwition of tih S vsteli :\.Agreemrent. in Slidh allintnints anld for :;Il- Crliidlvratiln calculated fr..Ml time tortime as if the System Agreement had remained in effect and *S*1[ and .such Partics were parties thereto. Notwithstanding such withdrawal from, or cancellation or termination of. the System Agrecitent, each Party shall remain hound by the terms of this Agreimntt. with respect to any M'SEI Generating Unit which has been designated as being subject to this Agreement at the trime of such withdrawal, cancellation or termination f.n considherations of MSF['s c,,mmitment to tinrerleakc c*'.ttruitcim of :w Project lariiti ,ther ,:, igatimr s h:re-rcrder and o:f the right (,f the Parties to receive Power available at any MSEI Generating Unit under the terms of the System Agreement for any ieparate agreement referred to above), tire Parties agree to pay to MSEF. commencing on the .late on which a particular MSN[E Generating Unit is deemed to he in operation for the purposes of this Agreement, such amounts from time to time as. when added to aunnunts received by MSEI 2

from 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, i ch:i' ling (withour limitation), for the purposes .o this Agreenient. (i) all cxpenses, dednctions. charges and other items 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 cffect 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 to this Agreencut by MSEI and tihe Parties, then, solely for the purposes Of-.determining MSEI's total operating expenses under this Section 4. such MSEI Generating Unit shall be deem.*ed to be in operation on the date, and the accnial of depreciation as an operating expense with respect to the MS!I 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 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 be 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 A\greement, in the ratio of each such Party's deficiency to the sum o( 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 Agreement, the Capability of all MSEI Generating Units shall be included in the System Capability, as such terms are defined in the System Agreentent. 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 defined 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 heriby 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 uf depreciation and amortization with respect to the Project shall be deemed to Cominience on the earlier of such dates; that such accrual of depreciation and amuortization shall be at lie rate 6f 3.65% per annumA *0 the aggregate amount properly chargeable (prior to the deductLion therefrom of any depreciation (or amortizatiom) at the time with respect to the P'o~ect to Bala'ce Slicer :\ccounts l01. 102, R13. 104, 105, 106. 107 (tie aforemcentioned accounts being exclusive of land and land rights). 118. 120 (.1 through .5), 121.'123, 123.1, 124, 1.51. 152, 1-53. 1.;4. 155, 156, 157, 163, 182. 1-80, IS4, 18.5. 186, 187 and 188 of die Uniform System of Accounts and such other accounts as are properly subject to depreciation or amortization at the time purs.uant to stuch Uniform Systten 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, .hall ever commence operation and/or remain in operation; provided, however, hat it Unit No. I is placed in commercial operation prior to December 31, 1982 and Unit No. 2 is not completed and ready for 3.

I

service at such time, then until December 3). 1982 or the date Unit-No.' 2 is placed in commercial operation, whichever'daTe occurs earlier, expenditures included in Account 107 which are identified exclusiv"ely with the construction bf Unit No. 2 may he excluded front the calculation of the aggregate amount subject to the accrualof depreciation ind amortization pursuant to this paragraph.

6. The performance of the obligations of MSEI hereunder shall be subject to the receipt and continued effectiveness of all authorizations of governmental regulatory authorities at the time necesiary to permit MSEi to perform its duties and obligations hereunder. including the receipt and continued effectivene.ss of all authorizations by. governmental regulatory authorities at the time necessary. to pcrnit MSEI to finance, to construct or cause .to he constructecl, to operate or cause tV be operated,

 ",id/or ro make available to tthe Parties the Power available at any MSE[ Generating Unit. MSEI
 .hall use its best efforts to seiure and nmaintain all s1i0: I a ilh0'ilat ioMs lby. gýovcrliinental regulatory auLthorities.

7. The performance by each Party of its obl.igations hereunder shall 'be subject to the receipt and continued effectiveness oi all authorizations of governmental regulatory authorities necessary at the time to.1pcnnit it to perform' its duties and obligations hereunder, including the receipt and conitinued effectiveness of all authorizations by governmental regulatory authorities necessary at the time to permit it to pay to ,ISEI, in consideration for the right to receive, its share of the Power available at any. MSEI Generating Unit, the amnounts provided for in Section 4 of this Agreement.

Each Party shall use its. best efforts to secure. and maititain all such authorizations by governmental regulatory authorities. Each Party shail, to the extent permitted by'law, be obligated to perform.its duties ald( obligations hereunrder, subject to the then applicable provisions of this Section 7, (a). whether or not MSEI shall have received all. autthorizations of governmental regulatory authorities necessary to permit MSEI to perform its 'duties and obligations hereunder or under the System

\greeicrnt, (b)' whether or- not. such atithorizations, or any tsuch authorization, shall at any time -in (qiestion bemin effect, (c) whether or-not the System Agreement shall, from time to time, be amended, -1 modified or supplemented or shall be cancelled or terminated or such Party shall have withdrawn therefrom and (d) so long as NMSEL. and such Party shall continue'to be subsidiary crmpanies of S'fidldle South Utilities, Inc. (as said termn is defined in Section 2(a) (8) of the Public Utility Holding Company Act of 1935) or a successor thereto, whether or not, at any time -in question. MrSEI shall have performed its duties and obligations under this Agreement or the System Agreement. In the event that MSSEl or any.Party shall cease to be such a suhsidiary company, then and 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 God, fire, flood, explosion, strike, civil or military authority.

insurrection, riot,. act of the elements, failure of equipment, or for any other 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 adejuacy of a remedy at law which may be asserted as a lar to the remedy of specific performance in any action brotught against it for specific performance of this Agre ement by any other party to this Agreement. or by a trustee tider any, mortgage or other debt in*strument which aly suIch pi rty I:., this Agreemciet may. -i.ibject to rc(lltisiie, rcgqmlt*ory al lthority. enter into,

.1. itv mny receiver or trtlstee appointed for any ýmich party uonler the h:tunlrptcy or ittsolvency laws
'I; any juris.ihction to which any such party may lie slhbject,          priwvicd. hov..ner, that. nothiirig lir.rei i

,-wtlai ,ed .ShMl be ,.lmed to constitute a r, presentation or warranty by aniparty to this Agreement that -teir r(!:plective obligaf.ions ,ilder this .'\grl:cntenit are, as a nmater of law, sit bject to the eqtlitable. reriedy of specific performance. .'.

9. No Party shall he entitled to sct off again.vt any payment rellutired to be made by such Party inder this Agreement (i) any amounts owed by MSEl to such Party or (ii.) thi amount of any claim by sttci Party against MSEI. The foregoing, however, shall no.)t affect in any other way a - A'-' )iL,~,# ~ a

tie rights and remedies of any Party with respect to any such amounts owed to siuch Party by MSEI or any such claim by such P'arty against MSEI.

10. The invalidity or utieniorceability ro any provision o(f this Agreement shall not affect the remaining provisions hereof.

[I. This Agreement shall Income effective forthwith. This Agreement may he amended, nitxlfied tr terminatcd only with the consent of MSEI and of the I'artie., then having responsibility for two-thirds or more of the amounts to be paid under Section 4 hereof, and upon the receipt and continued effectiveness of all authorizations of governmental regulatory authorities at the Line necessary.

12. This Agreement shall be bindinig upon the Parties and MSiEI and their respective successors nmdassigns, but no assignment hereof, or of any right to any funds due or to become due under this Agreement, shall in any event relieve any Party or MSEI of any of their respective obligations here-utnder, or, in the case of the Parties, reduce to any exteit their entitlement to receive Power available from time to time at any MSEI Generating Unit.

13. The agreements herein set forth have been made 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 by virtue of this Agreenent..

IN WITNlESS WII.oREO. 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. ARKANSA. POwFR &- LicTtr COMPANY By .................... ....... ........ WVitness :Title ARKANSAS-MIsSOURI POU'ER COM, PANY B y ....... ... . .. ..... ........ ....... Witness: Title

                             . . .. . . .. . . .   .   , ( .,  ,\  .    "O  l-       .. ¢ l T ('   .r      N f L.OUiSIAN;A POV!F( & 1.1611-C CONO'A N I3y . .. . .. . . . . . .. . . . .. . . . . . .. . . . . . . . . .. . . .

W~its" Title 5

APPENDIX A Definition of -"Capability Responsibility"- As Used in Availability Agreement "Capability Responsibility" shall mean: with respect to any "Cunmpany", the "System Capability" multiplied by the "Responsibility Ratio" for that Company.

      "Company" shall meaC.tn  one of the Middle South Utilities, Inc.'s System operating companies, as defined in the Availability Agreement; "System Capability" shall nmean 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 'f 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 conditions 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 megawatts available under-contract to such Company from a supplying source; provided, however, that each Company shall be-deeemed to have at least one Kilowatt of Capability, whether or not it has any 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 differentt (lay, occurring during the twelve month period ending with the current month, but not less than 90%7 of the average of the four highest such demands occurring during the twenty-four (24) month period ending with the current mont h, where each such demand shall represent the simultaneous hourly input front all sources into the system oi a company, less the sum of the simultaneous hourly outputs to the systcem of other interconnected utilities (Company demands shall include firm power supplied to other systems fe.r its.own account), (b) less the 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     ..

FIRST AMENDMENT TO AVAILABILITY AGRREEMENT.

                                   -TrWEEN 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 or 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. (NOPSI.), 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), WITNEssETu 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 WrITNsS 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. 7 By ..... 44 Z 2&7 . . . . . . . . . . . . ARKANSAS POWER & LIGHT COMPANY By......... * ...... President President ARIJAAs-MIssoURI POWER COMPANY NEW ORLEANS PUBLIC SERVICE INC.

         .....             .       ........................... By                                               -.-.e President                                                  Preside4 MIDDLE SO      H ENERGYt              .-

By. . . ...... 7 Vice Presidefit, Finance 145 P,,- _45 M wf

Ad 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 [NC.

TH. S SECOND AMENDMENT, dated as of the 15th day of June, 1981. be-tween Middle South Energy, Inc. (MSE) and Arkansas Power & Light Com-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), WrrNESSETm 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. thevpfvisio of Section 4 of the Availa*,lityt C Agreement, it has been agreei. that the Parties shall be entitled, subjeV to thCr then applicable requirements-of the Sytem Agreement (or aU7 Pmoo 1ý substituted therefor), to receive ali Power available from time to. W a ,TX:A MSEI Qenerating Unit and shall be' responsible for certain of.o expens.,.of such Units apportioned in accordance with the formuila s forti in SectiontIanid

                            *      .       *         *:30,5-000%-000"-
                     *,              t.*, ..                                          *        .     ... .....
      ~o.';*'*i'*.,*          ,:*,                                 -   -                .I***'&-{.**

2 WHEREAS, Unit No. 1 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 ,able WHEREAS, MSE and the Parties have determined that it would be prefer-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

                                                                                  Ž,i305-002._-000

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. I 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 MSE[ to become a party to the System Agreement in such a man-ner 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

_____ *~~~'13c'.E5-00:)(3:)-cOc(:O4

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 (q) 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 shall 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

S 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% MP&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 Ml i;0 . I ý=00 M ý, RD I 0 IN C. L MAH ýLM W M -I WE

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.

E;:3(jS- c:)c:)

              -                    ,~                                     .4
                                        .47.-

~

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 MSE! 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. I 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. I 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.

S IN WrrNsS 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 CO NY By: (2 ý 0-Senior VicoP*Asidef tident and

                                   *"

• Chi~Ex~ecutive Officer ARKANSAS POWER & LIGHT COMPANY .

By: NEW ORLEANS PUBLIC SERVICE INC. By: " l&4 1iPresiden*' and Chief Executive Officer .~- ~' 44

      -                                      4             ~            _

..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&Ll. 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), WrTNESSETr 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. 1 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, 198 1, 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 NOPSI have entered into (i) a First. Fourth. Fifth and 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 ]. 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 S of the Availability Agreement accordingly. A~' ~y. J ~ .- ~7~c' -CA -

NOW. THEREFORE. in consideration of the terms and conditions hereinafter set forth. the panics hereto agree with each other as follows: I. 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 MISSISSIPPI Pow G2t Bv ... I *'..... . ** By: . . . . .... .... ..................... B y.... ..... a.. . . . . . . . By ..... ...........

            )erry/1**      'Maul*den',-.....         ....            D. A . Lutk~en, ýChairm~an of the Boar President                                                and Chief Executive Officer LOUISIANA POWER      &  LIGHT COMPANY                     NEW ORLEANS PUBLIC SERVICE INC.

Xreside~nt r*siden t MIDDLE SOUTH ENERGY. INC. F.W. Lewis, President 2

                                                                                                      ,, ~.

4 .Y~ f i~y. '~ ~ ~

FOURTH AMENDMENT TO AVAILABILITY AGREEMENT Between SYSTEM ENERGY RESOURCES, INC. And ARKANSAS POWER & LIGHT COMPANY, LOUISIANA POWER & LIGHT COMPANY, MISSISSIPPI POWER & LIGHT COMPANY, and NEW ORLEANS PUBLIC SERVICE INC. This Fourth AMENDMENT, dated as of the Ist day of June, 1989, between System Energy Resources, Inc. (System Energy), and Arkansas Power & Light Conpany (A?&L), Louisiana Power & Light Company (LP&L), Mississippi Power

    & Light Company (MP&L) and New Orleans Public Service Inc.

(HOPSI), 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, LP&L, MP&L and NOPSI, as amended by the First Amendment thereto dated as of June 30, 1977, the Second Amendment 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, 1.986, System Energy's name was changed from Middle South Energy, Inc. to System

 .' Energy Resources, Inc.; and IR

WHEREAS, System Energy, AP&L, LP&I., FP&L and NOPSI have entered into (i) a sixteenth Assignment of the Availability Agreement, Consent and Agreement, dated as of May 1, 1986, with United States Tnust Company of 1-ew York and Malcolm J. Hcod, as Trustees, (ii) a Fourteenth and Fifteenth Assignment of the Availability Agreement, Consent and Agreement, dated as of ;une 15, 1985 and May 1, 1986, respectively, with Deposit Guaranty 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 December 1, 1987, respectively, with United States Trust Company of New York and Gerard F. Ganey, as Trustees, and (iv) a Twenty-second Assignment 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

                .he Project is Abandoned prior to its Completion, the portion of System Energy's investment wnich it is not permitted to charge to its customers in wholesale rates ("disallowed investment") andthe 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
             -~                             r             .~4

______ ~ ___ ~ I,. '-,~1f~ ~' - _

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 cccurred:   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.

SYSTEM, ENERGY IRESOURCES,. INC..

                     /  .

P re s id e nt ARKANSAS 'POWER & LIGHT. 'COMPANY MISSISSIPPI POWER & LIGHT CO?4PANY By:. _________ LOUISIANA POWER & LIGHT* COMIAUNY By: NEW ORLEANS PUBLIC SERVI.CE INC.

                                             ,.1

Attachment 3 (Page 1 of 1) ENTERGY GULF STATES LOUISIANA, L.L.C. Status Report of Decommissioning Funding For Year Ending December 31, 2014 - 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) (2014$): $460.2 million 1

2. ISFSI Obligation as of 12/31/14 $2.32 million

3. Decommissioning Fund Total As of 12/31/14: $305.0 million

4. Annual amounts remaining to be collected: See Attachment 3-B

5. Assumptions used:

Rate of Escalation of Decommissioning Costs: See item below - Rate of Earnings on Decommissioning Funds: 2% real rate of retum per 10 CFR 50.75(e)(1)(i) Authority for use of Real Earnings Over 2%: N/A

6. Contracts upon which licensee is relying 2

For Decommissioning Funding: See footnote

7. Modifications to Method of Financial Assurance since Last Report: See footnote 3

8. Material Changes to Trust Agreements: 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. 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 (Page 1 of 1) ENTERGY GULF STATES LOUISIANA, L.L.C. Calculation of Minimum Amount For Year Ending December 31, 2014 - 10 CFR 50.75(f)(1) 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 (3,091MWt) 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) Factor L=Labor (South) 2.431 E=Energy (BWR) 2.252 B=Waste Burial-Vendor (BWR) 14.1603 BWR Escalation Factor: 0.65(L) +0.13(E) +0.22(B)= 4.98750 1986 BWR Base Year $ Escalated:

   $131,819,000

• Factor= $657,446,702 River Bend 70% Regulated Interest: $460,212,691 River Bend 30% Non-Regulated Interest: $197,234,010 Total $657,446,702 1

Bureau of Labor Statistics, Series Report ID: CI1U2010000000220i (40 Quarter 2012) 2 Bureau of Labor Statistics, Series Report ID: wpu0543 and wpu0573 (December 2012) 3 Nuclear Regulatory Commission: NUREG-1 307 Revision 15, Table 2.1 (2012)

Attachment 3-B (Page 1 of 1) Schedule of Remaining Principal Payments into River Bend Decommissioning Fund ($ Thousands) Year LPSC PUCT FERC Total 2015 $ 8,996 $ 1,126 $ 113 $10,235 2016 $ 8,996 $ 1,126 $ 113 $10,235 2017 $ 8,995 $ 1,126 $ 113 $10,234 2018 $ 8,995 $ 1,126 $ 113 $10,234 2019 $ 8,996 $ 1,126 $ 113 $10,235 2020 $10,195 $ 1,126 $ 113 $11,434 2021 $10,195 $ 1,126 $ 113 $11,434 2022 $10,195 $ 1,126 $ 113 $11,434 2023 $10,195 $ 1,126 $ 113 $11,434 2024 $10,195 $ 1,126 $ 113 $11,434 2025 $11,693 $ 751 $ 165 $12,609 2026 $11,693 $0 $0 $11,693 2027 $11,693 $0 $0 $11,693 2028 $11,693 $0 $0 $11,693 2029 $11,693 $0 $0 $11,693 2030 $13,513 $0 $0 $13,513 Note: Approved in LPSC Docket No.U-31237, see Attachment 3-D; PUCT Order in Docket No. 39896, See Attachment 3-E; FERC Order in Docket Nos. ER86-558-002, see Attachment 3-F.

Attachment 3-C (Page 1 of 1) ENTERGY GULF STATES LOUISIANA, L.L.C. Status Report of Decommissioning Funding For Year Ending December 31, 2012 - 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) (2014$): $197.2 million 1

2. ISFSI Obligation as of 12/31/14 $0.99 m illion

3. Decommissioning Fund Total As of 12/31/14: $332.8 million

4. Annual amounts remaining to be collected: None

5. Assumptions used:

Rate of Escalation of Decommissioning Costs: See nex:t item Rate of Earnings on Decommissioning Funds: 2% real rate of retum per 10 CFR 50.75(e)(1)(i) Authority for use of Real Earnings Over 2%: N/A

6. Contracts upon which licensee is relying For Decommissioning Funding: None

7. Modifications to Method of Financial Assurance since Last Report: None

8. Material Changes to Trust Agreements: None 1 See Attachment 3-A

Attachment 3-D (Page 1 of 20) 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. U-31237 In re: JointApplication of Entergy GulfStates Louisiana,LL.C. and Entergy Louisiana,LLC for approval of an Increase in Fundingfor Decommissioningfor River Bend and Waterford 3 Nuclear FacilitiesLPSC Docket No. U-31237. (Decided at the Commission's July 28, 2010 Business and Executive Session.) Overview and ProceduralHistory 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 generating station located near Killona, Louisiana that was constructed by ELL's predecessor, Louisiana Power & Light Company, and began commercial operation inSeptember 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. (I) The Commission shall exercise all necessary power and authority over any street, railway, gas, electric light, beat, 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. 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. UncontestedStipulatedSettlement 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 EGSL/ELL 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; EGSUELL Exhibit I- Settlement Testimony of Kenneth F. Gallagher, dated July 9, 2010; EGSLJELL Exhibit 2- Direct Testimony of Kenneth F. Gallagher, redacted public version, dated December 2009; and EGSIJELL 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 year3 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. 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 SIO. 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) affd 119 F.3' 349 (5h 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. S The $379.8 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 ($5.83 1 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, S-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 S7.843 million amount is on a retail basis. Order No. U-3)1237 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.

1i. 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 ISI LAMBERT C. BOISSIERE, III DISTRICT III CHAIRMAN LAMBERT C. BOISSIERE, III

                                   /S/ JAMES M. FIELD DISTRICT II VICE CHAIRMAN JAMES M. FIELD IS/FOSTER L. CAMPBELL DISTRICT V COMMISSIONER FOSTER L. CAMPBELL
                                   /S/ ERIC F. SKRMETTA DISTRICT I COMMISSIONER ERIC F. SKRMETTA EVE KAHAO GONZALEZ                  /S/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 EnMu Lacsiswwa U.C V4W~oid-3 OaecomaIsoi*w Modd No TOW LPSO CNO ArudWMlno (31 Yeiw S-vaL(1 ndc 2 2010 S."4T sAII 1'16 5.947 6.8,11 2 2011 5,947 5.831 116 3 2012 5.947 5.631 4 2013 5.947 5.831 118 5 2014 S.531 !13 5.947 6 2015 6.821 133 7 2016 6.588 6 .821 201?Y 133 133 6.821 8.605 9 2018 6.521 MtI 133 10 2019 6.668 151 11 2M2 7.731 7.500 151 12 202f 7,731 7.580 151 13 2M0 7.731 15l 7.380 14 2M2 7.731  ?.go 151 I5 202A 7.731 7.660 0 Notes. (1) See Eil*" A Pes 2. (2) TOWCaiPsOy

• LPSC Production OSnasbdAloclo Factor GBOSI (3) TOW Compainy - I.PSC Juriadk.o

S.e,, Rep Revision Yer 2Nol Exhibit A 9 f 4.25% Page 2 of5 1w~ord4-.10,imm ub Modd Revemne RequkwnoM K Fund BaWmneand Expldw Summsa'nry Tow Company Una Revne Tax No Yewr Rp (ii1 Qur, J* .Osoarm. 1L [ I 8"eg*rmi 5 213.001 2 2010 S?47 227.329 0. 3 2011 6.947 246.951 0 4 2Mj 6.041 250.384 a S 2013 5,047 201.40w a 6 2014 5.947 316.413 0 7 201S 6.621 344.050 0 a Zola 6.821 37U.660 0 9 2017 6.821 406.077 0 10 2016 6.821v 436.T9 a 11 2019 6.621 474814 0 12 2020 7.731 014,26, 0 13 202m 7.? 508,61427 0 14 2022 7.761 80$.313 0 is 2023 7.661 26247.991 1 Is 2024 7.731 4OZ,24 3,004 17 2M2S 8.007 OX5323 as5,too 12 20M U4 2O45.t 314 25 20 . 0 203.9 20 2ma, 8,.0"? 2O2.117 111.2.37 21 2029 $,N?* 170,727 115.650 22 2030 10.246 68.810 100.606 23 2031* 44.001 42,090 24 2032 542 45.564 2S 2033 0 552 (11The Wmnua Revene AequkwemM(5.247)Is dman so OWlfOwDwcmnmbufa Fund Salatoa Is wn In9, to mZ5 of mm1nsn*,oO. r42See Ex~dMd A Page2. M3See E~lbi A PPagS. 141NWon-TexCumed TOuM tance + T" Oufffiad True! Belae 15]Seo Of..bA Poge 4.

Exhibit A Page 3 ofS L7,. lesma ew Mg T;ia4w M1. . No O4M. , Q0iaI4q f.t Yaw RmIII P ..r4 Tor ....A 1_I. o .F..L _E ..... J M ..... Bd_._ . I O4gk1w - - d13V01n 2160"1 2 2010 5.47 6-71% 3.7 9.407 213 12.= 0 2274M.3 100.% 3 2011 5.947 5*6% 6047 13X&4 226 MW 0 3"Al5 100*0 4 2013 5a"4 49% 5.947 157,33 246 21"M 0 201.340 MOM00 7 201. 1W 8* 6m am 1,551 233. .,,. 0

• 1 3_.M 10600%

6.5%621 3* 3321 M1851 0 9 2017 " sm 6.4% 61 25j.= 35 1 0 406.07. "00, 14 16* _11 7,7J1 2!*1~, 6.0 6,321 2.25 1.12 54~ 307l~l

                                                                                      /             1 427.637               0       344060qll  106.O%

It 21 6.1 621 2k4.17 *6,*413 3. .0 474M4 10o600% 12T-2"M 7.3 5 .731 32109 442 3%4411 0 64.0 0000 14 2016*m 2022 .3

                            ..    .    . 3% ..     . 771 ...       . ., .
                                                                   .2.7
                                                                                .- 1 .      .. 69
                                                                                                        ._       mz 0.72..... 601516A
                                                                                                                                ,!560 -  10000 MOM IS        2023           71            69              .3             ,0           656          49.47                0        97.591     I0wo*

41 Y am .6 367 i6.7% 0* 622 4IA36 W6m183 6.326 1000% 1._ 202..... . 7..o . .314. 7....1...... .. ..... *....79 4... 0**... ..... 55.. 1060.. 0%, 111 2027 6.557 &771 6*67" 30*66 474 311.4811 203,2 3.44=7 10600% 6.,6% - .. !621=1 10600 21 2029 6.667 6.79% 1.6 556 M6 34.260 1M07 6 22 2000.46 4.9% 1024 10 181 19749 100.66 am*10 100.00 2 201 0 4.110% 0 06 42144.M 25 203 a 4*6% 0 27 If 10 682 a "OAK6 20 29n*=~a 068 L18 W .2--4 AI- ** X A 0 ad In (11The Nm46 ftVW.. R4**-@amI(GA047 meiss dudDo1Oscawr4almki FundBalor. bIs o 12 R-ww Rsqs*w- I Cludtg Pe-atW (100%) 141Pew. Yaw Bhlulm Cwew14a Shff4r,4wdf Cwuw Yaw SmIig fCtkwl4Ye Tramdw I Cigwa Yew6.11fl91 Rame

                                                                                 %~d 134Ca424eled Inacowdewei 4..       be.8m        ftd maiqd wale-ee OWNidýw ankvhe~ 6Im k Sm MWA Pap 4.

161TraiWi 6 Eand2gs- Mw-qais Pea. I)Aemme c"6 bcamwwululv 7e5621 we m4e"at "W WAa- go* A fte 2 (8dFle Yw 56mm *dNAddlWom -0omwnwABm42g 514.20,6g

Exhibit A Page 4 of 5 Lon cum CumNWOi 0.w-mb-f 0100www54 ma VONfcpOJ(I] CONU CostEar fll e~r"C vtf" 4 1 2005 WA MA 1.0000 0 0 2 2000 WSA 1.000 1.0426 0 0 2 2010 1.0217 1.22 1.086 0 0 A 2011 1.2 1.046 1.1220 0 0 5 2012 IM26 1.066 1.1812 0 0

• Z013 1.0231 1.004 1.2314 0 0 7 2014 1.0235 1120 1.2637 0 0
• 2015 f.040 1,147 I-1AM 0 0 2016 W .0244 +1176 1.32 0 0 10 2017 1i024 1.204 1.4546 0 0 11 2016 1.02 1.25

                                    ,            .l43                     0               0 12          2015       1.*        1..'         1..60?                     0              0 13          2020       1020       1.300        1.0479                     0              0 14          2m I        .27       1.335        1.7179                     0               0 16           a        1.0272      1.371        1.7600                     0              0 IS          202,2      100317     1.409        1.6670                     0              0 117                    1.02262    1.440  "               1.V943      I".304 Is          203        1.026      1.401       2.0290                41.0"3          8S.182 to          20"        1.0292     I.538       11152                 01.422         103.=6 20         2027       1.1'r;      1.51        2.2051                941           203.910 21          2028      1.0304      1.629       21 2                  48.380         111.23?

22 202 1.0310 I.M7 UM96 48.215 1I&M6 n3 2030 I.OX2I 1,723 2.44 40,M02 16a.160 24 =31 I.0261 1.7 2.6m4 ISA4? 49.06 25 2032 1.0281 1.914 .7153 16.761 4566 26 2033 1.0201 1.561 LW307 15 53 37 TOW dbx.5 400.1M 00.264 11 CPJ pw 01 t2010.2M, Ow 2-1% for 20302034 Ift u WOFaorcam far amp Wv201061 029. 2!Cwmu6Uag IlUMMo Cc*lEacAll Al4.259 WaWow. 13!Dawoom dahoOW Cad Egimal pea 200 NRC UAhingm (2006 6laft. 141 Dommoisioft Cod Es*s*

• Cuwas. Mxbmr Coo e1fg g,.

Exhibit A Page 3 of 5 EnleWg Leidalans, LLC Waterfood-3 Oscommissiorwnp Model Fees and OUMe Data(SmiThousands) Ta. Ovasllfled Trutafe fnd lnvasbeent Usesoer Fee USchedles TO Annual Fees 19.00 Adder (S$000) Bremeolints ($000 Basis points FixedIl Cwniutlave TO Trustse Fens 0 1 .00 TO Manag Fee 0 2Z70 5.:x0 17.70 11.350 11-30

                                              ,000                16.90             5.310             1.GA0 16.000                1570             13.520             30.180 20.000                9.50              6.280             3.480 a"Do R               " "                                        o.,,    N      ,cao+c-fM                             4.25%)

Revision Yer [3) 2010 JiusddloignAlocallon Faclor (1 100.00%i

       .Le g.ate*l Year (43                                             2M     TO Fund Fedeual Tax Rat* 11                 20.00%)

e W (Comwpasib Tax Rato M L.LF,+.m._n_,¶ 1 +..1a........ 36.48% End ofFunding Peiod 100m.00%...................- 1212030. Notes: [ICtJ tlcled so snte oleow eraorpls8260 - IS70IP* (20,000. 16.000) tlO.000 For balance f $25M: TO Management Fee o 41.210 36.460 + (9.50* *(25.000 - 20.000))/ 10.000. [21 BWdDebts wreassumed o be zero. 131First year sho"n0 impa of rvised dec<mmlawrtg ree"e resiremmmnt [41 Year upon whichdthe dwi otn g cos esltimate Is bae%" [51State income Tsx Rate Ii W0%, ~ltive rate Is 5.35%. 1l1 Entergy Lovisiana. LLC. tunding werest in Watestrd-3 is 100%. [71 Nuclest Cost Escalator Is 4 25% 181 Production demand sftoca*o" for Louisiana Retail 0

ORDER NO. U-31237 EXHIBIT B

Exhibit B Step Page I ofs

• 5-Year

Exhibit B 0 Page 2 of S Ednty Go*Stags LagIt* LLC RPimsw 9 oowmft~ru mod Non-Tax Ousll d TrdWCeis NMrTea Oua8Sed TRW Ub* RlW#Mi* Oarrimn barier MILg4 He Decommi ~ ITO% No Yewr R~n [I] R30 ToTrig M5 SA~ 1~41 F-~L IM N Exerm. M 101t BM"P I i elnh Bat@nof1330111i '148315 2 2010 7.843 &.45% 0 82a 17 05 0 18t9, 0.00M% 3 2011 7.043 5.54% 0 881 18 884 0 18.858 0.00% 4 2012 ',043 &,M09. 0 874 19 @51 0 17,511 0.00% 5 2013 7.843 8.8% 0 1.043 19 1.024 0 18.834 0.00% 6 2014 7.843 5.97% 0 1.123 20 1.103 0 19.837 0.00% 7 2015 B.909 &22% 0 1.194 21 1.173 0 20.WAS 0.0% 8 2018 8.99 1101% 0 1,289 22 1.247 0 22.067? O. " 9 2017 8.9901 &02% 0 1.346 23 1.324 0 23,M1 0.00% 10 2016 8.06 41.04% 0 1,434 25 1.40 0 24.790 0.00% 11 2019 8.99 6&06% 0 1528 26 1.490 0 Z289 1.00% 12 2020 10.0195 &0% 0 1,523 27 1.505 0 27.84 0.00% 13 2021 10,1 60.10% 0 1,724 29 1.606 0 29.579 0.00%

   ,4             222              10,195         602%               0         1.807         10        I.77            0             31.3m      C00%

IS 2023 10.1" S.97% 0 1.O00 32 1.88 0 33.225 000% il 2024 10.1AM &.25% 0 1,787 33 1.734 0 34.95 0.00% 17 2025 11.603 &10% 0 1.80 35 1,771 12.408 24,331 0.00% 18 2020 11.8A3 4.89% 0 1,204 25 1.178 28,499 0 0.00% 19 2027 11.093 4.89% 0 0 0 0 0 0 0.00O 20 2028 A1V103 4.89% 0 0 0 0 0 0 100% 21 2029 11.81 4.48% 0 0 0 0 0 0 0.00% 22 2030 13.513 4.80% 0 0 0 0 0 0 0.00% 23 2031 0 451% 0 0 0 0 0 0 0.00% 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 0.00% IlI see F..or e Page 1. (21P1*01. 40f4* ii-40 law (31 R~evwxm eq&*n- * (I. -uam" Perow"Wil 141prio Yew lianr Comrpowuld Soodanmilat 5 Cwaet YetWE m Re*e ,

• Cum* Yew T-wu* "CuMYo.u Erk Rome.

153 CaelcuaMud an efsege babnce (Avg Do - Pior Yr. 551. * %(ttruIMin

• EamuZ) in gt 50rdance with the fhe iAde for teloee "d mewgwo wd aaplpable tax ris.m 54e S E 9b4ItB Pae 5 M83 Tnjorfo, + EarotbV - Lmengoomrno Fe.

(7MAsumftes 1 Non-Tax QO*Md Batance Is utftod Io pay ft daowwoasoiel thei costs befoe IO TO Bswom Ste Extbk 6 Pe" 4 for the 8 aL (8)Prior Yew aatence* NeoAddisclon. Decommilselwdr Experx.uteL

Exhibit B Page 2 of 5 amwg OwM selat.LuNWUl LLC R96r BOW 0.mod~ MOMa Laulatwnnew Nan-Tax Oi0fud ?,ani 0.DOW laNI-Tsa00*99.0 YTla Line Revenue 6*i mnt" MOM Rd Demon0

• 4. to Wa Yjes Rn 11 at 2 ToTiust133 fwrf 141 AMi.m P)EpnLr F"!.LLAdats o"I wt 2 2010 7.843 &45% 0 822 17 606 0 $15891 0.00%

3 2011 7.843 5.54% 0 881 to 684 0 1i.58 0.00% 4 2012 T.043 5.80% 0 974 19 956 0 17,511 0.00% 5 2013 7.843 5.87% 0 1.043 19 1.024 0 18.I4O 0.00% 6 2014 7.843 5.97% 0 1.123 20 1.103 0 19,837 0 7 2015 8.&H6 5.99% 0 1,194 21 1.173 0 20,800 0.00% a 2016 t.w9o 0.01% 0 1.209 22 1.247 0 22.057 0.O%" 9 2017 0.16 4.02% 0 1348 23 1,324 0 23.281 0.00% 10 2016 &.56 8.04% 0 1.434 25 1.100 0 24.70 1.00% I1 2010 6.996 am06% 0 125 26 1.406 0 2&.289 0.00% 12 2020 10.105 8.06% 0 1.33 27 1.505 0 27,84 0.00% 13 2021 Wo.1o6 6.09% 0 1,724 29 1.695 0 29.570 0.0016

-A           2022             10.196        4&02%          0        1.607             so       1,71          a      11.3S,    0.00%

Is 2023 10.191 S.97 0 1.90 32 I.'m 0 33.235 OO% 16 2024 10.195 5.25% 0 1,76? 23 3 .334 0a 34.9m 0.00 17 2025 11.693 6.10% 0 1.8" 35 1.771 12.408 24.321 O00% 18 2026 11,893 4.89% 0 1204 25 1.176 25,499 0 Q.O 19 2027 11,693 4.609% 0 0 0 0 0 0 000% 21 2028 11.593 4.89% 0 0 0 0 0 0 O00% 21 2029 1t.693 4,86% 0 0 0 0 0 0 0.00% 22 2030 13.513 4C09% 0 0 0 0 0 0 0.00% 23 2031 0 451% 0 0 0 0 0 0 0.00% 24 2032 0 4.51% 0 0 0 0 0 0 G00% 25 20(W 0 4.51% 0 0 0 0 0 0 0.00% 26 2034 0 4.61% 0 0 0 0 0 0 0.00% 111S4e ExiI a Pogp I. (21 PM*ectWafter-W eanno,W*. (31Reveue~a ROL*-- * (I~ 0- Am't' PWernlaea1 Pior Year Blane Com* .na"d"Smnanmnay d C t YoauEnngs Rate

• 1 Cumdu Year Transfe CI eft Year Eankv Rate.

(S3Caklated on avoeta belnce (Avg Sa- Prior Yr.Bd. . %(Tranisfen *eamlkna) inoccwdm wt th fee sch edatWfor bultess and nmagmS md appkss Lemrstes. See5£ M a Ps" S 16PTranefIe + Eambnth . Mm.91wm1 Fee. (7'Asmu~es OWtthe INn-Tax Ous*MtdBalsace is ublMadto pay thedmctrnouaw.& costsbefte WATO iWw4& See Exh*ie8 Page4 th Me -ttaL (83Pita, Vest Balae - NotAddlona - Decanmlaalanhtg Expowengne.

Exhibit B Pap3 of5 MW 3O eow. Lm*4un La" LOuWBOl ReW TaxOauahid Tnnl Oda0 TTa QUM2 TTedA LIM Revenue E g lT rh UPCo w O . NO 'VOW RFrA (If "RM To rM Ern U1 Fe 5 Ad33 101~ier&. M~f BaloncL II A.-o-I OeghwlklgBOleM13131110 3.4 2 2010 7.543 &0% Z8.614 1.431 31 4.014 0 36.164 100.00% 3 2011 7.643 6.63.% 7643 2.414 36 40.221 0 47,179 00.00% 4 2012 T.643 6.20% 7.843 3213 42 t1114 0 56.189 100.00% 5 2013 7.413 6.20% 7.643 3.964 49 11.756 0 6".041 100.00% 6 2014 7.843 &.47% 7.843 4.652 67 12.863 0 62.6 100.00% 7 2015 0,906 6530% 8.1196 &.741 as 14.078 0 P.263 100.00% a 2016 8,NO 4.12% 8.211 6.738 7s '5.6S9 0 '12.92 100.00% 0 2017 6T090 6& 4% .09 7Am4 as 16,711 0 120,633 100,00% 10 2018 60.66 6.571 6.906 8052 g6 17.852 0 147.485 100.00% II 2019 too .5W0% &1M0 150178 107 9.0664 0 166.549 10.O00% 12 2020 10.105 6.60% 10.195 I1.28 t20 21.504 0 166,153 I0.O0% 13 2021 10,105 6.6M% 10,196 13.011 133 2&.01 0 Z11224 100.00% 14 2022 10.195 6.."% 10.125 14.620 148 24.867 0 236.901 200.00%

 . is 15 1

16 19 2023 202 2025 2M0 2027 10,195 10,195 "1.83 11.603 11.603 e.33m a612% 5,75% 5,76%

                                            .Te7%

10.195 20.295 21.503 t1.833 11.693 15.641

                                                                       *1656 17.143 16,647 10.243 254 260 197 215 220 2S.672 26.581 28*39 30=

WI.T71 23.153 103.721 0 0 0 26IJ,3 208.154 318,793 3234575 260..70 ioo.0o% 100.00% 100.00% MOM 200.00% 20 2026 11.03 5.76% 12.603 14.9"7 173 26.408 07.774 270.26 100.00% 22 2029 11,603 &16% I1s693 0.61i3 128 22,376 97.507 134.166 100j"A 22 2030 13.513 5,76% 130513 a.xe8 200 21.642 70.3768 85,30 100.00% 23 2031 0 4.88% 0 4.0 64 4.156 S06108 3A78 6 100,00% 24 2022 0 4.16% 0 1.0g0 35 1.921 24,71 16.632 100.00% 25 23 0 4.680% 0 622 20 801 15.117 1.5ts 100.00% 26 2034 0 4.0a% 0 75 7 67 1.564 0 100.00% Notes. III a"e EXhF aiPa*e 1. M2 Projeced Atlet-.o Oeevig rate. 133Reyerw Raqlkr.rem4 , ueofpaig psurae.t (42 Prior Y*e Sar no CompoMrded SWMNlaly Cof a20 Year Earnins.Rats Curem Yew Transfer Curnerd ver Earngs fte. 151Caladeted ranavwqe belawc (A g4 Od

• Prim Yr. EWL* NaITuialua
• Iringa2 inl mdallm oft to6 Oft $do""a forSMua madmemown U-4 "&"al la MweeSa"EalaM Bae pop (61TmWeer- Eambuge- Maeageer Foe.

(71Assuerse Ow Me NMe-Tax QuuaWW Slsamne Is u]zed to pay 42 deczzersior" costs before 0*2TO Balance See ULU 8 Page 4. [() Prior Yearf alnce Net Addlme - Oeoornr "ledO.. owe.e 0

Exhibit B Page 4 of S Enm~y Guff5151. Lojmwa U.C

                                                     -, W ov mmaw             up" .o.*,

Lh" No yew Lb~iC~m CP3U L1 CLUIL CPIU cum. Cu¶ wA con 0Sm(21

                                                         ~        P.Po P Ig.a4
                                                                   ?M6B            EVIL 70%1of 5081.W              LA id    5 AIRetal
                                                                                                                             ~ L
                                                                                                                       ..I0L(tL 1          200         MA       14A              1.00W                     0                       0              00 z        209           MA    1.000               um042                   0                       0              0                  0 3          2010      1.0217    1.022             1.0m88                    0                       0              0                  0 4          2011      10222     1.045             1.1330                    0                       0              0                  0 5          2012      1.0228    1.00              S.1812                    0                       0              0 8          2013         I0231  1.004             1.2314                    0                       0              0                  a 7          2014      t.038     1..20             1237                      0                       0              0                  0 8          202S      1.0240    1.147             1.3383                    0                       0              0                  0 9          2M8       1.0244    1.178             1.,05                    0                        0             0                  0 10          2017      1.0240    1.204             IAS15                    0                       0              0                  0 it          2028      1.0254    1.235             2.5183                   0                        0             0                   0 12          2010      1.02m     t.2117            1.5807                   0                        0             0                   0 13          2020      1.0283    1.300            1.847l                    0                       0              0                  0 14          2021      1.028O    1.3"8             1.7173                   0                       0              0                   0 1s          2022      1.0272    1.371            I.7900                    0                       0              0                  0 10          2023      1.02?7    1.400            1.8870                      0                                    0                  0 11          2024      I.0a      1.440            1.54,3                    0                       0              0                  0 18          2025     1.28       1.491            2.z0                 11.043                  .A.330          $.115             12.408 1           20        1.0293    1.5m5              .1152              41.68                  24.074         23.188             48.042 20          2M7       1.08      1.581             u"5                 84038                  48.830         47,'              103.721 2t            S 2.=25     ,.0304                     288                  76.5O4                 '44.18         42.532             07.774 22          202n      t.0310    1.8              26                   SO.5?                  20.29          28019              67".50 23          2030      1.0241    1.723            2.4964               W0.88?                 25..49         28.1LO             7I..76 24          2031      1.028     1.7M              .6048               34.740                 101105.23m                        s0.1 25          2032      1.0281    1.814            Z.7163               1WY467                   0.485          9.119            24.781 26          2033      1.0281    2.81             2.8307               10.14                    SA83M          6.623            15.617 27          2034     1.0281     1.10             2.8810                  960                     557            537              1.584 28        Tag Espwon                                                 378.71T               217.782         209.126            453.220 III CPIUpf Per   aI kuOg Fcawas for 2010.-202&. Oi 2.01%#or 2M302034 ie Me awm       ~2010 fo       b252M.

M2 CwuAmulv MWIWCntfoIa W. 14.25% gpe yew. 131O coswniw&f Cost paF.n2. 2008y NR Avmxmiua= (08010 1410.oo-wh"ut Co mm 'eni1 CamQ v 1625(2001)

• 1410R~sWAmcnlOwwe POAwith E77(42.5%(

Enfovg Outl821.6Fu ii'dlfl (51 CEGSL Fwn-ng Sh"r ofCos EsamaN I (Loidinfl Re*WPiaucdacin Ownand A&ocntn (98.3094%81 161Loe~uisaROW - cwnwls§v Nudst cogsesraista

Exhibit 8 Pape 5ofs EntargGOlStab" Louisistra. I.S. RWvrBn eomnaien Modve -LouisIaa

                                                        .O.s gild Other Data(I in Thousendsl Tax Qaueit~d Tinns. end Investment Manstser Fee Schedules fU TO Aginual Fees                             6.320 Adder (S 0001 BreAloodlae   ($000)      Basis Poises        7usdIll           Cwumtalivs TO Maralgat, Asset Based Trustee Fee                   0.3,3                 17.50             2.46"             2.467 2.063                  15.00             1.313             3-779 2.667 0                    13.50 15.50            O075               4.54W 3.333                  12.00            0900               &5"4 4.167                   9.50             1.000             6.554 2.333                   7.00            7.758             14.312 Non-Tax      uffe      mse    andtlbl~oftol    14ef(MM91'  Fog 30110du Ma NTQ Annual Fee                              51000 Ad.     $000)

Breakhpoint (So0) BaUW Points FiYed(( Cumulative NTO Manager &Assel 0 18.50 Based Trustee Fee 1.000 17.50 I18 1.650 0 1.560 2.0o0 2."00 15.00 13s50 12.00 O.M6 Q66O 0.676 2.630 1490 41165 3.00 7.0 O.1 4.217 Miscefllanous *Mou OA4 ead DW Rats 23% Nude.rcosteEs.aator, ) 4.25% Revigion Ye 131 =0 o GoS.. LARoatl 181 9.30943% Coal usltmate Year [41 2005 To Fund Federal Tax Nate 96 & Aftrerl 20).00% Comosft Effetve Tax RaoS) 389 3.4% End of Ftm g Peraod 1201J" Enserg Gull Suas Ownersp ShareM1 100.00% Notes: (I Calculated as in thetallowing example: Fm, balance of51M: TO Management Fee .9.837 &6S54

• 7,Dbp"(10.00- 4.1567))l10.000.

121Sad OWelshandled in Cost of Service Study. (31 First year sto,,g impact of revised deconmnissionng revenue requirements. 141Year uWowhIh the denri osataestat Mone isbasead. (SI Loumiana Income Tax Reg is.6.0%. however. in Louisiana Federal Incometaxes are deductile. therefore the effective Louisiana rate is 5.35%. The effective Fe*dr" Rate is 33.13% msutng in Composite Rate of 38.48%. J61CasnEstimate provided lot Reguiated Pottion (70%)woEGSt.tndig matreatis 100%. (71 Nuclear Cos Escalaitors 4.25% 181Per the 2009 FRP based on 1213tIM resnYear. Thisis LARNaiaporto of 1GSL. (9, Effecuve FederalTax Rates fr Or ade*d Trusts. These IluslA do not pay state taxes.

Attachment 3-E (Page 1 of 49) PUCT Order in Docket No. 39896

PUC DOCKET NO. 39896 "%%U4 \, SOAH DOCKET NO. 473-12-2979 APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMSS INC. FOR AUTHORITY TO CHANGE § ov RATES, RECONCILE FUEL COSTS, § OF TEXAS AND OBTAIN DEFERRED § ACCOUNTING TREATMENT § ORDER This Order addresses the application of Entergy Texas, Inc. for authority to change rates, reconcile fuel costs, and defer costs for the transition to the Midwest Independent System Operator (MISO). In its application, Entergy requested approval of an increase in annual base-rate revenues of approximately $111.8 million (later lowered to $104.8 million), proposed tariff schedules, including new riders to recover costs related to purchased-power capacity and renewable-energy credit requirements, requested final reconciliation of its fuel costs, and requested waivers to the rate-filing package requirements. On July 6, 2012, the State Office of Administrative Hearings (SOAH) administrative law judges (ALJs) issued a proposal for decision in which they recommended an overall rate increase for Entergy of $28.3 million resulting in a total revenue requirement of approximately $781 million. The AUs also recommended approving total fuel costs of approximately $1.3 billion. The AJs did not recommend approving the renewable-energy credit rider and the Commission earlier removed the purchased-power capacity rider as an issue to be addressed in this docket.' On August 8, 2012, the ALJs filed corrections to the proposal for decision based on the exceptions and replies of the parties. 2 Except as discussed in this Order, the Commission adopts the proposal for decision, as corrected, including findings of fact and conclusions of law.

        'Supplemental Preliminary Order at 2, 3 (Jan. 19, 2012).

2Letter from SOAH judges to PUC (Aug. 8, 2012). AnnnnnnAq

PUC Docket No. 39896 Order Page 2 of 43 SOAH Docket No. 473-12-2979 I. Discussion A. Prepaid Pension Asset Balance Entergy included in rate base an approximately $56 million item named Unfunded Pension.3 This amount represents the accumulated difference between the annual pension costs calculated in accordance with the Statement of Financial Accounting Standards (SFAS) No. 87 and the actual contributions made by Entergy to the pension fund-Entergy contributed nearly $56 million more to its pension fund than the minimum required by SFAS No. 87.' In Docket No. 33309, the Commission allowed a pension prepayment asset, excluding the portion of the asset that is capitalized to construction work in progress (CWIP), less accrued deferred federal income taxes (ADFIT) to be included in rate base. 5 For the excluded portion, the Commission allowed the accrual of an allowance for funds used during construction (AFUDC). 6 The ALUs concluded that this approach was sound and should be followed in this case. 7 Thus, the ALJs recommended that the CWIP-related portion of Entergy's prepaid pension asset ($25,311,236) should be excluded from the asset and should accrue AFUDC.8 However, the ALJs did not address ADFIT. The Commission agrees that the CWIP-related portion of Entergy's pension asset should be excluded from the asset and that this excluded portion should accrue AFUDC. However, the Commission also finds that the impact of this exclusion on Entergy's ADFIT should be reflected. When items are excluded from rate base, the related ADFIT should also be excluded. The adjusted ADFIT for the prepaid pension asset remaining in Entergy's rate base should be reduced by $8,858,933, the deferred taxes related to the excluded $25 million. The Commission adds new finding of fact 28A to reflect this modification to Entergy's ADFIT. 3 Proposal for Decision at 23 (July 6, 2012) (PFD). 4PFD at 23-24. 5 Application of AEP Texas Central Companyfor Authority to Change Rates, Docket No. 33309, Order on Rehearing (March 4, 2008). 6 Remand of Docket No. 33309 (Application of AEP Texas Central Company for Authority to Change Rates), Docket No. 38772, Order on Remand (Jan. 20, 2011). 7 PFD at 26. 8 Id. at 24-26.

PUC Docket No. 39896 Order Page 3 of 43 SOAH Docket No. 473-12.2979 B. FIN 48 The Financial Accounting Standards Board's Interpretation No. 48 (FIN 48) prescribes the way in which a company must analyze, quantify, and disclose the potential consequences of tax positions that the company has taken that are legally uncertain. Entergy reported that its uncertain tax positions totaled $5,916,461. FIN 48 requires that this amount be recorded on Entergy's balance sheet as a tax liability. Entergy also reported that it made a cash deposit with the IRS in the amount of $1,294,683 associated with its FIN 48 liability. 9 The ALIs concluded that Entergy's FIN 48 liability should be included in its ADFIT balance, but the amount of the cash deposit made by Entergy to the IRS attributable to Entergy's FIN 48 liability should not be included in Entergy's ADFIT balance. Accordingly, the ALJs recommended that $4,621,778 (Entergy's FIN 48 liability of $5,916,461 less the $1,294,683 cash deposit Entergy has already made with the IRS) be added to Entergy's ADFIT balance and thus be used to offset Entergy's rate base.' 0 The ALJs did not recommend the addition of a deferred-tax-account rider because no party expressly advocated the addition of such a rider." The Commission adopts the proposal for decision regarding the adjustment to Entergy's ADFIT for the amount attributable to Entergy's FIN 48 liability. However, the Commission also follows its precedent regarding the creation of a deferred-tax-account tracker and modifies the proposal for decision on this point. In CenterPoint's Electric Delivery Company's last rate case, Docket No. 38339,12 the Commission found that tax schedule UTP-on which companies must describe, list, and rank each uncertain tax position-would provide the IRS auditors sufficient information to quickly determine which uncertain tax positions are of a magnitude worth investigating and that an IRS audit would be more likely to occur on some uncertain tax positions. If an IRS audit of a FIN 48 uncertain tax position results in an unfavorable outcome, the utility would not be able to earn a return on the amount paid to the IRS until the next rate case. 9 PFD at 26-27 (citing Rebuttal Testimony of Roberts, Entergy Ex. 64 at 6), 29 (citing Rebuttal Testimony of Roberts, Entergy Ex. 64 at 8).

        'oPFD at 29.
           /Id.at 29.

12 Application of CenterPoint Electric Delivery Company. LLC for Authority to Change Rates, Docket No. 38339, Order on Rehearing at 3-4 (June 23, 2011).

PUC Docket No. 39896 Order Page 4 of 43 SOAH Docket No. 473-12-2979 Accordingly, the Commission authorizes Entergy to establish a rider to track unfavorable FIN-48 rulings by the IRS. The rider will also allow Entergy to recover on a prospective basis an after-tax return of 8.27% on the amounts paid to the IRS that result from an unfavorable FIN-48 unfavorable-tax-position audit. The return will be applied prospectively to FIN-48 amounts disallowed by an IRS audit after such amounts are actually paid to the federal government. If Entergy subsequently prevails in an appeal of an unfavorable FIN-48 unfavorable-tax-position decision by the IRS, then any amounts collected under rider related to that overturned decision shall be credited back to ratepayers. The Commission adds new finding of fact 40A and deletes finding of fact 41 consistent with its decision to authorize the deferred-tax-account tracker. C. Capitalized Incentive Compensation Entergy capitalized into plant-in-service accounts some of the incentive payments made to employees and sought to include those amounts in rate base. The ALls determined that Entergy should not be able to recover its financially based incentive-compensation costs.13 Therefore, the portion of Entergy's incentive-compensation costs capitalized during the period July 1, 2009 through June 30, 2010 that were financially based was excluded from Entergy's rate base. The ALJs also determined that the actual percentages should be used to determine the amount that is financially based.14 In discussing Entergy's incentive compensation as a component of operating expenses, the AUs adopted the method advocated by Texas Industrial Energy Consumers (TIEC) for calculating the amount of the financially based incentive costs. This method uses the actual percentage reductions applicable to each of the annual incentive programs that included a 5 component of financially-based costs.' In its exceptions regarding capitalized incentive compensation, Entergy advocated for the use of TIEC's methodology to also calculate the amount of capitalized incentive compensation that is financially based. Entergy also noted that the amount of the disallowance reflected in the 3 PFD at 171. 14 Id. at 72. 15Id. at 174; see also Entergy's Exceptions to the Proposal for Decision at 25-26 (July 23, 2012). nnnnnnAnd

PUC Docket No. 39896 Order Page 5 of 43 SOAH Docket No. 473-12-2979 schedules, $1,333,352, was calculated using a disallowance factor that included incentive compensation tied to cost-control measures, which the Aids found to be recoverable in the operating-cost incentive-compensation calculation.16 When the TIEC methodology is applied to the capitalized incentive-compensation costs in rate base, the net result under TIEC's methodology is that only $335,752.96 should be disallowed from capital costs.17 The Commission agrees that capitalized incentive compensation that is financially based should be excluded from rate base and that the exclusion only applies to incentive costs that Entergy capitalized during the period from July 1, 2009 through June 30, 2010. However, the Commission finds that a consistent methodology should be used to calculate the amount to be excluded and therefore that TIEC's methodology should also be used for calculating the amount of capitalized financially based incentive-compensation costs that should be excluded from rate base. Accordingly, the total amount of capitalized incentive-compensation costs that should be disallowed from rate base is $335,752.96. Finding of fact 61 is modified to reflect this determination. As noted by Commission Staff, this disallowance to plant-in-service alters the expense for ad valorem taxes. Accounting for this disallowance, the appropriate expense amount for ad valorem taxes is $24,921,022,18 an adjustment of $1,222,106 to Entergy's test year amount. Finding of fact 151 is modified to reflect this adjustment to property taxes. D. Rate of Return and Cost of Capital The ALJs found the proper range of an acceptable return on equity for Entergy would be from 9.3 percent to 10.0 percent.19 The mid-point of the range is 9.65 percent. The ALJs found that the effect of unsettled economic conditions facing utilities on the appropriate return on equity should be taken into account and that the effect would be to move the ultimate return on equity towards the upper limits of the range that was determined to be reasonable. 20 The ALJs 16 Entergy's Exceptions to the Proposal for Decision at 25-26.

       "  Id. at 25-26.
       '8Commission Number-Run Memorandum at 2 (Aug. 28, 2012).
       '9PFD at 94.

2_Id. nnnnnnnnt

PUC Docket No. 39896 Order Page 6 of 43 SOAH Docket No. 473-12-2979 found that the reasonable adjustment would be 15 basis points, moving the reasonable return on equity to 9.80 percent.21 The Commission must establish a reasonable return for a utility and must consider applicable factors.22 The Commission disagrees with the ALJs that a utility's return on equity should be determined using an adder to reflect unsettled economic conditions facing utilities. The Commission agrees with the ALJs, however, that a return on equity of 9.80 percent will allow Entergy a reasonable opportunity to earn a reasonable return on its invested capital, but finds this rate appropriate independent of the 15-point adder recommended by the ALJs. A return on equity of 9.80 percent is within the range of an acceptable return on equity found by the AlJs. Accordingly, the Commission adds new finding of fact 65A to reflect the Commission's decision on this point. E. Purchased-Power Capacity Expense The ALJs rejected Entergy's request to recover $31 million more in purchased-power capacity costs than its actual test-year expenses because Entergy had failed to prove that the adjustment was known and measurable, 23 and because the request violated the matching principle. 24 Consequently, the AUs recommended that Entergy's test-year expenses of $245,432,884 be used to set rates in this docket.25 Entergy pointed to an additional $533,002 of purchased-power capacity expenses that were properly included in Entergy's rate-filing package, but not provided for in the proposal for decision. 26 The Commission finds that an additional $533,002 ($6,132 for test-year expenses for Southwest Power Pool fees, $654,082 for Toledo Bend hydro fixed-charges, and -$127,212 for an Entergy intra-system billing adjustment that were all recorded in FERC account 555) of purchased-power capacity costs were incurred during the test-year and should be added to the purchased-power capacity costs in Entergy's revenue requirement. The Commission modifies 21 Id. at 94. 22 PURA §§ 36.05 1, .052. 23 PFD at 108-09. 24 Id. at 109. 25 Id. 26 Entergy's Exceptions to the Proposal for Decision at 51. NNNfnnnnfl

PUC Docket No. 39896 Order Page 7 of 43 SOAH Docket No. 473-12-2979 findings of fact 72 and 86 to reflect the inclusion of the additional $533,002 of test-year purchased-power capacity costs, increasing the total amount to $245,965,886. F. Labor Costs - Incentive Compensation The AL~s found that $6,196,037, representing Entergy's financially-based incentives paid in the test-year, should be removed from Entergy's O&M expenses. 27 The ALJs agreed with Commission Staff and Cities that an additional reduction should be made to account for the FICA taxes that Entergy would have paid for those costs,2 8 but did not include this reduction in a finding of fact. The Commission agrees with the ALJs, but modifies finding of fact 133 to specifically include the decision that an additional reduction should be made to account for the FICA taxes Entergy would have paid on the disallowed fimancially-based incentive compensation. The Commission notes that this reduction for FICA taxes is reflected in the schedules attached to this Order.29 G. Affiliate Transactions OPUC argued that Entergy's sales and marketing expenses exclusively benefit the larger commercial and industrial customers, but the majority of the sales, marketing, and customer service expenses are allocated to the operating companies based on customer counts. Therefore, the majority of these expenses are allocated to residential and small business customers. OPUC argued that it is inappropriate for residential and small business customers to pay for these expenses. The ALJs did not adopt OPUC's position on this issue. The Commission agrees with OPUC and reverses the proposal for decision regarding allocation of Entergy's sales and marketing expense and finds that $2.086 million of sales and marketing expense should be reallocated using direct assignment. The Commission has 27 PFD at 175. 2' Id. at 175-76. 29 See Commission Number Run-Memorandum at 3 (Aug. 28, 2012). 30 Direct Testimony of Carol Szerszen, OPUC Ex. I at 44-45. nnnnnnnl7

PUC Docket No. 39896 Order Page 8 of 43 SOAH Docket No. 473-12-2979 previously expressed its preference for direct assignment of affiliate expenses.31 The Commission finds that the following amounts should be allocated based on a total-number-of-customers basis: (1) $46,490 for Project E10PCR56224 - Sales and Marketing - EGSI Texas; (2) $17,013 for Project F3PCD10049 - Regulated Retail Systems O&M; and (3) $30,167 for Project F3PPMMALI2 - Middle Market Mkt. Development. The remainder, $1,992,475, should be assigned to (1) General Service, (2) Large General Service and (3) Large Industrial Power Service. 32 The reallocation has the effect of increasing the revenue requirement allocated to the large business class customers and reduces the revenue requirement for small business and residential customers. New finding of fact 164A is added to reflect the proper allocation of these affiliate transactions. H. Fuel Reconciliation Entergy proposed to allocate costs for the fuel reconciliation to customers using a line-loss study performed in 1997. Entergy conducted a line-loss study for the year ending December 31, 2010, which falls in the middle of the two year fuel reconciliation period-July 2009 through June 201 1-and therefore reflects the actual line losses experienced by the customer classes during the reconciliation period. Cities argued that the allocation of fuel costs incurred over the reconciliation period should reflect the current line-loss study performed by Entergy for this case and recommended approval on a going-forward basis. Fuel factors under P.U.C. SUBST. R. 25.237(a)(3) are temporary rates subject to revision in a reconciliation proceeding described in P.U.C. SUBST. R. 25.236. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel reconciliation proceeding to include any issue related to the reasonableness of a utility's fuel 33 expenses and whether the utility has over- or under-recovered its reasonable fuel expenses. Cities calculated a $3,981,271 reduction to the Texas retail fuel expenses incurred over the reconciliation period using the current line-losses. The ALJs rejected Cities' proposed adjustment finding that the P.U.C. SUBST. R. 25.237(c)(2)(B) requires the use of Commission-3' Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965, Second Order on Rehearing at 87, COL 29 (Oct. 16, 1997). 32 Direct Testimony of Carol Szerszen, OPUC Ex. I at Schedule CAS-7. 33 Cities' Exceptions to the Proposal for Decision at 20-21 (July 23, 2012). Aflflfflnfno

PUC Docket No. 39896 Order Page 9 of 43 SOAH Docket No. 473-12-2979 approved line losses that were in effect at the time fuel costs were billed to customers in a fuel 34 reconciliation. The Commission agrees with Cities and reverses the proposal for decision regarding which line-loss factors should be used in Entergy's fuel reconciliation. Entergy used the 2010 study line-loss calculations to calculate the demand- and energy-related allocations in its cost of service analysis supporting its requested base rates. These same currently available line-loss factors should have been utilized in Entergy's fuel reconciliation. The Commission finds that Entergy's 2010 line-loss factors should be used to calculate Entergy's fuel reconciliation over-recovery. As a result, Entergy's fuel reconciliation over-recovery should be reduced by $3,981,271. Finding of fact 246A and conclusions of law 19A and 19B are added to reflect the Commission's finding that the 2010 line-loss factors be used to reconcile Entergy's fuel costs. I. MISO Transition Expenses During the Commission's consideration of the proposal for decision, the parties that contested the amount of Entergy's MISO transition expenses and how the transition expenses should be accounted for reached announced on the record that they had reached an agreement on these issues. 35 Those parties agreed that the MISO transition expenses would not be deferred and that Entergy's base rates should include $1.6 million for MISO transition expense. 36 The Commission adopts the agreement of the parties and accordingly modifies finding of fact 251 and deletes finding of fact 252. J. Purchased-Power Capacity Cost Baseline The Commission modified the amount of purchased-power capacity expense in the test-year to be $245,965,886 (see section E above). Finding of fact 255 is modified to reflect the change to the proper test-year purchased-power capacity expense. 34 PFD at 327-328. 35 Open Meeting Tr. at 138 (Aug. 17, 2012). 36 id. OOO0Oooo9

PUC Docket No. 39896 Order Page 10 of 43 SOAH Docket No. 473-12-2979 K. Other Issues New findings of fact 17A, 17B, 17C, 17D, and 17 E are added to reflect procedural aspects of the case after issuance of the proposal for decision. In addition, to reflect corrections recommended by the AUs, findings of fact 116, 123, 192, 194, and 202 are modified; and new finding of fact 182A is added. The Commission adopts the following findings of fact and conclusions of law: II. Findings of Fact ProceduralHistory

1. Entergy Texas, Inc. (ETI or the company) is an investor-owned electric utility with a retail service area located in southeastern Texas.

2. ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011, ETI served approximately 412,000 Texas retail customers. The Federal Energy Regulatory Commission (FERC) regulates ETI's wholesale electric operations.

3. On November 28, 2011, ETI filed an application requesting approval of: (I) a proposed increase in annual base rate revenues of approximately $111.8 million over adjusted test-year revenues; (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP) accompanying ETI's application and including new riders for recovery of costs related to purchased-power capacity and renewable energy credit requirements; (3) a request for final reconciliation of ETI's fuel and purchased-power costs for the reconciliation period from July 1, 2009 to June 30, 2011; and (4) certain waivers to the instructions in RFP Schedule V accompanying ETI's application.

4. The 12-month test-year employed in ETI's filing ended on June 30, 2011 (test-year).

5. 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 nnnnnfflfin

PUC Docket No. 39896 Order Page 11 of 43 SOAH Docket No. 473-12-2979 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.

6. The following parties were granted intervenor status in this docket: Office of Public Utility Counsel; the cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange (Cities), the Kroger Co.

(Kroger); State Agencies; Texas Industrial Energy Consumers; East Texas Electric Cooperative, Inc.; the United States Department of Energy (DOE); and Wal-Mart Stores Texas, LLC, and Sam's East, Inc. (Wal-Mart). The Staff (Staff) of the Public Utility Commission of Texas (Commission or PUC) was also a participant in this docket.

7. On November 29, 2011, the Commission referred this case to the State Office of Administrative Hearings (SOAH).

8. On December 7, 2011, the Commission issued its order requesting briefing on threshold legal/policy issues.

9. On December 19, 2011, the Commission issued its Preliminary Order, identifying 31 issues to be addressed in this proceeding.

10. On December 20, 2011, the Administrative Law Judges (ALJs) issued SOAH Order No. 2, which approved an agreement among the parties to establish a June 30, 2012 effective date for the company's new rates resulting from this case pursuant to certain agreed language and consolidate Application of Entergy Texas, Inc.for Authority to Defer Expenses Related to its Proposed Transition to Membership in the Midwest Independent System Operator,Docket No. 39741 (pending) into this proceeding. Although it did not agree, Staff did not oppose the consolidation.

11. On January 13, 2012, the ALIs issued SOAH Order No. 4 granting the motions for admission pro hac vice filed by Kurt J. Boehm and Jody M. Kyler to appear and participate as counsel for Kroger and the motion for admission pro hac vice filed by Rick D. Chamberlain to appear and participate as counsel for Wal-Mart.

nnnfnnnni

PUC Docket No. 39896 Order Page 12 of 43 SOAH Docket No. 473-12-2979

12. On January 19, 2012, the Commission issued a supplemental preliminary order identifying two additional issues to be addressed in this case and concluding that the company's proposed purchased-power capacity rider should not be addressed in this case and that such costs should be recovered through base rates.

13. ETI timely filed with the Commission petitions for review of the rate ordinances of the municipalities exercising original jurisdiction within its service territory. All such appeals were consolidated for determination in this proceeding.

14. On April 4, 2012, the ALJs issued SOAH Order No. 13 severing rate case expense issues into Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket No. 39896, Docket No. 40295 (pending).

15. On April 13, 2012, ETI adjusted its request for a proposed increase in annual base rate revenues to approximately $104.8 million over adjusted test-year revenues.

16. The hearing on the merits commenced on April 24 and concluded on May 4, 2012.

17. Initial post-hearing briefs were filed on May 18 and reply briefs were filed on May 30, 2012.

17A. On August 7, 2012, the SOAH ALJs filed a letter with the Commission recommending changes to the PFD. 17B At the July 27, 2012 open meeting, ETI agreed to extend the effective date of rates to August 31, 2012 to provide the Commission sufficient time to consider the issues in this proceeding. 17C. The Commission considered the proposal for decision at the August 17, 2012 and August 30, 2012 open meetings. 17D. At the August 30, 2012 open meeting, ETI agreed to extend the effective date of rates to September 14, 2012. 17E. At the August 17, 2012 open meeting, parties announced on the record a settlement of the amount of costs for the transition to MISO. nWonoo012

PUC Docket No. 39896 Order Page 13 of 43 SOAH Docket No. 473.12-2979 Rate Base

18. Capital additions that were closed to ETI's plant-in-service between July 1, 2009 and June 30, 2011, are used and useful in providing service to the public and were prudently incurred.

19. ETI's proposed Hurricane Rita regulatory asset was an issue resolved by the black-box settlement in Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744 (Dec. 13, 2010).

20. Accrual of carrying charges on the Hurricane Rita regulatory asset should have ceased when Docket No. 37744 concluded because the asset would have then begun earning a rate of return as part of rate base.

21. The appropriate calculation of the Hurricane Rita regulatory asset should begin with the amount claimed by ETI in Docket No. 37744, less amortization accruals to the end of the test-year in the present case, and less the amount of additional insurance proceeds received by ETI after the conclusion of Docket No. 37744.

22. A Test-Year-end balance of $15,175,563 for the Hurricane Rita regulatory asset should remain in rate base, applying a five-year amortization rate beginning August 15, 2010.

23. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance reserve.

24. The company requested in rate base its prepaid pension assets balance of $55,973,545, which represents the accumulated difference between the Statement of Financial Accounting Standards (SFAS) No. 87 calculated pension costs each year and the actual contributions made by the company to the pension fund.

25. The prepaid pension assets balance includes $25,311,236 capitalized to construction work in progress (CWIP).

26. It is not necessary to the financial integrity of ETI to include CWIP in rate base, and there was insufficient evidence showing that major projects under construction were efficiently and prudently managed.

nfnnnnn l3

PUC Docket No. 39896 Order Page 14 of 43 SOAH Docket No. 473-12-2979

27. The portion of the prepaid pension assets balance that is capitalized to CWIP should not be included in ETI's rate base.

28. The remainder of the prepaid pension assets balance should be included in ETI's rate base.

28A. When items are excluded from rate base, the related ADFIT should also be excluded. The amount of ADFIT associated with the $25 million capitalized to CWIP and excluded from rate base is $8,858,933. The adjusted ADFIT for the prepaid pension asset remaining in Entergy's rate base should be reduced by $8,858,933.

29. ETI should be permitted to accrue an allowance for funds used during construction on the portion of ETI's Prepaid Pension Assets Balance capitalized to CWIP.

30. The Financial Accounting Standard Board (FASB) Financial Interpretation No. 48 (FIN 48), "Accounting for Uncertainty in Income Taxes," requires ETI to identify each of its uncertain tax positions by evaluating the tax position on its technical merits to determine whether the position, and the corresponding deduction, is more-likely-than-not to be sustained by the Internal Revenue Service (IRS) if audited.

31. FIN 48 requires ETI to remove the amount of its uncertain tax positions from its Accumulated Deferred Federal Income Tax (ADFIT) balance for financial reporting purposes and record it as a potential liability with interest to better reflect the company's financial condition.

32. At test-year-end, ETI had $5,916,461 in FIN 48 liabilities, meaning ETI has, thus far, avoided paying to the IRS $5,916,461 in tax dollars (the FIN 48 liability) in reliance upon tax positions that the company believes will not prevail in the event the positions are challenged, via an audit, by the IRS.

33. ETI has deposited $1,294,683 with the IRS in connection with the FIN 48 liability.

34. The IRS may never audit ETI as to its uncertain tax positions creating the FIN 48 liability.

35. Even if ETI is audited, ETI might prevail on its uncertain tax positions.

36. ETI may never have to pay the IRS the FIN 48 liability.

AnnnnfIA

PUC Docket No. 39896 Order Page 15 of 43 SOAH Docket No. 473-12-2979

37. Other than the amount of its deposit with the IRS, ETI has current use of the FIN 48 liability funds.

38. Until actually paid to the IRS, the FIN 48 liability represents cost-free capital and should be deducted from rate base.

39. The amount of $4,621,778 (representing ETI's full FIN 48 liability of $5,916,461 less the

     $1,294,683 cash deposit ETI has made with the IRS for the FIN 48 liability) should be added to ETI's ADFIT and thus be used to reduce ETI's rate base.

40. ETI's application and proposed tariffs do not include a request for a tracking mechanism or rider to collect a return on the FIN 48 liability.

40A. It is appropriate for ETI to create a deferred-tax-account tracker in the form of a rider to recover on a prospective basis an after-tax return of 8.27% on the amounts paid to the IRS that result from an unfavorable FIN 48 audit. The rider will track unfavorable FIN 48 rulings and the return will be applied prospectively to FIN 48 amounts disallowed by an IRS audit after such amounts are actually paid to the federal government. If ETI prevails in an appeal of a FIN 48 decision, then any amounts collected under the rider related to that decision should be credited back to ratepayers.

41. Deleted.

42. Investor-owned electric utilities may include a reasonable allowance for cash working capital in rate base as determined by a lead-lag study conducted in accordance with the Commission's rules.

43. Cash working capital represents the amount of working capital, not specifically addressed in other rate base items, that is necessary to fund the gap between the time expenditures are made and the time corresponding revenues are received.

44. The lead-lag study conducted by ETI considered the actual operations of ETI, adjusted for known and measurable changes, and is consistent with P.U.C. SUBST.

R. 25.23 1(c)(2)(B)(iii). nnnnnnli

PUC Docket No. 39896 Order Page 16 of 43 SOAH Docket No. 473-12-2979

45. It is reasonable to establish ETI's cash working capital requirement based on ETI's lead-lag study as updated in Jay Joyce's rebuttal testimony and on the cost of service approved for ETI in this case.

46. As a result of the black-box settlements in Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 (Nov. 7, 2008) and Docket No. 37744, the Commission did not approve ETI's storm damage expenses since 1996 and its storm damage reserve balance.

47. ETI established a prima facie case concerning the prudence of its storm damage expenses incurred since 1996.

48. Adjustments to the storm damage reserve balance proposed by intervenors should be denied.

49. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance reserve.

50. ETI's appropriate Test-Year-end storm reserve balance was negative $59,799,744.

51. The amount of $9,846,037, representing the value of the average coal inventory maintained at ETI's coal-burning facilities, is reasonable, necessary, and should be included in rate base.

52. The Spindletop gas storage facility (Spindletop facility) is used and useful in providing reliable and flexible natural gas supplies to ETI's Sabine Station and Lewis Creek generating plants.

53. The Spindletop facility is critical to the economic, reliable operation of the Sabine Station and Lewis Creek generating plants due to their geographic location in the far western region of the Entergy system.

54. It is reasonable and appropriate to include ETI's share of the costs to operate the Spindletop facility in rate base.

55. Staff recommended updating ETI's balance amounts for short-term assets to the 13-month period ending December 2011, which was the most recent information available.

nnnnnn*nl

PUC Docket No. 39896 Order Page 17 of 43 SOAH Docket No. 473-12-2979 Staff's proposed adjustments should be incorporated into the calculation of ETI's rate base.

56. The following short-term asset amounts should be included in rate base: prepayments at

     $8,134,351; materials and supplies at $29,285,421; and fuel inventory at $52,693,485.

57. The amount of $1,127,778, representing costs incurred by ETI when it acquired the Spindletop facility, represent actual costs incurred to process and close the acquisition, not mere mark-up costs.

58. ETI's $1,127,778 in capitalized acquisition costs should be included in rate base because ETI incurred these costs in conjunction with the purchase of a viable asset that benefits its retail customers.

59. In its application, ETI capitalized into plant in service accounts some of the incentive payments ETI made to its employees. ETI seeks to include those amounts in rate base.

60. A portion of those capitalized incentive accounts represent payments made by ETI for incentive compensation tied to financial goals.

61. The portion of ETI's incentive payments that are capitalized and that are financially-based should be excluded from ETI's rate base because the benefits of such payments inure most immediately and predominantly to ETI's shareholders, rather than its electric customers. ETI's capitalized incentive compensation that is financially based is

     $335,752.96 and should be removed for rate base.

62. The test-year for ETI's prior ratemaking proceeding ended on June 30, 2009, and the reasonableness of ETI's capital costs (including capitalized incentive compensation) for that prior period was dealt with by the Commission in that proceeding and is not at issue in this proceeding.

63. In this proceeding, ETI's capitalized incentive compensation that is financially-based should be excluded from rate base, but only for incentive costs that ETI capitalized during the period from July 1, 2009 (the end of the prior test-year) through June 30, 2010 (the commencement of the current test-year).

nnNnnnl7

PUC Docket No. 39896 Order Page 18 of 43 SOAH Docket No. 473-12-2979 Rate of Return and Cost of Capital

64. A return on common equity (ROE) of 9.80 percent will allow ETI a reasonable opportunity to earn a reasonable return on its invested capital.

65. The results of the discounted cash flow model and risk premium approach support a ROE of 9.80 percent.

65A. It is not appropriate to add 15 points to the ROE due to unsettled economic conditions facing utilities.

66. A 9.80 percent ROE is consistent with ETI's business and regulatory risk.

67. ETI's proposed 6.74 percent embedded cost of debt is reasonable.

68. The appropriate capital structure for ETI is 50.08 percent long-term debt and 49.92 percent common equity.

69. A capital structure composed of 50.08 percent debt and 49.92 percent equity is reasonable in light of ETI's business and regulatory risks.

70. A capital structure composed of 50.08 percent debt and 49.92 percent equity will help ETI attract capital from investors.

71. ETI's overall rate of return should be set as follows:

CAPITAL WEIGHTED AVG COMPONENT STRUCTURE COST OF CAPITAL COST OF CAPITAL LONG-TERM DEBT 50.08% 6.74% 3.38% COMMON EQUITY 49.92% 9.80% 4.89% TOTAL 100.00% 18.27% OperatingExpenses

72. ETI's test-year purchased capacity expenses were $245,965,886.

73. ETI requested an upward adjustment of $30,809,355 as a post-test-year adjustment to its purchased capacity costs. This request was based on ETI's projections of its purchased capacity expenses during a period beginning June 1, 2012 and ending May 31, 2013 (the rate-year).

000000018

PUC Docket No. 39896 Order Page 19 of 43 SOAH Docket No. 473-12-2979

74. ETI's purchased capacity expense projections were based on estimates of rate-year expenses for: (a) reserve equalization payments under Schedule MSS- 1; (b) payments under third-party capacity contracts; and (c) payments under affiliate contracts.

75. ETI's projection of its rate-year reserve equalization payments under Schedule MSS-I is based on numerous assumptions, including load growths for ETI and its affiliates, future capacity contracts for ETI and its affiliates, and future values of the generation assets of ETI and its affiliates.

76. There is substantial uncertainty with regard to ETI's projection of its rate-year reserve equalization payments under Schedule MSS-1.

77. ETI's projection of its rate-year third-party capacity contract payments includes numerous assumptions, one of which is that every single third-party supplier will perform at the maximum level under the contract, even though that assumption is inconsistent with ETI's historical experience.

78. There is substantial uncertainty with regard to ETI's projection of its rate-year third-party capacity-contract payments.

79. ETI's estimates of its rate-year purchases under affiliate contracts are based on a mathematical formula set out in Schedule MSS-4.

80. The MSS-4 formula for rate-year affiliate capacity payments reflects that these payments will be based on ratios and costs that cannot be determined until the month that the payments are to be made.

81. Over $11 million of ETI's affiliate transactions were based on a 2013 contract (the EAI WBL Contract) that was not signed until April 11, 2012.

82. There is uncertainty about whether the EAI WBL Contract will ever go into effect.

83. ETI projects purchasing over 300 megawatts (MW) more in purchased capacity in the rate-year than it purchased in the test-year.

84. ETI experienced substantial load growth in the two years before the test-year, and it continues to project similar load growth in the future.

nnnnnnn4 n

PUC Docket No. 39896 Order Page 20 of 43 SOAH Docket No. 473-12-2979

85. ETI did not meet its burden of proof to demonstrate that a known and measurable adjustment of $30,809,355 should be made to its test-year purchased capacity expenses.

86. ETI's purchased capacity expense in this case should be based on the test-year level of

     $245,965,886.

87. ETI incurred $1,753,797 of transmission equalization expense during the test-year.

88. ETI proposed an upward adjustment of $8,942,785 for its transmission equalization expense. This request was based on ETI's projections of its transmission equalization expenses during the rate-year.

89. The transmission equalization expense that ETI will pay in the rate-year will depend on future costs and loads for each of the Entergy operating companies.

90. ETI's projection of its rate-year transmission equalization expenses is uncertain and speculative because it depends on a number of variables, including future transmission investments, deferred taxes, depreciation reserves, costs of capital, tax rates, operating expenses, and loads of each of the Entergy operating companies.

91. ETI seeks increased transmission equalization expenses for transmission projects that are not currently used and useful in providing electric service. ETI's post-test-year adjustment is based on the assumption that certain planned transmission projects will go into service after the test-year. At the close of the hearing, none of the planned transmission projects had been fully completed and some were still in the planning phase.

92. It is not reasonable for ETI to charge its retail ratepayers for transmission equalization expenses related to projects that are not yet in-service.

93. ETI's request for a post-test-year adjustment of $8,942,785 for rate-year transmission equalization expenses should be denied because those expenses are not known and measurable. ETI's post-test-year adjustment does not with reasonable certainty reflect what ETI's transmission equalization expense will be when rates are in effect.

94. ETI's transmission equalization expense in this case should be based on the test-year level of $1,753,797.

000000020

A - PUC Docket No. 39896 Order Page 21 of 43 SOAH Docket No. 473-12-2979

95. P.U.C. SUBST. R. 25.231(c)(2)(ii) states that the reserve for depreciation is the accumulation of recognized allocations of original cost, representing the recovery of initial investment over the estimated useful life of the asset.

96. Except in the case of the amortization of the general plant deficiency, the use of the remaining life depreciation method to recover differences between theoretical and actual depreciation reserves is the most appropriate method and should be continued.

97. It is reasonable for ETI to calculate depreciation reserve allocations on a straight-line basis over the remaining, expected useful life of the item or facility.

98. Except as described below, the service lives and net salvage rates proposed by the company are reasonable, and these service lives and net salvage rates should be used in calculating depreciation rates for the company's production, transmission, distribution, and general plant assets.

99. A 60-year life for Sabine Units 4 and 5 is reasonable for purposes of establishing production plant depreciation rates.

100. The retirement (actuarial) rate method, rather than the interim retirement method, should be used in the development of production plant depreciation rates. 101. Production plant net salvage is reasonably based on the negative five percent net salvage in existing rates. 102. The net salvage rate of negative 10 percent for ETI's transmission structures and improvements (FERC Account 352) is the most reasonable of those proposed and should be adopted. 103. The net salvage rate of negative 20 percent for ETI's transmission station equipment (FERC Account 353) is the most reasonable of those proposed and should be adopted. 104. The net salvage rate of negative five percent for ETI's transmission towers and fixtures (FERC Account 354) is the most reasonable of those proposed and should be adopted. 105. The net salvage rate of negative 30 percent for ETI's transmission poles and fixtures (FERC Account 355) is the most reasonable of those proposed and should be adopted. 000000021

PUC Docket No. 39896 Order Page 22 of 43 SOAH Docket No. 473-12-2979 106. The net salvage rate of negative 30 percent for ETI's transmission overhead conductors and devices (FERC Account 356) is the most reasonable of those proposed and should be adopted. 107. A service life of 65 years and a dispersion curve of R3 for ETI's distribution structures and improvements (FERC Account 361) are the most reasonable of those proposed and should be approved. 108. A service life of 40 years and a dispersion curve of RI for ETI's distribution poles, towers, and fixtures (FERC Account 364) are the most reasonable of those proposed and should be approved. 109. A service life of 39 years and a dispersion curve of RO.5 for ETI's distribution overhead conductors and devices (FERC Account 365) are the most reasonable of those proposed and should be approved. 110. A service life of 35 years and a dispersion curve of R1.5 for ETI's distribution underground conductors and devices (FERC Account 367) are the most reasonable of those proposed and should be approved. 111. A service life of 33 years and a dispersion curve of LO.5 for ETI's distribution line transformers (FERC Account 368) are the most reasonable of those proposed and should be approved. 112. A service life of 26 years and a dispersion curve of LA for ETI's distribution overhead service (FERC Account 369.1) are the most reasonable of those proposed and should be approved. 113. The net salvage rate of negative five percent for ETI's distribution structures and improvements (FERC Account 361) is the most reasonable of those proposed and should be adopted. 114. The net salvage rate of negative 10 percent for ETI's distribution station equipment (FERC Account 362) is the most reasonable of those proposed and should be adopted. 000000022

PUC Docket No. 39896 Order Page 23 of 43 SOAH Docket No. 473-12-2979 115. The net salvage rate of negative seven percent for ETI's distribution overhead conductors and devices (FERC Account 365) is the most reasonable of those proposed and should be adopted. 116. The net salvage rate of positive five percent for ETI's distribution line transformers (FERC Account 368) is the most reasonable of those proposed and should be adopted. 117. The net salvage rate of negative 10 percent for ETI's distribution overhead services (FERC Account 369.1) is the most reasonable of those proposed and should be adopted. 118. The net salvage rate of negative 10 percent for ETI's distribution underground services (FERC Account 369.2) is the most reasonable of those proposed and should be adopted. 119. A service life of 45 years and a dispersion curve of R2 for ETI's general structures and improvements (FERC Account 390) are the most reasonable of those proposed and should be approved. 120. The net salvage rate of negative 10 percent for ETI's general structures and improvements (FERC Account 390) is the most reasonable of those proposed and should be adopted. 121. It is reasonable to convert the $21.3 million deficit that has developed over time in the reserve for general plant accounts to General Plant Amortization. 122. A ten-year amortization of the deficit in the reserve for general plant accounts is reasonable and should be adopted. 123. FERC pronouncement AR-15 requires amortization over the same life as recommended based on standard life analysis. A standard life analysis determined that a five-year life was appropriate for general plant computer equipment (FERC Account 391.2). Therefore, a five year amortization for this account is reasonable and should be adopted. 124. ETI proposed adjustments to its test-year payroll costs to reflect: (a) changes to employee headcount levels at ETI and Entergy Services, Inc. (ESI); and (b) approved wage increases set to go into effect after the end of the test-year. 125. The proposed payroll adjustments are reasonable but should be updated to reflect the most recent available information on headcount levels as proposed by Commission Staff. nnnno nnn_'i

PUC Docket No. 39896 Order Page 24 of 43 SOAH Docket No. 473-12-2979 In addition to adjusting payroll expense levels, the more recent headcount numbers should be used to adjust the level of payroll tax expense, benefits expense, and savings plan expense. 126. Staff has appropriately updated headcount levels to the most recent available data but errors made by Staff should be corrected. The corrections related to: (a) a double counting of three ETI and one ESI employee; (b) inadvertent use of the ETI benefits cost percentage in the calculation of ESI benefits costs; (c) an inappropriate reduction of savings plan costs when such costs were already included in the benefits percentage adjustments; and (d) corrections for full-time equivalents calculations. Staff s ETI headcount adjustment (AG-7) overstated operation and maintenance (O&M) payroll reduction by $224,217, and ESI headcount adjustment (AG-7) understated O&M payroll increase by $37,531. 127. ETI included $14,187,744 for incentive compensation expenses in its cost of service. 128. The compensation packages that ETI offers its employees include a base payroll amount, annual incentive programs, and long-term incentive programs. The majority of the compensation is for operational measures, but some is for financial measures. 129. Incentive compensation that is based on financial measures is of more immediate and predominant benefit to shareholders, whereas incentive compensation based on operational measures is of more immediate and predominant benefit to ratepayers. 130. Incentives to achieve operational measures are necessary and reasonable to provide utility services but those to achieve financial measures are not. 131. The $5,376,975 that was paid for long term incentive programs was tied to financial measures and, therefore, should not be included in ETI's cost of service. 132. Of the amounts that were paid pursuant to the Executive Annual Incentive Plan, $819,062 was tied to financial measures and, therefore, should be disallowed. 133. In total, the amount of incentive compensation that should be disallowed is $6,196,037 because it was related to financial measures that are not reasonable and necessary for the provision of electric service. An additional reduction should be made to account for the 000000024

PUC Docket No. 39896 Order Page 25 of 43 SOAH Docket No. 473-12-2979 FICA taxes ETI would have paid on the disallowed financially based incentive compensation. 134. The amount of incentive compensation that should be included in the cost of service is

     $7,991,707.

135. To attract and retain highly qualified employees, the Entergy companies provide a total package of compensation and benefits that is equivalent in scope and cost with what other comparable companies within the utility business and other industries provide for their employees. 136. When using a benchmark analysis to compare companies' levels of compensation, it is reasonable to view the market level of compensation as a range rather than a precise, single point. 137. ETI's base pay levels are at market. 138. ETI's benefits plan levels are within a reasonable range of market levels. 139. ETI's level of compensation and benefits expense is reasonable and necessary. 140. ETI provides non-qualified supplemental executive retirement plans for highly compensated individuals such as key managerial employees and executives that, because of limitations imposed under the Internal Revenue Code, would otherwise not receive retirement benefits on their annual compensation over $245,000 per year. 141. ETI's non-qualified supplemental executive retirement plans are discretionary costs designed to attract, retain, and reward highly compensated employees whose interests are more closely aligned with those of the shareholders than the customers. 142. ETI's non-qualified executive retirement benefits in the amount of $2,114,931 are not reasonable or necessary to provide utility service to the public, not in the public interest, and should not be included in ETI's cost of service. 143. For the employee market in which ETI operates, most peer companies offer moving assistance. Such assistance is expected by employees, and ETI would be placed at a competitive disadvantage if it did not offer relocation expenses. 000000025

PUC Docket No. 39896 Order Page 26 of 43 SOAH Docket No. 473-12-2979 144. ETI's relocation expenses were reasonable and necessary. 145. The company's requested operating expenses should be reduced by $40,620 to reflect the removal of certain executive prerequisites proposed by Staff. 146. Staff properly adjusted the company's requested interest expense of $68,985 by removing

     $25,938 from FERC account 431 (using the interest rate of 0.12 percent for calendar year 2012), leaving a recommended interest expense of $43,047.

147. During the test-year, ETI's property tax expense equaled $23,708,829. 148. ETI requested an upward proforma adjustment of $2,592,420, to account for the property tax expenses ETI estimates it will pay in the rate-year. 149. ETI's requested proforma adjustment is not reasonable because it is based, in part, upon the prediction that ETI's property tax rate will be increased in 2012, a change that is speculative is not known and measurable. 150. Staff s recommendation to increase ETI's test-year property tax expenses by $1,214,688 is based on the historical effective tax rate applied to the known test-year-end plant in service value, consistent with Commission precedent, and based upon known and measurable changes. 151. ETI's test-year property tax burden should be adjusted upward by $1,222,106 for a total expense of $24,921,022. 152. Staff recommended reducing ETI's advertising, dues, and contributions expenses by

     $12,800. The recommendation, which no party contested, should be adopted.

153. The final cost of service should reflect changes to cost of service that affect other components of the revenue requirement such as the calculation of the Texas state gross receipts tax, the local gross receipts tax, the PUC Assessment Tax and the Uncollectible Expenses. 154. The company's requested Federal income tax expense is reasonable and necessary. 155. ETr's request for $2,019,000 to be included in its cost of service to account for the company's annual decommissioning expenses associated with River Bend is not 000000026

PUC Docket No. 39896 Order Page 27 of 43 SOAH Docket No. 473-12-2979 reasonable because it is not based upon "the most current information reasonably available regarding the cost of decommissioning" as required by P.U.C. SUBST. R. 25.23 1(b)(1)(F)(i). 156. Based on the most current information reasonably available, the appropriate level of decommissioning costs to be included in ETI's cost of service is $1,126,000. 157. ETI's appropriate total annual self-insurance storm damage reserve expense is

        $8,270,000, comprised of an annual accrual of $4,400,000 to provide for average annual expected storm losses, plus an annual accrual of $3,870,000 for 20 years to restore the reserve from its current deficit.

158. ETI's appropriate target self-insurance storm damage reserve is $17,595,000. 159. ETI should continue recording its annual storm damage reserve accrual until modified by a Commission order. 160. The operating costs of the Spindletop facility are reasonable and necessary. 161. The operating costs of the Spindletop facility paid to PB Energy Storage Services are eligible fuel expenses. Affiliate Transactions 162. ETI affiliates charged ETI $78,998,777 for services during the test-year. The majority of these O&M expenses-$69,098,041-were charged to ETI by ESI. The remaining affiliate services were charged (or credited) to ETI by: Entergy Gulf States Louisiana, L.L.C.; Entergy Arkansas, Inc.; Entergy Louisiana, LLC; Entergy Mississippi, Inc.; Entergy Operations, Inc.; and non-regulated affiliates. 163. ESI follows a number of processes to ensure that affiliate charges are reasonable and necessary and that ETI and its affiliates are charged the same rate for similar services. These processes include: (a) the use of service agreements to define the level of service required and the cost of those services; (b) direct billing of affiliate expenses where possible; (c) reasonable allocation methodologies for costs that cannot be directly billed; (d) budgeting processes and controls to provide budgeted costs that are reasonable and Ofnnnnnnn7

PUC Docket No. 39896 Order Page 28 of 43 SOAH Docket No. 473-12-2979 necessary to ensure appropriate levels of service to its customers; and (e) oversight controls by ETI's Affiliate Accounting and Allocations Department. 164. Affiliates charged expenses to ETI through 1292 project codes during the test-year. 164A. The $2,086,145 in affiliate transactions related to sales and marketing expenses should be reallocated using direct assignment. The following amounts should be allocated to all retail classes in proportion to number of customers: (1) $46,490 for Project E10PCR56224 - Sales and Marketing - EGSI Texas; (2) $17,013 for Project F3PCD10049 - Regulated Retail Systems O&M; and (3) $30,167 for Project F3PPMMALI2 - Middle Market Mkt. Development. The remainder, $1,992,475, should be assigned to (1) General Service, (2) Large General Service and (3) Large Industrial Power Service. 165. ETI agreed to remove the following affiliate transactions from its application: (1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the amount of $2,553; (2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of $14,288; and (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929. 166. The $356,151 (which figure includes the $112,531 agreed to by ETI) of costs associated with Projects F5PCZUBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non Qual Pension/Benf Dom Utl) are costs that are not reasonable and necessary for the provision of electric utility service and are not in the public interest. 167. The $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts Settlement) are not normally-recurring costs and should not be recoverable. 168. The $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are related to ESI's operations, it is more immediately related to Entergy Louisiana, Inc. and Entergy New Orleans, Inc. As such, they are not recoverable from Texas ratepayers. 169. The $171,032 of costs associated with Project F3PPE9981S (Integrated Energy Management for ESI) are research and development costs related to energy efficiency programs. As such, they should be recovered through the energy efficiency cost recovery factor rather than base rates. nnnnnnniR

PUC Docket No. 39896 Order Page 29 of 43 SOAH Docket No. 473-12-2979 170. Except as noted in the above findings of fact Nos. 162-169, all remaining affiliate transactions were reasonable and necessary, were allowable, were charged to ETI at a price no higher than was charged by the supplying affiliate to other affiliates, and the rate charged is a reasonable approximation of the cost of providing service. JurisdictionalCost Allocation 171. ETI has one full or partial requirements wholesale customer - East Texas Electric Cooperative, Inc. 172. ETI proposes that [50 MW be set as the wholesale load for developing retail rates in this docket. Using 150 MW to set the wholesale load is reasonable. The 150 MW used to set the wholesale load results in a retail production demand allocation factor of 95.3838 percent. 173. The 12 Coincident Peak (12 CP) allocation method is consistent with the approach used by the FERC to allocate between jurisdictions. 174. Using 12CP methodology to allocate production costs between the wholesale and retail jurisdictions is the best method to reflect cost responsibility and is appropriate based on ETI's reliance on capacity purchases. Class Cost Allocation and Rate Design 175. There is no express statutory authorization for ETI's proposed Renewable Energy Credits rider (REC rider). 176. REC rider constitutes improper piecemeal ratemaking and should be rejected. 177. ETI's test-year expense for renewable energy credits, $623,303, is reasonable and necessary and should be included in base rates. 178. Municipal Franchise Fees (MFF) is a rental expense paid by utilities for the right to use public rights-of-way to locate its facilities within municipal limits. 179. ETI is an integrated utility system. ETI's facilities located within municipal limits benefit all customers, whether the customers are located inside or outside of the municipal limits. 000000029

PUC Docket No. 39896 Order Page 30 of 43 SOAH Docket No. 473-12-2979 180. Because all customers benefit from ETI's rental of municipal right-of-way, municipal franchise fees should be charged to all customers in ETI's service area, regardless of geographic location. 181. It is reasonable and consistent with the Public Utility Regulatory Act (PURA)

      § 33.008(b) that MFF be allocated to each customer class on the basis of in-city kilowatt hour (kWh) sales, without an adjustment for the MFF rate in the municipality in which a given kWh sale occurred.

182. The same reasons for allocating and collecting MFF as set out in Finding of Fact Nos. 178-181 also apply to the allocation and collection of Miscellaneous Gross Receipts Taxes. The company's proposed allocation of these costs to all retail customer classes based on customer class revenues relative to total revenues is appropriate. 182A. ETI's proposed gross plant-based allocator is an appropriate method for allocating the Texas franchise tax. 183. The Average and Excess (A&E) 4CP method for allocating capacity-related production costs, including reserve equalization payments, to the retail classes is a standard methodology and the most reasonable methodology. 184. The A&E 4CP method for allocating transmission costs to the retail classes is standard and the most reasonable methodology. 185. ETI appropriately followed the rate class revenue requirements from its cost of service study to allocate costs among customer classes. ETI's revenue allocation properly sets rates at each class's cost of service. 186. It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any replacement of a functioning light with a lower-wattage bulb. 187. It is appropriate to require ETI to prepare and file, as part of its next base rate case, a study regarding the feasibility of instituting LED-based rates and, if the study shows that such rates are feasible, ETI should file proposals for LED-based lighting and traffic signal rates in its next rate case. nnnnnnn~n

PUC Docket No. 39896 Order Page 31 of 43 SOAH Docket No. 473-12-2979 188. An agreement was reached by the parties and approved by the Commission in Docket No. 37744 that directed ETI to exclude, in its next rate case, the life-of-contract demand ratchet for existing customers in the Large Industrial Power Service (LIPS), Large Industrial Power Service-Time of Day, General Service, General Service-Time of Day, Large General Service, and Large General Service-Time of Day rate schedules. 189. ETI's proposed tariffs in this case did not remove the life-of-contract demand ratchet from these rate schedules consistent with the parties' agreement in Docket No. 37744. 190. A perpetual billing obligation based on a life-of-contract demand ratchet, as ETI proposed, is not reasonable. 191. ETI's proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the agreement that was adopted by the Commission as just and reasonable in Docket No. 37744. Accordingly, these tariffs should be modified as set out in Findings of Fact No. 192-194. 192. ETI's Schedule LIPS and LIPS Time of Day § VI should be changed to read: DETERMINATION OF BILLING LOAD The kW of Billing Load will be the greatest of the following: (A) The Customer's maximum measured 30-minute demand during any 30-minute interval of the current billing month, subject to §§ III, IV and V above; or (B) 75% of Contract Power as defined in § VII; or (C) 2,500 kW. 193. ETI's Schedule LIPS and LIPS Time of Day § VII should be changed to read: DETERMINATION OF CONTRACT POWER Unless Company gives customer written notice to the contrary, Contract Power will be defined as below: Contract Power - the highest load established under § VI(A) above during the 12 months ending with the current month. For the initial 12 months of Customer's service under the currently effective contract, the Contract Power shall be the kW specified in 000000031

PUC Docket No. 39896 Order Page 32 of 43 SOAH Docket No. 473-12.2979 the currently effective contract unless exceeded in any month during the initial 12-month period. 194. The Large General Service, Large General Service-Time of Day, General Service, and General Service-Time of Day schedules should be similarly revised to eliminate ETI's life-of-contract demand ratchet. 195. In its proposed rate design for the LIPS class, the company took a conservative approach and increased the current rates by an equal percentage. This minimized customer bill impacts while maintaining cost causation principles on a rate class basis. 196. It is a reasonable move towards cost of service to add a customer charge of $630 to the LIPS rate schedule with subsequent increases to be considered in subsequent base rate cases. 197. It is a reasonable move towards cost of service to slightly decrease the LIPS energy charges and increase the demand charges as proposed by Staff witness William B. Abbott. 198. DOE proposed a new Schedule LIPS rider-Schedule "Schedulable Intermittent Pumping Service" (SIPS) for load schedulable at least four weeks in advance, that occurs in the off-season (November through April), that can be cancelled at any time, and for load not lasting more than 80 hours in a year. For customers whose loads match these SIPS characteristics (for example, DOE's Strategic Petroleum Reserve), the 12-month demand ratchet provision of Schedule LIPS does not apply to demands set under the provisions of the SIPS rider. The monthly demand set under the SIPS provisions would be applicable for billing purposes only in the month in which it occurred. In short, if a customer set a 12-month ratchet demand in that month, it would be forgiven and not applicable in the succeeding 12 months. 199. DOE's proposed Schedule SIPS is not restricted solely to the DOE and should be adopted. It more closely addresses specific customer characteristics and provides for cost-based rates, as does another ETI rider applicable to Pipeline Pumping Service. 200. Standby Maintenance Service (SMS) is available to customers who have their own generation equipment and who contract for this service from ETI. 000000032

PUC Docket No. 39896 Order Page 33 of 43 SOAH Docket No. 473-12-2979 201. P.U.C. SUBST. R. 25.242(k)(1) provides that rates for sales of standby and maintenance power to qualifying facilities should recognize system wide costing principles and should not be discriminatory. 202. It is reasonable to move Schedule SMS toward cost of service by: (a) adding a customer charge equivalent to that of the LIPS rate schedule only for SMS customers not purchasing supplementary power under another applicable rate; and (b) revising the tariff as follows: C Distribution Transmission Charge (less than 69KV) (69KV and greater) Billing Load Charge ($/kW): Standby $2.46 $0.79 Maintenance $2.27 $0.60 Non-Fuel Energy Charge (c/kWh) On-Peak 4.245¢ 4.0740 Off-Peak 0.5750 0.5520 203. ETI's Additional Facilities Charge rider (Schedule AFC) prescribes the monthly rental charge paid by a customer when ETI installs facilities for that customer that would not normally be supplied, such as line extensions, transformers, or dual feeds. 204. ETI existing Schedule AFC provides two pricing options. Option A is a monthly charge. Option B, which applies when a customer elects to amortize the directly-assigned facilities over a shorter term ranging from one to ten years, has a variable monthly charge. There is also a term charge that applies after the facility has been fully depreciated. 205. It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.20 percent per month of the installed cost of all facilities included in the agreement for additional facilities. 000000033

PUC Docket No. 39896 Order Page 34 of 43 SOAH Docket No. 473-12-2979 206. It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rate and the Post Term Recovery Charge as follows: Selected Recovery Term Recovery Term Charge Post Recovery Term Charge 1 10.88% 0.35% 2 5.39% 0.35% 3 3.92% 0.35% 4 3.20% 0.35% 5 2.76% 0.35% 6 2.48% 0.35% 7 2.28% 0.35% 8 2.14% 0.35% 9 1.97% 0.35% 10 1.94% 0.35% 207. The revisions in the above findings of fact to Schedule AFC rates reasonably reflect the costs of running, operating, and maintaining the directly-assigned facilities. 208. It is reasonable to modify the Large General Service rate schedule by increasing the demand charge from $10.25 to $12.81; decreasing the energy charge from $.01023 to

     $.00513; and maintaining the customer charge at $425.05.

209. Staff's proposed change to the General Service (GS) rate schedule to gradually move GS customers towards their cost of service by recommending a decrease in the customer charge from the current rate of $41.09 to $39.91, and a decrease in the energy charges is reasonable and should be adopted. 210. ETI's Residential Service (RS) rate schedule is composed of two elements: a customer charge of $5 per month and a consumption-based energy charge. The Energy charge is a fixed rate of 5.8020 per kWh from May through October (summer). In the months November through April (winter), the rates are structured as a declining block, in which the price of each unit is reduced after a defined level of usage. 211. ETI's Schedule RS declining block rate structure is contrary to energy-efficiency efforts and the Legislature's goal of reducing both energy demand and energy consumption in Texas, as stated in PURA § 39.905. 000000034

A - PUC Docket No. 39896 Order Page 35 of 43 SOAH Docket No. 473-12-2979 212. Schedule RS winter block rates should be modified consistent with the goal set out in PURA § 39.905, with the initial phase-in of a 20 percent reduction in the block differential proposed by ETI and subsequent reductions should be reviewed for consideration at the occurrence of each rate case filing. 213. Other elements of Schedule RS are just and reasonable. Fuel Reconciliation 214. ETI incurred $616,248,686 in natural-gas expenses during the reconciliation period, which is from July 2009 through June 2011. 215. ETI purchased natural gas in the monthly and daily markets and pursuant to a long-term contract with Enbridge Inc. pipeline. ETI also transported gas on its own account and negotiated operational balancing agreements with various pipeline companies. 216. ETI employed a diversified portfolio of gas supply and transportation agreements to meet its natural-gas requirements, and ETI prudently managed its gas-supply contracts. 217. ETI's natural gas expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers. 218. ETI incurred $90,821,317 in coal expenses during the reconciliation period. 219. ETI prudently managed its coal and coal-related contracts during the reconciliation period. 220. ETI monitored and audited coal invoices from Louisiana Generating, LLC for coal burned at the Big Cajun 11, Unit 3 facility. 221. ETI's coal expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers. 222. ETI incurred $990,041,434 in purchased-energy expenses during the reconciliation period. 223. The Entergy System's planning and procurement processes for purchased-power produced a reasonable mix of purchased resources at a reasonable price. 000000035

PUC Docket No. 39896 Order Page 36 of 43 SOAH Docket No. 473-12-2979 224. During the reconciliation period, ETI took advantage of opportunities in the fuel and purchased-power markets to reduce costs and to mitigate against price volatility. 225. ETI's purchased-energy expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers. 226. ETI provided sufficient contemporaneous documentation to support the reasonableness of its purchased-power planning and procurement processes and its actual power purchases during the reconciliation period. 227. The Entergy system sold power off system when the revenues were expected to be more than the incremental cost of supplying generation for the sale, subject to maintaining adequate reserves. 228. The System Agreement is the tariff approved by the FERC that provides the basis for the operation and planning of the Entergy system, including the six operating companies. The System Agreement governs the wholesale-power transactions among the operating companies by providing for joint operation and establishing the bases for equalization among the operating companies, including the costs associated with the construction, ownership, and operation of the Entergy system facilities. 229. Under the terms of the Entergy System Agreement, ETI was allocated its share of revenues and expenses from off-system sales. 230. During the reconciliation period, ETI recorded off-system sales revenue in the amount of

      $376,671,969 in FERC Account 447 and credited 100 percent of off-system sales revenues and margins from off-system sales to eligible fuel expenses.

231. ETI properly recorded revenues from off-system sales and credited those revenues to eligible fuel costs. 232. The Entergy system consists of six operating companies, including ETI, which are planned and operated as a single, integrated electric system under the terms of the System Agreement. 233. Service schedule MSS-1 of the System Agreement determines how the capability and ownership costs of reserves for the Entergy system are equalized among the operating 000000036

PUC Docket No. 39896 Order Page 37 of 43 SOAH Docket No. 473-12-2979 companies. These inter-system "reserve equalization" payments are the result of a formula rate related to the Entergy system's reserve capability that is applied on a monthly basis. 234. Reserve capability under service schedule MSS- I is capability in excess of the Entergy system's actual or planned load built or acquired to ensure the reliable, efficient operation of the electric system. 235. By approving service schedule MSS-I, the FERC has approved the method by which the operating companies share the cost of maintaining sufficient reserves to provide reliability for the Entergy system as a whole. 236. Service schedule MSS-3 of the System Agreement determines the pricing and exchange of energy among the operating companies. By approving service schedule MSS-3, the FERC has approved the method by which the operating companies are reimbursed for energy sold to the exchange energy pool and how that energy is purchased. 237. Service schedule MSS-4 of the System Agreement sets forth the method for determining the payment for unit power purchases between operating companies. By approving service schedule MSS-4, the FERC has approved the methodology for pricing inter-operating company unit power purchases. 238. The Entergy system is planned using multi-year, annual, seasonal, monthly, and next-day horizons. Once the planning process has identified the most economical resources that can be used to reliably meet the aggregate Entergy system demand, the next step is to procure the fuel necessary to operate the generating units as planned and acquire wholesale power from the market. 239. Once resources are procured to meet forecasted load, the Entergy system is operated during the current day using all the resources available to meet the total Entergy system demand. 240. After current-day operation, the System Agreement prescribes an accounting protocol to bill the costs of operating the system to the individual operating companies. This protocol is implemented via the intra-system bill to each operating company on a monthly basis. nnnnnnn'47

PUC Docket No. 39896 Order Page 38 of 43 SOAH Docket No. 473-12-2979 241. ETI purchased power from affiliated operating companies per the terms of service schedule MSS-3 of the System Agreement. The payments made under Schedule MSS-3 to affiliated operating companies are reasonable and necessary, and the FERC has approved the pricing formula and the obligation to purchase the energy. ETI pays the same price per megawatt hour for energy under service schedule MSS-3 as does any other operating company purchasing energy under service schedule MSS-3 during the same hour. 242. The Spindletop facility is used primarily to ensure gas-supply reliability and guard against gas-supply curtailments that can occur as a result of extreme weather or other unusual events. 243. The Spindletop facility provides a secondary benefit of flexibility in gas supply. ETI can back down gas-fired generation to take advantage of more economical wholesale power, or use gas from storage to supplement gas-fired generation when load increases during the day and thereby avoid more expensive intra-day gas purchases. 244. ETI's customers received benefits from the Spindletop facility during the reconciliation period through reliable gas supplies and ETI's monthly and daily storage activity. 245. ETI prudently managed the Spindletop facility to provide reliability and flexibility of gas supply for the benefit of customers. 246. ETI proposed new loss factors, based on a December 2010 line-loss study, to be applied for the purpose of allocating its costs to its wholesale customers and retail customer classes. 246A. ETI's 2010 line-loss factors should be used to reconcile ETI's fuel costs. Therefore, ETI's fuel reconciliation over-recovery should be reduced by $3,981,271. 247. ETI's proposed loss factors are reasonable and shall be implemented on a prospective basis as a result of this final order. 248. ETI seeks a special-circumstances exception to recover $99,715 resulting from the FERC's reallocation of rough production equalization costs in FERC Order No. 720-A, and to treat such costs as eligible fuel expense. 000000038

PUC Docket No. 39896 Order Page 39 of 43 SOAH Docket No. 473-12-2979 249. Special circumstances exist and it is appropriate for ETI torecover the rough production cost equalization costs reallocated to ETI as a result of the FERC's decision in Order No. 720-A. Other Issues 250. A deferred accounting of ETI's Midwest Independent Transmission System Operator (MISO) transition expenses is not necessary to carry out any requirement of PURA. 251. ETI should include $1.6 million in base rates for MISO transition expense. 252. Deleted. 253. Transmission Cost Recovery Factor baseline values should be set during the compliance phase of this docket, after the Commission makes final rulings on the various contested issues that may affect this calculation. 254. Distribution Cost Recovery Factor baseline values should be set during the compliance phase of this docket, after the Commission makes final rulings on the various contested issues that may affect this calculation. 255. The appropriate amount for ETI's purchased-power capacity expense to be included in base rates is $245,965,886. 256. The amount of ETI's purchased-power capacity expense includes third-party contracts, legacy affiliate contracts, other affiliate contracts, and reserve equalization. Whether the amounts for all contracts should be included in the baseline for a purchased-capacity rider that may be approved in Project No. 39246 is an issue that should be decided in that project. III. 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, 36.101-.111, and 36.203.

000000039

PUC Docket No. 39896 Order Page 40 of 43 SOAH Docket No. 473-12-2979

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 and the Texas Administrative Procedure Act, Tex. Gov't Code Ann. Chapter 2001.

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)(1)-(3).

6. Pursuant to PURA § 33.001, each municipality in ETI's service area that has not ceded jurisdiction to the Commission has jurisdiction over the company's application, which seeks to change rates for distribution services within each municipality.

7. Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a municipality's rate proceeding.

8. ETI has the burden of proving that the rate change it is requesting is just and reasonable pursuant to PURA § 36.006.

9. In compliance with PURA § 36.051, ETI's overall revenues approved in this proceeding permit ETI a reasonable opportunity to earn a reasonable return on its invested capital used and useful in providing service to the public in excess of its reasonable and necessary operating expenses.

10. Consistent with PURA § 36.053, the rates approved in this proceeding are based on original cost, less depreciation, of property used and useful to ETI in providing service.

11. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and P.U.C. SUBST. R. 25.23 1(c)(2)(C)(i).

12. Including the cash working capital approved in this proceeding in ETI's rate base is consistent with P.U.C. SUBST. R. 25.23 1(c)(2)(B)(iii)(IV), which allows a reasonable allowance for cash working capital to be included in rate base.

13. The ROE and overall rate of return authorized in this proceeding are consistent with the requirements of PURA §§ 36.051 and 36.052.

flflflflflflf.nn

PUC Docket No. 39896 Order Page 41 of 43 SOAH Docket No. 473-12-2979

14. The affiliate expenses approved in this proceeding and included in ETI's rates meet the affiliate payment standards articulated in PURA §§ 36.051, 36.058, and Railroad Commission of Texas v. Rio Grande Valley Gas Co., 683 S.W.2d 783 (Tex. App.-

Austin 1984, no writ).

15. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and P.U.C. SUBST. R. 25.23 1(c)(2)(C)(i).

16. Pursuant to P.U.C. SUBST. R. 25.231(b)(l)(F), the decommissioning expense approved in this case is based on the most current information reasonably available regarding the cost of decommissioning, the balance of funds in the decommissioning trust, anticipated escalation rates, the anticipated return on the funds in the decommissioning trust, and other relevant factors.

17. ETI has demonstrated that its eligible fuel expenses during the reconciliation period were reasonable and necessary expenses incurred to provide reliable electric service to retail customers as required by P.U.C. SUBST. R. 25.236(d)(I)(A). ETI has properly accounted for the amount of fuel-related revenues collected pursuant to the fuel factor during the reconciliation period as required by P.U.C. SUBST. R. 25.236(d)(1)(C).

18. ETI prudently managed the dispatch, operations, and maintenance of its fossil plants during the reconciliation period.

19. The reconciliation period level operating and maintenance expenses for the Spindletop facility are eligible fuel expenses pursuant to P.U.C. SUBST. R. 25.236(a).

19A. Fuel factors under P.U.C. SUBST. R. 25.237(a)(3) are temporary rates subject to revision in a reconciliation proceeding. 19B. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel reconciliation proceeding to include any issue related to the reasonableness of a utility's fuel expenses and whether the utility has over- or under-recovered its reasonable fuel expenses. It is proper to use the new line-loss study to calculate Entergy's fuel reconciliation and over-recovery.

20. Special circumstances are warranted pursuant to P.U.C. SUBST. R. 25.236(a)(6) to recover rough production equalization payments reallocated to ETI by the FERC.

000000041

PUC Docket No. 39896 Order Page 42 of 43 SOAH Docket No. 473-12-2979

21. ETI's rates, as approved in this proceeding, are just and reasonable in accordance with PURA § 36.003.

IV. Ordering Paragraphs In accordance with these findings of fact and conclusions of law, the Commission issues the following orders:

1. The proposal for decision prepared by the SOAH AUs is adopted to the extent consistent with this Order.

2. ETI's application is granted to the extent consistent with this Order.

3. ETI shall file in Tariff Control No. 40742 Compliance Tariff Pursuantto Final Order in Docket No. 39896 (Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment) tariffs consistent with this Order within 20 days of the date of this Order. No later than ten days after the date of the tariff filings, Staff shall file its comments recommending approval, modification, or rejection of the individual sheets of the tariff proposal. Responses to the Staff's recommendation shall be filed no later than 15 days after the filing of the tariff. The Commission shall by letter approve, modify, or reject each tariff sheet, effective the date of the letter.

4. The tariff sheets shall be deemed approved and shall become effective on the expiration of 20 days from the date of filing, in the absence of written notification of modification or rejection by the Commission. If any sheets are modified or rejected, ETI shall file proposed revisions of those sheets in accordance with the Commission's letter within ten days of the date of that letter, and the review procedure set out above shall apply to the revised sheets.

5. Copies of all tariff-related filings shall be served on all parties of record.

6. ETI shall prepare and file as part of its next base rate case a study regarding the feasibility of instituting LED-based rates and, if the study shows that such rates are feasible, ETI should file proposals for LED-based lighting and traffic signal rates in that case. If ETI has LED lighting customers taking service, the study shall include detailed 000000042

PUC Docket No. 39896 Order Page 43 of 43 SOAH Docket No. 473-12-2979 information regarding differences in the cost of serving LED and non-LED lighting customers. ETI shall provide the results of this study to Cities and interested parties as soon as practicable, but no later than the filing of its next rate case.

7. All other motions, requests for entry of specific findings of fact and conclusions of law, and any other requests for general or specific relief, if not expressly granted, are denied.

SIGNED AT AUSTIN, TEXAS the JH ýkday of September 2012. PUBLIC UTILITY COMMISSION OF TEXAS DONNA L.-NELSON, CHAIRMAN ROLANDO PABLO, OMMISSIONER I respectfully dissent regarding the utility- and executive-management-class affiliate transactions. To be consistent with Commission precedent in Docket No. 14965,37 the indirect costs of the management of Entergy's ultimate parent should not be borne by Texas ratepayers. Therefore, I would disallow the following: $173,867 for Project No. F3PCCPM001 (Corporate Performance Management); $372,919 for Project No. F3PCC31255 (Operations-Office of the CEO); and $74,485 for Project No. F3PPCOOOG1 (Chief Operating Officer). I join the Commission in all other respects for this Order. K NNETH W. ANDERSON, A ...- ° q:Acadmorders\final\39000\39896fo2.docx 37 Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965, Second Order on Rehearing (Oct. 16, 1997). nnnnnnnlf A

2011 ETI Rate Case Cities 10-22, Att 1 Page 1 of 5 Entergy Texas, Inc. River Bend Decommissioning Model - Texas Retail Revenue Requirement, Fund Balance and Expenditure Summary ($000) Decommissioning Fund Balances Line Revenue Non-Tax Tax Decomm. No Year Rqmt. [1] Qualified [2] Qualified [3] Total [4] Expend. [5] 1 Beginning Balance 2,597 114,375 116,972 2 2012 1,126 2,739 122,787 125,526 0 3 2013 1,126 2,890 131,731 134,621 0 4 2014 1,126 3,058 141,484 144,542 0 5 2015 1,126 3,236 151,891 155,128 0 6 2016 1,126 3,423 162,852 166,274 0 7 2017 1,126 3,620 174,520 178,139 0 8 2018 1,126 3,827 186,854 190,681 0 9 2019 1,126 4,045 199,886 203,931 0 10 2020 1,126 4,274 213,648 217,921 0 11 2021 1,126 4,514 228,171 232,685 0 12 2022 1,126 4,758 234,920 239,677 0 13 2023 1,126 4,995 249,797 254,792 0 14 2024 1,126 5,223 264,426 269,648 0 15 2025 751 0 275,331 275,331 8,644 16 2026 0 0 254,926 254,926 33,961 17 2027 0 0 196,094 196,094 71,394 18 2028 0 0 138,862 138,862 66,897 19 2029 0 0 99,791 99,791 45,912 20 2030 0 0 57,133 57,133 47,577 21 2031 0 0 26,277 26,277 33,670 22 2032 0 0 11,029 11,029 16,538 23 2033 0 0 1,000 1,000 10,568 24 2034 0 0 0 0 1,045 Notes: [1] The annual Revenue Requirement (1,126) is chosen so that the Decommissioning Fund Bal. is zero in the last year of decommissioning. The 2025 amount is through August. [2] See Cities 10-22, Att 1 Page 2. [3] See Cities 10-22, Att 1 Page 3. [4] Non-Tax Qualified Trust Balance + Tax Qualified Trust Balance. [5] See Cities 10-22, Att 1 Page 4. Amounts may not add or agree with other schedules due to rounding.

2011 ETI Rate Case Cities 10-22, Att 1 Page 2 of 5 Entergy Texas, Inc. River Bend Decommissioning Model -- Texas Retail Non-Tax Qualified Trust Detail ($000) Non-Tax Qualified Trust Line Revenue Earning Transfer Mgmt. Net Decomm. No Year Rqmt. [1] Rate [2] To Trust [3] Earnings [4] Fee [5] Additions [6] Expend. [7] Balance [8] 1 Beginning Balance 2,597 2 2012 1,126 5.567% 147 142 0 2,739 3 2013 1,126 5.607% 156 151 0 2,890 4 2014 1,126 5.896% 173 168 0 3,058 5 2015 1,126 5.909% 183 178 0 3,236 6 2016 1,126 5.826% 191 186 0 3,423 7 2017 1,126 5.830% 202 197 0 3,620 8 2018 1,126 5.790% 213 207 0 3,827 9 2019 1,126 5.748% 223 218 0 4,045 10 2020 1,126 5.712% 234 229 0 4,274 11 2021 1,126 5.670% 246 240 0 4,514 12 2022 1,126 5.458% 250 244 0 4,758 13 2023 1,126 5.055% 244 237 0 4,995 14 2024 1,126 4.628% 234 228 0 5,223 15 2025 751 4.516% 239 232 5,455 0 16 2026 0 4.409% 0 0 0 0 17 2027 0 4.409% 0 0 0 0 18 2028 0 4.409% 0 0 0 0 19 2029 0 4.409% 0 0 0 0 20 2030 0 4.409% 0 0 0 0 21 2031 0 4.409% 0 0 0 0 22 2032 0 4.409% 0 0 0 0 23 2033 0 4.409% 0 0 0 0 24 2034 0 4.409% 0 0 0 0 Notes: [1] See Cities 10-22, Att 1 Page 1. [2] Projected after-tax earning rate per Staff Witness Slate Cutter's Testimony in Docket No. 37744. [3] Revenue Requirement * (1 - Qualifying Percentage). See Cities 10-22, Att 1 Page 4 for Qualifying Percentage. [4] Pr Yr Bal Compounded Semiannually At Curr Yr Earnings Rate + 2 Curr Yr Transfer

• Curr Yr Earnings Rate.

[5] Calculated in accordance with fee sch for manager & trustee fees & applicable tax rates. See Cities 10-22, Att 1 Page 5. [6] Transfer + Earnings - Management Fee. [7] Assumes that decommissioning expenditures are made at YE and that the Non-Tax Qualified Balance is utilized to pay decommissioning costs before the TQ Balance. See Cities 10-22, Aft 1 Page 4. [8] Prior Year Balance + Net Additions - Decommissioning Expenditures. Beginning balance per Cities 10-22, Att 1 Page 1. Amounts may not add or agree with other schedules due to rounding.

2011 ETI Rate Case Cities 10-22, Att 1 Page 3 of 5 Entergy Texas, Inc. River Bend Decommissioning Model - Texas Retail Tax Qualified Trust Detail ($000) Tax Qualified Trust Line Revenue Earning Trans To Earnings Mgmt. Net Decomm. Qualifying No Year Rqmt. [1] Rate [2] Trust [3] [4] Fee [5] Additions [6] Expend. [7] Bal [8] Percent 1 Beginning Balance 114,375 2 2012 1,126 6.306% 1,126 7,361 74 8,412 0 122,787 100% 3 2013 1,126 6.304% 1,126 7,897 79 8,944 0 131,731 100% 4 2014 1,126 6.481% 1,126 8,712 85 9,753 0 141,484 100% 5 2015 1,126 6.493% 1,126 9,372 Qualified Trust 90 Tax 10,407 0 151,891 100% 6 2016 1,126 6.412% 1,126 9,931 96 10,960 0 162,852 100% 7 2017 1,126 6.412% 1,126 10,645 103 11,668 0 174,520 100% 8 2018 1,126 6.364% 1,126 11,318 109 12,335 0 186,854 100% 9 2019 1,126 6.316% 1,126 12,023 116 13,032 0 199,886 100% 10 2020 1,126 6.268% 1,126 12,759 124 13,761 0 213,648 100% 11 2021 1,126 6.220% 1,126 13,529 132 14,523 0 228,171 100% 12 2022 1,126 2.503% 1,126 5,761 138 6,749 0 234,920 100% 13 2023 1,126 5.817% 1,126 13,896 144 14,878 0 249,797 100% 14 2024 1,126 5.382% 1,126 13,654 152 14,628 0 264,426 100% 15 2025 751 5.036% 751 13,503 159 14,094 3,189 275,331 100% 16 2026 0 4.920% 0 13,713 157 13,556 33,961 254,926 100% 17 2027 0 4.920% 0 12,697 134 12,562 71,394 196,094 100% 18 2028 0 4.920% 0 9,767 102 9,665 66,897 138,862 100% 19 2029 0 4.920% 0 6,916 75 6,841 45,912 99,791 100% 20 2030 0 4.920% 0 4,970 52 4,918 47,577 57,133 100% 21 2031 0 4.920% 0 2,846 31 2,814 33,670 26,277 100% 22 2032 0 4.920% 0 1,309 18 1,290 16,538 11,029 100% 23 2033 0 4.920% 0 549 10 539 10,568 1,000 100% 24 2034 0 4.920% 0 50 5 45 1,045 0 100% Notes: [1] See Cities 10-22, Aft 1 Page 1. [2] Projected after-tax earning rate per Staff Witness Slate Cutter's Testimony in Docket No. 37744. [3] Revenue Requirement

• Qualifying Percentage.

[4] Pr Yr Bal Compounded Semiannually at Curr Yr Earnings Rate + 2 Curr Yr Transfer

• Curr Yr Earnings Rate.

[5] Calculated in accordance with fee schedules for manager and trustee fees & applicable tax rates. See Cities 10-22, Aft 1 Page 5. [6] Transfer + Earnings - Management Fee. [7] Assumes that decommissioning expenditures are made at year end & that the Non-Tax Qualified Balance is utilized to pay decommissioning costs before the TQ Balance. See Cities 10-22, Aft 1 Page 4. [8] Prior Year Balance + Net Additions - Decommissioning Expenditures. Beginning balance per Cities 10-22, Aft 1 Page 1. Amounts may not add or agree with other schedules due to rounding.

2011 ETI Rate Case Cities 10-22, Att 1 Page 4 of 5 Entergy Texas, Inc. River Bend Decommissioning Model -- Texas Retail Decommissioning Expenditures ($000) Line Cum. Nuclear Decommissioning Expenditures No Year Cost Esc. [1] Estimate [2] Texas Retail [3] TX Retail Esc. [4] 1 2008 1.0000 0 0 0 2 2009 1.0363 0 0 0 3 2010 1.0739 0 0 0 4 2011 1.1128 0 0 0 5 2012 1.1531 0 0 0 6 2013 1.1949 0 0 0 7 2014 1.2382 0 0 0 8 2015 1.2831 0 0 0 9 2016 1.3296 0 0 0 10 2017 1.3778 0 0 0 11 2018 1.4277 0 0 0 12 2019 1.4795 0 0 0 13 2020 1.5331 0 0 0 14 2021 1.5887 0 0 0 15 2022 1.6463 0 0 0 16 2023 1.7060 0 0 0 17 2024 1.7678 0 0 0 18 2025 1.8319 11,043 4,719 8,644 19 2026 1.8983 41,868 17,890 33,961 20 2027 1.9671 84,938 36,294 71,394 21 2028 2.0384 76,804 32,818 66,897 22 2029 2.1123 50,867 21,735 45,912 23 2030 2.1889 50,867 21,735 47,577 24 2031 2.2682 34,740 14,844 33,670 25 2032 2.3504 16,467 7,036 16,538 26 2033 2.4356 10,154 4,339 10,568 27 2034 2.5239 969 414 1,045 Total 378,717 161,826 336,205 Notes: [1] Nuclear Cost Escalation Rate at 3.625% per year. See Cities 10-22, Att 1 Page 5. [2] Decommissioning Cost Estimate per NRC Minimum (2008 dollars). See Exhibit KFG-2 in Docket No. 37744 [3] Decommissioning Cost Estimate

• TX Retail Prod Demand Alloc (42.730%)

[4] Texas Retail Decommissioning Cost Est

• Cumulative Nuclear Cost Escalator.

Amounts may not add or agree with other schedules due to rounding.

2011 ETI Rate Case Cities 10-22, Att 1 Page 5 of 5 Entergy Texas, Inc. River Bend Decommissioning Model - Texas Retail Fees and Other Data ($ in Thousands) Tax Qualified Trustee and Investment Manager Fee Schedules TQ Annual Fees 5.196 TQ Trustee Fees TQ Manager Fee 0 17.50 1,300 16.50 2.275 2.275 1,400 14.00 0.165 2.440 2,700 12.50 1.820 4.260 2,800 10.00 0.125 4.385 3,300 8.50 0.500 4.885 11,100 6.00 6.630 11.515 Non-Tax Qualified Trustee and Investment Manager Fee Schedules NTQ Annual Fees 3.050 Adder ($ 000) Breakr)oints ($000) Basis Points Fixed [11 Cumulative Points Fixed [11 Cumulative NTQ Trustee Fees Breakpoints 0 ($000) Basis1.00 0.000

                                     -           I              I.              *I~           I 1.00           0.000 0                1.00           0.000           0.000 0                1.00 0.000           0.000 0                1.00 0.000           0.000 NTQ Manager Fee                 0               17.50 1,000             16.50           1.750           1.750 1,100             14.00           0.165           1.915 2,000              12.50           1.260           3.175 2,100              10.00           0.125           3.300 2,500               8.50           0.400           3.700 8,400               6.00           5.015           8.715 Miscellaneous Inout Data Bad Debt Rate [2]                                   0.00% Nuclear Cost Escalator [7]                    3.625%

Revision Year [3] 2012 Jurisdictional Allocation Factor [8] 42.730% Cost Estimate Year [4] 2008 TQ Fund Federal Tax Rate [5] 20.00% Composite Tax Rate [5] 35.00% End of Op. License 8/29/2025 Regulated Interest [6] 70.00% Notes: [1] Calculated as in the following example: 0.500 = 10.00 * (3,300 - 2,800)/ 10,000 For balance of $25M: TQ Management Fee = 19.855 = 11.515 + (6.00 * (25,000 - 11,100)) / 10,000. [2] Bad Debts are assumed to be zero. [3] First year showing impact of revised decommissioning revenue requirement. [4] Year upon which the decommissioning cost estimate is based. [5] State Income Tax Rate in Texas is zero. Federal Rates are reflected. [6] Regulated interest in River Bend is 70%. [7] Nuclear Cost Escalator is 3.63% as approved in Docket No. 37744. [8] Production demand allocator for TX Retail is based on the Production Demand Allocation Factor per the Jurisdictional Separation Plan (9/30/07 test year). Amounts may not add or agree with other schedules due to rounding.

Attachment 3-F (Page 1 of 9) FERC Order in Docket Nos. ER86-558-002

V 3580jS UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION Before Commissioneras: Martha 0. Hesse, Chairmani Anthony G. Sousa, Charles G. Stalon and Charles A. Trabandt. Gulf States Utilities Company ) Docket Hoe. tR86-558-002, ER86-558-011 and ER86-558-013 ORDER CLARIFYING PREVIOUS ORDERS (Issued May 18, 1988) i On February 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 Cqmmiasion explicitly recognize that its contributions to Gulf Statos' decommissioning 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 Commission 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 Stats2 contands 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 schedule of rulinq amounts .unless a public utility conmission that establishes or approves rates for electric energy generated by the nuclear power plant to which the i_ Se Gulf States Utilities Company, 40 FERC 4 61,081 (1987); Gulf States Utilities Company, 40 FERC 4 61,380 (1987); and Gulf State2 Utilities Company,.. 4Z FýRC

       ¶ 61,098  (1988).                                  f

358016 Docket Nos. ER86-55s-002 and -011 - 2 - and -013 nuclear decommissioning fund relatas 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,'althouqh 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 Commisdion's letter orders approving the

 *,  settlements do not satisfy the requirements of its regulations.

We are not convinced that the instant clarifications are 7 necessary. It appears that Gulf States has never submitted to the IRS 'the letter orders approving Ihe settlements that specified the amount of decommissioning costs that will be reflected in Gulf Statos' wholesale rates. Based on Gulf States, filing it appears that they requested approval from the IRS on June 24, 1987. 2/ The letter orders were-not issued until July 22 And September 25, 1987 and January 31, 1988, respectively. We believe that had Gulf States properly submitted the latter orders that are the 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 settldmenta reached in this docket the Commission has authorized Gulf States&o roflact in its wholesala rates yearly decommissioning costs of $112,914. We

• " selieve such action to be 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 applica~ion to the rates being charged to Cajun. ThQ CodIszion order5: The Gulf States' and CaJun's requests for clarification are hereby granted.

• . By the Commiasion.

Loi3 D. Cashel!, Acting Secretary. 21 2& Petition for Clarification at 3-4, qucting Temp. Treas. Reg. I 1.468A-3T(g) (1986). Z/ 2m letter of September 22, 1987 of William J. Dwyer, Chief, Branch 6 Corporation Tax Divi3ion, :RS at 1.

C C BEFORE THE FEDERAL 91-WG I 0 REGULATORY COMMISSION Gulf States Utilities Company ) £LDcket NOS ER86-558-000, ER86-558-002v RLi ER86-558-011O ER86-558-013,w

                                                                    )      ER86-558-015         FEB 22 198 PETITION FOR CLARIFICATION OF ORDERS OF APPROVAL                              LEGAL SERVIC ES 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 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. 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)(1) (40-year life); Welsh Agreement, Art. III(E)(4) and Art. III(E)(l) (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 SC C-amounts" from the Internal Revenue Service. Temp. Treas. Reg. _1.468A-3T(a)(I)(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. §I.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 to be 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 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. Johnson 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.1 GUE F STATES UTILITIES COHPANY RIVER B NO FOR NUCLEAR DECOMHIS,;IONIM FUND 70/. CO-OHNER$111P BEGINNING ANNUAL CUVULATIVE ANNUAL CUMULATIV CONINIBUT1ONS ENDING YEAR BALANCE EARNINGS EARNINGS CONTRIOUTIONS BALANCE 1006 $ $ $ S 60974 $ 60974 $ 60974 60974 5(487 S487 173008 179375 1988 112914 179375 16144 216,1 112914 206002 30863S 1"989 303433 27759 49390 11291', 399716 449106

            '49106         40419                89009                11291,4 1Z29 14         512630          b02439 qqz       602439 7bqS7 7        5'.220 69261               1144029)             11Z914           6255'14         76957.

qqs Z13290 713458 951741 951748 OS658 290948 051372 15uS20 I199S qq(4 1160320 10352q 402477 112914 366763 996 366763 12S000 5254105 1077200 602660 997 602685 6b19727 11291' 1190114 1859041 85q841 67106 03',7 11 ' 1303028 2140141 998 999 214Ol4 192b12 112914 14 1594 2 220110 15,0056 Z7786b9 2000 27 76f91 2SO01 1499q18 lIZI~914 1641770 1I11608 53735; 2Ono S141t,86 282751 1702669 2914 1 754604 2002 2003 Z004 537S5S 968629 4430720 318362 357177 399485 2101031 2'58208 2857693 11291f 1914 112914 8(.7590 9.90512 2093626 39686219 44 30 720 4951119

                                                                                                                  ,Th 2005      4951119        445600              3303293               112914          22063'.0         5509633 20Db      5509635        495867              3799160               112914          2S19254          611041'.

b118414 550650 43,49U18 4Z6019(3 24 2168 2 5'.5002 6701986 2008 6781986 t,1037871 7505Z78 7505278 675475 5655671 I1914 2657996 8Z93667 Z009 zolO 8Z91667 746(4 10 630S2101 112914 2770910 9153011 2010 9153011 87,S771 7205872 11291It 2803824 1000969b 0089696 0113945 2996738 11110603 2011 2015 R 14 1110683 22Z23558 3436593 90007 3 999961 100121 209Z93 I 9113906-014OZ7 1423120 112914 112914 112914 3109652 3222566 3335400 Z22355ý1 1343659?. 14750800 2018 4758800 6200006 7770921 320292 4SO001 599182 I4209613 2751612 15808995 112914 112914 112914 31-4'.3394 561308 167422 620000b 7770921 9483217 019 948321 751490 75624a5 1i29I1 707136 21349621 020 21j4.962 921466 19483951 112914 9U0050 23384001 25601475 2104 560 21580511 12.914 112914 4.0IJ96'4

  *021 1022   2560147                            2309264'                                     0125878    3065310S 280185?                    7       164 4311 202t     o0b5310i                         29173090                                4351706         3524796 1352479b           52166
                         $0723Z           $ 32190322            $   164854      S   4516560        36706882 THE ANNUAL EARNINGS RATE IS      9.00 PERCENT This schedule is on a FERC jurisdictional basis.

t~i

Attachment 3-G (Page 1 of 13) MSS-4 Agreement and FERC's Acceptance

Entergy Services, Inc. 101 Constitution Avenue, NW.

  "      En'trg                                                           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: Entergy Services, Inc. Docket Nos. ER03-753- and ERI 1- -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")1 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. 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.'4 The Commission defined "long-term" transactions as "one year or more. 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 6 settlement. 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. I!. 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). 8 Entergy Services. Inc., I I FERC ¶ 61,035 at P 31; Louisiana Pub. Serv. Comm 'n v. Arkansas Power & Light Co., 44 FERC ¶ 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 rarmstl@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, /sf 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 are 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.

1I. 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. ("Buyer") pursuant to the Service Schedule MSS-4 of the System Agreement. SELLER'S BUYER'S BUYER'S CAPACITY* ALLOCATED ALLOCATED CAPACITY* 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. ER 11-2562-000 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. § 35.1 1) 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

Attachment 4 (Page 1 of 1) ENTERGY LOUISIANA, LLC Status Report of Decommissioning Funding For Year Ending December 31, 2012 - 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) (2014$): $516.9 million 1

2. ISFSI Obligation as of 12/31/14 $3.17 million

3. Decommissioning Fund Total As of 12/31/14: $383.6 million

4. Annual amounts remaining to be collected: See Attachment 4-B

5. Assumptions used:

Rate of Escalation of Decommissioning Costs: See item below Rate of Earnings on Decommissioning Funds: 2% real rate of return per 10 CFR 50.75(e)(1)(i) Authority for use of Real Earnings Over 2%: N/A

6. Contracts upon which licensee is relying For Decommissioning Funding: None

7. Modifications to Method of Financial Assurance since Last Report: None

8. Material Changes to Trust Agreements: None 1 See Attachment 4-A

Attachment 4-A (Page 1 of 1) 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 10CFR50.75(c)(2) Escalation Factor Formula: 0.65(L) +0.13(E) +0.22(B) Factor L=Labor (South) 2.431 E=Energy (PWR) 2.222 B=Waste Burial-Vendor (PWR) 13.8853 PWR Escalation Factor: 0.65(L) +0.13(E) +0.22(B)= 4.92276 1986 PWR Base Year $ Escalated:

   $105,000,000

• Factor= $516,889-516 1 Bureau of Labor Statistics, Series Report ID: CIU2010000000220i (4 th Quarter 2014) 2 Bureau of Labor Statistics, Series Report ID: wpu0543 and wpu0573 (December 2014) 3 Nuclear Regulatory Commission: NUREG-1307 Revision 15, Table 2.1 (2012)

Attachment 4-B (Page 1 of 1) Schedule of Remaining Principal Payments into Waterford 3 Decommissioning Fund ($ Thousands) Year LPSC City of New Orleans Total 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, CNO Resolution R-95-1081 in Docket UD-95-1, and CNO Resolution R-14-494 in Docket UD-13-01, see Attachments 4-C, 4-D, and 4-E.

Attachment 4-C (Page 1 of 20) 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-31237 In re: JointApplication of Entergy Gulf States Louisiana,LL.C. and Entergy Louisiana, LLC for approvalof an Increase in Fundingfor Decommissioningfor River Bend and Waterford3 Nuclear FacilitiesLPSC Docket No. U-31237. (Decided at the Commission's July 28, 2010 Business and Executive Session.) Overview and ProceduralHistory 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 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. 45:1163(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. UncontestedStipulatedSettlement 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 EGSL/ELL 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; EGSUELL Exhibit I- Settlement Testimony of Kenneth F. Gallagher, dated July 9, 2010; EGSIUELL Exhibit 2- Direct Testimony of Kenneth F. Gallagher, redacted public version, dated December 2009; and EGSUELL 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 supplemental funding for the decommissioning trusts maintained for the LPSC's jurisdictional portions of the Watefford 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 year3 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 Bend4, 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.' 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) affd 119 F.3'8 349 (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. V-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 S7.843 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: (I) 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 changesý 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 111 CHAIRMAN LAMBERT C. BOISSIERE, III

                                   /S/JAMES M. FIELD DISTRICT I1 VICE CHAIRMAN JAMES M. FIELD
                                   /SI FOSTER L. CAMPBELL DISTRICT V COMMISSIONER FOSTER L. CAMPBELL
                                   /S/ ERIC F. SKRMETTA DISTRICT I COMMISSIONER ERIC F. SKRMETTA EVE KAHAO GONZALEZ                  ISI CLYDE C. HOLLOWAY SECRETARY                           DISTRICT IV COMMISSIONER CLYDE C. HOLLOWAY Order No. U-31237 Page 7

ORDER NO. U-31237 EXHIBIT A

Exhi*it A Page I of 5 EjW1V 0 LoAdemu.LLC WWfturwd3 0aoonudselor"~ Model Reva ROILment 3--ny ("W0) Lkw Total Lpsc CNO No Yew conmmn (I) kr.Ž d- (2 2010 8.947 5.831 2 2011 5.831 118 9.947 3 2012 5.831 4 2013 3.947 5.831 116 2014 5.947 5.631 2016 6.821 133 7 2010 133 8 2017 6.821 6.80 133 9 2018 6.821 6.S8 13, 6.621 10 2019 133 11 202= 7,731 7.SW8 151 7.731 12 2021 7.580 151 7.731 13 2022 151 7.731 14 2023 151 7.731 7.680 is 2024 151 S Nots:. (1)G.s ExlilM A Pap X. (2) TOWaCcrn*wW 6 LPSC Ptaduclia Deffand Ab~ogmeFaec .'905%. (3) ToW Co.mpny - LPSCJwxhdican

S-Yea, Stap F.Waon Yea 2010 Fxhibit A Page 2 of 5 Eua&W 4.25% Enwow LMaaaa LLC WAtmh1rd-3 Oamnvi"irf modm Revenu RowqunKeevFundB"-"nc andEnpenogure Surmty TOW r Ciepany Ln Revenue Tax 0eow"v. No Yevow I. II [] E . L41 I OBwwftg Da 215,061 2 2010 SM.47 227.329 0 3 2011 5.947 246.961 0 4 2012 6.047 2384 0 5 2013 5,047 201.400 0 8 2014 5,4? 316.413 7 2018 6.821 344W00 0 8 2016 6,821 373.60* 0 O 2017 8.821 405.077 0 t0 2018 6.821 4X8.760 0 I1 2019 8.t21 474,814 0 12 2020 1.731 514,250 a 13 2021 7.731 550.427 0 14 2022 7.731 801.516 0 is 2023 7.731 647,91 0 Is 2024 7.V31 692.824 3.004 17 2026 6.86? M5.328 at t83 18 2028 8,also? MO. I M0.388 1t 2027 8.86? 344.370 203.0 20 202 8.88? 282.117 111.23? 21 2029 SAO? 170.727 115.650 22 2030 10240 88.810 100.680 23 2031 44.001 -0.000 24 2032 542 45.564 28 2033 0 552 [I) The wevuiaRevenue Aequiraemt 15.947) Is hoaan soMetlDew DeeonroixBdng Fund Balance is mm In fths yeas of dOim *tloiin. 121See D *uM A Page2. 131 See Si~u A Page3. (4) Non.TesCuaSgad TraistDalance + TeaCrumbe Trust Balance. 15)SeeEibNlA Page A.

Exhibit A Page 3 of 5 Wmbdw& 0.*otwvdmi MOMd TA0uo44 Thm D" tN. Remain Ea34ag T~wai MGM18 AM Omag I B*PVh' Bmi2at 3,1lO 218.08t 2 2010 0.94 . 6.71% 2...

                                                         ,.407 6                     .12.0       215        ..              .       .32. 0                            100.00,.,

3 2o11 $... SASS. am94? 13".64 22 10 0 240.,1 I 00.1OOS 4 2012 IL4T61 L.572262_  ?--M-08 4" 190000 2211 141,334 2M 2XW.1 0 1.40 "MO0.0% 1 5. . . . .. ._ ____ 7 . ._ .. . . .. o 7 20lS &M *V% 6. 21.123 307 2'.93 0 364A, 100= a 2017 6.82W 6.541 s6621 2.j51 35 31.914 0 10 2016 .,821 6.871. 6.21 27,25 264 23.712 0 426.7*9 100"1 It6 201 6 $A e 2.0t7 412 air- 4414 10.0 12A 200 7 . . . ". . ... .... o"i..... -- 9*1-

                                                                                             "32.4                                     "..        ..        --       'o. ,

13 202 " 7.731 a.m.% 7.731 34..1? - 4 W i" 0i 642 ,0-am%1 14, 222 '7.731 ,5% .0 3o.879 816 4..9 .. 1. 16 100.51.. is6 - 202" .. 2021 m . .. . &0 626% ,.. .71,31- .i 39.2= *..... as6 A474 a " 647*91

• I" O"i~,-

                                                                                                                                                                       .=of 100600%

It16 Fý--!?! 7M!3 .47.2

                                                                           !q412?.            50                            -~
                                                                                                                            ..       ý.        .      .     ..       ý1 17
            =7a                          &%            9.8                 40.8               612         4s"11                  Ski              SM1820 6.687a .8             66?                39 2.04                 01         48# 70                 gj.1!0001        8661
                                                                                                                                                         *4.270*        100.0 20 223      *

• 0.8a7.....................

                         .......      * &N7%..         O.56"       ....         ..... ....     --1~9...

474 ." 2311,4110 .... . 56.929 2 1.2 69...... 8,17- 6600 000 21 2029* 6if6780 R00n 0791 7&7% 808? 15.583 280 24=260 118.'6y IT0n 2 100

 .. 9 2027 23        203                0           4.881             0                4.267       .      06           4.28                46%9               44.M0           100.00%

26 2033a2A 0 .. , 11 10 so2 0000.0011 0 NoL (13Thi i1ar d RwJRoqrudkn*ea.9473 s wug., OWNo DeOwirNkrV FaN Sau b =a ( R- Re**emeh I OUd" P-c-Up (10%). 141P01WYaw Ba~m CanvarwaSa SenrAavwu1 Am Caaml Yaw gmdm19Rome # 11CaiNf Yew 1'wzd CavmTWYew Ea1148 RwL (23Cabdid N 6911c 34088a~sag54m 88 mnwaf & hulh leesom~ad a Ual.8 8803.ralmGwWP864. l~l M1As~unms 020 8e32010010164 wsantt we nm~eat w "~ 0.. 85* APop00 (53 P08.1900mt Ya . NotMdWom - OeMnAaleabaNEqivondkom

Exhibit A Page 4 of 5 Ensq Lta r*smLLC tma yewr Cm9JI CPIU cod 2am(21 aM Ew~ M.~ I 2M0 WA W4A 1.0w0 0 0 2 200m A 1.00 i.sOC 0 0 3 2010 1.0217 1.022 1.088 0 0 A 2011 1.0222 1.046 1.130 0 0 5 2012 1.0228 1.063 1.1812 0 0 1 2013 1.0231 i.o04 12314 0 0 1 2014 1.0238 t1120 1.2837 0 0

• 2015 1.0240 1,147 1.3283 0 0 9 2016 1.0244 1.175 1.39m 0 0 10 2017 1.0046 1.204 1.450 0 0 i4 2016 1.0284 .235 1S1M3 a 0 12 2019 1.085% 1.267 I.J80 0 0 13 2020 1028 1.300 1.6479 0 0 14 2021 1.L02 1.3=1 1.1709 0 0 is 2 l.02am 1.371 1.3908 a 0 to 2023 1.0277 1.409 1.1070 0 0 17 2021 121 1.449
• 19883 1.43 3.004 o 2025 1.028 1.401 2,.020 41%m3 55,183 10 2026 1.0M8 1..36 2.1152 91,428 103.398 20 2027 t.028 1.581 2.2051 92,481 ZDX3.92 21 202 1.004 1-u2m 22880 48.369 111.37 22 2m 1.0310 1.679 L38 49.254 113.A0 23 2020 i.m28 1.723 2.1"4 40362 Mae94 24 203t 1 1.81 108 .8048 18047 40.00 25 2032 1.0281 1.014 2.7153 1,71l 45.564 20 2002 1.0281 1.881 2.8307 198 852 2? Tow 6nzmm" 40017r $0A4 2

(i) CPIU pm GOlool in4% rPaecaut for 01O.202tI 2861%for 200.24 is go &AM" ON20101o020. 5 f2 Csmuw Ifuo" uftU Coan E64*ior at 4.2 3LW i Na. D31 ftymla ft.M COOEvalfdsWc2008NRCUhim~mWO0084000,1 1 Dom wf Col CosEsm4a Cwkdalw Mimr Coo Esacodor.

Exhibit A Pag 5 ot15 Enleigy LoWesans. LL. Fees en Other Daba (S Thatsands) Tax Oualffied Trusts* and Ivaestmeat Manaer Fee Schedules Ta Annual Fees 19.500 Adder(S 000) s& 4mak~lt 15000 Seam Paint Fuced III Cwnnulanive TO Trumtee Fees e 0, I-. , 1.00 1 1 = TO MAne Pee 0 22.70 6.000 17.70 11.350 11-350 6.000 16.90 5.310 MG.M0 16.000 1.70 13.5"0 30.160 20,000 9.50 6290 36W460 tillceflanmas Innut Dats ad Odem RatM2 0.00% Nude~ar~cateseimo'(7 4.25%) Revision Year rA 2010 Jh~We.r Aflnm* a FPt, q 100. iCast Emet. Yea,r [4 2..8 TO FundFederal TeeRte. 151 X0.00%i

                 ¶gTee Rate (336.46%                                         End oiFuxnftPfto                         12131I2030 Notes:              111                                                   16~0.000%1.0 l11 Camoutated meInd. Iolst,,ng eemw,16.260 . 1$7Og * (2,O.-          .16000)110,000 For balanoe o $25M TO Management Fee    e 41.210 - 36.480     (9.51bp(25.000- 20.000))l 10.000.

123Bad Debts me ssarmed to bezeo. 131Fitrt ,Vew shoetn, tnpaC ci rvised decomdesto g WrVneneMqUIremwO (41 Year uoon wNch the daconiu V cogs ecimae I base& (5] State Incom. Tax Rate Is .00. eftfdive rate Is 5.35%. 181Entergy Louisank LLC, unin Interest in Wabrlod-3 is 100%. [71 Nuclea Cos Elstaisor IsA 25% 181Productto demand allocator W.Lisan ReCA 0

ORDER NO. U-31237 EXHIBIT B

a

~J1W

Exhibit B Page 2 of 5 0O0 Eftm "~ StatuLUmwtt LLC

                              *

• TRm, sow Demd" f
• ecu. T" TTrustNmr.'TaOuaVfis Un. Revenlue Em"ifi rmkoew Iftfrt me Dae9mo. WG%

wo Yew P' jj(11 Roo TOTr'st M3Garvd," 141 " dO WP EJO- fn ..80-M! fJLO) I Seor& Balanc a4 313VO "14.88a 2 2010 7.643 5.45% 0 32 17 so 0 15,80l 0.00% 3 2011 7.843 5.56% 0 881 is 084 0 16s8 0.00% 4 2012 7.643 5.80% 0 074 19 856 0 17,511 0.00% 5 2013 7.843 S.8AM 0 1.043 10 1,024 0 18.M34 0.00% 6 2014 7.843 5.97% 0 I.Q23 20 1.103 0 19.637 5.00% 7 2015 B.986 &09% a 1.194 21 1,173 0 20809 0`.0% a 2016 6.086 &01% 0 1.269 22 1.247 a 22.067 GAM%" 9 2017 8996 &.02% 0 1.348 23 1%324 0 23,381 0.00% 10 201S 8.206 &.04% 0 1.434 25 1.4A 0 24.790 0.00% 11 2010 8.996 &.06% 0 I= 26 1.490 0 26.289 n.O 12 2020 10.s19s to$.% 0 .63 27 1.50 0 27A684 0.00% 13 2021 10.198 6.09% 0 1,724 2 1.8ag 0 20.570 000% 14 2022 10.195 C02% 0 1.807 30 1.Tty 0 11.356 0.00% 15 2023 10.105 097% 0 1.900 32 1A86 0 33.225 0.00% le 2024 10,195 5.25% 0 1.767 33 1.734 0 34.56 0A00% 17 2025 11.3 5.1S% 0 1.606 35 1.771I 12.406 24,321 0.00% 18 2026 11.693 4.80% 0 1.204 25 1.176 26.499 0 0.00% 19 2027 11.693 4.0%M 0 0 0 & 0 0 0.00% 22028 "M1.3 4.69% 0 0 0 0 0 0 0.00% 21 2029 11.691 460% 0 0 .0 0 0 0 0.00% 22 2030 13.513 to% 0 0 0 a 0 O &00% 23 2031 0 451% 0 0 0 0 0 0 &0W% 24 2033 0 4.51% 0 0 0 0 0 0 0.00% 25 2033 0 4.1M 0 0 0 0 0 0 G.90% 26 2034 0 4.51% 0 0 0 0 0 0 &00% (II S" ErrlW84aBPage 1. 121Pmoected aft*a-.ea* ,,rirate. (33 ftawerwe Reqwkrrur I (1. OujaWg Pqrcwotep (43Pr-or Yew Balencm CoWpaursed S&aWuwaly St COmWIYea, EMr RaHe O Carmed YearToms* C" Year E Rat. I5) COWalUlad ewagfe batsim (Avg.60 v PrIorYr. Ut * %I(TmWlsm

• EaMIWp in accaodaace 0On WrhOrefag Uh*jB uWIW blaee and mr ran and aPplrcale tax naes.S4 E~* BPage 5

[6 Tteuser . Eamk' .- sag.mr FaL (73Assurres Oa the Nnb.TaI Ousited BaOlr, Is uhTtzd to pay Ow desomamw"l . cla 951m b eO TOBo See Exh%6 S Page 4 far MretotaL J61Pr"WYea, 9.1W.r + MMAdlakrs - Oecaaaaoalorlrr exrponawre

Exhibit B aPsge 3 of 5 Entawo LCUOSS Small.4 UW snd Decomer"S4 mocil bo LOUIBIMS R"W Tax 0uam.d Trust DOW Tre 0ualmoe8Tma Li Raevenue Envr Tmrrr upd. Nat Doeren. Qua0yltr

"*                     Rg.u ill     Rae          To Tres (31j~ annpI                        AdM"j M      En i M       Bett     t      ecn 2          20ginning Baleec1t 3J31110                                                                                       1.040 2          2010            7.843        .10%             .614         1.431          31          4.014           0       36.954      100.O%

3 2011 7.843 5.83% 7.643 2.414 36 10.221 0 47.175 400.00% 4 201a d."43 6.20% 7.843 3.213 42 11.014 0 f8.180 M0O.00% 23013 7.843 8.29% 7.843 3.914 49 11.758 0 8094?1 I¶0M0% 6 2014 7.843 &.47% 7.843 4.65 S7 12.636 0 M2.685 tO4O00 7 2011 8.906 6.60% .96N, 1.744 as 14.S87 0 97.283 100,00% 8 2016 8 4106 8.92%8 8.906 8.738 75 15.659 0 112.022 100.001 9 2017 8,96 6.54% k9"6 7.80 as 16.711 0 129.33 100.00% to 2018 8.996 8.57% 6.906 8.952 g6 I7,852 0 147.486 100.00% II 2018 8.96 1096 85% UN ,178 107' 10,964 0 18834.1 11)(0% 12 2020 10,193 6.61% 10.196 11.S28 120 2108" 0 1a8.1S3 100,00% 13 2021 10.195 10.126 163% 13.019 133 23.081 0 211.334 100.00% 14 2022 10.15 .65% 10,156 14.620 148 24,67 0 23.001 100.00% 15 2023 10.195 0.39% 10.195 15.641 184 25,672 0 28473 100.00% la 26.581 0 28.154 100.00% i8 2024 10.145 a 12% 40.195 1$.8"6 17 2025 t1.693 5.75% 11,693 17.143 197 2869 0 316.793 100.00% 18 2(2 11.893 5.78% 11.693 18,847 211 30,325 23.543 323,57 100.00% i9 2027 11.693 5.76% 1.693 19.244 2ia 30.7? 03,721 260.570 400.00% 20 2028 I11.93 5.76% 11,683 14.977 173 26.498 07.774 171294 100.00% 21 2029 11.803 &.76% 41.693 10.013 1t8 22.378 67.507 134.166 100.00% 22 7A" 13.513 &.78% 43.13 4.228 100 21,642 70.378 85.430 400.00% 23 2031 0 4.80% 0 4.220 64 4.158 50.108 3OA78 100.00% 24 2032 0 4.88% 0 1.960 35 1.91s 24,741 18.82 100.00% 5 20 0 4.w8% 0 8m 20 801 15,t01 1*16 4004.0% 26 2034 0 4.88% 0 75 7 67 1.54 0 100.00% IM]Se Ex*b86 Pig. 1. 121Pmvo(93arlatlax haffarl rate. 133 Pr.e SeqwolrWat " uustling Paotam M43PrI0r YeOr Balanne CowWowldAd Searnow lRyat Cwtrens Yew, Earnin Rate . N Cwrwd Yewr Tres/la

• Crmard Year Erfngs Rate.

151C-414iWd -n eaeue bafance (Av.4Od - Prio Yr.8..

• V,(TranSlate Earnings) in acwdanui wth no be WAcldw fe(orIugte and Marugagt au) apipkabl.e tax ralee. Sea E,*.,s 8 Pa eS.

162Tran-

• Earn- s.- W rnamnt Fee.

171Assvm. 6W "0Non-Tax Quaffit Balerc is uwiod to pay e To7Sdet..

                                                                                     =.te obefa~alrrr rsin
       &M E-3hU 8 Paeg 4.

(84Pio Year saiwrce +Net Adiriong . Dftowxnessc4* Enpandgbura

Exhibit B Page 4 of 5 en""9L*&M~wtLC RNWova Do .o"us" F." CWnl.Ned~aW RPAPAEN. gq".4 LAPAW~ - No Yea CPRIU (t I CmI cost Em&(21 0 m0 1 70% Ao 4 LARiaS151 eummwlsM~ 1 200 NMA NIA M=00 0 0 a 2 20m NIA 1.000 1.2425 0 0 0 0 3 2010 1.0217 1.022 1,.686 0 0 0 4 2011 10222 1.045 1.1330 0 0 0 0 5 2012 1.0226 1.069 1.1812 0 0 0 0 1.031 1.004 I,2314 0 0 0 6 2013 0 7 2014 I,0m 1.120 1,252? 0 0 00 0 10240 1.147 1.3534 0 0 0 a 2015 0 1.0244 1.175 3.3552 0 0 0 9 201 0 I MOT 0 10 2017 1.024 1.204 O 0 0 II 2018 1.0254 1.235 0 0 0 1.5103 12 2010 1.020 1.26 0 0 0 0 1.6479 0 0 13 2020 1.0263 1,300 0 0 0 14 2021 1.0267 1.335 1.7170 0 0 0 1: 2022 1.0272 1.371 0 0 16 2023 1.0277 1.400 4 21IO 0 17 2024 1,0242 1.449 1.9461 6=1 1 2025 1.020? 1.491 11.04 IS 2026 1.0293 1.525 .11152 41.88 28,074 2027 1.0296 1.61 2.2011 1.721 3410 21 222 1.0204 1.02n to~ 6M4,3 44.162 22 2029 1,0310 1.6 L3965 29.249 67A?0 23 2030 1.0261 1.723 2.4984 9.9 20.249 70.,70 24 2031 1.0261 1.768 2.6W48 19.276 SI1011 25 20 203 2032 1.0261 1.0351l 1.814 1.0614 2.7153 1.460 24791 26 2= 'IOu I.Mll 10.154 139.17 403'2M 437 27 04 1.0351 1.510 2.9510 200.721 1.,64 28 Totel Eutpwatl* 217,702 Notes: III CPIUPwrW Clo i mlhl Forscast 8e2910 -228.1M. 18t%for 20301D034 IsMleeawws tMr20103so2M2. M2 CW-W-atvNuclear COWt EBCRWoA 4.251 OarWa 13Ocmumblimtstn Cog Et 0646 par 2006NRCkfkntm (2M8d9n (41 0000--.uonrWWOC Coat 0sn n 25i4)

                                         - 601a40Gull6666 FwvdingkftmK (1O0%), 3.23 Rati Alleade pa PPAwkh117 151ECSL   Fmn*V'  Shamn of   CoagEs~Owam

• aLouliaoa RA" PtoducltabewwWnd9AtNW(95.3094)

IS! LoUtWAtRtmS I cwwata~vg1,1tau CCUt69COWa.

Exhibit B Page S of5 rrEftwoWutSatool Louidiww 11.0 River 8end Oecoissoning Modl Louisiana Fees and OWerData (S in Thousands) Tax ausllts T1ugdee &nd fnw&nreot Meager IFe. Schedugp (I11 TQ Annual Fees 6.328 Adder (S000) Breapoifs ($000M Basis POWs Fined (I Cmilla" TO Manager&Ass 0 15.50 Based Trustee Fee 1.333 11.50 2.46? 2.461 2.083 15.00 1.313 3779 2.547 13.50 0.875 4r654 3.333 12.00 0.900 5.$54 4.167 9.50 1.000 6.S54 12.333 7.00 7 758 14.312 Nortel ualifiehd Truste idfItt* Mam FMuntt ar U119dulom NVQ Annual Fees 5000 Adder (S O _ Breaollok (5100) Basis Pon fAs (I) Cumdse. NTO MmsnrA Asms 0 16.50 Based Trussee F.. 1.000 17.50 I.50 I.15 1.560 15.00 0.160 2.6M0 2.000 13.50 0,860 3.490 2.100 12.00 0.675 4.165 3.130 9,50 0.M5 4.621 9.250 7.00 5.814 10.735 Mlsceflt2Veous (f"lM ,1At 84 DOetRatw 2 . 0.00% Nuci CostEscal*atr* A71

                                                                                                                                  .25%

ReW VisoYear 1) 2010 EGS1..LARewsdll 96.3094% Cot EatknMate Yesr 141 2 TO Fund Federal Tax Rate 86 &After M 20.00,1 Composte Effective Tsa Rate 151 38.48%End of Fidi Period 1210312030 Enter" Gulf States Ooewm"vShare 163 100.00% Votes: (1) Calcuated sa in the following exampte: For balance aoS3 loM TO Management Fee - 9.637 ,.554 * (7.01o (10.000 - 4.167) I 10.000. Bad OQeothandled in Cost of Save. Study.

    '21 (31 First year shot" inpad of revlsed del ainssaloni              rev e quiremlents (41 Yesr upo whim the decoranissn cmt eatiate is based,.

(51 Louisiana [scameTa Rate .i 8.0%. however. in Lowuiana FederalIncome laxes ar deductible. firefore the effective Louisiana rote is 535,3 The effective Fedr"l Rite is33.13% result in a CompositeRate of 38.48%, [61Cost Estimate provided 1t Regulated Potion (70%) so EGS0 Andivninterest is 100%.

17) Nuclear Cost Escalator is 4.25%

(JAPer the 2009 FRP based on 1231=0 Test Year. This is LARetail portion of EGSL (91 Effective Federal Tax Rates for Qualified Trusts. These Musts do not pay Slat taxes.

Attachment 4-D (Page 1 of 6) CNO Resolution R-95-1081 in Docket UD-95-01 and IRS Schedule of Ruling Amounts

RESOLUTION N4-II10tll CITY HALL. August $. 1925 BY: COUNCILMEMBERS CART.* SINGLETON. GLAPION. HAZELUR-OISTANCE. TERRELL, THOMAS AND WILSON RESOLUTION AND ORDER DIRECTiNG INVESTIATION OP LOUISIANA POWER ANdLUGHT COMPANY'S LPSL) RAPTES AND CHARGES RUATIVE TO ALGIERS AND ERTASISHING COUNCIL DOCKET NO. UID-S.1 WHEREAS. pursuant to Section 4-1604 of the Home Ruse Charter for the CIty of New Orlans IVC1ityI. the Council of the City of New Orleans ICouncil'l has vested in it al powers of supervision. regulation, and control over the ramas of electric. as., host. power ... and other putic utilities within the Ct, including One New Orleans Public Service. Inc. VNOPSI') and the Louisiana Power end Ugt C.mrpany I'LP&LL'; and WHEREAS. in 1936 LPAL applied to the Council for a rate increase related pnmarily to te Construction costs associated with its Waterford 3 Nuclear Power Plant and IP&L's 14% share of Grand Gulf Unit No. 1. which application was considered in Docket No. Co-as6-1 and WHEREAS. In 1981. during the tindi.omv ol the Council's decision with respect to LP&L's rate increase application, the Council passed Resolution R-89-03 establishing Docket No. CO-894 to investigate the allocation and approprisatl disoosition of the proceeds received by LP&L incident to litigation with United Gas P'peline Comcany IUnmited-l: and WHEREAS. attar consideting all of the vmdence in Oociets No. CO-86-1 and CCO89-1, .vnci dockets ware consolidated for trie purpose of procedurally exoediltng the diSoosition of the doCkets. rth Council determined trat LP&L should

be atowed to Irraase th$ bae$ OlctiC ratie epsctable to Cut*rt'ers in Algiers on a phase-in basis provided It amortized 03.940.000 dollars of United proceeds alloclal to Algiers over the same period. and WHEREAS, the rite increase was further conditioned on LP&L's agreement to not seek a base rate increase to be effeCtive through May 14. 1994, i.e., rates wore to be "capPedo and WHEREAS, a simnilar rate cap was in place on that portlon lapproximately 98%1 of the IP&L system that is subjlct to the Jurisdiction of the Louisians Public Service Commission (LPSC'1. which also ended on M 14. 1994: and W1HEREAS. in 1994 a rate making investigation was initiated by the LPSC to review the rates and operationa of LP&L. and hearings were held by the LPSC In March. 1995: and WHEREAS. following the hearings, the LPSC ordered tUat LP&L.' base rates should be reduced by $49.4 million; and WHEREAS, on July S. 199". LP&L fMied rates with the LPSC. which filIng will decreaise tho elcltric rate charged by LP&L outside Algiers (hereimfteir, State levell. which filing implemented $34.7 minllion of an ordered 049.4 milion decrease (114.7 million is subject to a tenmpoarl restrainingorderi mandated by LPSC Order No. U-20925; and WHEREAS, LP&L'a filing of July 19. 1995 with the Council. seeks to decrease the current Algiers rates to the State level rates as filed by LP&L with the LPSC on July 5, 1991. to expedite implementation of reduced rates for the benefit at Algiers customers ladditionalfy, LP&L indlcates that after the issue relating to the temporary restraining order is resolved, a filing for a revision to the Algiers rates will be made it the then resolved State pricing level): and WHEREAS, that portion of the LP&L system regulated by the Council is aDproximatety, 2%; and WHEREAS. as detailed in the LP&L filing, the typical summer residential bill for 1,000 kWh will decrease from 078,58 to $76.78. a decrease of 01.80, s typtcal commercial bill for 10 kW and 1,825 kWh will decrease from $207.88 to 2

$202.52. a decreae of t5.36. and a typical Industrial bill for 1.000kW and 182.500 kWh will decrease froM 412.988,65 to 412.709.40. a decrtease of 6279.2S: and WHEREAS. the Council finds it in the Public Interest to estabslah an sxpdhald schedule to consider the impliemantailon of (educed rates for Algiers Ratepayers: now, therefore si IT RESOLVED BY THE COUNCIL OF THIE CITY OF NEW ORLEANS that LP&L's f*ilng tot doccsallof electIc rates in the 15th Ward of the Cht (*Algqlerl is accepted for filing by the Council and the rates are hereby adopted and shadl tb placed into affect by LP&L for bills renderod on or after July 19. 1991. BE (T FURTHER RESOLVED that the Council is hereby Initiating an investigation into the reasonableness of LP&L'sI rates anrd charges relative to Algiers under Docket No. UD 96-1 which Docket is hereby established. BE IT FURTHER RESOLVED that the following Procedural Schedule and Rules governing this proceeding are hereby established: August 8. 1995 - Discovery couzwnences by the Councfa Advisors. August 11, 1995 - Publlcatlin of the Public Notice For Intervenlaone. August 21, 1995 - Closing Date for the filing of Interventions. Interventions and &I servIce " be filed in accordance with the Official Service List established for this proceeding by the City Counci Ullhis Regulatory Office. August 28, 1995 - Deedline for opposing Interventions. Septemoer 7. 1996 - City Council Action on any oppositions to Interventions. September 18. 1995 - Last Date for submission of Discovery Requests by any paNy. All Discovery in this Docket is to be considered 15 Day 'Rolling Dlscovery" (i.e. Al Discovery responses are due within 15 days of the receipt of the Requesti end as parties are encouraged to commence discovery Is soon as possible to expedite the Discovery process. October 3, 1995 - Discovery Closes. October 18, 1995 - Submission of statements of posiion with regard to the justness and reasonableness of the then *tfactiv@ rates by Ill parties to the proceeding Other then 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 CNO No Year Company (1) Jurisdiction (2) Jurisdiction (3) 1 2010 5,947 5,831 116 2 2011 5,947 5,831 116 3 2012 5,947 5,831 116 4 2013 5,947 5,831 116 5 2014 5,947 5,831 116 6 2015 6,821 6,688 133 7 2016 6,821 6,688 133 8 2017 6,821 6,688 133 9 2018 6,821 6,688 133 10 2019 6,821 6,688 133 11 2020 7,731 7,580 151. 12 2021 7,731 7,580 151 13 2022 7,731 7,580 151 14 2023 7,731 7,580 151 15 2024 7,731 7,580 151 16 2025 8,867 8,694 173 17 2026 8,867 8,694 173 18 2027 8,867 8,694 173 19 2028 8,867 8,694 173 20 2029 8,867 8,694 173 21 2030 10,246 10,047 200 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 11/1512006 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 schedule 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 07102/07 604,884.00 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

Attachment 4-E (Page 1 of 4) CNO Resolution R-14-494 in Docket UD-13-01

RESOLUTION NO. R-14-494 CITY HAIL: Novembpejr2Ol.201 BY: COUNCILMEMBERS SET APPLICATION OF ENTERGY LOUISIANA, LLC FOR AUTHORITY TO CHANGE RATES, APPROVAL OF FORMULA RATE PLAN AND FOR RELATED RELIEF FOR OPERATIONS IN ALGIERS DOCKET UD-13-01 RESOLUTION AND ORDER APPROVING JOINT COMPLIANCE FILING WHEREAS, pursuant to the Constitution of the State of Louisiana and the Home Rule Charter of the City of New Orleans ("Charter"), the Council of the City of New Orleans ("Council") is the governmental body with the power of supervision, regulation and control over public utilities providing service within the City of New Orleans; and WHEREAS, pursuant to its powers of supervision, regulation and, control over public utilities, the Council is responsible for fixing and changing rates and charges of public utilities and making all necessary rules and regulations to govern applications for the fixing and changing of rates and charges of public utilities; and WHEREAS, Entergy New Orleans, Inc. ("ENO" or "Company") is a public utility providing electric service to all of New Orleans, except the Fifteenth Ward ("Algiers"), and gas service to all ofNew Orleans; and WHEREAS, Entergy Louisiana, LLC ("ELL") provides ele6tric service to the Algiers section of New Orleans; and

WHEREAS, on March 28, 2013, ELL filed its Application for Entergy Louisiana, LLC for Authority to Change Rates, Approval of Formula Rate Plan and for Related Relief for Operations in Algiers ("Application"); and WHEREAS, the Application included ELL's request for a change in electric rates and new rate schedules applicable to electric service in Algiers; and WHEREAS, all of the parties, i.e., ELL, "the Advisors and AARP Corporation ("AARP"), reached a settlement.with respect to all of the issues in the docket, and that settlement was embodied in the Agreement in Principle ("AIP") recommended to the Council and reflected in Resolution R-14-278; and WHEREAS, Resolution R-14-278 approving the ATP was adopted by the Council at its regular meeting on July 10, 2014; and WHEREAS, pursuant to said resolution, and the terms of the AIP, ELL and the Advisors were directed to participate in technical conferences to facilitate agreement upon the final form of certain riders referenced in thý ATP with the intent of achieving a consensus compliance filing that could be made with the Council; and WHEREAS, more particularly, those riders related to Paragraphs 16 (PPA Capacity Rider); Paragraph 18 (Ninemile 6 Interim Rider); Paragraph 42 (Fuel Adjustment Clause ("FAC"); and Paragraph 43 (Environmental Adjustment Clause ("EAC`); and WHEREAS, the technical conferences were held, and ELL and the Advisors were able to reach agreement with respect to the form of all the riders; and WHEREAS, on October 22, 2014, ELL and the Advisors submitted their Joint Compliance filing for approval by the Council; and WHEREAS, the Council finds the Joint Compliance Filing of ELL and its Advisors to 2

be in conformity with the AIP; NOW THEREFORE BE IT RESOLVED BY THE COUNCIL OF THE CITY OF NEW ORLEANS, That the Joint Compliance filing of ELL and the Advisors submitted herein is hereby APPROVED. THE FOREGOING RESOLUTION WAS READ IN FULL, THE ROLL WAS CALLED ON THE ADOPTION THEREOF AND RESULTED AS FOLLOWS: YEAS: Brossett, Cantrell, Gray, Guidry, Head, Ramsey, Williams - 7 NAYS: 0 ABSENT: 0 FOREGOING IS CERTIFIED AND THE RESOLUTION WAS ADOPTED. TOTHE BE A TRUE AND CORRECT COPY CLERK OF C -C CIL 3

Attachment 5 Minimum Funding Assurance Calculation Worksheets (Page 1 of 10) Plant name: Arkansas Nuclear One, Unit I Month Day Year Year of Biennial: 12 31 2014 Termination of Operation: 5 20 2034 SMWth 1986$ ECI Base Lx I Fx I I I E 1 PWR 2568 r $97,598,400 r 122.7 1.98 1 0.65 r - 2.695 I I 0.13 2.22 0.22 13.885 NRC Minimum: $480,453,236 Site Specific: F Licensee: Entergy

                        % Owned:

100.00% Amount of NRC MinimumlSite Specific:

                                                              $480,453,236 Amount in Trust Fundt
                                                                                                            $429,513,088      1 Step 1:

Earnings Credit: Trust Fund Balance:

   $429,513,088 Step 2:
                     -1Real Rate of Years LeftI Return per in License ITotal Real Rate of Return:

0 2.35 / 19.39 I 1.56880 Total Earnings:

                                                                                      $673,821,318             ITotal Earnings = Trust Fund balance x (1+RRR)^Years left in license Accumulation:

Value of Annuity per Real Rate of year Return per Years of Annuity: Total Annuity:

         $0               2.35%                        0                                     $0 Total Step 2
                                                                                             $0 Total Step 1 + Step 2
                                                                                      $673,821,318 Step 3:

Decom Period: Real Rate of Decom Total Earnings: Return per Period: Total Real Rate of Return: Total Earnings for Decom:

   $673,821,318             2%            7              0.14869                        $50,093,786             Total Earnings for Decom = (112) x Total Earnings x [(l+RRR)^Decom period - 1]

I Accumulation during Decom

                                                                           +      Total of Steps 1 - 3:
                                                                                      $723,915,104            ITotal = Total Earnings + Total Earnings for Decom Excess (Shortfall)                     $                   243,461,868 to NRC minimum
                                                                             $                    (1,974,219) Less ISFSI
                                                                             $                            -      Parent Co Guaranty
                                                                             $                   241,487,649 Total Excess Financial Assurance

Attachme tnt 5 Minimum Funding Assurance CalculEation Worksheets (Page 2 of 10) Plant name: Arkansas Nuclea r One, Unit 2 Month Day Year Year of Biennial: 12 31 2014 Termination of Operation: 7 17 2038 1 MWth 1 1986 ECI Base Lx L Px 2.695 I

10. 13 rr2.22 10.22 PWR 3026 r$101,628,800r 122.7 1.98 0.65 r2.43r 1.880 2.2 0. I 113.885 g3;88 NRC Minimum: $500,293,917 Site I pecific:

Licensee: %Owned: Amount of NIRC Minimum/Site Specific: IAmount in Trust Fund Entergy 100.00% $500,293,917 $34(0,369,4422 Step 1: Earnings Credit: Real Rate of Years Left Trust Fund Balance: Return per in License Total Real Rate of Return: I Total Earnings:

    $340,369,442          2.70%        23.54             1.87252          1          $637,347,657                    '

Total Earnings = Trust Fund balance x (l+RRR)^Years left in license Step 2: Accumulation: Value of Annuity per I Real Rate of year Return per Years of Annuity: Total Annuity:

          $0              2.70%                        0                                     $0 Total Step 2
                                                                                            $0 Total Step 1 + Step 2
                                                                                    $637,347,657 Step 3:

Decom Period: Real Rate of Decorn Total Eamings: Return per Perod: Total Real Rate of Return: Total Earnings for Decorn:

    $637,347,657            2%           7               0.14869                     $47,382,231                     Total Earnings for Decom = (112) x Total Earnings x [(1+RRR)^Decom period - 1]

Accumulation during Decorn Total of Steps 1 - 3:

                                                                                    $ 68 4 , 72 9 , 8 88             Total = Total Earnings + Total Earnings for Decom Excess (Shortfall)                     $                       184,435,971 to NRC minimum
                                                                            $                          (1,974,219) Less ISFSI
                                                                                                               -       Parent Co Guaranty
                                                                            $                        182.461.751      Total Excess Financial Assurance

Attachment 5 Minimum Funding Assurance Calculation Worksheets (Page 3 of 10) Plant name: Grand Gulf Nuclear Station (SERI 90%) Month Day Year Year of Biennial: 12 31 2014 Termination of Operation: 11 1 2024 MWth 1 E I Base Lx Px I Fx Ex B.Pxx BWR 4408 r$135,000,000 r 122.7 1.98 0.65 2.43 1.880 2.695 0.13 r 2.25 0.22 14.16 NRC Minimum: $673,311,926 Site Specific: I. Licensee: Entergy

                        %Owned:

90.00% Amount of NRC MinimumlSite Specific:

                                                              $605,980,734 Amount in Trust Fund
                                                                                                            $679,839,789 Step 1:

Earnings Credit: 1= Trust Fund Balance:

    $679,839,789 Real Rate of Years Left Return per in Licensel Total Real Rate of Return:

2.09/6 9.83 1 1.21501 Total Earnings:

                                                                                     $826,008,948 I

ITotal Earnings = Trust Fund balance x (l+RRR)^Years left in license Step 2: Accumulation: Value of Annuity per Real Rate of year Return per Years of Annuity: Total Annuity: See Annuity Sheet 2.09/6 8 $219,058,458 Total Step 2

                                                                                     $219,058,458 Total Step 1 + Step 2
                                                                                    $1,045,067,406 Step 3:

Decom Period: Real Rate of Decorn Total Earnings: Return per Pedod: Total Real Rate of Return: Total Earnings for Decom:

   $1,045,067,406          2%              7              0.14869                     $77,693,272               Total Earnings for Decom = (112) x Total Earnings x [(I+RRR)^Decom period - 1]

I Accumulation during Decorn Total of Steps 1 - 3:

                                                                                    $1,122,760,678             ITotal = Total Earnings + Total Earnings for Decom Excess (Shortfall)                    $                  516,779,944      to NRC minimum
                                                                            $                    (3,336,105) Less ISFSI
                                                                            $                             -      Parent Co Guaranty
                                                                            $                   513,443,840      Total Excess Financial Assurance

Attachment 5 Minimum Funding Assurance Calculation Worksheets (Page 4 of 10) Plant I iame: Grand Gulf Terminati on of Operations: 2025 Real Total Year Annuity: Rate of Accumulation 2015 $22,285,000' 2.00% $27,165,291 Total Accumulation = Annuity x (l+RRR)AYears left from 2016 $24,550,000 2.00% $29,339,523 Accum 2017 $24,550,000 2.00% $28,764,238 2018 $24,550,000 2.00% $28,200,233 2019 $24,550,000 2.00% $27,647,287 2020 $24,550,000 2.00% $27,105,184 2021 $29,878,000 2.00% $32,340,908 2022 $17,429,000 2.00% $18,495,794 2023 $0 2.00% $0 2024 $0 2.00% $0 2025 $0 2.00% $0 Total: $219,058,458

Attachment 5 Minimum Funding Assurance Calculation Worksheets (Page 5 of 10) Plant name: Grand Gulf Nuclear Station (SMEPA 10%) Month Day Year Year of Biennial: 12 31 2014 Termination of Operation: 11 1 2024 MWth 1 1986$ EClI Base Lx ILx 1 Px Fx E& 1 B1_xx BWR 4408 [$135,000,000 r 122.7 1.98 0.65 2.43 1.880 2.695 0.13 r 2.25 0.22 14.16 NRC Minimum: $673,311,926 Site Specific: Licensee: %Owned: Amount of NRC Minimum/Site Specific: Amount in Trust Fundi Entergy 10.00% $67,331,193 $55,158,417 1 Step 1: Earnings Credit: Real Rate of Years Left I Trust Fund Balance: Return per in License Total Real Rate of Return: Total Earnings:

    $55,158,417           2.91%         9.83             1.32591                       $73,135,045             ITotal Earnings = Trust Fund balance x (1+RRR)'Years left in license Step 2:

Accumulation: Value of Annuity per Real Rate of year See Annuity Sheet Return per 2.91% Years of Annuity: 8 t Total Annuity:

                                                                                            $0                 I Total Step 2
                                                                                            $0 Total Step 1 + Step 2
                                                                                       $73,135,045 Step 3:

Decom Period: Real Rate of DecomII F Total Earnings:

    $73,135,045 Return per 2%

Period: 7 Total Real Rate of Return: 0.14869 Total Earnings for Decom:

                                                                                        $5,437,067             ITotal Earnings  for Decom = (112) x Total Earnings x [(1+RRR)ADecom period - 1]

Accumulation during Decomr Total of Steps 1-3:

                                                                                       $78,572,112 "            Total = Total Earnings + Total Earnings for Decom Excess (Shortfall)                     $                    11,240,919 to NRC minimum
                                                                             $                       (370,678) Less ISFSI
                                                                                                           -     Parent Co Guaranty
                                                                            $                     10,870,241 Total Excess Financial Assurance

Attachment 5 Minimum Funding Assurance Calculation Worksheets (Page 6 of 10) Plant name: River Bend (Regulated 70%) Month Day Year Year of Biennial: 12 31 2014 Termination of Operation: 8 29 2025 MWth 1 1986$ 1 ECI Base Lx BWR 3091 r$131,819,00° r 122.7 1.98 0.65 2.43 1.880 2.695 10.13 2.25 0.22 14.16 NRC Minimum: $657,446,702 Site Specific: Licensee: %Owned: Amount of NRC MinimumlSite Specific: Amount in Trust Fund Entergy 70.00% $460,212,692 $304,950,7522 Step 1: Earnings Credit: IReal Rate of Iyears LeftToaErngs Trust Fund Balance: Return per in License[ Total Real Rate of Return: Total Earnings:

   $304,950,752           2.00%        10.66 1           1.23506                      $376,632,463              ITotal Earnings = Trust Fund balance x (1+RRR)^Years left in license Step 2:

Accumulation: Value of Annuity per Real Rate of year IuReturn per Years of Annuity: Total Annuity: I See Annuity Sheet 1 2.00% 11 $0 Total Step 2

                                                                                      $133,282,919 Total Step 1 + Step 2
                                                                                      $509,915,382 Step 3:

Decom Period: Real Rate of Decorn Total Earnings: Return per Pedod: Total Real Rate of Return: Total Earnings for Decom:

   $509,915,382             2%           7               0.14869                       $37,908,554              ITotal  Earn ings for Decom = (112) x Total Earnings x [(1+RRR)^Decom period - 1]

Accumulation during Decorn Total of Steps 1 - 3:

                                                 $60,285,000               1          $608,108,936             ITotal = Total Earnings + Total Earnings for Decom Excess (Shortfall)                      $                   147,896,244 to NRC minimum
                                                                             $                    (2,317,475) Less ISFSI
                                                                             $                             -      Parent Co Guaranty
                                                                             $                   145,578,769 Tolal Excess Financial Assurance

Attachment 5 Minimum Funding Assurance Calculation Worksheets (Page 7 of 10) Plant name: River Bend Station (Regulated 70%) Termination of Operations: 2025 Real Total Year LPSC PUCT FERC Annuity: Rate of Accumulation 2015 $8,996,000 $1,126,000 1 13,000 $10,235,000 2.0% $12,476,408 Total Accumulation = Annuity x (1+RRR)AYears left from 2016 $8,996,000 $1,126,000 0113,000 $10,235,000 2.0% $12,231,772 Accum 2017 $8,995,000 $1,126,000 $113,000 $10,234,000 2.0% $11,990,762 2018 $8,995,000 $1,126,000 1 13,000 $10,234,000 2.0% $11,755,649 2019 $8,996,000 $1,126,000 1 13,000 $10,235,000 2.0% $11,526,272 2020 $10,195,000 $1,126,000 1 13,000 $11,434,000 2.0% $12,624,060 2021 $10,195,000 $1,126,000 1 13,000 $11,434,000 2.0% $12,376,529 2022 $10,195,000 $1,126,000 1 13,000 $11,434,000 2.0% $12,133,852 2023 $10,195,000 $1,126,000 1 13,000 $11,434,000 2.0% $11,895,934 2024 $10,195,000 $1,126,000 1 13,000 $11,434,000 2.0% $11,662,680 2025 $11,693,000 $751,000 $165,000 $12,609,000 2.0% $12,609,000 Total: $133,282,919 Accumulation During Decomm Period 2026 $11,693,000 $0 $0 $11,693,000 $11,693,000 2027 $11,693,000 $0 $0 $11,693,000 $11,693,000 2028 $11,693,000 $0 $0 $11,693,000 $11,693,000 2029 $11,693,000 $0 $0 $11,693,000 $11,693,000 2030 $13,513,000 $0 $0 $13,513,000 $13,513,000 2031 $0 $0 $0 $0 $0 2032 $0 $0 $0 $0 $0 2033 $0 $0 $0 $0 $0 2034 $0 $0 $0 $0 $0 Total: $60,285,000

Attachment 5 Minimum Funding Assurance Calculation Worksheets (Page 8 of 10) Plant name: River Bend (Non-Regulated 30%) Month Day Year Year of Biennial: 12 31 2014 Termination of Operation: 8 29 2025 BWR I -MWth 3091 1986$ ECI r$131,819,000F 122.7 Base Lx 1.98 0.65 r 2.43 r I IPx 1.880 r Fx 2.695 I I 0.13 I gýý r 2.25 I 0.22 B. 114.16ý NRC Minimum: $657,446,702 Site Specific: Licensee: %Owned: Amount of NRC MinimumlSite Specific: lAmount in Trust Fundt Entergy 30.00% $197,234,011 1 $332,793.599 Step 1: Earnings Credit: 4 Real Rate of IYears Left Total Real Trust Fund Balance: Return per Iin Licensel Rate of Total Earnings: 1

   $332,793,599             2%      1 10.66 1 1.23506                     $411,020,048              Total Earnings = Trust Fund balance x (I+RRR)AYears left in license Step 2:

Accumulation: Value of Annuity per Real Rate o year Return per Years of Annuity: Total Annuity:

         $0                 2%                   0                             $0 Real Rate of   Years remaining after Total Annuity        Return per            annuity                     Total Step 2
         $0                 2%             10.66118721                         $0 Total Step 1 + Step 2
                                                                          $411,020,048 Step 3:

Decom Period: Real Rate of Decom Total Real F Total Earnings:

   $411,020,048 Return per 2%

Period: 7 Rate of 0.14869 Total Eamin asfor Decom:

                                                                           $30,556,395              Total Earnings for Decom = (112) x Total Earnings x [(I+RRRrDecom period -1A Total of Steps 1 - 3:        1
                                                                          $441,576,443             [Total = Total Earnings + Total Earnings for Decom Excess (Shortfall)          $                  244,342,433      to NRC minimum
                                                                 $                      (993,204) Less ISFSI
                                                                 $                            -      Parent Co Guaranty
                                                                 $                   243,349,229 Total Excess Financial Assurance

Attachment 5 Minimum Funding Assurance Calculation Worksheets (Page 9 of 10) Plant name: Waterford 3 Month Day Year Year of Biennial: 12 31 2014 Termination of Operation: 12 18 2024 PWR I MWth 3716 NRC Minimum: 1986$ [$105,000,000r 1ECI 122.7 *1* Base Lx 1.98

                                                          $516,889,516 0.65               2.43 Site Specific:

Pxl 1.880 FxI 2.695 0.13 I E 2.22 I 0.22 I BPx 13.885 F Licensee: Entergy

                         %Owned:

100.00% Amount of NRC MinimumlSite Specific:

                                                              $516,889,516 Amount in Trust Fund
                                                                                                             $383,615,384 Step 1:

Earnings Credit-Real Rate of Years Leftj Trust Fund Balance: Return per in License Total Real Rate of Return: Total Earnings::

    $383,615,384             2%          9.96  1          1.21813          I          $467,295,313                Total Earnings = Trust Fund balance x (1+RRR)AYears left in license Step 2:

Accumulation: Value of Annuity per Real Rate of year Return per Years of Annuity: Total Annuity: I See Annuity Sheet 2% 10 $0 Total Step 2

                                                                                       $81,542,100 Total Step 1+ Step 2
                                                                                      $548,837,413 Step 3:

Decom Period: Real Rate of IDecorn [ Total Earnings:

    $548,837,413 Return per 2%

Period: Total Real Rate of Return: 7 1 0.14869 Total Earnings for Decom:

                                                                                       $40,802,129                Total Earnings for Decom = (112)x Total Earningsx [(1+RRR)ADecom period - 1]

I. Accumulation during Decom

                                                  $53,517,000              IH     Total of Steps 1 - 3:
                                                                                      $643,156,542"                rotal = Total Eamings+ Total Earnings for Decom Excess (Shortfall)                     $                  126,267,025 to NRC minimum
                                                                             $                    (3,167,786) Less ISFSI
                                                                             $                             -       Parent Co GuarantY
                                                                             $                   123,099,239       Total Excess Financial Assurance

Attachment 5 Minimum Funding Assurance Calculation Worksheets (Page 10 of 10) Plant name: Waterford Generating Station, Unit 3 Termination of Operations: 2025 Real Tota I Year LPSC CNO Annuity: Rate of Accumulatio 2015 $6,688,000 $189,000 $6,877,000 2.00% $8,383,025 Total Accumulation = Annuity x (l+RRR)AYears left from 2016 $6,688,000 $189,000 $6,877,000 2.00% $8,218,652 Accum 2017 $6,688,000 $189,000 $6,877,000 2.00% $8,057,502 2018 $6,688,000 $189,000 $6,877,000 2.00% $7,899,511 2019 $6,688,000 $189,000 $6,877,000 2.00% $7,744,619 2020 $7,580,000 $189,000 $7,769,000 2.00% $8,577,604 2021 $7,580,000 $189,000 $7,769,000 2.00% $8,409,415 2022 $7,580,000 $189,000 $7,769,000 2.00% $8,244,525 2023 $7,580,000 $189,000 $7,769,000 2.00% $8,082,868 2024 $7,580,000 $189,000 $7,769,000 2.00% $7,924,380 Total: $81,542,100 Accumulation During De comm 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}}