Text

Entergy Operations, Inc., Status of Decommissioning Funding Report
	ML050940264
Person / Time
Site:	Grand Gulf, Arkansas Nuclear, River Bend, Waterford
Issue date:	03/31/2005
From:	Burford F; Entergy Operations
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	-RFPFR, CNRO-2005-00022
	Download: ML050940264 (67)
	v • d • e

Entergy Operations, Inc.

En tergy 1340 Echelon Parkway Jackson. Mississippi 39213-8298 Tel 601-368-5758 F. G. Burford Acting Director Nuclear Safety & Licensing CNRO-2005-00022 March 31, 2005 U.S. Nuclear Regulatory Commission Attn: Document Control Desk 11555 Rockville Pike Rockville, MD 20852-2738 (301) 415-7000

SUBJECT:

Entergy Operations, Inc Status of Decommissioning Funding Report River Bend Station Grand Gulf Nuclear Station Docket No. 50-458 Docket No. 50-416 License No. NPF-47 License No. NPF-29 Arkansas Nuclear One Waterford 3 Steam Electric Units 1 & 2 Station Docket Nos. 50-313 & 50-368 Docket No. 50-382 License Nos. DPR-51 & NPF-6 License No. NPF-38

Dear Sir or Madam:

On behalf of the captioned reactor licensees, Entergy Operations, Inc. ("EOI"), submits documentation in accordance with the biennial reporting requirements contained in 10 CFR Section 50.75(f). In accordance with these requirements, EOI provides reports on the status of its decommissioning funding at least once every two years from this date.

Since EOl's last biennial report, the Louisiana Public Service Commission has ordered that the decommissioning collections for River Bend be based on an assumption that the operating license and the useful life of River Bend will be extended. This results in a collection rate of zero dollars per year for decommissioning for the Louisiana regulated share of River Bend. As EOI noted in its last biennial report, the Arkansas Public Service Commission took a similar action for the Arkansas Nuclear One plant.

This submittal contains no new commitments.

cC ( litady 65 es p V

CNRO-2005-00022 Page 2 of 2 Please address any comments or questions regarding this matter to Mr. L. A. England at 601-368-5766.

Sincerely, FGB/LAE/baa Attachments:

1. ANO Report

2. GGNS Report

3. RBS Report - 70% Regulated; 30% Non-Regulated

4. WF3 Report cc: (All Below w/o Attachments - See File Copy for Attachments)

Mr. T. A. Burke (M-ECH-62)

Mr. W. R. Campbell (M-ECH-65)

Mr. J. P. DeRoy (M-ECH-579)

Mr. W. A. Eaton (M-ECH-3X)

Mr. J. S. Forbes (N-GSB-46)

Mr. P. D. Hinnenkamp (R-GSB-40)

Mr. J. R. McGaha (M-ECH-65)

Mr. N. S. Reynolds (W&S)

Mr. L. Jager Smith (Wise, Carter)

Mr. G. J. Taylor (M-ECH-65)

Mr. J. E. Venable (W-GSB-300)

Mr. G. A. Williams (G-ESC3-VPO)

Mr. T. W. Alexion, Project Manager, ANO Mr. D. G. Holland, Project Manager, ANO-2 Mr. N. Kalyanam, Project Manager, W-3 Dr. B. S. Mallett, Regional Administrator, Region IV Mr. B. K. Vaidya, Project Manager, GGNS Mr. M. K. Webb, Project Manager, RBS

Attachment I ANO Report Report on Status of Decommissioning Funding Required by 10 CFR 50.75(fXD)

March 1. 2005 Arkansas Nuclear One - Units I and 2

1. Decommissioning funds estimated pursuant to 10 CFR 50.75(b) and (c) (004$):

Arkansas Nuclear One - Unit 1: S 54Z535.478 '

Arkansas Nuciear One - Unit 2: S 554 597. 998' Total s 1,*97,133,476

2. Market value of funds accumulated as of December 31 20D4:

Arkansas Nuclear One . Unit 1: s 214,e04,s34' Arkansas Nuclear One - Unit 2. S 176.35981 2 Total $ 390D.984815

3. Current schedule of annual amounts remaining to be collected: See Attachment 1-C 4

4. Assumed rate of decommissioning cost escalation used hi funding projections (Attachment 1-C):

5. Assumed average after-tax rates of earnings used hI funding projections: Unit I 6.18% 5 Unit 2 6.53% a

6. Assumed rates of other factors used hI funding projections: See Attachment 1-C 4

7. Contracts assuring collection of decommissioning funds: None

8. Modifications to method of providing financisl assurance since March 31, 2003 filing (external sinking fund): See Footnote

9. Material changes to trust agreements since March 31 2003 filing: See Footnote e Supplemental Informaton:

1.Site-Specific cost estiumate escalated to 2004(20 Base Year Dollars):

Arkansas Nuclear One

Unit 1: S 391,163807 '

Arkansas Nuclear One - Unit 2. S 385482170 '

Total S 776,625g977

2. Decommissioning rmethod assumed for planning purposes Insite-specific esbimate: Oi-ON '

3. Year ste-pecific estimate complete: 2003

4. Frequency of updates (approximately: once every 5 years 5.Funding based on NRC minimum or site-specific estimate7 Site-specific

6. Decommissioning rate regulation (approximately):

Arkansas Public Service Commission 88%

Federal Energy Regulatory Commission 14%

' See Attachment 1-A calculations.

2 Source: December 31. 2004 ANO Trust Fund Reports.

' See Attachment 1-B for calculations. Also ee footnotes 4 and 5 to Attachment 1-A for Information on the generic baseline cost estimate using the waste vendor disposal factor (Bamwel).

On October 3,2000. the APSC ordered Entergy Arkansas to reflct a 20 yr. life extension in Its determination of the ANO1 and ANO2 decommissioning revenue requirements for rates to be effectve January 1.2001. The amount of decommissioning costs collected hI rates for ANO was et to zero as a result of the APSC order. See Attachment 1-C.

' Assumed weighted average after-tax eamings rate for the non-qualified and tax qualified decommissioning funds for the period 2005-2045 for Unit I and 2005-2026 for Unit 2 Pocket 87-16-TF Orders No. 27.32 and 41).

The following section was added to l trust agreements on December17. 2003:

Notice Reoardino Disbursements or Payments Notwithsbnding anything to the contrary h this Agreement except or (D)payments d ordinary administrative costs (including baxes) and other incidental expenses of theTrust Fund (ncluding legal, accounting, actuarial, and SuccessorTrustee expenses) Inconnection with the operstion of theTrust Fund. ril withdrawals being made under10 CFR 50.82(a)t8). and (iii0 transfers between Oualified and Noniqualified Funds Inaccordance with the provisions of this Agreement no disbursement or payment may be made from the Trust Fund until written notice of te intention to make a disbursement or payment has been given to the Director, Office of Nuclear Reactor Regulation, or the Director. Office of Nuclear Material Safety and Safeguards, as applicable, at least 30 working days before the date of the intended disbursement or payment The disbursement or payment from the Trust Fund, if it is otherwise Incompliance with the ternnand conditions of this Agreement may be made following the 30-workina day notice period if no written notice of oblection from the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards. as applicable. Is received by the Successor Trustee or the Company within the notice period. The required notice may be made by the Successor Trustee or on the Succssor Trustes behalf. This Section 8.D4 it Intended to Qualify ach and every provision d his Tnust Aoreement alloing distributions from the Trust Fund, and in the event of any conflict between any such provision and this Section, this Section shall control.

'Unit 2 will be inSAFSTOR until Unit 1 shuts down, at which time DECON will be the decomrnissioning method used for both.

Attachment 1-A ANO Report ARKANSAS NUCLEAR ONE - UNITS 1 AND 2 CALCULATION OF MINIMUM AMOUNT AS PER 10CFR 50.75 (b)AND (c)

Determination of Minimum Amount Entergy Arkansas, Inc.: 100% ownership interest Plant Location: Russellville, Arkansas Reactor Type: Pressurized Water Reactor ("PWR")

ANO Unit I Power Level: <3,400 MWt. (2,568 MWt)

ANO Unit I PWR Base Year 1986$: $97,600,000 ANO Unit 2 Power Level: <3,400 MWt. (3,026 MWt)

ANO Unit 2 PWR Base Year 1986$: $99,770,000 Labor Region: South Waste Burial Facility: Barnwell, South Carolina I OCFR50.75(c)(2) Escalation Factor Formula:

0.65(L) + 0.13(E) + 0.22(B)

Factor L=Labor (South) 1.925 '

E=Energy (PWR) 1.434 2 B=Waste Burial (PWR) 18.732 '

PWR Escalation Factor:

0.65(L) + 0.13(E) + 0.22(B) = 5.55877 1986 PWR Base Year $ Escalated:

ANO 1: $97,600,000 ^ Escalation Factom $ 542,535,478 4 ANO 2: $99,770,000 ^ Escalation Factor= $ 554,597,998 5 Total ANO Units I and 2: $ 1,097,133,476 1Source: Bureau of Labor Statistics: series report Idecu13202i (March 2005).

2 Source: Bureau of Labor Statistics: series report Idwpu0543 and wpuO573 (March 2005).

3Source: Nuclear Regulatory Commission:Table 2.1 of 'Report on Waste Burial Charges". NUREG-1307 revision 10 (October 2002).

4 Application of the 9.467 waste vendor disposal factor (South Carolina) from Table 2.1 of 'Report on Waste Burial Charges'.

NUREG 1307 Revision 10 (October 2002) yields a generic baseline cost = $ 343,597,398 5Application of the 9.467 waste vendor disposal factor (South Carolina) from Table 2.1 of Report on Waste Burial Charges',

NUREG 1307 Revision 10 (October 2002) yields a generic baseline cost = $ 351,236,807

Attachment 1-B ANO Report ARKANSAS NUCLEAR ONE - UNIT 1 CALCULATION OF SITE-SPECIFIC COST ESTIMATE ESCALATED TO 2004 DOLLARS Site-Specific Cost Estimate (2002$)

Unit I Unit 2 Site-Specific Cost Estimate (2002$):

NRC License Termination Cost: $ 353,840,000 $ 321,714,000 Non-NRC License Termination Cost: $ 18,002,000 2 $ 44,708,000 2 Total Site-Specific Cost Estimate: $ 371,842,000 $ 366,422,000 Annual Escalation Factor: CPI 1 CPI 1 Years of Escalation (2002 Base Year to 2004): 2 2 Cumulative Factor: 1.0520 1.0520 Site-Specific Cost Estimate (2004$):

NRC License Termination Cost

Cumulative Factor: $ 372,226,379 $ 338,431,035 Non-NRC License Termination Cost:

Cumulative Factor: $ 18,937,427 $ 47,031,135 Total Site-Specific Cost Estimate: l $ 391,163,807 l $ 385,462,170 l 1 Based on site-specific cost estimates in 2002$ and escalation rates tied to projections of the Consumer Price Index-Urban ('CPI") for the period from 2002 through 2004 of 5.2%.

2 The APSC Order 41 in Docket # 87-166-TF excluded spent fuel management costs from this amount.

Attachment 1-C ANO Report I of 2 Entergy Arkansas, Inc.

ANO Decommissioning Model Unit 1 Summary (t0SO)

Non-Tax Qualified Trust Deferred Tax Qualified Trust Decomm.

Line Revenue Net Trust Tax Net Trust Decomm. Fund No. Year Rqmt. Additions Balance Bal. Additions Balance Expend.[1J Balance 1 Beginning Balance 38,856 7,830 159.359 206,045 2 2005 2,339 41,195 7,830 9,378 168,737 0 217,762 3 2006 2,489 43,684 7,830 9,983 178,720 0 230,233 4 2007 2,648 46,332 7,830 10,612 189,331 0 243,493 5 2008 2,819 49,151 7,830 11,828 201,159 0 258,140 6 2009 3,006 52,157 7,830 13.232 214,392 0 274,379 7 2010 3.207 55,364 7,830 14,126 228.518 0 291,712 8 2011 3.427 58,792 7,830 15,082 243,600 0 310,222 9 2012 3,640 62,432 7,830 16,079 259,679 0 329,941 10 2013 3.866 66.297 7,830 17,142 276,821 0 350,949 11 2014 4,106 70,403 7,830 18,275 295.096 0 373,330 12 2015 4,360 74,764 7,830 19,483 314.579 0 397,173 13 2016 4,631 79,395 7,830 20,771 335,350 0 422,575 14 2017 4,918 84,313 7,830 22,144 357,494 0 449,637 15 2018 5,224 89,537 7,830 23,607 381,101 0 478,467 16 2019 5,548 95,085 7,830 25,168 406.268 0 509,183 17 2020 5,892 100,977 7,830 26,831 433,099 0 541,906 18 2021 6,258 107,234 7,830 28,604 461,704 0 576,768 19 2022 6,646 113,880 7,830 30,495 492,199 0 613,909 20 2023 7,058 120,938 7,830 32,511 524,710 0 653,478 21 2024 7,496 128,435 7,830 34,660 559,369 0 695,634 22 2025 7.961 136,396 7,830 36,951 596,320 0 740,546 23 2026 8.455 144,852 7,830 39,393 635,713 0 788,394 24 2027 8,980 153,832 7,830 41,997 677,709 0 839,371 25 2028 9,537 163,369 7,830 44,772 722,482 0 893,681 26 2029 10,129 173,498 7,830 47,732 770,214 0 951,542 27 2030 10,758 184,256 7,830 50,887 821,100 0 1,013,187 28 2031 11.425 195,682 7,830 54,250 875,351 0 1,078,862 29 2032 11,630 207,312 7,830 56,210 931,560 0 1,146,702 30 2033 11,491 218.803 7,830 56,076 987,637 0 1,214,269 31 2034 11,207 185,275 0 55,694 1,043.331 52,565 1,228.605 32 2035 9,090 37,961 0 56,799 1,100.130 156,404 1,138,091 33 2036 1.868 0 0 60.232 994,927 205,264 994,927 34 2037 0 0 0 54,470 896,855 152,542 896,855 35 2038 0 0 0 49,559 861,839 84,574 861,839 36 2039 0 0 48,420 824.021 86,238 824,021 0

37 2040 0 0 46,633 812,678 57,976 812.678 0

0o 38 2041 0 0 47,412 823,764 36,325 823,764 0

39 2042 0 0 48,144 845,432 26,476 845,432 Notes:

[I] Funding amounts are based on site-specific cost estimates in 2002S (see Attachment 1-.).

Miscellaneous Input Data Nuclear Cost Escalator CPIU Composite Tax Rate 39.35%

TO Fund Federal Tax Rate 20.00%

Attachment 1-C ANO Report 2 of 2 Entergy Arkansas, Inc.

ANO Decommissioning Model Unit 2 Summary

($000)

Non-Tax Qualified Trust Deferred Tax Qualified Trust Decomm.

Line Revenue Net Trust Tax Net Trust Decomm. Fund No Year Rqmt. Additions Balance Sal. Additions Balance Expend.1l) Balance 1 Beginning Balar ice 15,880 4,240 147,936 168,056 2 2005 O 951 16,831 4,240 8,948 156,884 0 177.955 3 2006 0 1,012 17,843 4,240 9,522 166,406 0 188,489 4 2007 0 1,077 18,920 4,240 10,153 176.559 0 199,719 5 2008 0 1,146 20,066 4,240 11,265 187,824 0 212,131 6 2009 0 1,223 21,289 4,240 12,528 200,353 0 225,882 7 2010 0 1,304 22,593 4,240 13,407 213,759 0 240,593 8 2011 0 1,394 23,987 4,240 14,328 228.087 0 256,314 9 2012 0 1,488 25,475 4.240 15,360 243,447 0 273,162 10 2013 0 1,591 27,065 4,240 16,421 259.868 0 291,174 11 2014 0 1,699 28,765 4,240 17,664 277,533 0 310,537 12 2015 0 1,818 30,583 4,240 19,068 296,600 0 331,423 13 2016 0 1,934 32,517 4,240 20,379 316,979 0 353,736 14 2017 0 2,057 34,573 4.240 21,781 338,760 0 377,573 15 2018 0 2,187 21,588 0 23,279 362,039 19,412 383,627 16 2019 0 1,363 0 0 24,880 346,387 63,482 346,387 17 2020 0 0 0 0 23,804 365,357 4,834 365,357 18 2021 0 0 0 0 25,108 390,465 0 390,465 19 2022 0 0 0 0 26,835 417,301 0 417,301 20 2023 0 0 0 0 28,681 445,982 0 445,982 21 2024 0 0 0 0 30,654 476,636 0 476,636 22 2025 0 0 0 0 32.762 509,398 0 509,398 23 2026 0 0 0 0 35,016 544,414 0 544,414 24 2027 0 0 0 0 37,424 581,839 0 581,839 25 2028 0 0 0 0 39,999 621,838 0 621,838 26 2029 0 0 0 0 42,750 664,588 0 664,588 27 2030 0 0 0 0 45,690 710,278 0 710,278 28 2031 0 0 0 0 48,833 759,111 0 759,111 29 2032 0 0 0 0 52,192 811,303 0 811,303 30 2033 0 0 0 0 55,782 867,085 0 867,085 31 2034 0 0 0 0 59,619 926,704 0 926,704 32 2035 0 0 0 0 63,720 990,423 0 990,423 33 2036 0 0 0 0 66,260 1,031,658 25,026 1,031,658 34 2037 0 0 0 0 64,123 1,030,524 65,257 1,030,524 35 2038 O 0 0 0 59,491 888,477 201,538 888,477 36 2039 0 0 0 0 49,917 712,212 226,182 712,212 37 2040 0 0 0 0 40,303 651,181 101,334 651,181 38 2041 0 0 0 0 37,986 617,480 71,686 617,480 39 2042 0 0 0 0 36.082 605,902 47,661 605,902 Notes:

[1 Funding amounts are based on site-specific cost esfimates in 2002$ (see Attachment 1.B).

Attachment 2 GGNS Report Report on Status of Decommissioning Funding Required by 10 CFR 50.75(f)(1)

March 31, 2005 Grand Gulf Nuclear Station Minimum Reportina Requirements as per 10 CFR 50.75l1010:

1. Decommissioning funds estimated pursuant to 10 CFR 50.75(b) and (c) (2004$):

System Energy Resources, Inc. ("System Energy") 90% ownership/leasehold interest: S 621,417,825 '

South Mississippi Electric Power Association ("SMEPA") 10% ownership interest: S 69.046,425 Total $ 690,464,250

2. Market value of funds accumulated as of December 31, 2004:

System Energy 90% ownership/leasehold Interest: S 210,036.129 2 SMEPA 10% ownership interest: $ 15,055,000 2 Total $ 225,091,129

3. Current schedule of annual amounts remaining to be collected:

System Energy 90% ownership/leasehold interest: See Attachment 2-C SMEPA 10% ownership interest: See Attachment 2-D

4. Assumed rate of decommissioning cost escalation used In funding projections (Attachment 2-C):

System Energy 90% ownership/leasehold interest: 5.50%

SMEPA 10% ownership interest: 4.00%

5. Assumed average after-tax rates of earnings used in funding projections:

System Energy 90% ownership/leasehold interest: 6.74% 5 SMEPA 10% ownership interest: See Attachment 2-D

6. Assumed rates of other factors used in funding projections:

System Energy 90% ownership/leasehold interest: See Attachment 2-C SMEPA 10% ownership interest: See Attachment 2-D

7. Contracts assuring collection of decommissioning funds: See Attachment 2-E&F

8. Modifications to method of providing financial assurance since March 31, 2003 filing (external sinking fund): None

9. Material changes to trust agreements since March 31, 2003 filing:

System Energy 90% ownership/leasehold interest: See Footnote 6 SMEPA 10% ownership interest: None Supplemental Information:

1. Site-Specific cost estimate escalated to 2004 (1993 Base Year Dollars):

System Energy 90% ownership/leasehold interest:

NRC License Termination Cost: $ 587,194,158 3 Non-NRC License Termination Cost: S 27,508,897 3 Total 5 614,703,054 SMEPA 10% ownership interest:

NRC License Termination Cost: S 55,735.114 3 Non-NRC License Termination Cost: $ 2,611,081 3 Total $ 58,346,195

2. Decommissioning method assumed for planning purposes in site-specific estimate: DECON

Attachment 2 GGNS Report Report on Status of Decommissioning Funding Required by 10 CFR 50.75(f)(1)

March 31, 2005 Grand Gulf Nuclear Station

3. Year site-specific estimate complete: 1994 '

4. Frequency of updates (approximately): once every 5 years 4

5. Funding based on NRC minimum or site-specific estimate?: Site-specific

6. Decommissioning rate regulation:

System Energy 90% ownership/leasehold interest (Federal Energy Regulatory Commission): 100%

SMEPA 10% ownership interest (Rural Utilities Service): 100%

See Attachment 2-A for calculation.

2 Source: December 31, 2004 Grand Gulf Trust Fund Reports.

3 See Attachment 2-B for calculations. Also see footnotes 4 and 5 to Attachment 2-A for information on the generic baseline cost estimate using the waste vendor disposal factor (Barnwell, South Carolina).

On July 31, 2000, the FERC Issued an order approving a lower decommissioning costs than requested.

In July 2001, FERC denied a request for rehearing and the July 2000 order became final. SERI made refunds in December 2001. SERI collects at the '93 cost study amount of $365.9 million less S24.8 million for reduced greenfielding cost.

The 1999 cost update ($600.9 million) of $540.8 million for SERI's 90% has not yet been filed with the FERC.

The 2004 cost update has not been finalized.

5 Assumed weighted average after-tax earnings rate for the non-qualified and tax qualified decommissioning funds for the period 2004-2031 (FERC Order No. ER95 1042-000 July 2000).

6 The following section was added to all trust agreements on December 17, 2003:

Notice Regardino Disbursements or Payments Notwithstanding anything to the contrary in this Agreement, except for (i) payments of ordinary administrative costs (including taxes) and other Incidental expenses of the Trust Fund (including legal, accounting, actuarial, and Successor Trustee expenses) in connection with the operation of the Trust Fund, (ii) withdrawals being made under 10 CFR 50.82(a)(8), and (iii) transfers between Qualified and Nonqualified Funds in accordance with the provisions of this Agreement, no disbursement or payment may be made from the Trust Fund until written notice of the intention to make a disbursement or payment has been given to the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, at least 30 working days before the date of the Intended disbursement or payment. The disbursement or payment from the Trust Fund, if it is otherwise in compliance with the terms and conditions of this Agreement, may be made following the 30-working day notice period if no written notice of objection from the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, is received by the Successor Trustee or the Company within the notice period. The required notice may be made by the Successor Trustee or on the Successor Trustee's behalf. This Section 8.04 is intended to qualify each and every provision of this Trust Agreement allowing distributions from the Trust Fund, and in the event of any conflict between any such provision and this Section, this Section shall control.

Attachment 2-A GGNS Report GRAND GULF NUCLEAR STATION CALCULATION OF MINIMUM AMOUNT AS PER I OCFR 50.75 (b) AND (c)

Determination of Minimum Amount 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.

1986 BWR Base Year $: $135,000,000 Labor Region: South Waste Burial Facility: Bamwell, South Carolina I0CFR50.75(c)(2) Escalation Factor Formula:

0.65(L) + 0.13(E) + 0.22(B)

Factor L=Labor (South) 1.925 '

E=Energy (BWR) 1.448 2 B=Waste Burial (BWR) 16.705 3 BWR Escalation Factor:

0.65(L) + 0.13(E) + 0.22(B) = 5.11455 1986 BWR Base Year $ Escalated:

$135,000,000

Escalation Factor = $ 690,464,250 System Energy Interest (90%): $ 621,417,825 4 SMEPA Interest (10%) $ 69,046,425 5 Total $ 690,464,250 Source: Bureau of Labor Statistics: series report Id ecuI3202i (March 2005).

2 Source: Bureau of Labor Statistics: series report id wpu0543 and wpu0573 (March 2005).

3 Source: Nuclear Regulatory Commission:Table 2.1 of 'Report on Waste Burial Charges", NUREG-1307revision 10(October 2002).

4Application of the 8.860 waste vendor disposal factor (South Carolina) from Table 2.1 of "Report on Waste Burial Charges",

NUREG 1307 Revision 10 (October 2002) yields a generic baseline cost = $ 411,720,993 5Application of the 8.860 waste vendor disposal factor (South Carolina) from Table 2.1 of "Report on Waste Burial Charges",

NUREG 1307 Revision 10 (October 2002) yields a generic baseline cost = $ 45,746,777

Attachment 2-B GGNS Report GRAND GULF NUCLEAR STATION CALCULATION OF SITE-SPECIFIC COST ESTIMATE ESCALATED TO 2004 DOLLARS Site-Svecific Cost Estimate (1993$)

System Energy SMVEPA Total (90% Interest) 1 (10% Interest) 2 Estimate Site-Specific Cost Estimate (1993$):

NRC License Termination Cost: $ 325,840,205 $ 36,204,467 $ 362,044,672 Non-NRC License Termination Cost: $ 15,264,976 $ 1,696.108 $ 16,961,084 Total Site-Specific Cost Estimate: $ 341,105,180 $ 37,900,576 $ 379,005,756 Annual Escalation Factor 5.50% ' 4.00% 2 Years of Escalation (1993 Base Year to 2004): 11 11 Cumulative Factor (1 + Factor)A 1: 1.80 1.54 Site-Specific Cost Estimate (2004$):

NRC License Termination Cost

Cumulative Factor: $ 587,194,158 $ 55,735,114 $ 642,929,272 Non-NRC License Termination Cost: ^ Cumulative Factor $ 27,508,897 $ 2,611,081 $ 30.119,978 Total Site-Specific Cost Estimate: $ 614.703,054 $ 58,346,195 1$ 673,049.249 1 Funding amounts (Attachment 2-C) based on site-specific cost estimate in 1993$ (with reduced greenfielding, as shown above) and 5.50% annual escalation rate.

2 Funding amounts (Attachment 2-D) based on site-specific cost estimate in 1993$ (with reduced greenfielding, as shown above) and 4.0% annual escalation rate.

Attachment 2-C GGNS Report I of 2 System Energy Resources, Inc.

Grand Gulf Decommissioning Model Owned Portion Summary

($000)

Decommissioning Fund Balances Line Revenue Non-Tax Tax Decomm.

No Year Rqrnt. Qualified (2) Qualified (2) Total Expend. (1) 1 Beinning Balance 486 25.920 26,406 2 ___ 1995 6,813 616 34,579 35,195 0 3 1996 11,195 818 48,282 49,100 0 4 1997 11,195 1,033 62.907 63,940 _ _ 0 5 1998 11,195 1,261 78.517 79,778 0 6 1999 11.195 1,503 95.178 96.681 0 7 2000 11.195 1,760 112,961 114,721 0 8 2001 13.624 2,068 134,415 136.483 0 9 2002 13.624 2.395 157,314 159,710 0 10 ____2003 13.624 2.743 181,755 184,498 0 11 2004 13.624 3.111 207,842 210,953 0

-12 2005 13.624 3.502 235,685 239,187 __ 0 13 2006 16.590 3,961 268,423 272,385 0 14 2007 _ 16,590 4,448 303,367 307,815 _0 15 2008 16.590 4,965 340,663 345,628 0 16 2009 16,590 5.514 380,471 385,985 0 17 2010 16,590 6,097 422,959 429,055 0 18le _ 2011 20.184 6.768 471,967 478.735 0 19 2012 20,184 7,480 524,275 531,755 0 20 2013 20,184 8,236 580,106 588,342 0 21 2014 20.184 9,038 639,696 648,734 0 22 2015 20.184 9.592 703.597 713,189 0 23 2016 24,550 10,180 776.311 786,491 0

.24 2017 24.550 10,804 853,921 864,725 ___ 0 25 2018 24,550 11,467 936,757 948.224 0 26 2019 24.550 12,170 1,025.171 1,037,341 _ 0 27 2020 24.550 12,916 1,119,538 1,132,454 0 28 _ 2021- _ 2.9,878 113.708 1,225,765 1,239,473 0 29 2022 17,429 0 1,303,048 1,303,048 37,78-4 30 2,023. 0 IC__ _0 1,305,389 1,305.389 85,375 31 2024 0 0 1,140,563 1,140,563 252,699

_32 -. 2025 0- 0 951,474 951,474 265,864 33 2026 0 0 732,399 732.399 283,117

.34 2027 0 0 482.996 482,996 298,693 35 2028 0 0 203,197 203,197 312,296 36 2029 0 0 86.632 86.632 130,222 37 2030 0 0 6,095 6.095 86,344 38 2031 0 0 0 0 6,491 Notes:

1) Nuclear cost escalator is 5.5% per year.

2) Assumed weighted average after-tax earnings rate is:

non-tax qualified tax qualified 3,111 207,842 210.953 6.14% 6.75%

0.09% 6.65% 6.74%

Attachment 2-C GGNS Report 2 of 2 System Energy Resources, Inc.

Grand Gulf Decommissioning Model Leased Portion Summary

($000)

Decommissioning Fund Balances Line Revenue Ncin-Tax Tax Decomm.

No Year Rqmt. Ci. ralified (2) Qualified (2) Total Expend. (1) 1 Beginning Balance 81 4,578 4,659 2 1995 1,208 -104- 6,104 6.208 0 3 1996 1,997 139 8,534 8.673 0 4 1997 1.997 177 __ 11.123 11,300 0 217 13,886 14,103 -

5 1998 1,997 0

6 19991,9 259 16.833 17,093 0

7 2000 1,997 304 19,978 20,282 0

8 2001 2.431 359 23,774 24,133 0

9 2002 2,431 416 27.825 28,241 0

10 2003 2,431 477 32.148 32.625 11 2004 2,431 542 36,762 37,305 0 12 2005 2.431 611 41,688 42.298 _ 0-O 13 2006 2,960 692 47,483 48,175 0 14 2007 2.960 777 53,669 54,446 0 15 2008 2.960 868 60.272 61,140 0 16 _ 2009 _ 2.960 965 _ 67,319 68,284 _ -0 17 2010 2,960 1,067 74,840 75,908 0 18 2011 __ __3.601 1,186 83,521 84,707 0 19 2012 3.601 1,311 92,787 94,098 0 20 2013 3.601 1.444 102,676 104,120 -0 21 2014 3,601 1,586 113,231 114,817 0 22 2015 2.101 1,683 123.000 124,683 0 23 2016 0 1,786 131,257 133,043 0 24 2017 0 .1,895 1-40,069 141,964 0 25 2018 0 2,011 149,475 151,486 0 6- 2019 -0 214 159,515 161,649 0 27 2020 0 2.265 170,230 172,495 0 28 __ 2021 0 2.403 181,667 184.070 29 2022 0 0 190,893 190,893 5,531 30 2023 0 0- -191,222 191,222 12,499 31 2024 0 0 167,078 167,078 36,994 32 2025 __0 0 __139.382 139,382 38,921 33 2026 0 0 107,294 107,294 41,447 34 __2027 0 0 70.766 70,766 43,727 35 2028 0 0 29,786 29,786 45,719 36 2029 __ 0 0 12,701 12.701 19,064 37 2030 0 0 896 896 12.640 38 2031 0 0 0 0 950 Noles

1) Nuclear cost escalator is 5.5% per year.

2) Assumed weighted average after-tax eamnings rate is 6.74%.

03/14/2005 12:13 FAX 601 261 2351 SMEPA - HATTIESBURG la 002 Attachment 2-D GGNS Report GGDecomModRO104 1-26-05 SMEPA'S EXTERNAL TRUST FOR GRAND GULF DECOMMISSIONING 1999

$ In000s Study Updated Proforma Plan 10% ROI Value SMEPA's Cumulative Current Current Current 1OLiability EEOY Market Year Year Year Escalated Year Value Contrib'n Eaminas Chance at4 %

1999 NA NA* NA NA 60,093 2000 NA NA NA NA 62,497 2001 NA NA NA NA 64,997 2002 NA NA NA NA 67,596 2003 NA NA NA NA 70,300 2004 15,055 NA' NA 15,055 73,112 2005 17,663 1,060 1,558 2,608 76,037 2006 20,532 1,050 1,819 2,869 79,078 2007 23,687 1,050 2,106 3,156 82,241 2008 27,159 1,050 2,421 3,471 85,531 2009 30,977 1,050 2,768 3,818 88,952 2010 35,177 1,050 3,150 4,200 92,510 2011 39,798 1,050 3,570 4,620 96,211 2012 44,880 1,050 4,032 5.082 100,059 2013 50,470 1,050 4,540 51590 104,062 2014 56,620 1,050 5,100 6,150 108,224 2015 63,384 1,050 5,714 6,764 112,553 2016 70,825 1,050 6,391 7,441 117,055 2017 79,010 1,050 7,135 8,185 121,737 2018 88,014 1,050 7,954 9,004 126,607 2019 97,918 1,060 8,854 9,904 131,671 2020 108,812 1,050 9,844 101894 136,938 2021 120,796 1,050 10,934 11;984 142,416 2022 133,978 1,060 12,132 13,182 148,112 2023 148,478 1,050 13,450 14;500 164,037 2024 164,428 1,050 .

14,900 15,950 160,198 21,000 128,373 164,428 The 2004 cumulative market value is actual value at December 31.

GGDecomModRO104 1-26-05

Attachment 2-E GGNS Report Page 1 of 12 SERI Exhibit _ (RKG-3)

Page I of 12 I Appendix 1 Page 1 of 6 SYSTEM ENERGY RESOURCES, INC.

GRAND GULF POWER CHARGE FORMULA I I1. GENERAL 2

3 This Grand Gulf Power Charge Formula (-PCF) sets out the procedures that shall be used to 4 determine the monthly amounts which System Energy Resources, Inc. ('SERI') shall charge Arkansas 5 Power & Light Company; Louisiana Power & Light Company; Mississippi Power & Light Company; l6 and New Orleans Public Service Inc. (referred to hereafter, coiiectiveiy.. as 'Purchaser. 0,c.

7 individually, as 'Purchaser), for capacity and energy from the Grand Gulf Nuclear Station ('Grand 8 Guir) pursuant to the Unit Power Sales Agreement ('UPSA-) between SERI and the Purchasers to I9 which this document is attached as Appendix 1. The monthly charges for capacity ('Monthly Capacity 10 Charged) shall'be deermiined in accordan6e with the provision's of Secti6n 2 befow; theibrithly 11 charges for. fuel ('Monthly Fuel Charges') shall be determined in accordance with the provisions of 2o- SecSt.nr 3 The A.O.^.Ikly CcPe yC'a'- Cnd - Fu C'Q-'= .C-,-n-4 .d 13 accordance with the provisions of this PCF shall be billed to the Purchasers monthly in accordance 14 with the provisions of Section 4 below.

Attachment 2-E GGNS Report Page 2 of 12 SERI Exhibit_ (RKG-3)

Page 2 of 12 Appendix I Page 2 of 6 1 2. MONTHLY CAPACITY CHARGE 3 A. Monthly Capacity Charge Formula 5 The Monthly Capacity Charge Formula, as set out in Attachment A, and as applied in accordance 6 with the procedures set out below, shall determine the Monthly Capacity Charge which SERI shall 7 bill to each of the Purchasers.

9 B. ANNUAL REDETERMINATION I On orabout May 1 of each-year, beginning in 1996, SERI shall submit an Informational filing to the Federal Energy Regulatory Commission ( FERC or Commission") containing a redetermination

l. of the Monthly .Capacity Charges prepared in accordance with the provisions set out in this I Section 2.6. Each annual redetermination of the Monthly Capacity Charges shall reflect application of the Monthly Capacity Charge Formula set out In Attachment A to data for the twelve month perioqd ending Pecember.31 of the prior calendar year (Test Year"). All data utilized in each such redetermination shall be based on actual results for the Test Year as recorded on the books of SERI in accordance with the Uniform System of Accounts, or such other documentation as, may>,be-approppa.te..or applicable. Each such informational filing shall include workpapers supporting the data and calculations reflected in the redetermined Monthly Caoacity Charges. A copy of each such annual informational filing shall also be provided to each of the Purchasers and each of the Purchasers' retail regulators.

Attachment 2-E GGNS Report Page 3 of 12 SERI Exhibit (RKG-3)

Page 3 of 12 Appendix 1 Page 3 of 6 The FERC and the Purchasers shall then have until June 15 of the filing year to review the informational filing to ensure that it complies with the requirements of this Section 2.B. If the FERC or the Purchasers should detect an error(s) in the application of the procedure set out in this Section 2.B. such error(s) shall be formally communicated In writing to SERI on or before June 15 of the filing year. Similarly, if SERI should detect an error(s) subsequent to the submission of any annual filing, SERI shall formally notify the FERC and the Purchasers in writing of such error(s). -A7l such indicated errors shall Include documentation of the proposed correction(s). SERI shall then have until June 25 of the filing year to file corrected Monthly Capacity Charges. SERI shall provide the FERC with workpapers supporting any corrections made to the Monthly Capacity Charges initially filed on May I of that year. A copy of any such correcting filing shall also be provided to each of the Purchasers' retail regulators.

The Monthly Capacity Charges initially filed, or such corrected Monthly Capacity Charges as may be determined pursuant to the terms of this Section 2.8, shall, after acceptance by the FERC, become effective for bills rendered in July for service in June of the filing year. Those Monthly Capacity Charges shall then remain in effdct until changed pursuan *. th provisons of this PCF.

The Monthly Capacity Charges to be initially effective under this PCF shall be based on the most recently available calendar year data as of the date this PCF becomes effective. Such calendar year data shall be adjusted to reflect on an annualized basis 1) the cost and accounting changes proposed by SERI in its May 12. 1995 filing with the FERC requesting approval of this PCF and 2) the effects of the Stipulation and Agreement approved by the FERC cn November 30.

1994. in FERC Docket No. FA89-28 ('1994 FERC Setleement').

Attachment 2-E GGNS Report Page 4 of 12 SERI Exhibit (RKG-3)

Page 4 of 12 Appendix 1 Page 4 of 6 C. Interim Redetermination In the event that either the statutory state (Mississippi) or federal corporate income tax rates decrease after the annual redetermination is submitted in any year, then the Monthly Capacity Charges shall be redetermined on an interim basis to reflect such tax rate decrease. Should such state or federal income tax rates increase, then SERI may, at its sole discretion, redetermine the then effective Monthly Capacity Charges on an interim basis to reflect such tax rate increase.

Should such an interim redetermination be made, all other parameters utilized in the determination of bie LIen effert Monthly Capacity Charges shall remain unchanged. The redetermined Monthly Capacity Charges shall become effective commencing with the billing month in which the tax rate(s) change. Any such redetermination shall be submitted to the FERC in an informational filing consisting of the following:

(a) transmittal letter setting out basis for the change (b) copy of documentation supporting the change in statutory tax rate(s)

(c) redetermination of the Monthly Capacity Charges reflecting the revised tax rate(s)

Any such interim redetermination filing shall be reviewed in the same general manner as an annual redetermination filed pursuant to Section 2.8 above.

Attachment 2-E GGNS Report Page 5 of 12 SERI Exhibit _ (RKG-3)

Page 5 of 12 Appendix 1 Page 5 of 6 1 3. MONTHLY FUEL CHARGE 2

3 A. Monthly Fuel Charge Formula 5 The Monthly Fuel Charge Formula, as set out in Attachment B. applied in accordance with the 16 procedures set out in Section 3.B below shall determine the Monthly Fuel Charge which SERI 7 shall bill to each of the Purchasers.

8 B. Determination of Monthly Fuel Charge

0 Each month SERI shall determine the Monthly Fuel Charge applicable to each of the Purchasers.

11 . which .amount shall be included in SERI's monthly billings to the Purchasers in accordance with 2 the provisions of Section 4 below. The Monthly Fuel Charge to be billed to each of the 3' Purchasers in any month shall be determined by applying the Monthly Fuel Charge Formula set 4' out in Attachment B to fuel cost data for the immediately preceding month.

5..

4. BILLING SERI shall render a billing to each of the Purchasers each month for service provided during the immediately preceding month. Each such monthly billing shall reflect the Monthly Capacity Charge in effect for that Purchaser during the preceding month together with that Purchaser's Monthly Fuel Charge for the preceding month. In addition, any applicable and appropriate adjustments shall be reflected in each of the monthly billings. The monthly billings shall be submitted to the Purchasers on or before the fifth workday of each month for service provided in the preceding month and shall ce 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 at the rate required for refunds rendered pursuant to FERC Regulations under the Federal Power Act. Entergy Services Inc., acting as aver

Attachment 2-E GGNS Report Page 6 of 12 SERI Exhibit_ (RKG-3)

Page 6 of 12 Appendix I Page 6 of 6 t afor SERI and the Purchasers, may prepare the necessary billings to the Purchasers and arrange for payment in accordance with the above requirements.

I S. EFFECTIVE DATE AND TERM 5

55 This PCF shall be effective for service rendered on and after September 1, 1995, or such later date as 7 the FERC may specify, and shall continue in effect until modified or terminated in accordance with the

'8 provisions of this PCF or applicable regulations or laws.

10 6. FORCE MAJEURE

2 In addition to the rights of SERI under this PCF, or as provided by law, to make a filing for a change in rates outside the terms of this PCF, if any event or events beyond the reasonable control of SERI.

I~ including natural disaster, damage or loss of generating capacity, and orders or acts of civil or military

!5 authority, cause increased costs to SERI and result in a deficiency in revenues which is not readily p capable of being redressed in a timely manner under this PCF. SERI may unilaterally file for rate or 7 other relief outside the provisions of this PCF. Such request shall be considered by the Commission 8 in accordance with its regulations and applicable law governing such filings.

Attachment 2-E.

GGNS Report Page 7 of 12 SERI Exhibit - (RKG-3)

Page 7 of 12 A17ACHMENT A Page I of 5 SYSTEM ENERGY RESOURCES, INC.

MONTHLY CAPACITY CHARGE FORMULA DETERMINATION OF MONTHLY CAPACITY CHARGES UNE NO DESCRIPTION REFERENCE CAPACITY REVENUE REQUIREMENT Page 3. Lbine 1 MONTHLY CAPACITY CHARGE FOR AP&L 36% 'Lble 1112 MONTHLY CAPACITY CHARGE FOR LP&L 14%Unew 1112 MONTHLY CAPACITY CHARGE FOR MP&L 33% UnLke 1112 MONTHLY CAPACITY CHARGE FOR NOPSI ~17%UnLke I1 12

Attachment 2-E.

GGNS Report Page 8 of 12 SERI Exhibit - (RKG-3)

Page 8 of 12 ATrACHMENT A Page 2 of 5 SYSTEM ENERGY RESOURCES, INC.

MONTHLY CAPACITY CHARGE FORMULA DEVELOPMENT OF RATE BASE (1)

TEST LINE YEAR NO DESCRIPTION AMOUNT REFERENCE i PLANT IN SERVICE FERCAccounts 101. 106 2 ACCUMULATED DEPRECIATION & AMORTIZATION FERC Accounts 108. 11 1 (2) 3 NET UTILITY PLANT Una I Plu Une 2 4 NUCLEAR FUEL FERC Accounts 120.2-120.4 5 AMORTIZATION OF NUCLEAR FUEL FERC Account 120.5 6 MATERIALS & SUPPLIES FERCAccounts 154. 163 7 PREPAYMENTS FERC Account 165 a - DEFERRED REFUELING OUTAGE COSTS *. . FERCAccoait174 9 ACCUMULATED DEFERRED INCOME TAXES . FERC Accounts 190.281.282.283 10 RATE BASE . . Sum of Lines 3 - 9 NOTES:.. -..

(13 Tv bED-cic LNrL.A i i. Mviriii-AVC-C1AGE bLAN WIIIIH UECEMttR OF THE TEST YEAH.

ENDI?1M (2) THE BALANCE FOR ACCUMULATED DEPRECtATION AND AMORTIZATION IS TO BE REDUCED BY ANY DECOMMISSIONING RESERVE AND RESERVE FOR DISPOSAL OF NUCLEAR FUEL INCLUDED IN FERC ACCOUNTS 108 AND I 1.

rrvwh= NP I

Attachment 2-E.

GGNS Report Page 9 of 12 SERI Exhibit - (RKG-3)

Page 9 of 12 ATTACHMENT A Page 3 of 5 SYSTEM ENERGY RESOURCES, INC.

MONTHLY CAPACITY CHARGE FORMULA DEVELOPMENT OF CAPACITY REVENUE REQUIREMENT UNE NO DESCRIPTION REFERENCE CAPAC3ITY RFEVhNUF. REUU1KIEMENT Delernined as descibed In Nole 2 below.

OPERATION 6 MAINTENANCE EXPENSE (1) FERCAccouns 517. 519-525. 528-532.

556.57. 560-573. 901-905. 920-931. 935 DEPRECIATION EXPENSE FERC Acfut 403-Excluding Dscornlssl Expense DECOMMISSIONING EXPENSE (3) FERC Account 403 AMORTIZATION EXPENSE FERC Accounts 404-407 a TAXES OTHER THAN INCOME TAXES FERC Account 408.1

.7 CURRENT STATE INCOME TAX Pv 4. the 16 a CURRENT FEDERAL INCOME TAX Page 4, Lln 25 9 PROVISION FOR DEFERRED INCOME TAX-STATE Stile Portion of FERC Accounts 410.1. 411.1 (4) 10 PROVISION FOR DEFERRED INCOME TAX-FEDERAL Fderl Portion of FERC Accounls 410.1. 411.1 (4) 11 INVESTMENT TAX CREDIT-NET - FERC Account 411.4 12 GAINS/LOSSES ON DISPOSITION OF UTILITY PLANT FERCAccourts 411.6. 411.7 13 UTILITY OPERATING EXPENSES Sum of Unes 2 - 12 UTILITY OPERATING INCOME Line minus Lne 13 VERIFICATION6: I.-

RATE BASE.' Page 2. Lne 10 RATE OF RETURN ON RATE BASE Line 14 1Une 16(Must equal Una 18)

COST OF CAPITAL Paoes. Lime 11. Column 0 NOTE:

1) EXCLUSIVE OF FUEL EXPENSE IN FERC ACCOUNT 518.

2) THE CAPACITY REVENUE REQUIREMENT FOR THE TEST YEAR IS THE VALUE THAT RESULTS IN A UTILITY OPERATING..

INCOME WHICH. WHEN DMOED BY THE RATE BASE (DETERMINED IN ACCORDANCE WITH PAGE 2) PRODUCES A RATE OF RETURN ON RATE BASE ELIUAL TO THE COST OF CAPITAL (DETERMINED IN ACCORDANCE VVITH PAGE 5).

3) SHOULD THE FERC APPROVE A CHANGE IN SYSTEM ENERGYS SCHEDULE OF ANNUAL DECOMMISSIOMNG EXPENSES DURING THE TEST YEAR. THE ANNUALIZED LEVEL IN EFFECT ON DECEMBER 31 OF THE TEST YEAR SHALL BE UTILIZED.

OTHERWISE. THE AMOUNT CHARGED TO FERC ACCOUNT 403 IN THE TEST YEAR SHALL BE UTILIZED.

4) RESTRICTED TO THOSE ITEMS FOR WHICH CORRESPONDING TIMING DIFFERENCES ARE INCLUDED IN THE ADJUSTMENTS TO NET INCOME BEFORE INCOME TAX (SEE PAGE 4. LINE 10).

Attachment 2-E

. GGNS Report Page 10 of 12 SERI Exhibit - (RKG-3)

Page 10 of 12 ATTACHMENT A Page 4 of S SYSTEM ENERGY RESOURCES, INC.

MONTHLY CAPACITY CHARGE FORMULA DEVELOPMENT OF CURRENT INCOME TAX EXPENSE IN TEST LINE NO DESCRIPTION YEAR AMOUNT jREFERENCE 1 CAPACITY REVENUE REQUIREMENT Page 3. Lhne 1 2 OPERATION AMAINTENANCE EXPENSE Page 3. Lne 2 3 DEPRECIATION EXPENSE Pag 3. Lie 3 4 DECOMMISSIONING EXPENSE Pae 3. Lke 4 AMORTIZATION EXPENSE Page 3. Lihe 5 TAXES OTHER THAN INCOME Page 3. Le 6 7 NET INCOME BEFORE INCOME TAXES Lhwe I - (Sum of Lines 248) a ADJUSTMENTS TO NET INCOME BEFORE INCOME TAX:

9 INTEREST SYNCHRONIZATION Rate Base (Page 2. Lne 10)

Total Debt Rta (Page S. Line 16) 10 OTHER ADJUSTMENTS. _ See Not.1 11 TOTAL ADJUSTMENTS Lnef9 Pk Line IO TAXABLE INCOME- _he'7 jiis LWi'11 COMPUTATION OF STATE INCOME TAX 13 STATE TAXABLE INCOME BEFORE ADJUSTMENTS Lie 12

.NET.ADJUSTMENT.TO STATE TAXABLE INCOME _ _ __ SeeNote1 __ _ .. _. _ _

15 STATE TAXABEe IFCuOM -. Lie 13 phus Lie 14 I

16 STATE INCOME:TAX BEFORE ADJUSTMENTS Lhie 15 MIssilssippi State Tax Rsle(2) 17 ADJUSTMENTS TO STATE TAX S" Note 1 SiAn Of Lines.15.17 CIJRRENT STAT It 1rUMt,1A Sbirn Of LIMS.1 - 17 COMPUTATION OF FEDERAL INCOME TAX 19 FEDERAL TAXABLE INCOME BEFORE ADJUSTMENTS Lhe 12 20 CURRENT STATE INCOME TAX DEDUCTION Lne 18 (Shown as deducion) 21 OTHER ADJUSTMENTS TO FEDERAL TAXABLE INCOME See Note 1 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 I 25 I CURRENT FEDERAL INCOME, TAX I Sum of Lines 23 24 L ___________ I.

JTE.

I) ITEMS FROM TEST YEAR TAX DETERMINATION THAT ARE APPROPRIATE FOR RATEMAKING PURPOSES.

2) RATE IN EFFECT AT TIME OF ANNUAL REDETERMINATICN FILING.

Attachment 2-E GGNS Report Page 11 of12 SERI Exhibit - (RKG-3)

Page 11 of 12 ATTACHMENT A Page S of 5 SYSTEM ENERGY RESOURCES, INC.

MONTHLY CAPACITY CHARGE FORMULA DEVELOPMENT OF COST OF CAPITAL (A) (I (C) (0)

LINE CAPITAL CAPITALIZATION COST WEIGHTED NO CAPITAUZATION AMOUNT RATIO RATE COST RATE (1 (21 (3) (7) i BEGINNING OF TEST YEAR 2 DEBT 3 LONG TERM (4) 4 SHORT TERM . (5) ._._.

5 TOTAL DEBT 6 COMMON EQUITY 1300%

7 TOTAL 100.00% NA 8 END OF TEST YEAR . . . .

9 DEBT .

10 LONGTERM .. . . . . (4) 11 SHORT TERM . (5) 12 TOTAL DEBT (6) 13.- COMMON EQUITY 13.00%

14 rOTAL -

15 AVERAGE RATE FOR TEST YEAR 6 TOTAL DEBT`" NA NA NA (8)

17. COMMON EQUITY _ NA7. . _.. .. -

18 COST.OF CAPITAL- NA NA NOTES:

(1) .LONG TERM DEBT.SHALL INCLUDE ALL ISSUES AND REFLECT THE PRINCIPAL AMOUNT. NET.OF: .1)UNAMORTIZED OEBT-- .--.

DISCOUNT. 2)DEBT PREMIUM. 3) DEBT EXPENSE AND 4) ANY LOSS ON REACQUIRED DEBT.

(2) SHORT TERM DEBT SHALL INCLUDE ONLY THAT PORTION NOT REFLECTED IN THE CALCULATION OF SERIFS RATE FOR ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION.

(3) APPLICABLE CAPITAL AMOUNT DIVIDED BY THE TOTAL CAPITAL AMOUNT.

(4) AVERAGE COST RATE FOR ALL OUTSTANDING ISSUES INCLUDING APPLICABLE AMORTIZATION OF DEBT DISCOUNT.

PREMIUM. AND EXPENSE TOGETHER WNTH AMORTIZATION OF LOSS ON REACQUIRED DEBT.

(5) THE AVERAGE COST RATE FOR ELIGIBLE SHORT TERM DEBT.

.(6) WEIGHTED AVERAGE COST RATE FOR LONG TERM DEBT AND SHORT TERM DEBT.

(7) CAPITAUZATION RATIO FOR THE APPLICABLE CAPITAL SOURCE MULTIPLIED BY THE CORRESPONDING COST RATE.

(8) WEIGHTED AVERAGE RATE BASED ON AMOUNTS AT BEGINNING AND ENDING OF THE TEST YEAR.

Attachment 2-E GGNS Report Page 12 of 12 SERI Exhibit - (RKG-3)

Page 12 of 12 ATTACHMENT B SYSTEM ENERGY RESOURCES, INC.

MONTHLY FUEL CHARGE FORMULA SERVICE LINE MONTH NO DESCRIPTION AMOUNT REFERENCE 1 FUEL EXPENSE FOR APPLICABLE SERVICE MONTH FERC Account 518 2 MONTHLY FUEL CHARGE FOR AP&L 36%

Une 1 3 MONTHLY FUEL CHARGE FOR LP&L 14%

Une 1 4 MONTHLY FUEL CHARGE FOR MP&L 33%

Une 1 5 MONTHLY FUEL CHARGE FOR NOPSI 17%

Unel

Attachmnien 2r-GGNS Rcpoart Pagc I orIs QOCQX Of ZSttleTm.fl, D~e N= t$6800 EL90-16-OQO, and EL90-4S-000 Sc-cond Rrvised Shcrez Sysum Enrwy Kcsotmcs, Inc-PRat Schodule FERC No. 2 PUJBLIC UTLITtS R.EaWTM SEAVICE lampEg 16T~S OQMXa X Arbnsa Powa k ULght Company ILcultiang Power & Ught Company K'islusippi Powc~& light czmp3Jny New Oritans Public Service Inc.

SM, : M %7FRQojjpy t-IR~R I&ATE S a= =t~J~

Wholesale Sate of Elecuic Powrxr

Attachment 2 CGGNS Report P'ug 2 of 1!

Seccnd Rev~ised Shee:

Unit PowZX qzIC3 Aerrneenj THIS AGREEMENITmAlde, CAn-Czr- into, Ind elfettiyc as of this 10th day of June.

19K2 by and anong Arkansas Powrr &Light Company (AM~ Loijisianx Powet & Ught Co~pany' (t-P&L1). Mississipp! PawWv &U1h Compmny (",PLNewOrlewss Public Seritc:

Inc.. CNOPSI-) Ind Middle South Eoery, -Inc Wr[MESSETH THAT:.

WILERE-AS, MSEN was ier oio eruay 11, 1974 undsr thc laws of the State of Arkcansas to owni ciraln fuwrm geneatmnz capacity for ft Middle South Sysmm. of which AM&L, LP&L., MP&L aInd NOSIS (ystemn CdmpwnIc&) am~ membsrz and WMRZM, Synen Enegy hasacor10 u44a1n h v*Tz~hIP & auidnuimng of inundividd imsteu In., Wnconsmedon o(4 fth 0 uGGnn Station, a two-unith nuctm-f~ucled eckci jrneradag station on the can back of te Mlstissipp River rmf Pon Gibson, Ksis~sspip (-Prqjecs, and WHCEREAS. the System CompanieS own ati o.~mte 4=7eC~ gemealtnt, wnimlszion

&nd dristfv oni facUldoo La Arka~am, Lwuis~na WissW* ip(Md Mltuofad&Mgrenmni u'rinsmit and scU c~c enes both it retufl and wmholesal in zgcl smzes. aied WHE~REAS. Syzwnt Energy has srwAe to sell tb AP&L, LP&L, MY&L and NOPSI

('Puwhtsrs) specified pereerm~get of al of the c=ptcirj asid anzy ivailbl to Sys=e Energy fmtn the qcc n te System Comp~pants havt qmed io Wmi wfiIt Synaem Enegy, bef=r the date Unit 1 of the Project is placed in~rit = in ezcudng an agrtement which will icst fort In detai the sermi and cordtdlons for the sale of iuch Cacity arid enegy by Sys=e Energ Co the

.System Comupinls: and NOW. TEREFXORE Sy-mmr Energy uid the System Cocupanes MVUtaly anderawd and gre as follows:

~Aieout naueIngy.Inc~

as ijjgg4'a Ssv~Enuy R~we, ~c. (ysim Egy)otu1Y22.

GGNS Report Second ReViSC4 Sheet Li1 syltemnEet z2h1L subJaM to Lhe iertn and candidons of ths AgrWmenL Miake i~villable,orcausetO be ma viabl~eilaPshcn allof ftapady andcrowhichshall be available to Symtm Enewg u the Prj~cL fzclu&ihs testcz produtcd during the cows of the causugcictt and tcsdag of Unit I mnd Unit2 of theg Pjet"MN ,Ce 1.2 Tho ?urhascrs shall, supj=c to the tems azd qwndaaos of fth Apemcmnt, be.

rdddto rwgive all of the o which shafllbe avablbe to Ssm ZnV at the Proje~ct In follows:.

211,ddmcun Prcreutitzg Unit No. V Unit No. I AJP&L 36%

1LP&td 14%

MP&L~ 33%

N4OPS1 17%

1.3 Coammnclnj witb the azlicrof (a)thl dAM Of w=MUecW Op~iOa Of each U4i Or Cb)Dee~er31 1U ~resp buto 1)orDofmt~r 31, 198 ws U 2ti n4.

?tfpcd~ly orinui; m hly thruftr until thi Aptement Is-termrsv~ o h oF~ecinnconidematou of &hright to receive la EndeisPrng o provisions sucPWUi~n echUnteach PtrcUcw~lWPas Sysnm EOCrg an SMu:eu~ osc Pgb&WSp dditement Pcventage muldplie by Sylimm Enerz's Toml oto c~cfrsc Unit for such mtonth4 The "Thai Cost a( Srvctoc for each Unt for any month shall be the s=i of' (a)Systern Energy'sf Operadnj Expenss for uch month for such Unit, plus (b)an azounc wqual to one-mwLfth of the Cornpoute Pr==tgg m uldplled ty fte Net Unit Invetstmz for suich Unix.

'FERC" thall Sezi the Federg Enery Regulatxy Comiti~fon (or sny sucessoz rovaenmencd Autbqsity).

'Uniform Syn=m shall mma tht Uiorm System of Acconts proscribed by Lhe TF-RC for MaUjor Pu1lic UdIIdes and Uicensacs, as ftrm time wo drne Lii eff=%.

6.

GGN'S RePOJ PjijC 4 0?

Offer.ot Settle.,ent, Dock~et N03. ER89-678-0000, AkPPENDIX C Thi:-d Rcviscd Shcet System EncrZY's 'Oper'Ati Expenses' shall include, with rtspect to each Ulnit. iii amounuspropesty Ch2*gebletto SysMtem zcg's opendng expc 1CCoUnU, leS1&AY-R pp1Licble acdlrthatsominaccrdaJcc wish the Utif~onS 31m; It heini uzdeld thit for pwposesr(this Agrwn OpAtZd xpenhes' h&U Wntu& o tiiot Wel1itc to)(z)diepr~iaon &=ad at a nmt -atIt=s suffWcint to fUlY amOrte the non-SaZLiag~blPe PLmnt Lamuss itc, Including the cost of rmnovaJ of lzncrm md~rricu, Qver thg rcdrmatc4 t1hn trnaii1,ng uscful U&f of Lhc ui~js (b cbtigtdans incurred incaonecdon with die Jasinggof fuel Inventory and/or umordzAdon of fuel bv=m4; Cc) arccralS to arerscryc osaublishd by S mEne gyt rovu1e for decmmlszloning the ugilf Ove the e~sdmarcd then zmmainlg useful at Ift unit.&d d accruals for disposa of spcn: accleaw Nue.

"Nei Unit Iavwgim.nx" for saiy month shal be computed as of the Lws dxy of that prt-~iout month and shal consist with ftsp to etrch Uait. of (a) Ome tmtga, amount ptopcriy csenable mlths rtims In accordance with the Uniorm System to $yt=EAWy' udthly pl& litecounhs Cicluding, but not UInftad to. (1)contSrucdon work Inpro gtu, to tha extct aflowed by the PERC.

rmuted w each Unit ufter its ftsremsve COmmerewa Opardoei dasa, and CHI) curlew fuel MCMunts otithan niudestfl21In prmoss of fabdadon), less the alans, at the dne of any&accuIla1d pfov1Juiodefo de pr.e&Udon and Amodatintia of utiy plant (excluhve of &an decowblsdosiui mscrve), incdudlitg aMocdzzdan of the Cost Of zvclea~ tuel (excUSIva of aMy reseve for disposal of nulauelm).ii dettrmined in accoidance with the Uniorm SysMM: plus (b)tho aw~gate amount ptoperly chargtable at the tdma in aco~danc with the Umiftrni Syss__ to -cotants ;prcehrng matreials and supplser. Oln () such nasonabla allowances for Ppuepd Items and cashpwwo- idng capital as may foro time to thie be determfrmed by System EneziW plus (4)recverable Income taxes to the extent pttviusly Criwed to udlty plans accouats arAnot yet zulzed excluding Lnounts Sli~ted to consO'uction work inpOgress that are ifo; Incladed La net unil invemeat but that vs Included Inzhe ullowincs for fwids used during constrcton corputadon: and less Ce) acm~ulzted pro-Atuon for dcfcnzd Income taxci and less (f)other deferrid credits.

'CompoidtePrcentate" for any month shallbe UhaX coput4as of the last daj offth previous umonth empumdafo dain Cmo its P~e~n ase of a com~putatdoti date ah be she sum of (a) thirtee percent (13 %)usI4 ie y mderowc heEut jnvesucnten3 Of SUCsh djue, is to the Total Capital as of ()t 'ICe~pu "fed irsra per annum of eachi pfincipall unocut of debt (other than lonfravzcsmd yth Comminockboldee of Systm Energy) outswading on such date for money borWe Mu!plidy hrao which such principal amounr isto Total Capitul isof suc~h date; plus Wc the 'c r annumn of crxn pelvdydcdria Seres of preftmd stock outns~rdIng Ls of 3uch dare muldp~lldb h

Attachment 2-GGNS Report Page 5 of 1S FRnt ReviSad Shect

.441 rado which the unountua which such yprdcm stok would be rcflwct On a baUznce shmc of Sys=c Energy is to ToWa C4apitasI of such dam. Tbe ettfactvc izi=istrtsa 'of "C principal amount of WMb sderrd to in clausa (b) will WU=lc the mnu.al inteng rouirments to thi cxcct sppUkabe1c =rnordza~c of Issue ex encdscouzts and premitums, tioldeg fund call pmrnttl.CpTSSfl ex d isrnt, t1ZOhI r&~tCpCtses, d~scouns and premiums, and &Alother expeflxs applicable to fth Issuo of suh lndzcbcdncsss. The 'effccdvc dlvldnd at'aw or each series of pitfeffed stock reecred to In cleaus (C)WOl -.fl=c the anull dividend vcquirttntnts applikable to ckhawi uh =1r4c of pr'tczrud su~k.

"Eqmhy Ttweruimea ii of any dad shOl vionsist of the sum of((a) ani aanomct thevswo paid to Systom Enaersy for all =oaio rapital stock tbcr~~ ifoi uedplus aU ca*(ats convibtuions, tdvwoaz or PloIM lon ww ouiy0pla c uon d mens~i; les the o unmu sum f L~dbySyt=n Eczj' to In, mmon stockholda In the'm-of vtock teumeo nyt amPurcts p c 1 Md~dy A f aia o esmet c a mes r loans;.

plus Cb) &Aycftdk balanca (I)'I toe Mid In CapWm aIunt =o Inludid unde (it)and (11) In the rztalnc eshings account on the books of Systan E=cg as of such daze

-roaj Iaitzlo is of iny date shall be fthEgitty tnivcseitm plus the tWI of the amount which woul bo reflected cm a balumc sheet of Syste Enag fAir 111 othe soc~uddeal debt and pzufezrre stork then OuuUnidint.

Pr1Wrto the ea,'l= rof (a) the dst of uudrcal Ccr~doa oeudsUrilt orb WD*=mnber 31, 1984 (wih sp to Unit I) orDemsmber 31, 1958 (W r*etIn n 2), the PurcbuesC shil pymothlSste Enrg Ii uctxdnc wih teirm~cveEnddernencPerc.enta~es for anPOW cie~ ote ~neahsc ntbewdtUart equal to the incemcnal cm~

Z. Mh performanc of fte oblipftu of System EncrM berwndu shHl big subjein to th ceip9taand Contnuo eflecr-vemncsof laufthzadonsofgovcmicnTU fulatos7authorldes as th# dme nessazy to pcsmhsystem iugyto peomits dudcs nd oblig onSbcivv~k.

including she mccpt and coodnoed efibedvteu oWali atbodztzaions by governtmeaul =guluz~y Authotldel at thc ding.nFcsty f to erIt the cmp1don by Systato Eerkry of she coovueuc~n 6f thePrjet. h -liraon or the PMoec,

= and yseEeg_o to makea availble to the P ha&3ri

.21 of the Power available tO Systcn EA~rp 1 the PrOJWt Symtm Enargy shall us hIt best tffor's to secure and malnuain all such tudhoriz~aiions by govercnuUta reguaroy authoddes

ALxicmcrnt2-p Fint Revisad Shct

3. System, Energy shall p taan maintjai the ?rvj= in acord&ncc with good uthlity pradce. OVtagCaor Insp~cdon, m en"es rful ~~ atr hllb ppac awnd, t painW abluen shall beusy a ptd to by 5y~cm Energy W4dite PUnweus

4. ~Dcvery of Power sold to tha PU~hLW2r FW$UanC t this Aptaemev shall occur as the Projects mtp-up transufarmwc and ghOl bo mutt indie fonm of tbmv-phas,m$ he=

altenuadeg Curtn at a nomiftul vohage of SW0 kilovolu Sy~nem Eoe ll' adm intn sl alu z~c"Smy rnuidaj[ equipment for deuesbnag the quin"ty un co= ~oam ordi~ Ndas AFW~ System Energy will furnish to the Pu:asc such swrnmzimof nd An~rdn Otarinformasion as may muaonably be mjuticed.

I cd bS. MondthybWiflcaculae In aordanet with the provlsln of Sacton 1.3 shiU be ISUySys=Enagy on the fifth workidn day of ud month ind thall be payable in lmmfflmlzvzlzbe und onorbefm d Ith tyofruch month. After the 15hday, kw~t~s shall ac=vc on any balanqv; due as the rate reulred ft r efuns cede4 pwzuAn to IEFRC lp Regulations under the Federnl Power Act.

6. Notihng contded hein s 4 be muaffcd u Lffc iny way theright of System Energy to unittalealy make applcti~on to FERC for ak change in the rmms cornulhCd hcrtn or an~y othar t=n or condition of this Apz~ncnu under Sectdon 205 of the-F~dera Power Act ad pwuamw to FERC Rules and Regilanions promulgnad theziundat.

7. No Purhase shall be entitUe to~set off atom~any paymet ruquirr4 to bo made by Itunder this Agrmrnent (a) any amounts wowd by System Eniergy toAWY Puwchascr or (b)the munotz of any claln by any Purhuor agpinst Syrcz= Enegy. Tefgou.howcvsr. sluI Mot Wfe= in any other way the rights and remedies of any Punhsrc wt epc to any such taxouznti owcd to any Puchascr by Sys=c Enerly or any such claim by an uebSpr gann Syem Enctgy.

S. 'Me lflvilid-Y ir4 pedomabl~iy of icy proision of tlis Agrmeratt tall niot Lffe~cl the remainng provi~ons hcrco(.

9. 'This Agr~ment. shall continu uwil wUminaed by munWa asmement of all parties herzto

Azachrnent i2-GGNS Rcporn P1ae70of1S 8

Second Rcviied Sheex

10. This Atemet Shall be bindlz¶ Upon the pardC her=to and their succcssoii and Ijsigns, bug no assipibM heof, or f any right to any fds due or to bscome due tudecthu Apmrent. shall any ev eent rcuee tidtIfty PwChzser or System EOy of any of their rnspecuvc obUipatons bcrtUndr, or, in the casc of the Pubas. d=sc to any cxeni their enadesnent to rwclve all of the Powar 2vailable to Systrm Energy fhM dne to thne at the ProecM t 1l. The agmemcnts hln set fonb havc bee midc for benefi of the Puhas and Systim E nergy cnd &7Cirrspecdve niessM 4 asslCiU &Wnotherperson shall acquire or have any ight unetr or by virmue of this Ape enL

12. The Pachucxi and System Engy may, subjr to twh ptions of tis (lto

ag ccat or & nts bcfwcn the pta x a s ny S"

Energy. :twig t dhtled o and pro'Aians nladng to *A peifom&= by the Phuscs d Sy1tam v s .vs oUpdoudr thi sASMcnL $o smcaoptentac 4 inso uder tit Sccot 1Z sh, howvan, alt to any subssarve de&= s obuldo of ny pxy to this Agreemnt In rAy manca cndismnt, 4ith any of the rIbmS sead of this Agtt

13. BAch of the Puhasers thl 4 as any dmce vW ftm dmn to dte, be endded to assign ail t ndanll 1 teo mdgh of dd Power wOch sytthet of sl be eadded undet tls Apec t, but o Pzhasc ehaL by such asgn kbe s1ed of acy of Its obli dons nd dine this Agreament Cnder except thri the payment to Sysu= Energy. by or oniehlf of such h rch, of the amount or Msounts Whics such Purchser shaul be obbgated to piy pursuant to the tems of this ApoengcnL LW TMESS MMEOF, the pantes hertio have caused W3 AgKm ent to be duly ezetucd. is of the day ad yearssbbove. rvzn.

Attachment 2.f GUNS ReIouN Page 8 of I S Fir": PIvstd 5hett

.S.1:)LZ SC:UDS ENEACY, ;NT.

BY _

A2U.AS2AS ?CW1-:R A L:C2t Cx~

WrUISIM ?OWIR 6 LIZU? CCXPi.X KCW O9LW4S MaLIC SEYXC! INC.

ay. ~n4~ 2I/.4?Vz _....

HMddle South ziargy, Inc.'s name was changed to Systed Energy Resources, Ince

("Systes EnTrTy") on July 22, tL86.

D Page 9 of 1S Pint R;rvsrd Sheet Sysiazi RUMt Rescares, Inc.

Billing Format 41

Atinchvrngnt GGNS Report Parv 10 of 15 Fourth Arvviud .Shac "MT!'JENZROY BESQQAC3SS.i.

M~ON1X.199 OMeATION VEXNSIM FVUL CCPSE (ACCOUNT 513)S MAINTVANCR ZPSWq (ACCOV14IT5 525-S32.

~VERICIATIQN uppisE.(Accou"rTAM -

SCH4LDULS A DECOMMZSIONMH XPERS8 (ACCOUN4T 403) 1' AMORMhATION EXPVSSU (ACCOUMt 404-d07 TAUSJ OTHER T)(AN IMPCOMI TA=E (ACCOUNT cr 1c~)

TAXIS - ?H~OMSACCOUNTS 40.1. 4O.3,410.1.

9AINSLJLo3s PROM DISPOSmITIO OF UTrn.rr PL&( ACIMUNrS 4t1.4.d 1.7i; TOTAL MPEATING EXPSN3E$ s A'DIUrdN.T~x OF ?KtVRt iTffLIUVS - I-SME20LI OPERATING WXPMS9U AS $ILLE. I OPIRATW1G MPlNStl A.CTTJA.L B.ETI1OON NTa UNIT 1WNtm&? La~t~ ______

11 THI MIONTHLY 01COMXMSSZONfuO XXflJ~t FOR GRANDO CULP UNM I11 INJ ACCORZACI'C wVTH3 ?ZRC S21-LVW4KNT ACIW.4IHT. THK AM4OUNT. VAIrMA LACH YEAR IASED ON TNIL APPROYEO IDECOMMISSIO?1140 3CHROULE.

~- - -

Attachmect 2 GONS Rporl panc II of 15 Sixth Xevisad Shbes SVjSTVM ENSROY RESO1URCMS INC. SCE(CDULE A QZEPRq[AIATN ES VORPECIASLE PLANT E77M2~TV AXUAL aI7McA1rom FLANT PUNC1r0M SAL-ANCU RAThS 11 eaV'2 MWCLUAR FLANT s (Ae=OUX? l0t S 2.1s s CENAL'4SO PLANT S 1.33 %

(ACCOUNKT 101)

TLA(*OR1ATION I LISS S (ACCOUINT t01) r OTAL. 5 S li IJFKCTtVETAMhUAAY 1.19S7 A

. A I,

Aituchmcnt 2-.

GONS Repour Page 12 of 15 mhird ReviwA sbh4 SYSTEM ENIlOY R-somrCes. 11C.

PIS' I of Z rR oQCr MNTT MNnESTMT AND COMPOSrME PERSCETAOE Lmun LANST U SWvIcS (ACCOUNTS 101. 10,.

s LUSS: ACCUMULATED PROVISION FOR OPRECIA21ON AMORTZATION (ACCOUNTS 105, Ill. 12, S 1, (LuStV9 OF ANY OfCOMMS!OlINGQ RAX3vt AND AY RSSUV FOR ODIPOs.L OF NUC1LZA IJV)

N6T VIfLITY PLANT IN 35iVICt S I' ATMALS & SUPP= (ACCOUNTS 1. 1M S 11 jPpAymDT (ACCOUNT ItS - tXCLUDINO PWAI rlNTI3rT) it WooIfNg CAFMAL ALLVwAfCA TOTAL WOWNG CAPITAL I A==LE = rfACCOUn 160).

S A/

aGix .s l CACPU1A T W - 3AL ^

LWEAJACK OP A PORTION Of CRAND GULF WNITT 0 I if ACVMULAtLO PRoVISION FOR DMFEM!O INCCME TAX (ACCOUtM I". lU. 2)

I 11 Her UwNIT INV!mAUN1 5 S 11 I,

xUm A COMPSFtS PEICINTACI (SCR. 521 ANET lUNT INVSTh*2Ir DIVIDED aY 12 11 eA1- .L&1tv " 111teftO 3eV."i W "CLa

alPCTI'1 dAP. 19"'W UI'WffXAL AWAW4$a it9=6 AnMAwd WITW "E FUC Wkfl.sT sCAVUMW.

in..uiWSA*Z DO.L 48n au 'Cr uvW 4~M v.? DIAtft 8A~p= W T~vz ID4il. PM ~fI W A W di L.tA&IPCWXAlM~?t1 KID5.ZWP&"WAZ £)iO4!t At A CM =f TO ?MC PTAhILb*PAAhTA T a'#WlrqP4 MlV *I/'

'" $ UW s u cIemterr c"I s0vt

.to

Attachment 2j GGNS Rcpvrt Page 13 of 1S Foutmh Ptavijed Shtgt AxrSTEm ENEICYx RESOVRcRs. I4c.

RErIM'-J ON NET UNiT R^yTMBNT AND COUMPOal 1ERCENtiAGE CAMlALZATWN AJ40UNT' CAP. O6o RATE. COMPOKICWT 011? LACCWNJTS III. 139.2I.- Al AIJA 0% AAA0

%U.us, 231)

"ZRUMW CT0C (ACCOUNTS 20d. AZ2 Al/AO Ps (AJA4)PS COMJ4ON lQUIrY (ACCOUNI'r 201. ZOL. Ai/M4 Cs (A3/M)CS

'TOTAL CAPIALIZATiON m _______

W~¶fE&u 0 IS WEIOGRTID AVUACK OEBI RATR ICU4JOMN SKOPWT TIMM PUBT To fl12 WMMtHOTI UQ71Tlu2M WN APUOc "cutAT4 N.

WHIM, P IS WLJOHT20 AvgLACR IMEYVZO 9TOCX DIVIDK$D YviiEP c is 23% PXTuIN ON COMMON zqtJiTy. II 1l BPFC"4APAIL 2. 1P9

Aaachment 2.F GGNS Report Page 14 of 15 SocefI4 Rsvu4a Sheol sysmigm1 aNg-ime ?L=tSOJP!J. flMC.

PACS I OF Z INCOME =A M~ISKS cumftelv t4e'E9AE PW 4

OPOATU mIPVw =Avqv-~wpowTA A

P6f6 TAX PUMSCM

NuA x.~nu a

i4 1:10 01 ffA W ;UNW WAM

M " PI OkRI pq Mam oloob VAN

i I TAW UI TV1~A" OPCOGIA VCC*VT 40J1I TAW CADfM=L P MGM DOWPgb STA~hIMC~eaRA2 purovWU ___

Jell 1emI pflpvwj~ £ 1101101 mpu*m P1aM E "=*aE ?AK Pg*"Mu MU P4'.A 1 (9. 4 U J. A W 2 L ~ T ~i CCASM FEDCALTAX 00If LAC=WMf a15. 411.11 SGIM I APA PM 0fl l o 410.1.6allis Ire O.CV.. 7mmAoraff ItS .4 i t . . . ~ ** ~ ~ ~m ~ ubb.

I' d Lt~.., .~ ie. e7 w ~~e 1 fl~i .'..~i. - b~~ I"

AnachrDcnt 2-p GCONS ReporL Paye IS of lb Seomd Reviced Sheut SYtEM OEN Pigs~i2 z kHQNrH. IWoX DE ATION Of AUDC - S TAX BASIS Of UNIT 1J s TAICj CAPtTALIZD PEA ROOKS 14ST OF TZsr mzacY (ACCQUY'tS o0L3. 10134) 1AIiS POX DpWSU TAX CALCULATION I DOCK SAIIS I

&ATIO OF RAStS foR DtgRXA= TAX CALCULATIONS TO BOOK NBAS.

00 8RICATIOHN Of 3At*f FOIL 09MRR5 TAX CALCULATION ROCK OCRs=ITION (ACCOUNT' 4031 t.1 .3.

OIMMIiAT1tON OF A.DC J4" 0 AM* qTAMtANMNT ExPIS (ACCOUNTS 511. S*.S25. S JW.J. 556. 5W7. S60--sf

M M43. 923)

PES10H4 XV>NS9 (ACCOUNT 921) £

-L FUL 7W28 . 3 S TAX D9EPMCATION Of NUeLCLBAA FUIL £ wTE=T A140 QMER CeDovO3Lt £XzNsu (ACCOUNT SI$)

NUCLAM MEL EXP4S PER BOOKS tACOUNT SIS) 02PUC1ATION PENSE - S TAX DEMt ATION OF UNt I (ACCOUNT 402)

DoK?= ^T1Q OrPNASIS FOR OtrE1UL TAX CALCLATION *.

fixcws saeC"IONING MINSE - S TAX DEOiCTZQIO FOR ACCUED DICO4MISSZONINO WPINSE I s

Oll ACCAUAL FOR VECOMMIIsIpNOG F£XP5h (ACCOUNT 443)

PSPJZICPEUXP&N3 - £ I

TAX OEOUCTION FOR ACCRUED FIHSIOI SXPENSEU sOco ACCAVAJ YOR rIstorl ExrNsE" (ACcOUNT 9t6)

I "Cus

Report on Status of Decommissioning Funding 10 CFR 50.75(0(1)

March 31, 2005 Attachment 3 RBS-70% Report River Bend Station-70% Regulated Interest Minimum Reporting Requirements as per 10 CFR 50.75(f)M1):

1. Decommissioning funds estimated pursuant to 10 CFR 50.75(b) and (c) (2004$):

Regulated 70% Funding Interest $ 471,936,421 '

2. Market value of funds accumulated as of December 31, 2004:

Louisiana Jurisdiction $ 42,801,282 2.9 Texas Jurisdiction S 77,401,160 2.9 FERC Jurisdiction S 3,895,331 2.9

3. Current schedule of annual amounts remaining to be collected:

Louisiana Jurisdiction See Attachment 3-E 4 Texas Jurisdiction See Attachment 3-E FERC Jurisdiction See Attachment 3-G

4. Assumed rate of decommissioning cost escalation used in funding projections:

Louisiana Jurisdiction - Attachment 3-E CPI/2.53% 8 Texas Jurisdiction - Attachment 3-F 4.81%

FERC Jurisdiction - Attachment 3-G 4.00%

5. Assumed average after-tax rates of earnings used in funding projections:

Louisiana Jurisdiction 5.65% "

Texas Jurisdiction 6.62% 7 FERC Jurisdiction See Attachment 3-G

6. Assumed rates of other factors used in funding projections:

Louisiana Jurisdiction See Attachment 3-E Texas Jurisdiction See Attachments 3-E & F FERC Jurisdiction See Attachment 3-G

7. Contracts assuring collection of decommissioning funds: None

8. Modifications to method of providing financial assurance since March 31, 2003 filing (external sinking fund): None

9. Material changes to trust agreements since March 31, 2003 filing: See Footnote 10 Supplemental Information:

1. Site-Specific cost estimate escalated to 2004 (Jurisdictional basis):

Regulated 70% Funding Interest - Louisiana Jurisdiction (1996 Base Year Dollars)

NRC License Termination Cost: $ 309,744,540 3 Non-NRC License Termination Cost: $ 41,897,983 3 Total $ 351,642,522 Regulated 70% Funding Interest - Texas Jurisdiction (1996 Base Year Dollars)

NRC License Termination Cost: S 345,869,231 3 Non-NRC License Termination Cost: $ 46,784,434 3 Total S 392,653,665

Report on Status of Decommissioning Funding 10 CFR 50.75(f)(1)

March 31, 2005 Attachment 3 RBS-70% Report River Bend Station-70% Regulated Interest Regulated 70% Funding Interest - FERC Jurisdiction (1985 Base Year Dollars)

NRC License Termination Cost: $ 197,893,077 3 Non-NRC License Termination Cost: $ 99,139,368 3 Total $ 297,032,446

2. Decommissioning method assumed for planning purposes in site-specific estimate: DECON

3. Year site-specific estimate complete: 1996 4

4. Frequency of updates (approximately): once every 5 years

5. Funding based on NRC minimum or site-specific estimate?: Site-specific

6. Decommissioning rate regulation (approximately):

Louisiana Public Service Commission (based on 70% funding interest) 20.03%

Public Utility Commission of Texas (based on 70% funding Interest) 30.10%

Federal Energy Regulatory Commission (based on 70% funding interest) 2.10%

Unregulated (based on 70% funding interest) 17.77% 5 70.00%

1 See Attachment 3-A for calculations.

2 Source: December 31, 2004 River Bend Station Trust Fund Report.

3 See Attachments 3-B, 3-C, and 3-D for calculations. Also see footnote 4 to Attachment 3-A for information on the generic baseline cost estimate using the waste vendor disposal factor (Barnwell, South Carolina).

4 A 1999 cost update was prepared and filed with the LPSC and the PUCT. Based upon a settlement in the 8th Earnings Review in Louisiana, the LPSC reflected an assumed life extension using the 1996 decommissioning cost estimate, and correspondingly set the amount of decommissioning costs collected in rates to zero beginning January 2003.

The 2004 cost update of $466.97 million (70% of $667.1 million in '04 S)has not been filed.

5 This amount Is below the 20% threshold provided In footnote No. 8 to NUREG 1577, Rev 1, "Standard Review Plan on Power Reactor Licensee Financial Qualifications and Decommissioning Funding Assurance" dated March 1999.

8 Assumed weighted average after-tax earnings rate for the non-qualified and tax qualified decommissioning funds for the period 2004-2038 (LPSC Consolidated Dockets No. U-22491, U-23358, U-24182, U-24993 and U-25687).

7 Assumed average after-tax earnings rate for the decommissioning fund (tax qualified) for the period 2004-2032 (PUCT Docket No. 20150).

8 The Nuclear Escalator is 2.53% beginning 2003, based on a Settlement Agreement between the LPSC and Entergy Gulf States, setting the 4th, 5th, 6th, 7th, and 8th Post Earnings Reviews pursuant to Order U-1 9904, instead of using CPI as in prior periods.

9 Funds accumulated for each jurisdiction may only be used for decommissioning costs associated with that jurisdiction.

10 The following section was added to all trust agreements on December 17, 2003:

Notice Regarding Disbursements or Payments. Notwithstanding anything to the contrary in this Agreement, except for (I) payments of ordinary administrative costs (including taxes) and other incidental expenses of the Trust Fund (including legal, accounting, actuarial, and Successor Trustee expenses) In connection with the operation of the Trust Fund, (ii) withdrawals being made under 10 CFR 50.82(a)(8), and (iii) transfers between Qualified and Nonqualified Funds in accordance with the provisions of this Agreement, no disbursement or payment may be made from the Trust Fund until written notice of the intention to make a disbursement or payment has been given to the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, at least 30 working days before the date of the intended disbursement or payment. The disbursement or payment from the Trust Fund, If it is otherwise in compliance with the terms and conditions of this Agreement, may be made following the 30-working day notice period if no written notice of objection from the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, is received by the Successor Trustee or the Company within the notice period. The required notice may be made by the Successor Trustee or on the Successor Trustee's behalf. This Section 8.04 is intended to qualify each and every provision of this Trust Agreement allowing distributions from the Trust Fund, and In the event of any conflict between any such provision and this Section, this Section shall control.

Attachment 3-A RBS-70% Report RIVER BEND STATION CALCULATION OF MINIMUM AMOUNT AS PER 10CFR 50.75 (b) AND (c)

Determination of Minimum Amount - Regulated 70% Interest Entergy Gulf States, Inc.: 100% ownership interest Plant Location: St. Francisville, Louisiana Reactor Type: Boiling Water Reactor ("BWR")

Power Level: <3400 MWt (Approx. 3091 MWt.)

1986 BWR Base Year S: $131,819,000 Waste Burial Facility: Barnwell, South Carolina 10 CFR 50.75(c)(2) Escalation Factor Formula:

0.65(L) + 0.13(E) + 0.22(B)

Factor L= Labor (South) 1.925 E= Energy (BWR) 2 1.448 2 B= Waste Burial (BWR) 16.705 BWR Escalation Factor:

0.65(L) + 0.13(E) + 0.22(B) = 5.11455 1986 BWR Base Year $ Escalated:

1986 BWR Base Year $

Escalation Factor = $ 674,194,886 4 Regulated 70% Funding Interest $ 471,936,4214 Source: Bureau of Labor Statistics: series report id ecu13202i (March 2005).

2 Source: Bureau of Labor Statistics: series report Id wpuO143 and wpu2573 (March 2005).

3 Source:Nuclear Regulatory Commission:Table 2.1 of Report on Waste Burial Charges". NUREG-1307 revision 1O(October 2002).

4Application of the 8.860 waste vendor disposal factor (South Carolina) from Table 2.1 of Report on Waste Burial Charges",

NUREG 1307 Revision 10 (October 2002) yields a generic baseline cost of.

Regulated 70% Funding Interest = $ 312,681,932

Attachment 3-B RBS-70% Report RIVER BEND STATION CALCULATION OF SITE-SPECIFIC COST ESTIMATE ESCALATED TO 2004 DOLLARS RIVER BEND 70% FUNDING INTEREST LOUISIANA JURISDICTION Site-Specific Cost Estimate (1996$)

Site-Soecific Cost Estimate (1996$_-70%): (1996$)

NRC License Termination Cost: $ 258,324,954 2 Non-NRC License Termination Cost: $ 34,942,648 3 Total Site-Specific Cost Estimate: $ 293,267,602 t CPI (1996-2002), 2.53%

Annual Escalation Factor (2002-present) 6yrsatCPI, Years of Escalation: 2 yrs at 2.53%

Cumulative Factor: 1.199 Site-Specific Cost Estimate (escalated): (2004$)

NRC License Termination Cost

Cumulative Factor $ 309,744,540 Non-NRC License Termination Cost: ' Cumulative Factor: $ 41,897,983 Total Site-Specific Cost Estimate: l $ 351,642,522 1

' The Louisiana Public Service Commission (LPSC) authorized funding amounts (Attachment 3-E) based on 70% of the site-specific cost estimate of S418,953.716 in 1996S and escalated annually at rates tied to projections of the Consumer Price Index-Urban ("CPI"). The projection for the CPI from the period 1996 through 2002 was 14.06%. The Nuclear escalation factor is 2.53% beginning 2003.

based on a Settlement Agreement between the LPSC and Entergy Gulf States, settling the 4th, 5th, 6th, 7th, and 8th Post Merger Earnings Reviews pursuant to Order U-19904.

2 From 1996 Decommissioning Cost Estimate for River Bend, Table C, times 70%.

3 From 1996 Decommissioning Cost Estimate for River Bend, Table C, times 70%.

Attachment 3-C RBS-70% Report RIVER BEND STATION CALCULATION OF SITE-SPECIFIC COST ESTIMATE ESCALATED TO 2004 DOLLARS RIVER BEND 70% FUNDING INTEREST TEXAS JURISDICTION Site-Specific Cost Estimate (1996$)

Site-Specific Cost Estimate (1996$ - 70%):

NRC License Termination Cost: $ 237,514,518 2 Non-NRC License Termination Cost: S 32,127,698 3 Total Site-Specific Cost Estimate: $ 269,642,216 1 Annual Escalation Factor 4.81% 1 Years of Escalation (1996 Base Year to 2004): 8 Cumulative Factor (1+Factor)A8: 1.456 Site-Specific Cost Estimate (2004$):

NRC License Termination Cost

Cumulative Factor: $ 345,869,231 Non-NRC License Termination Cost: ^ Cumulative Factor. $ 46,784,434 Total Site-Specific Cost Estimate: l $ 392,653,665 i

¶ The Public Utility Commission of Texas authorized funding amounts (Attachment 3-F) based on 70% of site-specific cost estimate of $418,953,716 in 1996$ adjusted to reflect statutory contingency limit of 10% for ratemaking purposes. Cost estimate escalated annually at 4.81%.

2 From 1996 Decommissioning Cost Estimate for River Bend, Table C. times 70%.

3 From 1996 Decommissioning Cost Estimate for River Bend, Table C, times 70%.

Attachment 3-D RBS-70% Report RIVER BEND STATION CALCULATION OF SITE-SPECIFIC COST ESTIMATE ESCALATED TO 2004 DOLLARS RIVER BEND 70% FUNDING INTEREST FERC JURISDICTION Site-Specific Cost Estimate (1985$)

Site-Specific Cost Estimate (1985$ - 70%):

NRC License Termination Cost: $ 93.928.450 Non-NRC License Termination Cost: $ 47,055,750 Total Site-Specific Cost Estimate: $ 140,984,200 1 Annual Escalation Factor: 4.00% 1 Years of Escalation (1985 Base Year to 2004): 19 Cumulative Factor (1+Factor)A19 : 2.107 Site-Specific Cost Estimate (2004S):

NRC License Termination Cost' Cumulative Factor: $ 197,893,077 Non-NRC License Termination Cost:

Cumulative Factor $ 99,139,368 Total Site-Specific Cost Estimate: l $ 297,032,446 1 FERC authorized funding amounts (Attachment 3-G) based on 70% of site-specific cost estimate In 1985$ escalated annually at 4.0%.

Attachment 3-E RBS-70% Report I of 3 Entergy Gunf States, Inc.

River Bend Decommissioning Model - Louisiana Retail Non-DAP Portion Revenue Requirement, Fund Balance and Expenditure Summary

($000)

Decommissioning Fund Balances Une Revenue Non-Tax Tax Decomm.

No Year Rqmt. Qualified Qualified Total Expend.

1 Begnning Balance 1.909 25.099 27.008 2 2002 0 2.021 26,830 28.851 _0 3 2003 0 2.140 28.687 30.827 0 4 2004 0 2266 30_673 32.938 0 5 2005 0 2.399 32.796 35.195 0 6 2006 0 2.540 35.067 37.607 _ 0 7 2007 0 2.690 37.496 40.186 0 8 2008 0 2.848 40.095 42.943 _ 0 9 2009 0 3.016 42.874 45.890 0 10 2010 0 3.194 45.847 49,041 0 11 2011 0 3.383 49.026 52.409 0 12 2012 0 3.583 52.427 56.011 0 13 2013 0 3,795 56.065 59,861 0 14 2014 0 4,020 59.957 63,977 0 15 2015 0 4.258 64.119 68.377 0 18 2016 0 4.510 68.571 73,081 0 17 2017 0 4,777 73.333 78.111 0 18 2018 0 5.061 78.427 83,488 _ 0 19 2019 0 5,361 83.875 89.236 0 20 2020 0 5.676 89.607 95.283 0 21 2021 0 5.996 95.427 101,423 0 22 2022 0 6.314 101.192 107,507 0 23 2023 0 6.627 106.849 113.478 0

_24 2024 _ 0__ __693.4__ 112.351 _119.284_ 0 25 2025 0 0 115.155 115,155 9,861 26 2026 0 _ 0 96.483 96,483 24,119 27 2027 0 0 75.887 75.887 25,157 28 2028 0_ 0 53.569 53,569_ 25.903 29 2029 0 0 29,879 29.879 26,217 30 2030 0 0 4,539 4,539 26.744 31 2031 0 0 .22.763 -22,763 27,510 3 _32 20 _32 - 0 0 _ 47.724 .37,724 13.869 33 2033 0 0 .48,493 .48.493 8.960 34 2034 0 0 .59.367 -59,367 8,58 35 2035 0 0 .62.994 .62.994 779 36 -2036 .0 0 .66.816 .66.816 801 37 2037 0 0 -70,840 -70.840 819 38 2038 0 0 -82,473 -82,473 8.236 LA Ine Tax Rate Is 8 0%. however. In LA Federal Income taxes are deducible, therelore the effective LA rate Is 5.35%. The effective Federal Rate Is 33.13% resulting In a Composite Rate of 38.48%.

Entergy Gulf States funding Interest In River Bend Is 70%.

Nudear Cost Escalator Is 2.53% effective 1/1103 per the Settlement Agreement pursuant to Order U-19904.

Attachment 3-E RBS-70% Report 2 of 3 Entergy Gulf States. Inc.

River Bend Decommrssioning Model -Texas Revenue Requirement. Fund Balance and Expenditure Summary

($000)

Decommissioning Fund Balances Line Revenue Non-Tax Tax Decomm.

No Year Rtmt. Qualified Qualified Total Expend.

I Beginming Balance 0 41,503 41.503 2 1997 8.551 0 53,042 53.042 0 3 1998 8.551 0 65,342 65.342 0 4 1999 8.551 0 79,068 79.068 0 5 2000 8,551 0 93,820 93.820 0 6 2001 8.551 0 109,875 109.675 0 7 2002 8,551 0 126.715 126.715 0 8 2003 8.551 0 145.030 145.030 0 9 2004 8.551 0 164.714 164.714 0 10 2005 8.551 0 185,869 185.869 0 11 2006 8.551 0 208.806 208,606 0 12 2007 8,551 0 233.043 233,043 0 13 2008 8,551 0 259.307 259.307 0 14 2009 8,551 0 287.535 287.535 0 15 2010 8.551 0 317.873 317,873 0 16 2011 8.551 0 350.480 350,480 0 17 2012 8.551 0 385.524 385,524 0 18 2013 8.551 0 423,188 423,188 0 19 2014 8.551 0 463,668 463,668 0 20 2015 8,551 0 507.175 507.175 0 21 2016 8,551 0 553,935 553,935 0 22 2017 8,551 0 604.190 604.190 0 23 2018 8.551 0 658.203 658,203 0 24 2019 8.551 0 716,254 716.254 0 25 2020 8,551 0 778.645 778.645 0 26 2021 8.551 0 829.458 829.458 0 27 2022 8.551 0 883.015 883.015 0 28 2023 8,551 0 939.464 939,464 0 29 2024 8.551 0 998.962 998.962 0 30 2025 5.701 0 1.043.086 1.043.086 15,274 31 2026 0 0 1.051.288 1.051.288 46.774 32 2027 0 0 924,532 924.532 178,356 33 2028 0 0 755,709 755.709 212.585 34 2029 0 0 567.884 567.884 222.190 35 2030 0 0 358.131 358.131 233.642 36 2031 0 0 145.837 145.837 225.104 37 2032 0 0 0 0 149.378 Nuclear Cost Escalator Is4 81%.

Attachment 3-E RBS-70% Report 3 of 3 Entergy Gulf States. Inc.

River Bend Decommissionig Model - Louisiana Retat DAP Portion Revenue Reqturement Fund Balance and Expenditure Summary (SOCO)

Decommfiissioning Fund Balances Line Revenue Non-Tax Tax Dectomm.

No Year Rqmt. Cualified Qualfied Total Expend.

1 Begenrnrg Balance 9.151 6.251 15.402 2 2002 0 9.696 6,678 16.374 0 3 2003 0 10,274 7.136 17.410 0 4 2004 0 10.887 7.626 18.512 0 5 2005 0 11,536 8.149 19.685 0 6 2006 0 12.224 8.709 20.933 0 7 2007 0 12,953 9.308 22,261 0 8 2008 0 13.726 9,948 0 9 2009 0 14,546 10.633 25.178 0 10 2010 0 15,414 11.365 26,779 0 11 2011 0 16,335 12,148 28,482 0 12 2012 0 17.310 12.985 30,295 0 13 2013 0 18.344 13.881 32.225 0 14 2014 0 19.440 14,838 34,279 0 15 2015 0 20.602 15,863 36.465 0 16 2016 0 21,833 16.958 38.791 0 17 2017 0 23.139 18,129 41.268 0 18 2018 0 24.522 19.382 43.904 0 19 2019 0 25.989 20.722 46.711 0 20 2020 0 27.528 22.131 49,659 0 21 2021 0 29,094 23.560 52.654 0 22 2022 0 30.650 24,976 55.626 0 23 2023 0 32.182 26.364 58,547 0 24 2024 0 33.683 27,714 61.397 0 25 2025 0 26.709 29.044 55.753 8,459 26 2026 0 7,177 30.409 37,586 20,686 27 2027 0 0 17.753 17.753 21.570 28 2028 0 0 -3.618 -3,618 22.204 29 2029 0 0 .26.259 .26,259 22.467 30 2030 0 0 -50.431 -50.431 22.913 31 2031 0 0 -76,411 -76,411 23.562 32 2032 0 0 .91.951 -91.951 11.875 33 2033 0 0 -104,031 -104.031 7,670 34 2034 0 0 .116.336 -116.336 7.315 35 2035 0 0 -122.582 -122.582 666 36 2036 0 0 -129,147 .129.147 685 37 2037 0 0 .136,041 -136.041 700 38 2038 0 0 .149.605 .149,605 7.040

Attachment 3-F RBS Report Page I of J PUC DOCKET NO. 16705 SOAH DOCKET NO. 473-96-2285 APPLICATION OF ENTERGY TEXAS § FOR APPROVAL OF ITS TRANSITION § TO COMPETITION PLAN AND THE § PUBLIC UTILITY COMrESS N TARIFFS IMPLEMENTING THE PLAN, § I"

%.I AND FOR THE AUTHORITY TO § OF TEXAS > 31 RECONCILE FUEL COSTS, TO SET § REVISED FUEL FACTORS, AND TO a,_ rn 1-

§ X,.

RECOVER A SURCHARGE FOR § ril UNDER-RECOVERED FUEL COSTS § 0

'in SECOND ORDER ON RIEHEARING X This Second Order on Rehearing (Order) addresses the application filed by Entergy Gulf States, Inc. (EGS or the Company) on November 27, 1996, in accordance with Paragraph 9b of the Stipulation and Agreement approved by the Commission in Docket No. 11292.' Through this Order, the Commission adopts in part and modifies in part the Proposal for Decision (PFD) as corrected and the Supplemental Proposal for Decision (SPFD) issued by the State Office of Administrative Hearings (SOAH) Administrative Law Judges (ALJs) in late March 1998.2 I. Introduction The SOAH ALJs conducted separate evidentiary hearings on the four component parts of this docket: fuel, revenue requirement, cost allocation/rate design, and competitive issues. After completion of the hearings and review of the record evidence, the ALJs recommended that the Commission order EGS to reduce its current Texas retail base rates by S137 million, which A4pplicatfon of Entergy Corporation and Gui/States Utilities Company for Sakc Transfer or Merger, Docket No. 1 292, 19 P.U.C. BULL 2040, 2041 (Ordering Paragraph 5) (Dec. 29, 1993).

The AlJs issued the PFD on March 25, 1998, as revised by clarifications, revised text, and revised schedules filed on June 4, 12, and 16, 1998. The AIJs issued the SPFD, which addresses supplemental fuel-related issues, on March 27, 1998. The Commission considered the matters addressed in this Order at its open meetings convened on June 30, July 8 through 10, July 13, Judy 16, and July 22, 1998. The Commission issued its "final" order in this docket on July 22, 1998. The Commission considered motions for rehearing at its open meetings convened on August 26, and October 8, 1998. A more detailed procedural history of this case is contained in Attachment A to the PFD and the Findings of Fact (FoF) and Conclusions of Law (CoL), as modified. contained in this Order.

AnachmenL3 RBS Rept PUC DOCKET NO. 16705 Second Order on Rehesring Page 91 of 156 Page 2 o:'

SOAH DOCKET NO. 473-96-2585 Non-Reconcilable Fuel and Purchased Power Expenses 177. It is reasonable to include non-reconcilable coal, gas, and purchased power expenses in the amount of $4,853,684 in cost of service.

Decommissioning Expense 178. The cost to decommission the River Bend plant, adjusted for a ten percent ceiling value for. contingencies, will be S385.2 million. EGS' 70% share of this amount is S269,640,000.

179. Based on the Commission's previous adoption of low level radioactive waste disposal costs at 7.5%, the fact that River Bend specific inflation factor has been very low in the past several years, and the fact that decommisioning does escalate at a rate higher than general inflation, a 4.81% escalation rate is reasonable.

180. AnI 11.47%/o trust equity return and overall 6.6% return for the trust fund results from the most reasonable assesment of return projections.

181. Total company annual decommissioning expense of S8,551,000 is EGS' reasonable and necessary share of River Bend decommissioning costs as evaluated in PFD §VII.B.

Depreciation Rates and Expense 182. The total reasonable depreciation expense for EGS is stated on Commission Schedule I.

Production Plant 183. Because EGS has no specific plan to retire any generating unit soon, it is reasonable to assume that the units will be retired in the middle of the year, because they may, in fact, be retired at any time during the year.

184. The retirement dates for planning purposes should be used for depreciation purposes, as well. The River Bend license expiration date of August 29, 2025 should be used as the

Artachment3f RBS Rep.

Page 3 d,9 PUC DOCKET NO. 16705 Second Order on Rehearing Page 155 of 156 SOAH DOCKET rhO. 473-9642285 SIGNED AT AUSTIN, TEXAS the __a_ of October 1998.

PUB LITY COMMISSION OF TEXAS PAT WOOD, II9 CHAIRMA

,mr3-iSIONNR Q:%-SHARENORDERS\FJNALsI 6000X1 6705RH2.DOC

- -. . .,4 S.

l Schedule KS r xI IDtt ket No. 16705 COMMiSSION I *mcsity (;wirstaiesa Inc. ()(7rOIER t9s Summary of Tex&. Retail Revenue Requirement Alloatilom Page I of I I Ihousands of Dollaus)

I:ligible Fuel & Putch Power 2S7.233 79.121 3.781 40,234 22.104 5r.567 56,036 1.332 Non-Eligible Fuel & Purch Power 6.481 2.419 141 1.122 512 1.142 1.119 27 Operating and Maintenance !~5312 62.411 4.335 21.035 7.939 14.594 13.4t3 1.396 1Decommissioning Expense 1.451 90 651 210 596 570 14 Depreciation Expense 60.177 27,332 1.900 11.926 4.233 6.9112 6.1t7 1.466 Amoniration (7.773) (3.095) (190) (1.396) (594) 11.265) (1.210) (29)

Interest (n Customer Deposits 501 230 16 102 36 59 53 7 1axts Other Than State Income Tax 39.737 17.006 1.109 7.341 2.914 5.599 5.317 4S0 Sta;le Income Taxes 0 0 0 0 0 0 0 0 I Wecial Income Taxes 27.5316 12.459 342 5.469 1.934 3.247 3,005 630 Ruturn on Invested Capital (Return on Rate Dime) 101,476 49.633 3.401 21,961 7.761 12.659 11.529 1.413

ains rrom Disposition of Allowance 1lorrAL REVENUE REQUIREMENT 621,390 249,101 15,475 103.452 47,119 98.179 96,289 6,775 Quzlity of Service Adj. Allocaled.Ratu Base 2.211 1.013 69 443 151 253 235 30 Quality of Service Adj. Reallocated *Distribution Lines (2.211) (1.2835) (31) (615) (164) (49) (19)

Adjustment due to IS.Creditsilo LPS & IILFS (5.9I1) (4,944) (974)

Adjustment due to IS.Crcdits allocated to Finn Classes 5.911 2,463 1[S 1.113 475 305 117 21 Adjustment due to Senior Citi7en Discount Residential (457) (457)

Adjustment due lo Senior Citizen Discount Allocated lo All 457 113 II 10 35 7Z 71 5

'I olrAL REVENUE REQUIREMENT ADJUSTED 62,130 21,019 13,626 109.477 47.623 94,322 96,508 6.N15 Fixed Futl Factor Revenue 221.734 79.123 3.711 40.234 22.104 30.507 5 1.697 1.3 12 Non Fixed Fuel Factor Revenue 21.449 24.060 4.319 Other Revenues 16.926 7.910 515 3.671 1.290 .1,767 1.554 150 HASE RATE REVENUE Before Imputatilo 347.230 163.9t1 11,330 65.573 24,229 37,93 311,363 5.332 Inprit;ntion due to SSTS 7.222 5.393 1.,29 Imputation due to EEDS 1.261 29 452 515 195 IHASY ItATE REVENUE w1 ImputatIon 333.747 163.911 11,330 65.544 23.777 32.010 36.844 5,332

s fra (n 3 loll2191 I 26 ANt

4. ; :3 o -t,

-. 0 J. 'I -'i

.Achment3-G RBS Report 580Pare I o6 UNITED STATE:S OF AfIC.

-FEDEAL ENERGY REGUtL&ORY COMMISSION BQ40re Coam:misioners: Martha 0. Hasse, Chair=an;

.Anthony G. Souza, Charles G. Stalon and Charlau A. Trabandt.

Gul:' States Utilities Company ) Dockat NoC. ER86-558-OO2, ER86-558-01l and ER86-558-o01 ORDER CL.I.RUNG PRZvious ORDERS

(IzsuCd Hay 1i, 1988)

Cn Fabruary 16, 1988, Gulf States Utilities.Ccmpany (Gulf States) filed a petition for clarification of cortain lattar orders approving zdttlamentz in this proceeding. ;,/ The letter orders approved settlement ratos reflecting decommissioning expenzes funded through an external fund (River Vend Nuclear Decc-issioning Fund) adjumtad for a forty-year funding period:

on Harch 2, 1988, Cajun Electric Power Cooperative, Inc.

(Cajun) requested that the Cqmmiiaion Qxplicitly recognize that its contributions to Gulf States' docozzissioning fund are, and have been, on the basis of unadjusted decommissioning expenses, and that the instant ordmr will have no application to tha rates being charged to Cajun.

Gulf States requests thit the Commission expressly recogni2e the amount of yearly decommissioning costs which it is entitled to collect. Gulf States ascartz that aboant such expross recognition, the Intarnal 'Rvenuz Service. (RS) will not pe.=it.

its deduction or yearly cash contributions to the River Bend Nuclar Decommissioning .Fund.

Gulf Statas contands that it must firzt receive a "schedule of ruling amounts" from the IRS in order to take this deduction.

Gulf Statas furthar =mintains that the IRS will nct piovide a taxpayer vith a fienedUl Of ?Ulibq aboun&t "unless a public utility co=miszion that cstablish.s or approves ratas for electric energy generated by the nuclear pocwer plant to which the

}/ Son Gulf States Utilities Company, 40 7ZRC ' 61,081 (1987); Gulf Statas Utilities Company, 40 FrRC 1 61,3B0

(.987)i and Gulf Stzta3 Utilities Companv, 42 EFC

< 61,098 (1958).

A-tachment 3-G RBS Report Page'ot6 258016 Docket Ncs. ER86-55S-002 and -011 - 2 -

and -02.3 nuclear decommissioning fund relates has determined the amount cv decommissioning costs of such nuclear power plant to be included in the taxpayer's cost of service for ratemakcing pUrpcses. 21 culf States maintains that tha cc--ission's lettor crders approving the settlements do not expressly address

deccmmissioning costs, althcugh the settlement rates which.the cc-ission has approved are expressly based upon specified deccmissioning COCts. Gulf Statas also claims that the I-S has deterinod that tho Coaiz-ion's letter ordars approving the settlseents do not satisfy the reiuirements of its ragulations.

'W are not convinced t~hat, the instant clarificaticns are necessary. It appears that Gulf States has never submitted to the^ IPS the lettzr orders approving tha settlenents that apecifSod tho amount of deccmizsaionng costs that will be roflocted in Cult Statca' wholesale rates. Based on Gulf States' tiling it appaars that they requested approval from the IRS on June 24, 1987. 2/ The letter ordeirs.wers-not issued un t4 July 22 And September 25, 1987 and January 31, 1988, respectively. Va believe that had Gulf Statoz properly sumittaed the latter orders that ar* tho subject of our order tcdzy to the IRS that no clar'fication of these orders would be necessary.

We shall nevertheless grant the requests-of Gulf States and Cajun. In approving the settlment3 reached in this dockeE the Commission h ozedGulf toroflec: in itn

- whoesalo rates yearly decoissicninr coztz of S112,914. We r-aGJave MucM actIhn to D nre the pubi+/-c intarest to allcw Gulf states to receive the proper tax deduction for its yearly cash contributions to thei River Bend Nuclear Decommissioning Fund.

This ordor will also have no applica$ion to the rates being charged to Cajun.

'ho Coe isnion orders :

The Gulf States' and Cajunlz' ruests a for clarification are hereby granted.

By the Co=iicn.

(5E A L)

Lois D. Cashel!,

Actrng Secretary.

21 5 petition for Clarif'cation at 3-4, quct'.. Temp.

Treas. Rego. I 1.46a-3T(g) (1t486).

,/ ~ letter of Saptemb-er 22, 1987 of Willian J. D-ver, Chief, Branch 6 Corporation Tax Division, :RS at 1.

, , ,C.,. .r -e 55 _ . .; - -:Z.

Attachment 3-G RBS Report Page 3 of 6 FEDERAL ENERGY RESULATORY COMMISSIDH IRS Schedule Of Ralipg Asoatts, dated May 22, 1989

. ... I Internal Revenue Service Department of the Treasury - -- - .

PO. Box 7604 Atachment 3-G Ben Franklin Station RBS Repor Index No.: 0468A.10-03 Washington. OC 20044 Page 4 of b Person to

Contact:

B.J. Willis, Vice President Martin Schaffer and Controller Telepohone Number:

Gulf States Utilities Co. (202) 566-6589 350 Pine St., P.O. Box 2951 Refer Reply to:

Beaumont, TX 77704 CC:P&SI:6 TR-31-824-89 Date: AY 2 2. IM In re: Schedule of Ruling Amounts Gulf States Utilities Co.

River Bend Nuclear Power Plant Company: Gulf States Utilities Co.

EIN: 74-0662730 Plant: River Bend Nuclear Power Plant (a 940MW boiling water reactor)

Location: Just south of St. Francisville, LA (28 miles north of Baton Rouge, LA)

Utility: Cajun Electric Power Cooperative Commission A: Federal Energy Regulatory Commission Commission B: Public Utility Commission of Texas Commission C: Louisiana Public Service Commission State A: Texas State B: Louisiana

Dear Mr. Willis:

This is in response to your request dated February 24, 1989, for a revised schedule of ruling amounts. Information was submitted by the Company in accordance with section 1.468A-3(h)(2) of the Income Tax Regulations. ThM facts as represented by the Company follow.

The Company, incorporated in State A, is an electric utility operating in States A and B. The Company owns 70

- e ' a~ait'Gil -1.-

Attachment 3-G RBS Report Page 5 of 6 TR-31-824-89 percent of the Plant as a tenant in common. The Utility owns the other 30 percent.

The Plant began commercial operations on June 16, 1986, and its operating license is scheduled to expire on August 29, 2025.

The rates for electric energy generated by the Plant are established by Commissions A, B, and C. The Internal Revenue Service approved a schedule of ruling amounts within the jurisdiction of Commission B on November 15, 1988, and within Commission C's jurisdiction on September 27, 1988.

The original schedule of ruling amounts under Commission A's jurisdiction was approved by the Internal Revenue Service on September 27, 1988. However, the Company failed to make a contribution to the nuclear decommissioning fund for the year 1986 with thirty days of receipt of the approved schedule, as required by section 1.468A-8(b)(2) of the rbgulations. This failure shortened the funding period, as defined in section 1.468A-3(c)(1), and thus changed the qualifying percentage, as defined in section 1.468-3(d)(4).

By orders dated July 22, 1987, September 25, 1987, January 21, 1988, and May 18, 1988, Commission A (jurisdictional percentage: 5.6358 percent) determined the amount of decommissioning costs to be included in the Company's cost of service for ratemaking purposes. There.is no proceeding pending before Commission A that may result in an increase or decrease in the amount of these decommissioning costs.

The estimated cost of decommissioning the Plant is S$201,406,000 in 1985 dollars. This estimate, based on the prompt removal/dismantlement method of decommissioning, was calculated by a site-specific engineering study ordered by the Company. The Company's share of the total estimated cost of decommissioning is $140,984,200, and its Commission A jurisdictional share is $7,945,588.

Based on an assumed inflation rate of four grnernt, the total cost of decommissioning expressed in future dollars is

$966,950,206. The Company's share of this amount is

$676,865,144. The Commission A jurisdictional amount is

$38,146,766.

Using an assumed after-tax rate of return of nine

-)e percent, Commission A determined the amount of decommissioning pecntO eomsinn

Attachment 0-G RBS Report Page 6 of 6 TR-31-824-89 costs to be included in the Company's 1988 cost of service i Is annual share of the total estimated costs) to be 1l12,91.

The estimated year in which substantial decommissioning costs will first be incurred is 2026;. The estimated year in which decommissioning of Plant will be substantially complete is 2031.

The first taxable year for which a deductible payment was made to the nuclear decommissioning fund is 1988. The taxable year that includes the estimated date on which decommissioning costs will no longer be included in the Company's cost of service is 2025. The taxable year that includes the estimated date on which the Plant will no longer be included in the Company's rate base is 2026 (January 1).

The funding period, the level funding limitation period, and the estimated period over which the nuclear decommissioning fund is to be in effect all are 38 years. The estimated useful life of the Plant is 40 years.

The Company's qualifying percentage is 95 percent.

Section 88 of the Internal Revenue Code provides that a taxpayer who is required to include nuclear decomissioning costs in its cost of service for ratemaking purposes shall include this amount in its gross income.

Section 468A(a) of the Code provides that a taxpayer may elect to deduct the amount of payments made to a qualified nuclear decommisslion.tIg fund. However, section 468A(b) limits the amount paid into the fund for any taxable year to the lesser of the amount of nuclear decomissioning costs allocable to the fund which is included in the taxpayer's cost of service for ratemaklng purposes for the taxable year or the ruling amount applicable to this year.

Section 468A(d)(1) of the Code provides that no deduction shall be allowed for any payment to the fund unless the taxpayer requests and receives from the Secretary a schedule of ruling amounts. The 'ruling amount' for any taxable year is defined under section 468A(d)(2) as the amount which the Secretary determines to be necessary to fund that portion of nuclear decommissioning costs which bears the same ratio to the total nuclear decommissioning costs in regard to the nuclear power plant as the period for which the decommissioning fund is in effect bears to the estimated

Report on Status of Decommissioning Funding 10 CFR 50.75(f)(1)

March 31, 2005 Attachment 3 RBS-30% Report River Bend Station-Non Regulated 30% Interest Minimum Reporting Requirements as per 10 CFR 50.75(f1(1):

1. Decommissioning funds estimated pursuant to 10 CFR 50.75(b) and (c) (2004$):

Non-Regulated 30% Interest S 202,258,466

2. Market value of funds accumulated as of December 31, 2004:

Non-Regulated 30% Interest $ 173,248,315 2.4

3. Current schedule of annual amounts remaining to be collected: N/A 4

4. Assumed rate of decommissioning cost escalation used in funding projections: N/A 4

5. Assumed average after-tax rates of earnings used in funding projections: N/A 4

6. Assumed rates of other factors used in funding projections: N/A 4

7. Contracts assuring collection of decommissioning funds: N/A4

8. Modifications to method of providing financial assurance since March 31, 2003 filing (external sinking fund): None

9. Material changes to trust agreements since March 31. 2003 filing: See Footnote 6 Supplemental Information:

1. Site-Specific cost estimate escalated to 2004:

Non-Regulated 30% Prefunded Interest (1996 Base Year Dollars)

NRC License Termination Cost: $ 132.838,872 3 Non-NRC License Termination Cost: $ 17,968,616 3 Total $ 150,807,487

2. Decommissioning method assumed for planning purposes in site-specific estimate: DECON

3. Year site-specific estimate complete: 1996 5

4. Frequency of updates (approximately): once every 5 years

5. Funding based on NRC minimum or site-specific estimate?: Site-specific

6. Decommissioning rate regulation (approximately):

Unregulated Interest (prefunded) 30.00% 4 See Attachment 3-A for calculations.

2 Source: December 31, 2004 River Bend Station Trust Fund Report.

3 See Attachment 3-B for calculations. Also see footnote 4 to Attachment 3-A for information on the generic baseline cost estimate using the waste vendor disposal factor (Bamwell, South Carolina).

4 Cajun contributed $132 million to prefund its decommissioning obligation with respect to its former 30% ownership share.

This fund may only be used to decommission the non-regulated 30% interest. Any excess funds after decommissioning must be returned to Rural Utilitiy Services.

5 The 2004 cost update for $200.13 million (30% of $667.1 million in '04 $) has not been filed.

5 The following section was added to all trust agreements on December 17, 2003:

Notice Regarding Disbursements or Payments Notwithstanding anything to the contrary in this Agreement, except for (i) payments of ordinary administrative costs (including taxes) and other incidental expenses of the Trust Fund (including legal, accounting, actuarial, and Successor Trustee expenses) in connection with the operation of the Trust Fund, (ii) withdrawals being made under 10 CFR 50.82(a)(8),

and (iii) transfers between Qualified and Nonqualified Funds in accordance with the provisions of this Agreement, no disbursement or payment may be made from the Trust Fund until written notice of the intention to make a disbursement or payment has been given to the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, at least 30 working days before the date of the intended disbursement or payment. The disbursement or payment from the Trust Fund, if it is otherwise in compliance with the terms and conditions of this Agreement, may be made following the 30-working day notice period if no written notice of objection from the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, is received by the Successor Trustee or the Company within the notice period. The required notice may be made by the Successor Trustee or on the Successor Trustee's behalf. This Section 8.04 Is intended to qualify each and every provision of this Trust Agreement allowing distributions from the Trust Fund, and in the event of any conflict between any such provision and this Section, this Section shall control.

Attachment 3-A RBS-30% Report RIVER BEND STATION CALCULATION OF MINIMUM AMOUNT AS PER 10CFR 50.75 (b) AND (c)

Determination of Minimum Amount-Non Regulated 30% Interest Entergy Gulf States, Inc.: 100% ownership interest Plant Location: St. Francisville, Louisiana Reactor Type: Boiling Water Reactor ('BWR")

Power Level: <3400 MWt (Approx. 3091 MWt.)

1986 BWR Base Year S: $131,819,000 Waste Burial Facility: Barnwell, South Carolina 10 CFR 50.75(c)(2) Escalation Factor Formula:

0.65(L) + 0.13(E) + 0.22(B)

Factor L= Labor (South) 1.925 2

E= Energy (BWR) 1.448 2 B= Waste Burial (BWR) 16.705 BWR Escalation Factor:

0.65(L) + 0.13(E) + 0.22(B) = 5.11455 1986 BWR Base Year S Escalated:

1986 BWR Base Year $ ' Escalation Factor = $ 674,194,886 4 Non-regulated 30% Interest S 202,258,466 4.5 Source: Bureau of Labor Statistics: series report id ecul 322i (March 2005).

2 Source: Bureau of Labor Statistics: series report id wpu0543 and wpu2573 (March 2005).

3 Source: Nuclear Regulatory Commission:Table 2.1 of "Report on Waste Burial Charges", NUREG-1 307 revision 10(October 2002).

'4Application of the 8.860 waste vendor disposal factor (South Carolina) from Table 2.1 of 'Report on Waste Burial Charges",

NUREG 1307 Revision 10 (October 2002) yields a generic baseline cost of:

Non-regulated 30% Interest = S 134,006,542 5 Cajun contributed 5132 million to prefund its decommissioning obligation with respect ot its former 30%

ownership share.

Attachment 3-B RBS-30% Report RIVER BEND STATION CALCULATION OF SITE-SPECIFIC COST ESTIMATE ESCALATED TO 2004 DOLLARS RIVER BEND 30% PREFUNDED INTEREST Site-Specific Cost Estimate (1996$)

Site-Specific Cost Estimate (1996$ - 30%):

NRC License Termination Cost: $ 110,710,694 2 Non-NRC License Termination Cost: $ 14,975,420 3 Total Site-Specific Cost Estimate: $ 125,686,114 1 Annual Escalation Factor: CPI Years of Escalation (1996 Base Year to 2004): 8 Cumulative Factor: 1.200 Site-Specific Cost Estimate (2004$):

NRC License Termination Cost ' Cumulative Factor $ 132,838,872 Non-NRC License Termination Cost: ' Cumulative Factor $ 17,968.616 Total Site-Specific Cost Estimate: l $ 150,807,487 1 1 Based on 30% of the site-specific cost estimate of $418,953,716 in 1996$ and escalated annually at rates tied to projections of the Consumer Price Index-Urban c(CPI). The projection for the cumulative CPI from the period 1996 through 2004 was 19.99%.

2 From 1996 Decommissioning Cost Estimate for River Bend, Table C, times 30%.

3 From 1996 Decommissioning Cost Estimate for River Bend. Table C, times 30%.

Report on Status of Decommissioning Funding Attachment 4 Required by 10 CFR 50.75(f)(1) WF3 Report March 31, 2005 Waterford 3 Steam Electric Station Minimum Reoortino Reaulrements as per 10 CFR 50.75(f01i:

2. Market value of funds accumulated as of December 31, 2004: $ 176.042,107 2

3. Current schedule of annual amounts remaining to be collected: See Attachment 4-C

4. Assumed rate of decommissioning cost escalation used in funding projections: 5.50%

5. Assumed average after-tax rates of earnings used in funding projections: 7.44% 5

6. Assumed rates of other factors used in funding projections: See Attachment 4-C

7. Contracts assuming collection of decommissioning funds: None

8. Modifications to method of providing financial assurance since March 31, 2003 filing (external sinking fund): None

9. Material changes to trust agreements since March 31. 2003 filing: See Footnote 6 Supplemental Information:

1. Site-Specific cost estimate escalated to 2004 (1993 Base Year Dollars):

NRC License Termination Amount: $ 522,670.324 Non-NRC License Termination Cost: $ 54,226.741 Total $ 576.897,065

2. Decommissioning method assumed for planning purposes in site-specific estimate: DECON

3. Year site specific estimate complete: 1994 '

4. Frequency of updates (approximately): once every 5 years 4

5. Funding based on NRC minimum or site-specific estimate?: Site-specific

6. Decommissioning rate regulation (approximately):

Louisiana Public Service Commission 97%

Council of the City of New Orleans 3%

l See Attachment 4-A for caluculations.

2 Source: December 31, 2004 Waterford 3 Trust Fund Report.

3 See Attachment 4-B for caluculations. Also see footnote 4 to Attachment 4-A for information on the generic baseline cost estimate using the waste vendor disposal factor (Bamwell, South Carolina).

4 Entergy Louisiana refiled a 1999 decommissioning cost update of 5481.5 million for Waterford 3 with the LPSC in the third quarter in a full rate case with the LPSC in July. 2003. The 2004 cost update has not been finalized.

5 Assumed after-tax earnings rate for the decommissioning fund for the period 2005-2040 (LPSC Docket No. U-17906-A).

S The following section was added to all trust agreements on December 17. 2003:

Notice Recardina Disbursements or Payments . Notwithstanding anything to the contrary Inthis Agreement, except for (i) payments of ordinary administrative costs (including taxes) and other Incidental expenses of the Trust Fund (including legal, accounting, actuarial, and Successor Trustee expenses) In connection with the operation of the Trust Fund. (ii) withdrawals being made under 10 CFR 50.82(a)(8). and (iii) transfers between Qualified and Nonqualified Funds In accordance with the provisions of this Agreement, no disbursement or payment may be made from the Trust Fund until written notice of the Intention to make a disbursement or payment has been given to the Director. Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, at least 30 working days before the date of the intended disbursement or payment. The disbursement or payment from the Trust Fund, if it is otherwise In compliance with the terms and conditions of this Agreement, may be made foflowing the 30-working day notice period if no written notice of objection from the Director. Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, Is received by the Successor Trustee or the Company within the notice period. The required notice may be made by the Successor Trustee or on the Successor Trustee's behalf. This Section 8.04 Is intended to qualify each and every provision of this Trust Agreement allowing distributions from the Trust Fund, and In the event of any conflict between any such provision and this Section, this Section shall control.

Attachment 4-A WF3 Report WATERFORD 3 STEAM ELECTRIC STATION CALCULATION OF MINIMUM AMOUNT AS PER 10CFR 50.75 (b) AND (c)

Determination of Minimum Amount Entergy Louisiana, Inc.: 100% ownership/leasehold interest Plant Location: Taft, Louisiana Reactor Type: Pressurized Water Reactor ("PWR")

Power Level: >3,400 MWt.

1986 PWR Base Year $: $105,000,000 Labor Region: South Waste Burial Facility: Barnwell, South Carolina 10 CFR 50.75(c)(2) Escalation Factor Formula:

0.65(L) + 0.13(E) + 0.22(B)

Factor L= Labor (South) 1.925 E= Energy (PWR) 1.434 2 B= Waste Burial (PWR) 18.732 3 PWR Escalation Factor:

0.65(L) + 0.13(E) + 0.22(B) = 5.55877 1986 PWR Base Year $ Escalated:

$ 105,000,000

Escalation Factor= $ 583,670,340 4

' Source: Bureau of Labor Statistics: series report id ecul3202i (March 2005).

2 Source: Bureau of Labor Statistics: series report id wpu0543 and wpu0573 (March 2005).

3 Source: Nuclear Regulatory Commission:Table 2.1 of "Report on Waste Burial Charges", NUREG-1307revisionlO(October 2002).

4 Application of the 9.467 waste vendor disposal factor (South Carolina) from Table 2.1 of "Report on Waste Burial Charges",

NUREG 1307 Revision 10 (October 2002) yields a generic baseline cost = $ 369,648,840

Attachment 4-B WF3 Report WATERFORD 3 STEAM ELECTRIC STATION CALCULATION OF SITE-SPECIFIC COST ESTIMATE ESCALATED TO 2004 DOLLARS Site-Specific Cost Estimate (1993S)

Site-Specific Cost Estimate (1993$):

NRC License Termination Cost: $ 290,035,252 Non-NRC License Termination Cost: $ 30,090,988 Total Site-Specific Cost Estimate: l $ 320,126,240 l '

Annual Escalation Factor: 5.50%

Years of Escalation (1993 Base Year to 2004): 11 Cumulative Factor (1 + Factor)A" 1.802 Site-Specific Cost Estimate (2004$):

NRC License Termination Cost

Cumulative Factor: $ 522,670,324 Non-NRC License Termination Cost

Cumulative Factor: $ 54,226,741 Total Site-Specific Cost Estimate: 1$ 576,897,065

'The funding amounts (Attachment 4-C) are based on site-specific cost estimates in 1993$ and an escalation rate of 5.50%.

Attachment 4-C WF3 Report Louisiana Power & Light Company Waterford-3 Decommissioning Model Trust Fund Summary

($000)

Tax Qualified Trust Line Revenue Earning Transfer Management Net Decomm.

No

- Year Rqmt. 11l Rate [21 To Trust Earnings 131 Fee Additions Funding 15] Balance Beginning Balance 29,172 1995 8.786 0.0675 8.786 2.299 (74) 11,011 0 40,183 1996 8,786 0.0675 8,786 3,055 (90) 11,750 0 51,934 1997 8,786 0.0675 8,786 3,861 (105) 12,542 0 64,475 1998 8,786 0.0675 8,786 4,722 (122) 13,386 0 77,862 1999 8,786 0.0800 8,786 6,705 (140) 15,351 0 93,213 2000 10,420 0.0800 10,420 8,023 (161) 18,282 0 111,495 2001 10,420 0.0800 10,420 9,515 (185) 19,750 0 131,244 2002 10,420 0.0800 10,420 11,126 (211) 21,335 0 152,580 2003 10.420 0.0800 10,420 12,867 (239) 23,048 0 175,628 2004 10,420 0.0800 10,420 14,748 (269) 24,899 0 200,527 2005 12,353 0.0800 12,353 16,857 (303) 28,907 0 229,434 2006 12,353 0.0800 12,353 19,216 (341) 31,228 0 260,662 2007 12,353 0.0800 12,353 21,764 (382) 33,735 0 294,397 2008 12,353 0.0800 12,353 24,517 (426) 36,444 0 330,841 2009 12,353 0.0800 12,353 27,491 (474) 39.370 0 370,211 2010 14,743 0.0800 14,743 30,799 (527) 45,014 0 415,225 2011 14,743 0.0800 14,743 34,472 (586) 48,629 0 463,854 2012 14,743 0.0800 14,743 38,440 (650) 52,533 0 516,387 2013 14,743 0.0800 14,743 42,727 (719) 56,751 0 573,138 2014 14,743 0.0800 14,743 47,358 (793) 61,307 0 634,445 2015 17,598 0.0800 17,598 52,475 (876) 69,197 0 703,642 2016 17,598 0.0800 17,598 58.121 (966) 74,753 0 778,395 2017 17.598 0.0800 17,598 64,221 (1,064) 80,755 0 859,150 2018 17.598 0.0800 17,598 70,811 (1,170) 87,238 0 946,388 2019 17,598 0.0800 17,598 77,929 (1,285) 94,243 0 1,040,631 2020 20.998 0.0800 20,998 85,755 (1.410) 105,343 0 1,145,974 2021 20.998 0.0675 20,998 79,367 (1,539) 98,826 0 1,244,800 2022 20,998 0.0675 20,998 86,151 (1,668) 105,481 0 1,350,281 2023 20,998 0.0675 20,998 93,391 (1,805) 112,584 0 1,462,865 2024 20,998 0.0675 20,998 101,118 (1.950) 120,167 (3,333) 1,579,699 2025 0 0.0675 0 108,429 (2,033) 106,396 (91.609) 1.594,486 2026 0 0.0675 0 109,444 (2,049) 107,395 (96,647) 1,605,234 2027 0 0.0675 0 110,182 (2,043) 108,139 (128,670) 1.584,703 2028 0 0.0675 0 108,773 (1,863) 106,910 (372,283) 1,319,329 2029 0 0.0675 0 90,558 (1,501) 89.056 (397,480) 1,010,905 2030 0 0.0675 0 69,388 (1,089) 68,298 (413,229) 665,975 2031 0 0.0675 0 45,712 (626) 45,086 (434,804) 276,256 2032 0 0.0675 0 18,962 (288) 18,674 (164,583) 130,346 2033 0 0.0675 0 8,947 (114) 8,833 (139,179) 0 (2,241,818) 7.44%

Notes-

1. The 2005 Revenue Requirement (10.420) Is chosen and escalated by Cumulative CPIU From 2005 every rifh year so that the Decommissioning Fund Balance Is zero in the last year of decommissioning.

The average annual CPIU rate is 3.6%.

2. Projected after-tax earnings rate, assumed average after-tax earnings rate Is 7.44%.

(Assumed after-tax earnings rate is 7.44% for the period 2005-2040.)

3. Prior Year Balance compounded semiannually at Current Year Earning Rate + % Current Year Transfer

Current Year Earning Rate.

4. Transfer + Eamings + Management Fee.

5. The Nuclear Cost Escalator Is 5.5%.

CNRO-2005-00022, Entergy Operations, Inc., Status of Decommissioning Funding Report

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CNRO-2005-00022, Entergy Operations, Inc., Status of Decommissioning Funding Report

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