ML030990088

Status of Decommissioning Funding Report

ML030990088
Person / Time
Site:	Grand Gulf, Arkansas Nuclear, River Bend, Waterford
Issue date:	03/31/2003
From:	Krupa M Entergy Operations
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CNRO-2003-00012
Download: ML030990088 (77)

Text

Ad En tefgy Entergy Operations, Inc.

1340 Echelon Parkway Jackson, MS 39213-8298 Tel 601 368 5758 Michael A. Krupa Director Nuclear Safety & Licensing CNRO-2003-00012 March 31, 2003 U.S. Nuclear Regulatory Commission Attn: Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852-2738 (301) 415-7000

Subject:

Entergy Operations, Inc.

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

Reference:

10 CFR50.75 (f)(1) Reporting and Recordkeeping for Decommissioning Planning

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)(1). In accordance with these requirements, EOI will provide reports on the status of its decommissioning funding at least once every two years from this date.

Also enclosed is the Arkansas Public Service Commission's Order No. 37, Docket No.

87-166-TF, which is required to be provided to the NRC with this filing, for ANO.

A DI I

,\\ex CA

CNRO-2003/00012 Page 2 of 2 Please address any comments or questions regarding this matter to Mr. Les England at (601) 368-5766.

Sincerely, MA LAE/bal Attachments: 1. ANO Report

2. GGNS Report

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

4. WF3 Report

Enclosure:

APSC Order 37, Docket No. 87-166-TF cc:

(All Below w/o Attachments - See File Copy For Attachments)

Mr. C. G. Anderson (ANO)

Mr. J. L. Blount (ECH)

Mr. W. R. Campbell (ECH)

Mr. W. A. Eaton (GGNS)

Mr. P. D. Hinnenkamp (RBS)

Mr. J. R. McGaha (ECH)

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

Mr. L. Jager Smith (Wise, Carter)

Mr. G. J. Taylor (ECH)

Mr. J. E. Venable (W-3)

Mr. G. A. Williams (ECH)

Mr. T. W. Alexion, Project Manager (ANO-2)

Mr. D. H. Jaffe, Project Manager (GGNS)

Mr. N. Kalyanam, Project Manager (WV-3)

Mr. E. W. Merschoff (NRC Region IV)

Mr. J. L. Minns, Project Manager (ANO-1)

Mr. M. K. Webb, Project Manager (RBS)

Attachment I ANO Report Report on Status of Decommissioning Funding Required by 10 CFR 60.76(f)(1)

March 31, 2003 Arkansas Nuclear One - Units I and 2 Minimum Reporting Requirements as per 10 CFR 60.75(f(1):

1 Decommissioning funds estimated pursuantto 10 CFR 5075(b) and (c) (2002$)

Arkansas Nuclear One - Unit I Arkansas Nuclear One - Unit 2 2 Market value of funds accumulated as of December 31, 2002 Arkansas Nuclear One - Unit 1 Arkansas Nuclear One - Unit 2 530,537,623 1 552,444,043 '

181,001,661 2 146,693,230 2 3 Current schedule of annual amounts remaining to be collected See Attachment 1-C '

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

CPI-U 5 Assumed average after-tax rates of earnings used in funding projections 6 66%-Unit 1 5 681%-Unit2 5 6 Assumed rates of other factors used in funding projections

7. Contracts assuring collection of decommissioning funds 8 Modifications to method of providing financial assurance since March 31, 2001 filing (external sinking fund) 9 Matenal changes to trust agreements since March 31, 2001 filing Supplemental Information:

See Attachment 1-C 4 None See Footnote 4 None 1 Site-Specific cost estimate escalated to 2002(1997 Base Year Dollars)

Arkansas Nuclear One - Unit 1 Arkansas Nuclear One - Unit 2 469,267,152 3 442,718,898 3 2 Decommissioning method assumed for planning purposes in site-specific estimate DECON 3 Year site-specific estimate complete 4 Frequency of updates (approximately) 5 Funding based on NRC minimum or site-specific estimate?

6 Decommissioning rate regulation (approximately)

Arkansas Public Service Commission Federal Energy Regulatory Commission 1998 once every 5 years Site-specific 86%

14%

1 See Attachment 1-A calculabons ANOl and ANO2's separate trust agreements do not permit use of funds for decommissioning the other unit, so these amounts should be considered separately and not added together 2 Source December 31, 2002 ANO Trust Fund Reports 3 See Attachment 1-B for calculabons Also see footnotes 4 and 5 to Attachment 1-A for information on the genenc baseline cost estimate using the waste vendor disposal factor (Barnwell) 4On October 3, 2000, the APSC ordered Entergy Arkansas to reflect a 20 yr life extension In Its determination of the ANO1 and ANO2 decommissioning revenue requirements for rates to be effective January 1. 2001. The amount of decommissioning costs collected In rates for ANO was set to zero as a result of the APSC order See Attachment 1-C 5 Assumed weighted average after-tax eamings rate for the non-qualified and tax qualified decommissioning funds for the penod 2002-2045 for Unit 1 and 2002-2026 for Unit 2.

-A ANO Report ARKANSAS NUCLEAR ONE - UNITS I 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 1 Power Level: <3,400 MWt. (2,568 MWt)

ANO Unit I PWR Base Year 1986$ $97,600,000 AND Unit 2 Power Level: <3,400 MWt (3026 MWt)

ANO Unit 2 PWR Base Year 1986$ $101,630,000 Labor Region: South Waste Burial Facility: Bamwell, South Carolina 10CFR50.75(c)(2) Escalation Factor Formula:

0 65(L) + 0 13(E) + 0 22(B)

L=Labor (South)

E=Energy (PWR)

B=Waste Burial (PWR)

Factor 1.794 '

1.143 2 18 732 3 PWR Escalation Factor:

0 65(L) + 0.13(E) + 0 22(B) =

5 43584 1986 PWR Base Year$ Escalated:

ANO 1: $97,600,000

• Escalation Factor=

AND 2: $101,630,000

• Escalation Factor=

530,537,623 4 552,444,043 5

' Source Bureau of Labor Statistics senes report id ecu13202i (January 2003).

2 Source Bureau of Labor Statistics senes report Id wpu0543 and wpu0573 (January 2003) 3 Source Nuclear Regulatory Commission Table 2 1 of 'Report on Waste Bunal Charges", NUREG-1307 revision 10 (October 2002) 4Application of the 9 467 waste vendor disposal factor (South Carolina) from Table 2 1 of "Report on Waste Bunal Charges".

NUREG 1307 Revision 10 (October 2002) yields a genenc baseline cost =

331,599,543 5rApplicabon of the 9 467 waste vendor disposal factor (South Carolina) from Table 2 1 of 'Report on Waste Bunal Charges".

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

345,291,614

-B ANO Report ARKANSAS NUCLEAR ONE - UNIT 1 CALCULATION OF SITE-SPECIFIC COST ESTIMATE ESCALATED TO 2002 DOLLARS Site-Specific Cost Estimate (1997$)

Unit I Unit 2 Site-Specific Cost Estimate (1997$):

NRC License Termination Cost:

Non-NRC License Termination Cost:

Total Site-Specific Cost Estimate:

$ 418,428,134 1

$ 394,756,039 1 Annual Escalation Factor:

Years of Escalation (1997 Base Year to 2002):

Cumulative Factor:

CPI 1 5

1.122 CPI 1 5

1.122 Site-Specific Cost Estimate (2002$):

NRC License Termination Cost

• Cumulative Factor:

Non-NRC License Termination Cost:

• Cumulative Factor:

Total Site-Specific Cost Estimate:

l$ 469,267,152l i$ 442,718,898 1 Based on site-specific cost estimates in 1997$ and escalation rates tied to projections of the Consumer Price Index-Urban ("CPI") for the period from 1997 through 2002 of 12.15%. Cost estimates do not segregate costs between NRC license termination costs and non-NRC license termination costs.

-C ANO Report Entergy Arkansas, Inc ANO Decommissioning Model Unit I Summary

($000)

Line No Year 1

Beginning Balar 2

2003 3

2004 4

2005 5

2006 6

2007 7

2008 8

2009 9

2010 10 2011 11 2012 12 2013 13 2014 14 2015 15 2016 16 2017 17 2018 18 2019 19 2020 20 2021 21 2022 22 2023 23 2024 24 2025 25 2026 26 2027 27 2028 28 2029 29 2030 30 2031 31 2032 32 2033 33 2034 34 2035 35 2036 36 2037 37 2038 38 2039 39 2040 40 2041 41 2042 42 2043 43 2044 44 2045 Non-Tax Qualified Trust Revenue Net Trust Rqmt II)

Additions Balance ice 30,405 0

2.061 32,466 0

2,212 34,678 0

2,366 37,045 0

2,448 39,493 0

2,565 42,058 0

2,707 44,765 0

2,881 47,646 0

3,072 50,718 0

3,271 53,989 0

3,482 57,471 0

3,707 61,178 0

3,947 65,124 0

4,202 69,326 0

4,473 73,799 0

4,762 78,562 0

5.070 83,632 0

5,398 89,029 0

5,747 94,776 0

6,118 100,894 0

6,513 107,408 0

6,934 114,342 0

7,383 121,725 0

7,860 129,584 0

8,368 137,952 0

8,908 146,861 0

9,484 156,345 0

10,097 166.442 0

10,750 177,192 0

11,445 188.636 0

11,523 200,159 0

12.104 212,263 0

11,374 191,224 0

9,795 128,958 0

6,841 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 Deferred Tax Bal Tax Qualified Trust Net Trust Additions Balance 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 7,830 0

0 0

0 0

0 0

0 0

0 0

0 9,268 10,056 11,612 12,585 13,220 14,030 14,923 15,891 17,068 18,257 19,527 20,887 22,341 23,896 25,559 27,338 29,241 31,277 33,454 35,783 38,274 40,938 43,788 46,836 50,096 53,583 57,313 61,303 65,570 66.385 68,210 67,247 68,967 75,530 76,853 68,895 57,425 54,332 52,542 50,248 48,305 46,075 42,913 143,917 153,185 163,242 174,854 187,439 200,659 214,689 229,613 245,504 262,572 280,828 300,356 321,243 343,583 367,479 393,038 420,376 449,618 480,895 514,349 550,132 588,405 629,343 673,131 719,966 770,062 823,646 880,959 942,261 1,007,831 1,074,217 1,142,427 1,209,674 1,278,640 1,267,893 1,095,667 907,370 852,948 819,565 786,321 749,876 712.987 659,866 652,926 Decomm.

Decomm Fund Expend Balance 182,152 0

193,482 0

205,750 0

219,729 0

234,762 0

250,548 0

267,284 0

285,089 0

304,052 0

324,391 0

346,129 0

369,364 0

394,197 0

420,739 0

449,108 0

479,430 0

511,838 0

546,477 0

583,501 0

623,073 0

665,369 0

710,577 0

758,898 0

810,545 0

865,749 0

924,753 0

987,820 0

1,055,231 0

1,127,283 0

1,204,298 0

1,282,206 0

1,362,520 40,242 1,400,898 72,061 1,407,598 222,077 1,267,893 249,079 1,095,667 257,192 907,370 111,847 852,948 87,715 819,565 85,786 786,321 86,692 749,876 85,194 712,987 99,196 659,866 49,853 652,926 Notes

[1] Funding amounts are based on site-specific cost estimates in 1997$ (see Attaciment 1-B)

-C ANO Report Entergy Arkansas, Inc ANO Decommissioning Model Unit 2 Summary

($000)

Line No Year Non-Tax Qualified Trust Revenue Net Trust Rqmt [11 Additions Balance Deferred Tax Bal 1

Beginning Balance 2

2003 3

2004 4

2005 5

2006 6

2007 7

2008 8

2009 9

2010 10 2011 11 2012 12 2013 13 2014 14 2015 15 2016 16 2017 17 2018 18 2019 19 2020 20 2021 21 2022 22 2023 23 2024 24 2025 25 2026 838 899 962 995 1,043 1,100 1,171 1,249 1,344 1,428 1,708 1,749 1,885 1,937 1,925 1,918 1,592 0

0 0

0 0

0 0

12,426 13,264 14,164 15,126 16.121 17,164 18,264 19,436 20,684 22.029 23,457 25,164 26,913 28,798 30,736 32,661 28,156 0

0 0

0 0

0 0

0 4,240 4.240 4,240 4,240 4,240 4,240 4.240 4,240 4,240 4,240 4,240 4,240 4,240 4,240 4,240 4,240 0

0 0

0 0

0 0

0 0

Tax Qualified Trust Net Trust Decomm Additions Balance Expend 129,752 8,582 138,334 0

9,308 147,642 0

10,669 158,311 0

11,507 169,817 0

12,099 181,916 0

12,849 194,765 0

13,677 208,442 0

14,596 223,039 0

15,712 238,751 0

16,796 255,547 0

19,250 274,796 0

20,530 295,327 0

22,372 317,698 0

23,640 341,338 0

23,845 365.184 0

24,003 389,187 10,664 24,619 350,448 93,105 22,311 260,450 112,309 16,683 158,264 118,869 10,097 41,274 127,087 2,639 (88,817) 132,730 (5,812)

(179,653) 85,023 (11,830)

(249,711) 58.229 (16,882)

(336,608) 70,015 Decomm Fund Balance 146,418 155,838 166,045 177,676 190,178 203,320 217,269 232,118 247,963 265,020 283,244 304,201 326,480 350,737 376,314 402,085 417,343 350,448 260,450 158,264 41,274 (88,817)

(179,653)

(249,711)

(336,608)

Notes:

[1] Funding amounts are based on site-specific cost estmates In 1997$ (see Attachment 1 -B).

-C ANO Report Entergy Arkansas, Inc AND Decommissioning Model Fees and Miscellaneous Input Data Fees r1l TQ Annual Fee NTO Annual Fee

($000) 7 376 3 688 Trustee Fees TO Investment Manager NTQ Investment Manager Adder ($000)

Breakpoints ($00 Basis Points Fixed Cumulative 0

100 0

20 00 5,333 19 00 10 666 10 666 10,000 16 50 8 867 19 533 10,667 15 00 1.101 20 634 13,333 13 50 3 999 24 633 25,000 8 50 15 750 40 383 0

J 1000 5,333 8 00 5 333 5 333 10,667 5 00 4 267 9 600 13,333 2 00 1.333 10 933 Miscellaneous Input Data Arkansas Retail Bad Debt Rate [1]

0 3032%

Composite Tax Rate 39 23%

Cost Estimate Year [2]

1997 TO Fund Federal Tax Rate 20 00%

Retail Allocation Factor 13]

0 8613 End Date - ANO 1 5120/2034 Wholesale Allocation Factor [4]

01387 End Date -ANO 2 7/17/2018 Nuclear Cost Escalator 15]

CPIU Notes

[1] Five-year (1997 through 2001) average

[2] Year upon which the decommissioning cost estimate is based 13] Production demand allocator for retail approved in Docket No 96-360-U.

[4] Wholesale allocation factor equals 1 minus the Retail Allocation Factor

[5] Nuclear Cost Escalator is based on CPIU The average annual CPIU for Unit I is 3 06%

(foryears2002-2045) and for Unit2 is3.1% (foryears 2002-2026)

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

March 31, 2003 Grand Gulf Nuclear Station Minimum Reporting Requirements as Per 10 CFR 50.75f)(1):

1. Decommissioning funds estimated pursuant to 10 CFR 50.75(b) and (c) (2002$)

System Energy Resources, Inc. ("System Energy") 90% ownership/leasehold interest.

South Mississippi Electric Power Association ("SMEPA") 10% ownership interest.

Total

2. Market value of funds accumulated as of December 31, 2002 System Energy 90% ownership/leasehold interest-SMEPA 10% ownership interest Total

3. Current schedule of annual amounts remaining to be collected, System Energy 90% ownership/leasehold interest SMEPA 10% ownership interest:

606,152,565 '

67,350,285 1 673,502,850 136,465,867 2 10,021 000 2 146,486,867 See Attachment 2-C See Attachment 2-D 4 Assumed rate of decommissioning cost escalation used in funding projections (Attachment 2-C)

System Energy 90% ownership/leasehold interest SMEPA 10% ownership interest 5 50%

4 00%

5 Assumed average after-tax rates of earnings used in funding projections System Energy 90% ownership/leasehold interest SMEPA 10% ownership interest:

6 74% 5 See Attachment 2-D 6 Assumed rates of other factors used in funding projections System Energy 90% ownership/leasehold interest SMEPA 10% ownership Interest:

See Attachment 2-C 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, 2001 filing (external sinking fund):

None 9 Material changes to trust agreements since March 31, 2001 filing.

System Energy 90% ownership/leasehold interest SMEPA 10% ownership interest.

None None Supplemental Information:

1. Site-Specific cost estimate escalated to 2002 (1993 Base Year Dollars)

System Energy 90% ownership/leasehold interest.

NRC License Termination Cost.

Non-NRC License Termination Cost Total SMEPA 10% ownership interest NRC License Termination Cost.

Non-NRC License Termination Cost.

Total 527,566,010 3 24,715,435 3 552,281,444 51,530,246 3 2,414,091 3 53,944,337 GGNS Report Report on Status of Decommissioning Funding Required by 10 CFR 50.75(0(1)

March 31, 2003 Grand Gulf Nuclear Station 2 Decommissioning method assumed for planning purposes in site-specific estimate DECON

3. Year site-specific estimate complete.

1994 4 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, 2002 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 (Bainwell, South Carolina) 4 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 $24 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.

5 Assumed weighted average after-tax earnings rate for the non-qualified and tax qualified decommissioning funds for the period 2002-2031.

-A GGNS Report GRAND GULF NUCLEAR STATION CALCULATION OF MINIMUM AMOUNT AS PER 10CFR 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: Barnwell, South Carolina IOCFR50.75(c)(2) Escalation Factor Formula:

0 65(L) + 0.13(E) + 0 22(B)

L=Labor (South)

E=Energy (BWR)

B=Waste Burial (BWR)

BWR Escalation Factor:

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

1986 BWR Base Year $ Escalated:

$135,000,000

• Escalation Factor =

Factor 1.794 1 1.135 2 16.705 3 v 4.98891 l $ 673,502,850 System Energy interest (90%):

SMEPA interest (10%)

Total

$ 606,152,565 4

$ 67,350,285 5

$ 673,502,850 1 Source Bureau of Labor Statistics series report id ecu13202i (January 2003) 2 Source Bureau of Labor Statistics series report id wpu0543 and wpu0573 (January 2003) 3Source Nuclear Regulatory Commission.Table2 1 of"Report on Waste Burial Charges", NUREG-1307revision 1O(October 2002) 4Appiication 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 =

$ 396,455,831 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 =

44,050,648

-B GGNS Report GRAND GULF NUCLEAR STATION CALCULATION OF SITE-SPECIFIC COST ESTIMATE ESCALATED TO 2002 DOLLARS Site-Specific Cost Estimate (1993$)

Site-Specific Cost Estimate (1993$):

NRC License Termination Cost Non-NRC License Termination Cost:

Total Site-Specific Cost Estimate:

System Energy (90% Interest) 1 325,840,205 15,264,976 341,105,180 SIMEPA (10% Interest) 2 36,204,467 1,696,108 37,900,576 Total Estimate 362,044,672 16,961,084 379,005,756 Annual Escalation Factor:

Years of Escalation (1993 Base Year to 2002)

Cumulabve Factor (1 + Factor)A9:

550% 1 9

1.62 4.00% 2 9

1.42 Site-Specific Cost Estimate (2002$):

NRC License Termination Cost

• Cumulative Factor Non-NRC License Termination Cost.

• Cumulabve Factor Total Site-Specific Cost Estimate:

527,566,010 24,715,435 l $

552,281,444 51,530,246 2,414,091 53,944,337 579,096,255 27,129,526 606,225,781 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.

-C GGNS Report 1 of 2 System Energy Resources, Inc Grand Gulf Decommissioning Model Owned Portion Summary

($000)

Decommissioning Fund Balances Line No 1

2 3

4 5

6 7

8 9

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 Revenue Non-Tax Year Rqmt Qualified (2)

Beginning Balance 486 1995 6,813 616 1996 11,195 818 1997 11,195 1,033 1998 11,195 1,261 1999 11.195 1,503 2000 11,195 1,760 2001 13,624 2,068 2002 13,624 2,395 2003 13,624 2,743 2004 13,624 3,111 2005 13,624 3,502 2006 16,590 3,961 2007 16,590 4,448 2008 16,590 4,965 2009 16,590 5,514 2010 16,590 6,097 2011 20,184 6,768 2012 20,184 7,480 2013 20,184 8,236 2014 20,184 9,038 2015 20,184 9,592 2016 24,550 10,180 2017 24,550 10,804 2018 24,550 11,467 2019 24,550 12,170 2020 24,550 12,916 2021 29,878 13,708 2022 17,429 0

2023 0

0 2024 0

0 2025 0

0 2026 0

0 2027 0

0 2028 0

0 2029 0

0 2030 0

0 2031 0

0 Tax Qualified (2) 25,920 34,579 48,282 62,907 78,517 95,178 112,961 134,415 157,314 181,755 207,842 235,685 268,423 303.367 340,663 380,471 422,959 471,967 524,275 580,106 639,696 703,597 776,311 853,921 936,757 1,025,171 1,119,538 1,225,765 1,303,048 1,305,389 1,140,563 951,474 732,399 482.996 203,197 86,632 6,095 0

Total 26,406 35,195 49,100 63,940 79,778 96,681 114,721 136,483 159,710 184,498 210,953 239,187 272,385 307,815 345,628 385,985 429,055 478,735 531,755 588,342 648,734 713,189 786,491 864,725 948,224 1,037,341 1,132,454 1,239,473 1,303,048 1,305,389 1,140,563 951,474 732,399 482,996 203,197 86,632 6,095 0

Decomm Expend (1) 0 0

0 0

0 0

0 0

0 0

0 a

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 37,784 85,375 252,699 265,864 283.117 298,693 312,296 130,222 86,344 6,491 Notes

1) Nudearcostescalatoris 55% peryear.

2) Assumed weighted average after-tax earnings rate is 6 74%

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

Grand Gulf Decommissioning Model Leased Portion Summary

($000)

Decommissioning Fund Balances Line No 1

2 3

4 S

6 7

8 9

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 Revenue Year Rqmt Beginning Balance 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 1,208 1,997 1,997 1,997 1,997 1,997 2,431 2,431 2,431 2,431 2,431 2,960 2,960 2,960 2,960 2.960 3,601 3,601 3,601 3,601 2,101 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 Non-Tax Qualified (2) 81 104 139 177 217 259 304 359 416 477 542 611 692 777 868 965 1,067 1,186 1,311 1,444 1,586 1,683 1,786 1,895 2,011 2,134 2,265 2,403 0

0 0

0 0

0 0

0 0

0 Tax Decomm Qualified (2) 4,578 6,104 8,534 11,123 13,886 16,833 19,978 23,774 27,825 32,148 36,762 41,688 47,483 53,669 60,272 67,319 74,840 83,521 92,787 102,676 113,231 123,000 131,257 140,069 149,475 159,515 170,230 181,667 190,893 191,222 167,078 139,382 107,294 70,766 29,786 12,701 896 0

Total 4,659 6,208 8,673 11,300 14,103 17,093 20,282 24,133 28,241 32,625 37,305 42,298 48,175 54.446 61,140 68,284 75,908 84,707 94,098 104,120 114,817 124,683 133,043 141,964 151,486 161,649 172,495 184,070 190,893 191.222 167,078 139,382 107,294 70,766 29,786 12,701 896 0

Expend (1) 0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 5,531 12,499 36,994 38,921 41,447 43,727 45,719 19,064 12,640 950 Notes

1) Nuclear cost escalator Is 5 5% per year

2) Assumed weighted average after-tax earnings rate is 6 74%

1Aul

+/- +/-%L oL J

3DUAU lo UUZ GGDecomModRO102 1-17-03 -D GGNS Report SMEPA'S EXTERNAL TRUST FOR DECOMMISSIONING GRAND GULF

$ in OOOs Yeai 1 999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 201£ 2020 2021 2022 2023 202A Updated F Cumulative EOY Market r

Value NA NA NA 10,021 12,126 14,441 16,987 19,788 22,870 26,259 29,988 34,089 38,600 43,563 49,022 55,026 61,631 68,897 76,889 85,681 95,351 105,989 117,690 130,562 144,721 160,295

'roforna Plan 10% ROI Value Current Current Current Year Year Year Contrib'n Eamings Change NA NA NA NA NA NA NA NA NA NA NA 10,021 1,050 1,055 2,105 1,050 1,265 2,315 1,050 1,497 2,547 1,050 1,751 2,801 1,050 2,031 3,081 1,050 2,339 3,389 1,050 2,678 3,728 1,050 3,051 4,101 1,050 3,461 4,511 1,050 3,913 4,963 1,050 4,409 5,459 1,050 4,955 6,005 1,050 5,555 6,605 1,050 6,216 7,266 1,050 6,942 7,992 1,050 7,741 8,791 1,050 8,621 9,671 1,050 9,588 10,638 1,050 10,651 11,701 1,050 11,822 12,872 1,050 13,109 14,159 10 5014525 15,575 23,100 127,174 160,295 1999 Study SMEPA's 1 O%Liability Escalated at4 %

60,093 62,497 64,997 67,596 70,300 73,112 76,037 79,078 82,241 85,531 88,952 92,510 96,211 100,059 104,062 108,224 112,553 117,055 121,737 126,607 131,671 136,938 142,416 148,112 154,037 160,198 The 2002 cumulative market value is December 31 actual value.

I::

GGDecomlModRO102 1-17-03

-E GGNS Report Page 1 of 12 Im SERI Exhibit _RKG-3)

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

I 4GRAND GULF POWER CHARGE FORMULA 1

1i. 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; 6

and New Orleans Public Service Inc. (referred to hereafter, coiieciiveiy. as "PurchaseS'.

id 7

individually, as 'Purchaser'), for capacity and energy from the Grand Gulf Nuclear Station ('Grand 8

Guln) pursuant to the Unit Power Sales Agreement ("UPSA") between SERI and the Purchasers to 9

which this document is attached as Apperidix 1. The monthly charges for capacity ("Monthly Capacity 10 bharges") shall'be determiined ir accordance with the provisions of Sectior 2 befdm; the riointhlj-11 charges for fuel ('Monthly Fuel Charges") shall be determined in accordance with the provisions of

!2-Sect-.n. 3 Th,.:.

T..e

....Sy Cap-..; C.

,s an t*.

on**

ho Fo C h tx*

SC

-t.*.-nz I

13 accordance with the provisions of this PCF shall be billed to the Purchasers monthly in accordance

4.

with the provisions of Section 4 below.

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

Page 2 of 12 Appendix 1 Page 2 of 6 l1

• 2.

MONTHLY CAPACITY CHARGE 2

3 A. Monthly Capacity Charge Formula 4

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.

8 9

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

1.

of the Monthly Capacity-Charges prepared in accordance with the provisions set out in this Section 2.B.

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 period ending December 31 of the prior calendar year ("Test Year"). All data utilized Ien 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-apropnate *or applicable.

Each such informational filing shall include wor'cpapers supporting the data and calculations reflected in the redetermined Monthly Capacity 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.

_o-".

-1, GGNS Report Page 3 of 12 SERI Exhibit -

(RKG-3)

Page 3 of 12 Appendix I 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 2.8 If the FERC or the Purchasers should detect an error(s) in the application of the procedure set out in this Section 2.8, 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 wnting of such error(s).

-Ail 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 1 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.B, 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 effeEt until changed pursuant to 'ho prov'sions 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 on November 30, 1994 in FERC Docket No FA89-28 ('1994 FERC Settlement").

PI-

-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 intenm basis to reflect such tax rate increase.

Should such an intenm redetermination be made, all other parameters utilized in the determination Cf the then effetye 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.

-E GGNS Report Page 5 of 12 SERI Exhibit -

(RKG-3)

Page 5 of 12 Appendix I

Page 5 of 6 1

3.

MONTHLY FUEL CHARGE 2

3 A. Monthly Fuel Charge Formula 4

5 The Monthly Fuel Charge Formula, as set out in Attachment B, applied in accordance with the 6

procedures set out in Section 3.8 below shall determine the Monthly Fuel Charge which SERI 7

shall bill to each of the Purchasers.

8 B. Determination of Monthly Fuel Charge 9

10 Each month SERI shall determine the Monthly Fuel Charge applicable to each of the Purchasers, 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 out in Attachment E to fuel cost data for the immediately preceding month.

4--

4. BILLING SERI shall render a billing to each of the Purchasers each month for service provided dunng 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 be payable in immediately available funds on or before Ihe 15th day of such month. After the 151h 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 agent 1-E GGNS Report Page 6 of 12 SERI Exhibit_ (RKG-3)

Page 6 of 12 Appendix 1 Page 6 of 6 1

for SERI and the Purchasers, may prepare the necessary billings to the Purchasers and arrange for payment in accordance with the above requirements.

OM

5. EFFECTIVE DATE AND TERM 5

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 provisions of this PCF or applicable regulations or laws.

10

6. FORCE MAJEURE 11 12 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, including natural disaster, damage or loss of generating capacity, and orders or acts of civil or military 15 authonty. cause increased costs to SERI and result in a deficiency in revenues which is not readily L-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 B

in accordance with its regulations and applicable law governing such filings.

-E.

GGNS Report Page 7 of 12 SERI Exhibit -

(RKG-3)

Page 7 of 12 ATTACHMENT A Page 1 of 5 SYSTEM ENERGY RESOURCES, INC.

MONTHLY CAPACITY CHARGE FORMULA DETERMINATION OF MONTHLY CAPACITY CHARGES DESCRIPTION REFERENCE

____ -I CAPACITY REVENUE REQUIREMENT MONTHLY CAPACITY CHARGE FOR AP&L MONTHLY CAPACrTY CHARGE FOR LP&L MONTHLY CAPACITY CHARGE FOR MP&L MONTHLY CAPACITY CHARGE FOR NOPSI Page 3. Line 1 38% ' Une 1 1 12 14% ' Une 1 /12 33% ' Lwne 1/12 17% ' Une 1 1 12 I

r I

-E.

GGNS Report Page 8 of 12 SERI Exhibit _

(RKG-3)

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

MONTHLY CAPACITY CHARGE FORMULA DEVELOPMENT OF RATE BASE (1)

DESCRIPTION PLANT IN SERVICE ACCUMULATED DEPRECIATION & AMORTIZATION NET UTILITY PLANT NUCLEAR FUEL AMORTIZATION OF NUCLEAR FUEL MATERIALS & SUPPUES PREPAYMENTS DEFERREDREFUELING OUTAGE COSTS ACCUMULATED DEFERRED INCOME TAXES REFERENCE FERC Accounts 101.106 FERC Accounts 108. 111 (2)

Una 1 Plus Una 2 FERC Accounts 120 2-120 4 FERC Account 120 5 FERC Accounts 154. 163 FERC Account 185 FERC Account 174 -

FERC Accounts 190. 281. 282, 283 Sum of Unes 3 - 9 1.-

NOTES: --- -

(Fj

.o iEDI DrERigED AS AS A i 3 MOH -Ii AVERALGE iBALANCE ENDING WI I H VECEMIR OF THE TEST YEAR.

(2)

THE BALANCE FOR ACCUMULATED DEPRECIATION AND AMORTIZATION IS TO BE REDUCED BY ANY DECOMMISSIONING

,.RESERVE AND RESERVE FOR DISPOSAL OF NUCLEAR FUEL INCLUDED IN FERC ACCOUNTS 108 AND 111.

0 4 I; :

~

-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 TEST YEAR AMOUNT REFERENCE DESCRIPTION 4

6

.7 8

9 10 11 12 CAPACITY REVENUE REQUIREMENT OPERATION & MAINTENANCE EXPENSE (1)

DEPRECIATION EXPENSE DECOMMISSIONING EXPENSE (3)

AMORTIZATION EXPENSE TAXES OTHER THAN INCOME TAXES CURRENT STATE INCOME TAX CURRENT FEDERAL INCOME TAX PROVISION FOR DEFERRED INCOME TAX-STATE PROVISION FOR DEFERRED INCOME TAX-FEDERAL INVESTMENT TAX CREDIT-NET GAINSILOSSES ON DISPOSITION OF UTILITY PLANT UTILITY OPERATING EXPENSES UTILITY OPERATING INCOME VERIFICATION RATE BASE --

RATE OF RETURN ON RATE BASE COST OF CAPITAL I

Determnmed as deslibed In Note 2 below FERC Accounts 517. 519-525.525-532.

556.567. 560-573. 901-905. 920-931. 935 FERC Account 403-Exduding Decommsstorifl Expense FERC Account 403 FERC Accounts 404-407 FERC Account 408.1 Pigj 4.bLne 18 Page 4. Line 25 Stite Portion of FERC Accounts 410.1. 411.1 (4)

Federal Portion of FERC Accounts 410 1. 411.1 (4)

FERC Account 411.4 FERC Accounts 411.6. 411.7 iumwu-I Sum DI unies d. -

1s

+

+

i fl 1 iu n

Lune i minus unet 1J 4.i 15 16 17 18 Page 2. Une 10 Une 14 1 Une 16 (Must equal2 Ine 18)

Page 5. Une 18. Column D 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 DIVIDED BY THE RATE BASE (DETERMINED IN ACCORDANCE WITH PAGE 2) PRODUCES A RATE OF RETURN ON RATE BASE EQUAL TO THE COST OF CAPITAL (DETERMINED IN ACCORDANCE WITH PAGE 5).

3)

SHOULD THE FERC APPROVE A CHANGE IN SYSTEM ENERGY'S SCHEDULE OF ANNUAL DECOMMISSIONING 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)

-E GGNS Report Page 10 of 12 SERI Exhibit -

(RKG-3)

Page 10 of 12 ATTACHMENT A Paoe 4 of 5 SYSTEM ENERGY RESOURCES, INC.

MONTHLY CAPACITY CHARGE FORMULA DEVELOPMENT OF CURRENT INCOME TAX EXPENSE TEST LINE YEAR NO DESCRIPTION AMOUNT REFERENCE 1

2 3

4 5

6 7

8 9

10 11 t12-13 15 16 17 18 19 20 21 22 23 24 25 2T1 CAPACfTY REVENUE REQUIREMENT OPERATION & MAINTENANCE EXPENSE DEPRECIATION EXPENSE DECOMMISSIONING EXPENSE AMORTIZATION EXPENSE TAXES OTHER THAN INCOME NET INCOME BEFORE INCOME TAXES ADJUSTMENTS TO NET INCOME BEFORE INCOME TAX:

INTEREST SYNCHRONIZATION OTHER ADJUSTMENTS TOTAL ADJUSTMENTS TAXABLE INCOME Page 3. Une I Page 3. Une 2 Page 3. Line 3 Page 3. Line 4 Page 3. Line 5 Page 3. Line 6 Line 1- (Sum of Lines 24)

Rate Base (Page 2. Une 10)

Total Debt Rate (Page 5. Line 16)

See Note 1 Une 9 plus Lne 10 Lie'7plus uni1 '-

Une 12 SeeNote-1 Line 13 plus Line 14 Une 15

• Mississpp State Tax Rate(2)

See Note I COMPUTATION OF STATE INCOME TAX STATE TAXABLE INCOME BEFORE ADJUSTMENTS

..NET-ADJUSTMENT TO STATE-TAXABLE INCOME STATETAXAttLE itNG-c-STATE INCOME TAX BEFORE ADJUSTMENTS ADJUSTMENTS TO STATE TAX CURRENT STATE INCUML TAX ISum of Lines 16 - 17 COMPUTATION OF FEDERAL INCOME TAX FEDERAL TAXABLE INCOME BEFORE ADJUSTMENTS CURRENT STATE INCOME TAX DEDUCTION OTHER ADJUSTMENTS TO FEDERAL TAXABLE INCOME FEDERAL TAXABLE INCOME FEDERAL INCOME TAX BEFORE ADJUSTMENTS ADJUSTMENTS TO FEDERAL TAX.

Une 12 Une 18 (Shown as deduction)

See Note 1 Sum of Lines 19-21 Line 22 ' Federal Tax Rate(2)

See Note 1 Sum of Lines Z.1 -

-CURRENT FEDERAL INCUME iAX Sum of Lines 23 - 24

DTE

1)

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

2)

RATE IN EFFECT AT TIME OF ANNUAL REDETERMINATION FILING

-E GGNS Report Page 11 of 12 SERI Exhibit -

(RKG-3)

Page 11 of 12 ATTACHMENTA Page 5 of 5 1). -LONGTERM DEBT-SHALL INCLUDEALL ISSUES AND REFLECTTHE PRINCIPAL AMOUNT. NE.OF: 1) UNAMORTIZED DEBT-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 SERI'S 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 WITH 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)

CAPITALIZATION 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

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

Page 12 of 12 ATTACHMENT B

Attachmcnt 2f GGNS Rcport Pagc I of 15 OfSeor or 5ttl

, Dket: iNo.

OZ39-678-000, EL90-16-000, and EL9o-4s-coo ApPPErl F

Sc~ond Rcvisc4 Sheet System Ewiy RAox s. Inca Rate Sdhcdule MRC No. 2 PUBLIC USnErS REaOV1NG SEaVIC IMM Pj6TF*SCHE xTJ Arkansas Powcr & aUght CDpany L=Isianz Power & sight Company

?VVIIaippl Powa & Light CSplay New Orleans Public Savice Inc.

s--

_ _ PROMMED I ATE sCjjmLR Wholesalc Salt of ElmCia Power v

-F GGNS Reporr Pdge 2 of iS Seccri~

Revised She-.:

Unit Eowzz qaIA3 At~rneten THIS AGREEMENT, made, cn,.crrd into, and e~ffectivc ts of this 10th day of June.

19M2 by and among Azktnsas Po*wer & Light Company (AP&L"), L~ouisiain Powet & Light Ceepany (-U.&1"). Mississippi Powu' & light Coin;aay CW&LU), New Orleans Public S-ervict Inc.. (NOPSI-) and Middle Sotith Energy, Inc.M~)*

147LNESSETM TiIAT:

WNERE-AS, MSEw wis incorpoatzed on ftbnuxy 11, 1974 under th;. laws of the State of rka~nsas to ow-n cerAin f~umm gencr=1 capacity for te Middle Sou~th System. of which AM&, LP&L, MP&L and NO'S I ('System Companie") az mccmbar and WHER7.AS, System Envrgy has'aeordi1ey und~aluo dhe owr~rship and Aniaicing of nuclwtea-olcd cdl~cgr~ncraiz~g stadion an ;he cast back of dwe MLstissippi Rivo nw Ponr Glbso, Mississippi (7rajecC); and WHEREAS. the System Companics own~ Lad opm elec-mic genmcing, transmiuzion and dsrisbvrion facildos in Arkaru~n, L,6iiaia NrisstW* trAz Mtsocil and zceemwe. nwnmit and sell electric energy both at mmfui and wholssalec In s~b -s; amd WHERF.AS, Syustm Enegy has agreed to sell to AP&L.4LP&L, MP&L Wn NOPS I

(-Pwrhagsre") specified pcre*rnm et of all of the eapteiry ard eunergy IvaiUba to S yst Eoegy fromn the Project. anid the System Cc~paries have apead io joIn with System Energ, be(fe tie dute Unit I of the Project is placed Ln servce, in execuudng in &Zz=mCnt Which wil sc? forth In detall the tem~s and condidions for the sale of such cipacity and eergy by System Eztsgy to the System Companies: and of 19S3; WEESUntIi xetdwt-paeineneilopertoni the fr~st quarte NOW, THEORE,0 Symim Energy &Ad the System Companies mnutualy unde.-snd AMagdmve as follows:

Artachinent 2-P GGNS Report Paci! 3 o[l5 Second Rcvisc4 Shc.~g 1.1 System~ Enerjy shill. subjew to the tcmu and eondltdons of this A PWemnL maLke Li-41able, or causc to bc mi& available, to the Pcruenis~ Ill of the capa an ng hc hl be avsilzble to Symtm EzaeWr a the Proj=c. fzCludIi~ test CnOzy PrOduc~C4 during tho co=-se. of thce oitructioe and tesding of Urilt 1and Unit2 of the Piject ('Powee)..

1.2 The PI~hxsc shall subject to the tezms azd condidoits of fth Aecrnent, bc endted to raeihe I o he PwtwihSWb zhl toSysem EnaU at the Projec IA acconiavwa with their rctpective Endilemet Pa~etagel. The Edmen~t rentaps AM as EAndiement Prc~erntges Unit N4o. I Ui o A.P&L 6

1LP&L 14%

MP&L.

33%

NOPSI 17%

100%

1.3 Co mm.cing with the aeria of (a) tho data at cwmmerci opemdon of each Unit or (b) Deeernber 31, 199 4 (with resp= to Unit 1)orD~ember 3 It 1988 (withiuee to U~nit2) &ad, tmpecdvelY condzinuinj mOnthIv thre&Waft und this Ag7remet is tccg o

Proyisons of Soccicn 9hereof. in Consideraton of the right to receive its rzd~ein~

such Power fro each Urnh, Mah P~lrchr Wil pay SytMM Ec~ya=

~uneua os Pu~huasr' Enddtement Pmrentage muldPlied by ystem Energ' oICs f evc o ie Unit for such month.

The "TOWI Cost Of S=ctcc for =ah Unit for any month shall be the sum of (a) System~

Ezergy's OPeradn ltxPenss for SUCh nIO!Ith for such Unit, plus (b an amount equul to one-rimlift of the Coraosite PFerCetag; muldpl~ed by the Net Unit Invts=n for such Unit.

7ERC" s& m=th Fve F.g cgla =y, C~iission (or usny succcsso r govm-rnmenua authqrity).

Unifoin System shall Mme the Uniform System of Accounts prescribed by the FEIRC fro Major PubIiC Ut~ttles and Llcensees, us from dme wo dme in cfrecT.

Ad r

• I

tNnz.

-j GGN'S Report offer-Of Settlement, Docket !Jo3. eR89-678-000, fI EL90-16-Ooo, and EL90-45-4oQ APPEN~DIX C ThL-d Rcviscd Shc~cr SYSytIM EnergY's "Operazing apen.tes' shall include, wit nspect to eac Unit.

il Ofunt't ~tP&ory CWzZeabio-tO SYtMM EneWg's S oPrM=g 6XPes ACCOunCs, less 8any applicable Credit IhCrCM in Iccordacc With the Unifomi System; it beinig underod that for purposes af tis A&Te~cmnt 'OPdtng Ex Aensee shall LntuWo (but nor Umi tod ) (a) dcprociation aQrucdS at a rare it Izt= s ficent to fuUy unord= the non-salvagu~ble. pL&An Iinve~s~ent. including the cost of removal of inmcrim mdce icits, oycr thg c~dmatd then ftrnazinirtg uscful Ufe of rho uz~it (b) obflgadans ihcuwie4 In conicecdon with die leasing of fuel InversotM and/or umortization of fuel bu=4-CC) a~Cnr*1S tO any escZ-vc-tbibc ySse Ezncpy1~proMd for decouimIszioning the unit oVer the esimautcd then reainaning uel f:oft ni, (d)ac&Ufor disposal of wpent ngelcai fuel.

"Not Unit lnucm.n~ri" for Lay month shOl be Compwtd as of the lart day of tho previbous month and shall consist with mreapc o each Unit. of C') the sgeate~

amioqw properly chaz'able mlt he drn* in accordance Vdth the TUnfrm, SYst= in SyMVc Inf sutflity ilail aeCounis (including, but not limited to, (i) casrrnc~oa work In progcwu, 1M IG 9xtant Zowed by the ME1C.

related w each IVnit after its respective Cormmeretal 0Op-trno~ date, and (Ii) outuaw fuel accounts other than suclear ful In procass of fabricadon), less the balanes, at the time of any accumultued proisle fr apr~Iaon ndAmmr'dzatg of udu1it' plant (excluive of any, dec -misslosing nctv),

ic~uo~g nrtiatin of the cost of Znucar fuel (eaclusive of mny res&ve for disposal of nueur uel. a deermnedin a conb=o with the uniform Systm: plus (b) the awgegaze zamount property cbargcable at the time in accord&=c with the Umifonn Systern to Acemnu rpr~en~fg mar&Ll and supplier plus (c) such rasonable allowanc for pripaid. ltsz and cash working capital as may fromf time to time be deterntined by System Eneixy plu3 (4) recoverable income taxes to the extant previowsly crtdited to udiliry plant accounts lmd not yets realized excluding arnounts Meated to consduction work in progress that are not InldedL ntunit investment. but that sm included in the allowincs for funds used during construction eomputatioN~ s-nd lws (e) acctmulzted pro*-iSion for deferred income taxes and less (1) other deferridd credits.

'Compozite Puicntigc' for any month shall be that ccmputcd as of the lair day of fth prev'ious month C'compuradioo date') Composite Patzzit Ls of a compuutaon. date shall be the sum of (a) thir'tma pesent (13%) multpie byter0 w Eqit Xwcstmncr as of such date, is to the. Total Capital as of nuch dLate; plus (b) ft 'cf civ nezczrt r annum of each pricipl anosr f ~

(oerthan loans or advuztces made by she commo ckholdej of Sytmm Eiergy oustadin onsuh date for money borrowei., muldplid, by the. ratio which such principal amout isto Ttal a sia of such date; plus (c) the Wfoacuyc dividend ragteM pj-r annum -of ic seres f pefc~d toc otstading IaS Of~uch date muldiplied by the

Attachmnent2-P GGNS Report Page 5 of 15

-4.

ratio which the a.mount at which such prefTcmd sM~k would be rrflwtcc on a balsncz sheet of System Energy is to Total Capual as of iuch dauz. The 'e ffattv inwu=U ra 0or ea~priJ.-ip amount of dibt nfesred to iA clause (b will cflcc the uinnual intars requirctnepts t

cxtapp1Icble, Amrntzldon of Issue expenscz. dlSco~ur and prwwdumns, sl~king fd call prnijurns eXpcns*$ add discOunts, Mtfundiag and retirmment cxpnses, discounts and premiums, and all ofthe expenses applicabLe to fth Isuo of such Inbtdci1noss. The Oeffecdvv dividen4 rac of~

eah sci*s of prefeffed scmk rfczd to in CIA=~s (e) Will mflzct the anual dividend roquiremernt applrnable to cch su.ch sacs of rtpnca-d szxLk "Equity Inv==en" tis of any datb shal consis of the sum of it) aM wiowun Lhe"Wrfa.s paid to Syr=er ienrgy for a1 coawtoa cqpiml stock thcreowfot Lsued plus all =,pizzl-connibuwnsn, sdvaji" or pro r= loans punmaai to any ftpiWa coaw4budon ar uumen; less the sum of any uno~un paid by Systen Energ to Its Oommon stockhokia in the st1MofC~k retmni ftp wh1:§4 cc z mptloae, mmum of caplul or tepsyments of audh zdvances or loans;.

plus (b) any &balance 0) 'mthe i ncptlu u bde ne i)cd()i h mutancd vnwings account 6ft the =

a tysu Encrgy as of such dime 76W~ C7apital' as of any duze shall be iLia Equity Ensm~enL plus the towa of the amOwnt which would be rflecie on a balanc shee of System Enrgy fot all other seicutnnes, debt

.nd pneferd stock then ouuunding.

PrIar to the evlctr of Ca) the date of cornrereial op~adon of each UtiIt or (b) D~mnber 31, 1984 (with rcspec to Unit 1) orDecetbcr 3 1, 1988 (with rtspect to Unit 2), fth Puchtual shall pay System En1erzy monthly in zeccordpece with thcir icspec ve Endtlencnt Pueziasez for any Powtr dclivezd to thern frome each such Unt hmzunder at a rate equAl to the incmmental. cOM of' eniergy displaced by such Power on the N~ddle South System.

2. The pesformanes of the obUptioas of System EneWg huundukr shall be suBjeq to th~

rcPiand ccntnu eedfcttecso l uhcz~n f oeieu itn u~ie at th nc essary to it S Mer Thiuy ptformis ues d obUgzons cuunder.

incluzdin the rMcdpt a cmtinued effctiveness o lazzizoos by govaefitaJ rtulsamoy authot1icz at the tim nes to- ~

it mhe copletdio by System Energy of the conseuc~on of' the Project, the Opczra a or the r4jct n for Sys=e Eaergy to make avallable to fte P haser

.31 of the Power avai1able to Syc E eryat the Prjc= Symtm Energy shall use its best tfforts to secure and malntalin all zuc zrhiaoz by gpv==nuntai megulay authodecs.

A uich me nx GGNb R.2porL rPage 6 ofri FIz; Revised Shecc

3. Systern Energy shall op~tw and mdtain~a thc Proj=c in accordarcc with goo~d utility II= Mce OuMPgS for insPc4cn, MMazroAnct, rfucling. rMpziis Wn repLaceents shall be Mcheulod In ac~rancz ;with good u1lzy pra~dcc.r andixfaz. a paucdcab.1., shall, be =utu-ally Agreed to by Syscm Energy and the Purchuzet

4. Delivcry of Power sold to the Parehuearl purmant to this Apgzument shall occur at the Projcct's :tcp-up uruzsfonrse and shal be mad% in the f(m of thtem-phim, tivy he=t alleeatang CM=itrns a nomiftil volute of 500 kilovolts. Sun am MU sup~y and mairnain all rccuuay fnme~n equipmnent for deserrnlnag the quantit and Ioem of vay andar Nhs Agreement. System ncryr will hun~ish to thc Pmhauicn surch swnmmares; of mnetar re~adings vAt adscr me=u inorm aton as May rmasonzbly be recusicd issud bS.

Monthl!y bills caleulacod In accordance witb the provisions of Saction 1.3 shafll be.

isu y System Enetgy on the. fifth worlInS day of each month wid. shall be, payable in immedlirely zvaible fundi on or befon. the 15th day o(such month. Afte die 15th day, Inumt~

shial &=vc on any balance; due ut the rate requilred for jefwvd on~ere4 piurrmt to FR Regulations under the Federal Power AcL or iny other ter or condi don of this Apmexacnt under Section 205 of the Fedctal Pew= Act ad PUWtuz to FE.RC Rules and Regulations pmroulptod thereundar.

7. No Purc-hascr shoall be entitled toset off agains: any paen~c zuqqirz4 to bo rnade by i under this Agreement. (a) any anourits owedby System Energ toany Puxhascr or (b) the umount of any clam by any Pu~rchascr zgulnsx Sys=e Enegy. Th. tortgouig. ha-paevr, shall ntte affact in any other way the righus and runiedcs of any Ptmhaser wish res~pe to winy such Uaouznu ow-ed to any Prvhas= by Systcm Encrly or *ny suct claim by Lny Flnrhass apmais S ymt S. The ivlX' ard uneaforceabilisy of any ptovisiou of this Apgnient shiall not ff~ect the remaining pronisions hcr~.f.

9. This Age~rnent shall contiue undl twuttnated by munWi agreement of a11 parsies

berzto,

Attachmenet GGNS Rcporr Plnge'7 of 1 5 Second Rcvised Sheet I0. This Agcrmcnt shall be bindIng upon sbe pus hezcso and cheir succssof3 ad Assigns. but no aszipent hbere, or of any right to any fhe P due or to bsdotio due uS=r Ind Agremcn, sha hn y even: rliecei any or Systo CMy of eay of thefr rspevc obligaions hc=Un4, Or, in the CasM of the Pwchascrs duce to any ecznt their ealesnent to receive all of the Power avalabke to Systm Energy frmu dMe to time a the Project I 1. The Agreemcnts hemin set forth hvc been mra for the benefit of the purezues and Sys=m Ena=y and dweIr rezpcdve xsuson ad assIgns nd C other person shaM uquire or have any right under or by vice ofthis AgmemenL

12. The Pu cs and System Engy nry, Iubjc s tOh CprovsioMs ofifs AV c=n m, caw Law a (wkr a*&v cat orentor aeCmtns bewcea K

haca and SysMcM nEr;y. :ctring forh caiied W=

na nlnadg to Ohd pform&n by the ad Sysum Enwa of thWfr sipdsve or th ApecmcnL No asea ten tren into Under this Sction 12 shall, howe-r, palo to any subs mndve de ee the oblons of ay paM to this Atreement In zay manner ;rzcr nr wi nay of tho foeagIng sadoc ofthIs

13. FACh of the Parhasers shW,u as ny tim~e &ad fi= imc to dmc, be enttlcd to assign III of It igt, ntide and intes in ld to all of ffi pwer 10 whIch ny of thm shll be tnddc under this Apemcnie but no Puchasw

thal, by such ip k sllyed of uy of it oblRtadons d duties under this Agrement except gh 2hep eris to Sys Energy, by or on behalf of such Purhaser, of the amon or OU hbobbgad to piy pusuant to thc tems of this Apement.

l WrrNUS W7MREOF, the paides hereto have caused thi Agreement to be duly executed as of the day azd year rzsS abovc wrten.

nT

.f GGNS Report Page E of Is Firs',

P~-l Sheurc ob.IDOLZ SZ-UTH ENERGY~,

N C I

-Y-by Jc XIrW QXLW~JS PUBLIC SERVICE :I4C.

Middle South tnergy, Inc. 's rama was changed to Systeut Entrgy' Rasourmt$, tflc.

("System EnetKY") Ont JulY 22. LOW6 I

iI-

Attachnicn: 2 F GGN'S Rtpnrt Page 9 of 15 Rut RCYind Shect Systam EaLrvy Rwltrcez, inc.

Billing Format r

7 T

' -1 Pros~"

I l

~

Attachmnont 2-F; GGNS Report Page 10 of 15 Fgurth Racisd Shact LY-zm NE~etay RESOUJ.

9.NC.

MOJ9 CRANDQIPN OPtLATION WENSE1 FUEL EXMSE (ACCOUNrt5)

S OTHIR OPZtATION WtIS S (ACCOUMTs sr.

5Is-25=. 5Sf. 157. Sd0-Sl,.~Ot4OC, I0-ft>,_

MALKTUANC& ItXS"qS (,CCOUNTS s23-5n2 16-573. 9S)*

D'R1CLAM1ON z

COUN

) -

SCXEDULU A DECOMMSICNIHO UXP>ESE (ACCOUWT 40) it AMORTZATION EXPUN S1S (ACCOUtNTS 404-0) rAXES OTHR TXAN INCOME TAM3 (ACCOtJt

43. 1)

TXI - flNCOM{S (ACCQU<tS 4CS.I. 409.5. 410.,

411.1. 41.L)

QANrSsIVJ P=RO 0153PmOII OF =1LIrr LAN (A=CCOUNS 41 l,6-dl, I TOTAL CPERA7N1G W SES S

ADjVST?

T OF PxroR 3Utc1 0WMULK -

oPERTINQ EXENSXS AS JUL=.

S oP&RArnNc XtPNstI ACTJAL

_N 11 ThE ?MONTHLY DECOM1.$SIOONLG ;XP0NXSt FOR GRA.D GULP UNIT 1 13 1I ACCORWANCI wrrx PruC 2TTLT AX T. ?tH MoloUN VAY - LACH YEA UBA$Ez 0

)

tH APPROVED ECOMMISSJORINO SCHEDULE.

At-.achmcrnt2 GGNS R-eport Pane 1I of 15 S;ix~h Rcyised Sbac SYSTEMA RNSROY RESOMFCES, INC.

SCHEDUL A

DZPRaClATTQH-EXFENS;-

MPONTML t99>

? LANT FUCTION' MUCLSAK PLANT (AcCOUNT 1011 DrCpREAxLe PLANT EP7ZCTry ACCRUJAL NALANCEZ LRAMf I,

. 52.3 DE7J%*=7lOH EXVN22 S

TRA4MJS&IMO PLANT CfjENP.L PLANT OPFFC EQUIPMENT (ACCOUNT? 101)

S 2usi S

I 3 S

LIS %

TZAN*OKIATIQ?'

LQUTVi4EIT (AcCQNT 101)

I L&S%

s TTAL s

v uFtFCTIVEJANUARY 1, 1fl7 h

I 1

Attachmra 2-GGNS Repurn Page 12 of 15 Third Ravi:,c Sh SYSTEM ENMY RESOUCESJ99L.l SLCi=ul Palo I.CZ RCOMOm(o PEiRCENTAGE tMErrr PtANT tN SESDVtC (ACCOUNTS 101. 104, 2c.2-120.4)

LUSL ACCUMULATED PROVISION FOR CUREICIATON/

AMORT1ZATION (ACCOUNTS 101. 111, 120.)

(EKCjCLVUS OF ANY VECOMZSSIONItNO PEStAVt AND ANY X1SMVI FOR DISPOZA.

OF NUCLm FUL)

X1T UTtLITY PLANT IN SERVICt WCO~tJ2y~ CAPITAL MATLVAL & SUPPt..

(ACCOUNT 1S,4 163)

PKPAWYDS (ACCOUNT 165 - KXCLUDt14C PROAZD nmxS WORXIX4 CAPITAL ALLOWACIE TOTAL WOWLING CAJITAL RI&OI LACCOEflT 146)

OT7f DETE3o CEkDIts t(ACGQtZ4? TIi - SAL AND LWIESACI OF A PORTION OP OXAND CULF UNrI n)

&=MUJLATI PROVIS1ON FOR DEFEIRREO rINCrM TAX tCCeOUNT3 JEO, M.

)

NET UNIT INvESTr1N?

URUN A; COMMO=IT1 Pr.CXNTACX (SCII. 121 x NET UNIT INVESTMENT DIVIDW BY 12 S

a1 I/

5 I1 5

It S

S 7A 5

t I

It I

It It CALCL^AII g" MEVWO31 cOT WA1A=

v 41*~CK?

A^IM. 3V" WrJqC^iAL A44WAt I LT ULU Di ACV%5.d WMi rft MAC MWTACA=WtN.

11 IQALutxs A ll i.Vm n1CRer r Lv'TuhLI? Co AC3ttTM 3WflV atFM X. I MMl C.

L.

CMT, 41

~t* Wt4 %I-.Ct UN A 4??=

MUA A-WAXAM041MAJ A ca To m um 4I4.bt9%.ATA OY G

• M PU ICtV02W irog tIn,.

CT

GGNS Rcport Page 13 of 15 Fowjh Itgevid She*%

SY$m tNEXQR REBSO=.RCtSgNC.

INC.

P.1.12.-

RETnJ ON NJET U

-R^

n NTANO COMSta h CEyrAGE CAIAJrZaON AMOUNT Cr.

RA=

RATE.

comPmror D01T (ACOUNTS 131.

119. 21.

Al AIIA CAIIM)0%

2'. us, 23 i)

PMUERD ITCO (ACCOUNTI 204.

AZ P1 (A2/AA)?%

iQs. m comMosiqurry (ACCOUNTS 201.202.

AJ ASI4 Cs (AYM)CU 29, 2l-AILI)A1 TOTAL CAPIALIATIN Ad

~s_-*

"¶ItLU Wti1S:

WHEM O

IS WECHT10 AVERAGE 01ar RJ.TI WCUIDrNo SHOWR TLXM DEST TO THE ZXTSl4 HOT UTIUZM IN APUDC CAL4ULAT10N.

p uI WUCOKTRI AVtIRACZ 'ftvuaz9 STocK DIUVzD&R RATL C

iS 15 PTJR.N ON COMMONf ZquITY. if ii tPFFITV APPIL 2. 1M

.ql A r.r.,-

^f1

Attachmenet2F GGNS Report Page 14 of 15 SOegfl4 Ruvis.J Shoes PACE I OF Z INCOME A

1LMjSNS

?0TM. lacy 09MUam TAX MUMVINA

• ?wAL JIM"am Mr uki'l 001MM" eAm "Oftsit 4A-~

tEy VAN ~

ea OPOIA"4 PM FMOM CWIxr~,

ste i06 A

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"d 1 v.4, Ag...tk wpb-AA" vw *IM 4St'AA UK

A~tachimnct 2.9 GONS RePOrt palte 15 of lb Second RtvjiS4 Sh~eet (Con&zua4)

EioQ1uLu Pugap 2

o 15rEPAte o4COPATA&X L"JWS)J CP rTNC, fA]

ATIOW1 DEFnWIATION OF AJIUDC TAX BASIS OF uNIT It TAW~ CA ItTALrZED PEk BOOKS NCT OF T&ST ENtRCY (ACCUNtrS -OI.3.

101I34)

BASIS FOR PEF1-U=~ TAX CAL-CULLATION SOCK AJ IS RATIO OF XASIS FOR DEFTARB= TAX CALCULATIONS TO 3OOK NAIS13 2MK 81FRICIAIION OP 2A.V9 MRP 09UDR TAX CA.LCULA.'1ON SC P3SCIATION (ACCOUNt d03) 01ft3"AT1ON OF AIUDC M"CA MD RNYRRTAZNMW.N EXPNSS (ACCOUNTs S1,. S19-152.

S23-17, M 55657. SW5-73201M.

M 2-92!. IIS)

PENSION 9W4SN3 (ACCOUNT 92S)

TNINO RIFFISENiCES?

FUIL UWIN29 S

TAX DF-PRECATION Of NIUCLEAX PUlL INTEREST AMCO 9T7(EP 090UCT131.

XPEHSU (ACCOUNT SII) l'UCLLAM PUIL. ZXMP52 PER BOOKS (ACCOUNtT WI) rJEPW.ECAflOH LXPI'N31 S

TAX VERIt=ATIOM4 OF UNIt i (ACCOUNT 402)

DVX.+/-r^rIQr4 OF DASIS FOR. 0.rERA.

TAX( CALCULAMN~

viCOMMmiaN~t'40 XPEH3E TAX DEDUCTLION FOR ACCRUED I)SCOMMTSSICNtNe rDPENZ5Si BMXi A CCRUAL FOR D!COmMi.(ssipritmo F£xrmsu CAccovN 403)

PISpJION3XCf TAX 09DUCTION FOR ACCRUED PV)SbON 9XPE?41L1 JOOC ACCRU.AL YOKt rW310KZ~r~ E 4jLSg (ACCOUNT 916) s I

£ I

I A

I I

s I

S I

s A

I

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

March 31, 2003 RBS-70% Report River Bend Station-70% Regulated Interest Minimum Reporting Requirements as per 10 CFR 50.75(fl(1):

1. Decommissioning funds estimated pursuant to 10 CFR 50 75(b) and (c) (2002$).

Regulated 70% Funding Interest 458,708,910 2 Market value of funds accumulated as of December 31, 2002.

Louisiana Jurisdiction Texas Jurisdiction FERC Jurisdiction 35,581,878 2.9 57,010,041 2.9 3,212,492 2.9 3 Current schedule of annual amounts remaining to be collected.

Louisiana Jurisdiction Texas Jurisdiction FERC Jurisdiction See Attachment 3-E 4 See Attachment 3-E See Attachment 3-G 4 Assumed rate of decommissioning cost escalation used in funding projections-Louisiana Jurisdiction - Attachment 3-E Texas Jurisdiction - Attachment 3-F FERC Jurisdiction - Attachment 3-G CP6 8 481%

4 00%

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

Louisiana Jurisdiction Texas Junsdiction FERC Jurisdiction 5 78% 6 6 67% 7 See Attachment 3-G 6 Assumed rates of other factors used in funding projections:

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

7. Contracts assuring collection of decommissioning funds 8 Modifications to method of providing financial assurance since March 31, 2001 filing (extemal sinking fund) 9 Material changes to trust agreements since March 31, 2001 filing None None None Supplemental Information:

1. Site-Specific cost estimate escalated to 2002 (Jurisdictional basis)

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

NRC License Termination Cost Non-NRC License Termination Cost:

Total 294,645,443 3 39,855,584 3 334,501,027 Regulated 70% Funding Interest - Texas Jurisdiction (1996 Base Year Dollars)

NRC License Termination Cost Non-NRC License Termination Cost Total 314,852,022 3 42,588,852 3 357,440,874

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

March 31, 2003 River Bend Station-70% Regulated Interest Regulated 70% Funding Interest - FERC Jurisdiction (1985 Base Year Dollars)

NRC License Termination Cost:

Non-NRC License Termination Cost.

Total RBS-70% Report 182,963,274 3 91,659.919 3

$ 274,623,193 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):

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

once every 5 years Site-specific 6 Decommissioning rate regulation (approximately).

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

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

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

Unregulated (based on 70% funding interest) 20 03%

30.10%

2.10%

17.77% 5 70.00%

1 See Attachment 3-A for calculations 2 Source: December 31, 2002 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 genenc 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 Eamings 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.

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 6 Assumed weighted average after-tax earnings rate for the non-qualified and tax qualified decommissioning funds for the period 2002-2038 7 Assumed average after-tax earnings rate for the decommissioning fund (tax qualified) for the period 2002 - 2032.

8 The Nuclear Escalator will be 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 9 Funds accumulated for each junsdiction may only be used for decommissioning costs associated with that jurisdiction

-A RBS-70% Report RIVER BEND STATION CALCULATION OF MINIMUM AMOUNT AS PER 10CFR 50 75 (b) AND (c)

Determination of Minimum Amount Entergy Gulf States, Inc.: 90% ownership interest Plant Location: St Francisville, Louisiana Reactor Type: Boiling Water Reactor ('BWR")

Power Level: <3400 MWt (Approx. 3039 MWt.)

1986 BWR Base Year S: $131,351,000 Waste Burial Facility: Bamwell, South Carolina 10 CFR 50.75(c)(2) Escalation Factor Formula:

0.65(L) + 0 13(E) + 0 22(B)

$131,351,000 L= Labor (South)

E= Energy (BWR)

B= Waste Burial (BWR)

Factor 1.794 1.135 16 705 2

BWR Escalation Factor:

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

4.98891 1986 BWR Base Year S Escalated:

$ 131,351,000

• Escalation Factor =

Regulated 70% Funding Interest 655,298,443 4

458,708,910 4

1 Source Bureau of Labor Statistics senes report Id ecul3202i (January 2003).

2 Source Bureau of Labor Statistics senes report id wpu0543 and wpuO573 (January 2003) 3Source Nuclear Regulatory Commission Table 2 1 of Report on Waste Bunal Charges", NUREG-1307 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 (October2002) yields a genenc baseline cost of Regulated 70% Funding Interest =

300,019,826

-B RBS-70% Report RIVER BEND STATION CALCULATION OF SITE-SPECIFIC COST ESTIMATE ESCALATED TO 2002 DOLLARS RIVER BEND 70% FUNDING INTEREST LOUISIANA JURISDICTION Site-Snecific Cost Estimate (1996$)

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

NRC License Termination Cost.

Non-NRC License Termination Cost:

Total Site-Specific Cost Estimate:

Annual Escalation Factor:

Years of Escalation (1996 Base Year to 2002)

Cumulative Factor:

Site-Specific Cost Estimate (2002$):

NRC License Termination Cost

• Cumulative Factor Non-NRC License Termination Cost

• Cumulative Factor:

Total Site-Specific Cost Estimate.

$ 258,324,954 2 34,942,648 3

$ 293,267,602 1 CPI 6

1.141

$ 294,645,443 39,855,584 l $ 334,501,027

' The Louisiana Pubiic Service Commission (LPSC) authorized funding amounts (Attachment 3-E) based on 70% of the site-specific cost estimate of $418,953,716 in 1996$ and escalated annually at rates ted to projections of the Consumer Pnce Index-Urban ('CPI") The projection for the CPI from the penod 1996 through 2002 was 14 06%. The Nuciear escalation factor will be 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%

-C RBS-70% Report RIVER BEND STATION CALCULATION OF SITE-SPECIFIC COST ESTIMATE ESCALATED TO 2002 DOLLARS RIVER BEND 70% FUNDING INTEREST TEXAS JURISDICTION Site-Specific Cost Estimate (1996$)

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

NRC License Termination Cost Non-NRC License Termination Cost Total Site-Specific Cost Estimate Annual Escalation Factor.

Years of Escalation (1996 Base Year to 2002):

Cumulative Factor (1+Factor)A6:

Site-Specific Cost Estimate (2002$):

NRC License Termination Cost

• Cumulative Factor Non-NRC License Termination Cost

• Cumulative Factor Total Site-Specific Cost Estimate

$ 237,514.518 2

$ 32,127,698 3

$ 269,642,216 '

481% 1 6

1.326

$ 314,852,022

$ 42,588,852 l $ 357,440,874

' 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 1996S 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%

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

-D RBS-70% Report RIVER BEND STATION CALCULATION OF SITE-SPECIFIC COST ESTIMATE ESCALATED TO 2002 DOLLARS RIVER BEND 70% FUNDING INTEREST FERC JURISDICTION Site-Specific Cost Estimate (1985$)

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

NRC License Termination Cost Non-NRC License Termination Cost Total Site-Specific Cost Estimate:

Annual Escalation Factor Years of Escalation (1985 Base Year to 2002)

Cumulative Factor (1+Factor)^17:

93,928,450 47,055,750 140,984,200 '

4 00% 1 17 1.948 Site-Specific Cost Estimate (2002$):

NRC License Termination Cost

• Cumulative Factor:

Non-NRC License Termination Cost:

• Cumulative Factor Total Site-Specific Cost Estimate:

182,963,274 91,659,919 274,623,193 1 FERC authonzed funding amounts (Attachment 3-G) based on 70% of site-specific cost estimate in 1985$ escalated annually at 4 0%

-E RBS-70% Report I of 5 Entergy Gulf States, Inc, River Bend Decommissioning Model - Louisiana Retail Non-DAP Portion Revenue Requirement, Fund Balance and Expenditure Summary (9000)

Decommissioning Fund Balances Une Revenue Non-Tax Tax Decomm No Year Rqmt Qualilfied Qualified Total Expend I

Beginning 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

2,266 30673 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

16 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 O

23 2023 0

6,627 106,849 113.476 0

24 2024 0

6 934 112,351 119.284 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 26217 30 2030 0

0 4,539 4,539 26,744 31 2031 0

0

-22,763

-22.763 27,510 32 2032 0

0

-37,724

-37,724 13.869 33 2033 0

0

• 48,493

• 48,493 8.960 34 2034 0

0

-59 367

-59 367 8 548 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

-82A473 8.236

-E RBS-70% Report 2 of 5 Entergy Gulf States, Inc, River Bend Decommissioning Model - Texas Revenue Requirement Fund Balance and Expenditure Summary

($ODD)

Decommissioning Fund Balances Line Revenue Non-Tax Tax No Year Rqmt Qualified Qualified 1

Begrnning Balance 0

41,503 2

1997 8,551 0

53.042 3

1998 8,551 0

65.342 4

1999 8,551 0

79,068 5

2000 8,551 0

93.820 6

2001 8,551 0

109,675 7

2002 8,551 0

126,715 8

2003 8,551 0

145,030 9

2004 8,551 0

164,714 10 2005 8,551 0

185,869 11 2006 8,551 0

208,606 12 2007 8.551 0

233,043 13 2008 8.551 0

259,307 14 2009 8.551 0

287,535 15 2010 8,551 0

317,873 16 2011 8,551 0

350,480 17 2012 8,551 0

385,524 18 2013 8,551 0

423,188 19 2014 8,551 0

463,668 20 2015 8.551 0

507,175 21 2016 8,551 0

553,935 22 2017 8,551 0

604,190 23 2018 8,551 0

658,203 24 2019 8,551 0

716,254 25 2020 8,551 0

778,645 26 2021 8,551 0

829,458 27 2022 8,551 0

883,015 28 2023 8.551 0

939,464 29 2024 8.551 0

998,962 30 2025 5,701 0

1,043,086 31 2026 0

0 1,051,288 32 2027 0

0 924,532 33 2028 0

0 755.709 34 2029 0

0 567.884 35 2030 0

0 358,131 36 2031 0

0 145,837 37 2032 0

0 0

Total 41,503 53,042 65,342 79,068 93,820 109,675 126,715 145,030 164,714 185,869 208,606 233.043 259,307 287,535 317,873 350,480 385,524 423,188 463,668 507,175 553.935 604,190 658,203 716,254 778,645 829,458 883,015 939,464 998,962 1,043,086 1,051,288 924,532 755,709 567,884 358,131 145,837 0

Decomm Expend 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 15,274 46,774 178,356 212,585 222,190 233,642 225,104 149,378

-E RBS-70% Report 3 of 5 Entergy Gulf States, Inc.

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

($000)

Decommissioning Fund Balances Line Revenue Non-Tax Tax Decomm No Year RqmL Qualified Qualified Total Expend I

Begtnning Balance 9.151 6,251 15,402 2

2002 0

9 696 6678 16,374 0

3 2003 0

10274 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

12224 8,709 20,933 0

7 2007 0

12,953 9,308 22,261 0

8 2008 0

13,726 9,948 23,674 0

9 2009 0

14,546 10,633 25,178 0

10 2010 0

15,414 11,365 26,T79 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

-26259 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

-E RBS-70% Report 4 of 5 Entergy Gulf States, Inc.

River Bend Decommissioning Model-Texas Retail Fees and Other Data ($ im Thousands)

Tax Qualified Trustee and Investment Manager Fee Schedules TO Annual Fees 2 83 Adder (S 000)

Breakpoints ($000)

Basis Points Fixed [1]

Cumulative TO Trustee Fees 0

5 00 833 200 0417 0417 1,667 1 00 0 167 0583 5.000 0 75 0 333 0917 TO Manager Fee 0

1750 1,333 1650 2 333 2 333 4,167 14 00 4 675 7 008 8.333 11 50 5 833 12 842 33.333 9 00 28 750 41 592 Non-Tax Qualified Trustee and Investment Manager Fee Schedules NTO Annual Fees 1 9 Adder (S 000)

Breakpoints ($000)

Basis Points Fixed 11]

Cumulative NTO Tnustee Fees 0

5 00 500 200 0 250 0250 1,000 1 00 0 100 0 350 3,000 075 0200 0 550 NTOManagerFee 0

1750 800 16 50 1 400 1400 2,500 14 0 2 805 4205 5,000 11 50 3 500 7.705 20,000 9 00 17250 24 955 Miscellaneous Input Data Bad Debt Rate 121 000%

NudearCost Escalatori61 481%

Cost Estimate Year [3]

1996 Junsdictional Atlocation Factor[7]

100 00%

Composite Tax Rate [4]

3500% TO Fund Federal Tax Rate 96 & After [5]

20 00%

GSU Ownership Share (51 70 00% End o Life a829/2025 Notes

[1]

For balance or S25M TO Management Fee = 32009 = 12842 +(11 Sbp ' (25,000- 8,333))110,000 (2]

Bad Debts handled In Cost of Service Study 3]

Year upon which the decommissioning cost estimate is based (4]

State Income Tax Rate in Texas is zero Federal Rates are reflected

[5]

Entergy Gulf States owns 70% of River Bend

[6]

Nudear Cost Escalator Is 4 81%

[7]

Production demand allocator for Texas-retait per 8130/96 Coat of Service Study

-E RBS-70% Report 5 of 5 Entergy Gulf States, Inc River Bend Decommissioning Model -Louisiana Retail Non-DAP and DAP Portion Fees and Other Data (S in Thousands)

Tax Qualified Trustee and Investment Manager Fee Schedules TO Annual Fees 2 83 Adder (S 000)

Breakpoints ($000) Basis Points Fixed I[1 Cumulative TQ Trustee Fees 0

500 695 2 00 0 348 0348 1.389 1 00 0 139 0486 4,167 075 0 278 0764 TQManagerFee 0

1750 1,333 16 50 2 333 2 333 2,667 1500 2.200 4533 3,333 13 50 1 000 5 533 4,167 1100 1 125 6658 8.333 8 50 4 583 11 242 33,333 600 21.250 32492 Non-Tax Qualified Trustee and Investment Manager Fee Schedules NTQ Annual Fees 1 90 Adder(S 000)

Breakpoints ($000) Basis Points Fixed [1I Cumulative NTO Trustee Fees 0

5 00 417 2 00 0.209 0 209 833 1 00 0083 0292 2,500 075 0167 0458 NTQManagerFee 0

1750 800 16 50 1 400 1 400 1,600 1500 1.320 2720 2,000 1350 0600 3320 2,500 11 00 0675 3 995 5,000 8 50 2 750 6 745 20,000 6 00 12 750 19 495 Miscellaneous Input Data Bad Debt Rate [21 0 00% Nuclear Cost Escalator [6]

2 53%

Cost Estimate Year [33 1999 Junsdictional Altocation Factor [73 48 88%

Composite Effective Tax Rate 141 3848% DAP Portion 18]

46 0275%

Entergy Gulf States Ownership Share 15]

70 00% TO Fund Federal Tax Rate 96 & After 91 20 00%

End of Operatng Ucense 8/29/2025 Notes

[1]

Forbalance ofS10M TQ Management Fee = 12659 = 11242 + (8 5bp (10.000-8,333))110,000

[21 Bad Debts handled in Cost of Service Study

[3]

Year upon which the decommissioning cost estimate Is based

[41 Louisiana Income Tax Rate is 8 0%, however. In Louisiana Federal Income taxes are deductible, therefore the effective Louisiana rate is 5 35% The effective Federal Rate is 3313% resulting In a Composite Rate of 38 48%

[5]

Entergy Gulf States funding Interest In River Bend is 70%

[61 Nuclear Cost Escalator Is 2 53% effective 111103 per the Settement Agreement pursuant to Order U-19904 m7 Production demand allocator for Louisiana-retail per 12131100 Cost of Service Study 18]

Deregulated Asset Plan per LPSC order

[91 Effectve Federal Tax Rates for Qualifed Trusts These trusts do not pay state taxes

-F Page I of 4 PUC DOCKET NO. 16705 SOAH DOCKET NO. 473-96-2285 APPLICATION OF ENTERGY TEXAS FOR APPROVAL OF ITS TRANSITION TO COMPETITION PLAN AN] THE TARIFFS IM3PLEMENTING THE PLAN, AND FOR TH E AUTHORITY TO RECONCILE FUEL COSTS, TO SET REVISED FUEL FACTORS, AND TO RECOVER A SURCHARGE FOR UNDER-RECOVERED FUEL COSTS

§

§§ PUBLIC UTILITY COMlgSSWDN

§ f_

=

§ OF TEXAS 1

§ F.

§

§ A

§ C, C N-cEAI ON REHEARING

n SECOND ORDER 4 This Second Order on Reheaing (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. 11292.1 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) Administraive 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 Applicaion of Entvgr Corporaoon and Gulf Staes UUiities Company for Sac Transfer or Merger.

Docket No. 11292, 19 P.U.C. BULL 2040, 2041 (Ordering Paragaph S) (Dec. 29, 1993).

• The AlJs issued the PFD on March 25. 1998, as revised by clanficatons, revised text, and revised schedules filed on June 4, 12, and 16, 1998. The A.Js issued the SPFD, which adesses supplemental fuel-related issues, on March 27, 1998. The Commission considered the matser addressed in this Order at its open meetings convened on June 30, July 8 through 10, July 13, July 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.

-F Page 2 of 4 PUC DOCKET NO. 16705 Second Order on Reheanng Page 91 of 156 SOAH DOCKET NO. 473-96-2235 Non-Reconcilable Fuel and Purchased Power Expenses 177.

It is reasonable to include non-reconcilable coal, gas, and purchased power expenses in Whe amount of 54,853,684 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 Commssion's previous adoption of low level radioactive waste disposal costs at 7.5%, the fact that River Bend specific inflation factor has bee very low in the past several years, and the fact that decommissioning does escalate at a rate higher than general inflation, a 4.81% escalation rate is reasonable.

180.

An 11.47%

1 st equity retun and overall 6.6% rtn for the trust fund results from the most reasonable assessment 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 1.

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

PUC DOCKET NO. 16705 SOAH DOCKET NO. 473-96-2285 -F Page 3 of 4 Page 155 of 156 Second Order on Rehearing SIGNED AT AUSTIN, TEXAS the 7

2aV of October 1998.

COMMISSION OF TEXAS T- -s-at

,,,,x,~

XWAL

/"

v' ASS I' O E Q:X-SHARE\\ORDERS\\,FINALI 6000\\1 670RH2.DOC

I *'IL I 1tu,1iy unlimissloui 4.1 I cxix

%eg No 16705 I -.. guy iull StItSe.

111, Su"mmary fTeta. Retail Revenue Requirement Allocatlo.

(IFhousands of Dollars)

Schedule KS-rx/

COMMISSION

()rormik:g 9,

Pas I eloI J

I legible Fuel & Purch Power Non-Eligible Fuel & Purch Power Operaling and Maintenance Decommissioning Expense lerreciation Expense Amrnieiration hiltrest an Customcr Lkepsits I axes Other Tuan Statc Income Tax l.alte Income Tacs

eJc.Jel lnconm Taxes Rclunlon Invested Capital (Retum on Rate Dase)

Giins From Disposition of Allowncie 1 1 rAL REVENUE REQIIIREMENT Qu3lity ofService Adj Allucaled-Rac asec Quality of Service Adj Reollocated -Distribution Lincs Adjustment due lo IS-Credits lo LPS A IlLFS Adjustment due to IS-Ctedit allocated to Firm Classes Adjustment due to Senior Citrien Discount Residential Adjustment due to Senior Citizen Discount Allocalcd to All I 0) NA L REVENUE REQIIIREIIENT ADJIIS1 ED l'ised Fuel Factor Revenue Non Fixed Fuel Factor Rcvenue Other Revenues HAlSE RATE REVENUE Wesrre Impultalan timreaitlon due to SSTS Imrpuiaion due to EEDS IIASI. RATE REVENUE w/ Imputation 257.233 79.121 3.711 40.2)4 22.104 54,567 56.016 1.132 6.411 2.419 141 1.122 512 1.142 1.119 27 jp.31j2.

62.411 43135 21.035 7.9i9 14.594 1).4 3 1.,96 QAA1.D 1.451 90 651 230 596 570 14 60.177 27.312 1.900 11.926 4,233 6.912 6.117 1.466 (7.771)

(.095)

(190)

(1.396)

(594)

(1.265)

(110)

(1(29)

'01 230 16 102 36 59 51 7

39,737 17.006 1.109 7,341 2.914 5.599 5,317 450 0

0 0

0 0

0 0

0 27.536 12.459 142

).469 1.934 3,247 1.005 610 101.476 49.613 3.401 21.961 7.761 12.659 11.529 1.411 62 1.390 249.161 15,475 103.452 47.119 9S3,179 96,289 2.211 (2.211)

(5.918) 5.9"l (47) 457 621.i 221.734 23.449 16.926 347,23e 7.222 1.261 3.1,747 1.013 (1,235) 2.463 (457)

II]

251.019 79.121 7.910 69 448 153 251 (1)

(615)

(164)

(49)

(4.9447 151 1,111 475 105 215 (974)

• 17 7 1 6.775 30 (19) 21 I I go 3) 72 1

I.62I 109,477 47,623 94,J2 9

7,508 3.731 51) 40.234 22.104

)0.507 24.060 3,671 1,290 1.767 51.697 4,).9 1,)54 6.31I 1.112 150 i.)JI 163.911 1IJJ3 65*S7J 24.229 29 452 163.911 11.330

'5.544 23.777 37.918 4.339 5.191 t51 1,129 195 32,010 16.844 t.312 10/ 12194 11 26 AM

-G Page 1 of 6 UNITED STATES OF AM=C.%

FZDE;AL ENERGY REGUIA2TORY CO.ISSION 2c-cre Coniasioners: Hartha 0. Hacsc, Chairman:

tinthony G. Sousa, Charles G. Stalon and Chazlen A. Trabandt.

Gulf States Utilities Co.pany

)

Dockat N~c=.

ER86-S58-O02, ER86-558-o11 and ERS6-558-o12 ORDER CLR.U'Y`NG PREVIOUS ORDERS (Isscuad May 18, 1988) r Cn Fabruary 16,- 1988, Gulf Stat^es Utilit4 ls.Ccmpany (Gulf States) filed a petition fo= clarification of certain lcttcr ordars approving dttlJentz in this procaeding. ;/

The letter orders approved seattlemnt ratts reflecting dccommi.zioning ex-renses funded through an external fund (River Band Nuclear Decoissioning Fund) adjuztad for a forty-year funding pericd.

On March 2, 1988, Cajun Elactric Power Cooperative, Inc.

(Cajun) requested that the Cqmmission explicitly recognize that its contributions to Gulf States' docommissioning fund ara, and have been, on the basis of unadjusted decomissioning expenses, and that the instant order will hav* no application to the ratas being charged to Cajun.

dulf States requests thit the eomi=insion ekpressly recognize the amount ot yearly decommissioning costs which it is entitled to collect. Gulf States aseartz that absent such express recogniticn, the Intornal Revenuz Service. (IRS) will not pe-4t its deduction or yearly caash contributions to the River Bend Nucl.ar Decommissioning -Fund.

Cul1 Statas contonds that it must firzt receive a "schedule of ruling amounts" from the IRS in order to take this deduction.

Gulf Statas further mintains that the IRS will nct ziovide a taxpayer with a sehedule of rul+/-ng azuits "uhl&as a public utility ccmmiszion that establishes or approves rates for eleczric energy generated by the nuclear power plant to which the 1/t Sea Culf States Utilities Company, 40 FZRC I 61,081 (1987): Gulf Statas Utilities Company, 40 FZRC 1 61,380 (1987) I and Gulf StataZ Ut~litiea Companv,.. 4.2 EFRC q 61,098 (1988).

W *

- -G Page 2 of 6 Doc.'Ct NCz.

ER86-55S-002 and -01 2-

'and -013 nuclear decommissioning fund relates has dete'r~ned -he a2-n-U.

c:

decommissioning costs of suc%.. nuclear power plant to be _.cl ded in the taxpayers cost of service cr ratemaking pu-cses.

" 2 Culf States =^antains that t%.c Ccmmi3SiOn's lettor cde-rs approving the settlements do no: eXprassly address dcccmissioning costs, *althcugh t'.e settlezment rates which. t:e c-tiBsicn has approved are expressly based upon. spec'i fed dec^: issioning ccsts.

Gulf Statzz also clai=s hat the :

has date+/--inod ttat tho Cciz:ionis letter Ordars ap--CVinq t:e settlsont:

do not satisfy the require-ents o: its r.gulat:cna.

WC are not convinced that the instant clarif4ct:tcnz are necessary.

It appoarz that Gulf States has never zubmlttad tc th-^ IPS tha lettar orders approving the sztteae.nts that sp;cif+/-'d tho amount of dacc='i-sisoning costs that will be ra4Qlcted in Gulf Stats

' wholasale ratoc.

Eazed on Gul ' States' filing it appaara that they requsated approval from thc IRS on JCLne 24, 1987.

1/ The lettar orders wzrs not issued un:tl July 22 and September 25, 1987 and January 3i, ls8s, respective1y.

WQ bal'eve that had Gulf Stztzz properly su!:i:ted the latttr orders that arc tho subject Of our order tcday to the IR that no clar ficaticn of thaS6 orders would be necessary.

We shall neverttheless grant the resuests of Gulf States and Calwn.

Zn approving the settlamenta reached in this docked the Ccmmission has au~torjized Gulf Statna.to ro'_ec:

9 wnolssalo rates yearly decommissicning coOt: of S112,924. We wueve suc3 ac-_cn to De In ta public intzrest to allcw Gulf States to receive the proper tax deduction for its yearly cash contributions to the River Bend Nuclear Decommisscning Fund.

This ordar will also have no applicarion to the rates being charged to Cajun.

The C

-n4s~ipy ordern~

The Gulf States' and Cajunzsreqmests for clarification are hereby granted.

By tha Commizsicon.

S E A L)

Loiz 0. Casheli, Acting Secretary.

21 5I Petition for Clari'c:tion at 3-4, quctin; Te~m.

Treas. Reg.

5 1.468A-3T(g)

(1986).

1/

5.-A letter of Sapteter 2.2, 1987 or Willia- ;. C1ve-,

C.ief, Branch 6 Corporaticn Tax Divizion, :RS a i.

-G Page 3 of 6 FEDERAL ENERGY REGULATORY COMMIISSION IRS Schedule Of Ruihq Amaunts, dated May 22, 1989

Intemal Revcnue Service Department of the Treasury PO. Box 7604 Ben Franklin Station Washington. OC 20044 Attachlnent S-G Pare 4 of 6 Index No.: 0468A.10-03 B.J. Willis, Vice President and Controller Gulf States Utilities Co.

350 Pine St., P.O. Box 2951 Beaumont, TX 77704 Person to

Contact:

Martin Schaffer Tefethone Number:

(202) 566-6589 Refer Rerwy to:

CC:P&SI:6 TR-31-824-89 Date:

MAY 2 2 W In re: Schedule of Ruling Amounts Gulf States Utilities Co.

River Bend Nuclear Power Plant Company:

Plant:

Location:

Utility:

Commission A:

Commission B:

Commission C:

State A:

State B:

Gulf States Utilities Co.

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

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

Cajun Electric Power Cooperative Federal Energy Regulatory Commission Public Utility Commission of Texas Louisiana Public Service Commission Texas 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.

The 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 A}..

'-G Page 5 of 6 TR-31-824-89 percent of the Plant as a tenant in common.

The Utility owns the other 30 percent.

2 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 regulations.

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

$ S201,406,000 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 S140,984,200, and its Commission A jurisdictional share is $7,945,588.

Based on an assumed inflation rate of four ppr-nnt, the total cost of decommissioning expressed in future dollars is S966,950,206.

The Company's share of this amount is S676,865,144.

The Commission A jurisdictional amount is S38,146,766.

Using an assumed after-tax rate of return of nine percent, Commission A determined the amount of decommissioning

-G Page 6 of 6 TR-3l-824-89 costs to be included in the Company's 1988 cost of service is annual share of the total estimated costs) to Abe S112.92.4._

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 decomnission'..g 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 ratemaking purposes for the taxable year or the ruling amount applicable to this year.

Section 468A(d)(l) 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, 2003 -H RBS-30% Report River Bend Station-Non Regulated 30% Interest Minimum Reporting Requirements as per 10 CFR 50.75ff)(l) 1 Decommissioning funds estimated pursuant to 10 CFR 50.75(b) and (c) (2002$)

Non-Regulated 30% Interest 196,589,533 '

2 Market value of funds accumulated as of December 31, 2002:

Non-Regulated 30% Interest 3 Current schedule of annual amounts remaining to be collected 142,695,947 2,5 N/A 4 N/A 4 4 Assumed rate of decommissioning cost escalation used in funding projections 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/A '

8 Modifications to method of providing financial assurance since March 31, 2001 filing (external sinking fund)

None 9 Material changes to trust agreements since March 31, 2001 filing None Supplemental Information:

1. Site-Specific cost estimate escalated to 2002 Non-Regulated 30% Prefunded Interest (1996 Base Year Dollars)

NRC License Termination Cost Non-NRC License Termination Cost Total 126,276,618 3 17,080,964 3 143,357,582 4 2 Decommissioning method assumed for planning purposes in site-specific estimate DECON 3 Year site-specific estimate complete 4 Frequency of updates (approximately) 1996 5 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, 2002 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 (Barnwell, South Carolina) 4 Cajun contributed $132 million to prefund its decommissioning obligation with respect to its former 30% ownership share 5 This fund may only be used to decommission the non-regulated 30% interest. Any excess funds after decommissioning must be returned to Rural Utility Services

-1 RBS-30% Report RIVER BEND STATION Non-Regulated 30% Interest CALCULATION OF MINIMUM AMOUNT AS PER 10CFR 50 75 (b) AND (c)

Determination of Minimum Amount Entergy Gulf States, Inc.: 90% ownership interest Plant Location: St Francisville, Louisiana Reactor Type: Boiling Water Reactor ("BWR")

Power Level: <3400 MWt (Approx 3039 MWt) 1986 BWR Base Year $: $131,351,000 Waste Burial Facility: Barnwell, South Carolina 10 CFR 50.75(c)(2) Escalation Factor Formula:

0 65(L) + 0.13(E) + 0 22(B)

$131,351,000 L= Labor (South)

E= Energy (BWR)

B= Waste Burial (BWR)

Factor 1.794 1.135 16 705 2

3 BWR Escalation Factor:

0 65(L) + 0 13(E) + 0 22(B) =

4 98891 1986 BWR Base Year $ Escalated:

$ 131,351,000

• Escalation Factor =

655,298,443 4

Non-regulated 30% Interest 196,589,533 4'5 1 Source Bureau of Labor Statistics series report Id ecul3202i (January 2003) 2 Source Bureau of Labor Statistics series report id wpu0543 and wpu0573 (January 2003) 3 Source Nuclear Regulatory Commission Table 2 1 of "Report on Waste Burial Charges", NUREG-1307 revision 10(October 2002) 4Application of the 8 860 waste vendor disposal factor (South Carolina) from Table 2 1 of "Report on Waste Bunal Charges",

NUREG 1307 Revision 10 (October 2002) yields a generic baseline cost of Non-regulated 30% Interest=

128,579.926 5 Cajun contributed $132 million to prefund its decommissioning obligation with respect ot its former 30%

ownership share

-J RBS-30% Report RIVER BEND STATION CALCULATION OF SITE-SPECIFIC COST ESTIMATE ESCALATED TO 2002 DOLLARS RIVER BEND 30% PREFUNDED INTEREST Site-Specific Cost Estimate (1996$)

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

NRC License Termination Cost Non-NRC License Termination Cost Total Site-Specific Cost Estimate:

Annual Escalation Factor:

Years of Escalation (1996 Base Year to 2002)

Cumulative Factor:

Site-Specific Cost Estimate (2002$):

NRC License Termination Cost

• Cumulative Factor Non-NRC License Termination Cost

• Cumulative Factor:

Total Site-Specific Cost Estimate

$ 110,710,694 2 14,975,420 3

$ 125,686,114 1 CPI 6

1.141

$ 126,276,618 17,080,964 l $ 143,357,582 I' 1 Based on 30% of the site-specific cost estmate of $418,953,716 in 1996$ and escalated annually at rates tied to projections of the Consumer Pnce Index-Urban ('CPI") The projection for the cumulative CPI from the penod 1996 through 2002 was 14 06%

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

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

WF3 Report Waterford 3 Steam Electric Station Report on Status of Decommissioning Funding 10 CFR 50 75(f)(1)

March 31, 2003 Minimum Reporting Requirements as per 10 CFR 50.75(f)(1):

1 Decommissioning funds estimated pursuant to 10 CFR 50.75(b) and i (2002$)

2 Market value of funds accumulated as of December 31, 2002:

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

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

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

6. Assumed rates of other factors used in funding projections

7. Contracts assuming collection of decommissioning funds

8. Modifications to method of providing financial assurance since March 31, 2001 filing (external sinking fund) 9 Material changes to trust agreements since March 31, 2001 filing:

Supplemental Information:

1 Site-Specific cost estimate escalated to 2002 (1993 Base Year Dollars)

NRC License Termination Amount-Non-NRC License Termination Cost Total 2 Decommissioning method assumed for planning purposes in site-specific estimate.

3 Year site specific estimate complete:

4. Frequency of updates (approximately) 5 Funding based on NRC minimum or site-specific estimate?:

6 Decommissioning rate regulation (approximately)

Louisiana Public Service Commission Council of the City of New Orleans 570,762,812 1

123.471,825 2

See Attachment 4-C 5.50%

7.46%

5 See Attachment 4-C None None None 469,594,416 3

48,720,146 3

518,314,562 DECON 1994 4 once every 5 years 4 Site-specific 97%

3%

1 See Attachment 4-A for caluculations.

2 Source. December 31, 2002 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 (Barnwell, South Carolina) 4 Entergy Louisiana filed a 1999 decommissioning cost update of $481.5 million for Waterford 3 with the LPSC in the third quarter of 2002 5 Assumed after-tax earnings rate for the decommissioning fund for the period 2002 to 2040

V1 -A WF3 Report WATERFORD 3 STEAM ELECTRIC STATION CALCULATION OF MINIMUM AMOUNTAS PER 10 CFR 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)

L= Labor (South)

E= Energy (PWR)

B= Waste Burial (PWR)

PWR Escalation Factor:

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

Factor 1.794 1.143 2

18.732 3

5.43584 1986 PWR Base Year $ Escalated:

$ 105,000,000

• Escalation Factor =

l $

570,762,812 4

' Source: Bureau of Labor Statistics series report id ecul3202i (January 2003).

2 Source. Bureau of Labor Statistics, series report id wpu0543 and wpu0573 (January 2003).

3 Source: Nuclear Regulatory Commission:Table 2.1 of "Report on Waste Burial Charges", NUREG-1 307revisionl 0(October 2002).

4Application 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 =

356,741,312

-B WF3 Report WATERFORD 3 STEAM ELECTRIC STATION CALCULATION OF SITE-SPECIFIC COST ESTIMATE ESCALATED TO 2002 DOLLARS Site-Specific Cost Estimate (1993$)

Site-Specific Cost Estimate (1993$):

NRC License Termination Cost:

Non-NRC License Termination Cost:

Total Site-Specific Cost Estimate:

290,035,252 30,090,988 320,126,240 5.50%

9 1.619 Annual Escalation Factor:

Years of Escalation (1993 Base Year to 2002):

Cumulative Factor (1 + Factor)A9 Site-Specific Cost Estimate (2002$):

NRC License Termination Cost

• Cumulative Factor:

Non-NRC License Termination Cost

• Cumulative Factor:

Total Site-Specific Cost Estimate:

469,594,416 48,720,146 l $

518,314,562 l

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

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

($000)

Tax Qualified Trust Line Revenue Earning Transfer Management Net Decomm No Year RqmL [11 Rate [2]

To Trust Earnings [3]

Fee Additions [4]

Funding [5]

Balance 1

Beginning Balance 229.434 2

2002 10,420 0 0675 10,420 16,100 (338) 26,182 0

255,616 3

2003 10.420 0 0675 10,420 17,897 (372) 27,945 0

283,561 4

2004 10,420 0 0675 10,420 19,815 (408) 29,827 0

313,388 5

2005 7,786 0 0675 7,786 21,773 (446) 29,114 0

342,502 6

2006 7,786 0 0800 7,786 28,260 (486) 35,559 0

378,061 7

2007 7,786 0 0800 7,786 31,161 (533) 38,414 0

416,476 8

2008 7,786 0 0800 7,786 34,296 (583) 41,499 0

457,974 9

2009 7,786 0 0800 7,786 37,682 (638) 44,831 0

502,805 10 2010 10,285 0 0800 10,285 41,440 (698) 51,028 0

553,832 11 2011 10,285 0 0800 10,285 45,604 (765) 55,125 0

608,957 12 2012 10,285 0 0800 10,285 50,102 (837) 59,550 0

668,507 13 2013 10,285 0 0800 10,285 54,962 (915) 64,332 0

732,839 14 2014 10,285 00800 10,285 60,211 (1,000) 69,497 0

802,336 15 2015 12.279 0 0800 12,279 65,962 (1,092) 77,148 0

879,484 16 2016 12,279 0 0800 12,279 72,257 (1,193) 83,342 0

962,826 17 2017 12,279 0 0800 12,279 79,058 (1,303) 90,034 0

1,052.860 18 2018 12,279 0 0800 12,279 86,405 (1,421) 97,262 0

1,150,123 19 2019 12,279 0 0800 12,279 94,341 (1,548) 105,072 0

1,255,194 20 2020 14,646 0 0800 14,646 103,010 (1,688) 115,968 0

1,371,162 21 2021 14,646 0 0800 14.646 112,473 (1,840) 125,279 0

1,496,440 22 2022 14,646 0 0800 14,646 122,695 (2,004) 135,337 0

1,631,777 23 2023 14,646 0.0800 14,646 133,739 (2,182) 146,203 0

1,777,980 24 2024 14,646 0 0800 14,646 145,669 (2,371) 157,944 (3,333) 1,932,591 25 2025 0

0 0800 0

157,699 (2,509) 155,191 (91,609) 1,996,173 26 2026 0

0 0800 0

162,888 (2,589) 160,299 (96,647) 2,059,825 27 2027 0

0 0800 0

168,082 (2,652) 165,429 (128,670) 2,096,584 28 2028 0

0 0675 0

143,908 (2,530) 141,378 (372,283) 1,865,679 29 2029 0

0 0675 0

128,058 (2,213) 125,845 (397,480) 1,594,044 30 2030 0

0 0675 0

109,414 (1,849) 107,565 (413,229) 1,288,379 31 2031 0

0 0675 0

88,433 (1,437) 86,996 (434,804) 940,571 32 2032 0

0 0675 0

64,560 (1,154) 63,406 (164,583) 839,393 33 2033 0

0 0675 0

57,615 (1,038) 56,577 (139,179) 756,791 34 2034 0

0 0675 0

51,945 (931) 51,015 (139,179) 668,627 35 2035 0

0 0675 0

45,894 (816) 45,078 (139,179) 574,526 36 2036 0

0 0675 0

39,435 (693) 38,742 (139,179) 474,089 37 2037 0

0 0675 0

32,541 (562) 31,979 (139,179) 366,888 38 2038 0

0 0675 0

25,183 (423) 24,760 (139,179) 252,470 39 2039 0

0 0675 0

17,329 (273) 17,056 (139,179) 130,346 40 2040 0

0 0675 0

8,947 (114) 8,833 (139,179) 0 (1,712,820)

Notes

1. The 2005 Revenue Requirement (10,420) is chosen and escalated by Cumulative CPIU from 2005 every fifth year so that the Decommissioning Fund Balance is zero in the last year of decommissioning The average annual CPIU rate is 3 6%

2Projected after-tax earnings rate, assumed average after-tax earnings rate is 7 455%

3Prior Year Balance compounded semiannually at Current Year Earning Rate + % Current Year Transfer Current Year Earning Rate 4 Transfer + Earnings + Management Fee 5 The Nuclear Cost Escalator Is 5 5%

A....

.Ji i

l i -" ; C ARKANSAS PUBLIC SERVICE COMMISSION IN THE MATTER OF ARKANSAS POWER AND)

LIGHT COMPANY'S PROPOSED NUCLEAR

)

DOCKET NO. 87-166-TF DECOMMISSIONING COST RIDER M26

)

ORDER NO.

17 AND PROPOSED DEPRECIATION RATE

)

REDUCTION RIDER M41

)

ORDER Rider M26 Annual Update On November 1,2002, Entergy Arkansas, Inc. ("EAI") filed its annual updated tariffattachment to EAI Rider M26 ("2002 M26 Update") pursuant to the provisions of OrderNos. 5,27, and 32 of this Docket. EAI's 2002 M26 Update consisted of: (I) Attachment I which is EAI's Revised Attachment A to Rider M26, reflecting decommissioning rate adjustments' for 2003; (2) Attachment 2 which included (a) the summary page of the decommissioning model using license expiration dates of 2034 and 2018 for ANO Units 1 and 2, respectively, and (b) an alternative Attachment A to Rider M26, with decommissioning rate adjustments resulting from that summary page; (3) Attachment 3 which is a summary page of the decommissioning model that reflects the suspension of revenue requirement for one year; and, (4) Attachment 4 which is a Chart showing the ANO units' decommissioning trust find balances for the last five years. EAI also indicated in the 2002 M26 Update that (a) Unit 1 has been granted a 20 year licence extension by the NRC, (b) a similar 20-year licence extension application for

'The revised rate adjustments were developed utilizing the decommissioning cost estimate approved in the Commission's Order No. 27 and includes (1) 20-year plant life extensions for both ANO units, (2) 50 percent equity balances, and, (3) the WEFA forecasting data as outlined in Order No. 32.

DOCKET NO. 87-166-TF PAGE 2 Unit 2 will be filed with the NRC, (c) the NRC requires by its regulations2 that decommissioning balance accumulations and collections be based onthe currently-effectiveNRC licenceperiod andmay not be extended to reflect licence extensions until such extensions are approved, and, (d) Entergy Operations intends to report' to the NRC that EAI's fund balance calculation is inconsistent with NRC requirements because of the discrepancy between Commission Order No. 32 and those NRC regulations.

On December 10, 2002, Karen Fricke, Public Utility Analyst in the Financial Analysis Section of the General Staff of the Arkansas Public Service Commission ("Staff'), filed Prepared Testimony

("December 10 Testimony") and Exhibits ("December 10 Exhibits") in response to EAI's 2002 M26 Update. Staff witness Fricke confirms that the licence for ANO Unit 1 was extended for 20 years in June 2001 by the NRC and that Entergy Operations has notified the NRC that it will file in September 2003 for a 20-year licence extension for ANO Unit 2. Ms. Fricke notes that, pursuant to Orders No.

5, 27, and 32 in this Docket, EAI is to file on an annual basis:

1)

The decommissioning revenue requirement model as required by Rider M26,

2)

The decommissioning revenue requirement model with a revenue requirement of zero for the upcoming year, and

3)

A calculation of excess revenues assuming a 20 year licence 210 CFR Section 50.75 (e)(l)(ii).

'EA1 update filed pursuant to NRC requirement 10 CFR 50.75(f) as part of Entergy Operations' obligation to provide "reasonable assurance that funds will be available for the decommissioning process" for ANO (10 CFR 50.75(a)).

DOCKET NO. 87-166-TF PAGE 3 extension for both ANO units.

Witness Fricke advises that EAI's 2002 M26 Update (1) did not appropriately reflect the revenue requirement calculations assuming the 20 year life extensions for the two ANO units, and (2) did not appropriately reflect, for ANO Unit One, its current excess funding projections of approximately $653 million. As a result ofthese errors, witness Fricke testifies, 2002 M26 Update Attachments 2 and 3 also reflect incorrect data. Ms. Fricke provides corrected schedules in her December 10 Exhibits numbered KF-1 and KF-2. Ms. Fricke also notes that EAI has correctly filed, as Attachment 1, its Revised Attachment A to Rider M26, reflecting a zero adjustment rate for all classes.

Ms. Fricke testifies that she based her analysis and resulting recommendations on the Commission's conclusion drawn in Order No. 32, in which the Commission found that, "based on reasonably predictable future events," (1) there was a substantial risk that continued funding for the two ANO Units would result in significant over-collections from ratepayers, and (2) temporary cessation of collections would have comparatively de minimus ratepayer impact should the excesses not materialize. Concluding in Order 32 that it must appropriately balance the likely risks and impacts of each scenario, the Commission ordered EAI to prospectively file a zero-rate M26 rider. The Commission further ordered EAI to file an expanded annual analysis so that the ANO decommissioning funding may be more closely monitored.

Current Fund Balances Ms. Fricke testifies that she has reviewed current decommissioning fund balances as shown on EAI's chart labeled "Attachment 4". That chart shows annual Market Value fund balances for years 1998 through June 2002 and indicates that fund balances have dropped approximately 7 % over the

DOCKET NO. 87-166-TF PAGE 4 last few years. Ms. Fricke testifies, however, that such variations in fund balances are not unexpected.

Rather, such variations, witness Fricke advises, are already comprehended "in the projections and assumptions used as inputs to the Rider M26 model." Further, Ms. Fricke testifies that the December 31, 2002 fund balance predicted by that model was actually lower than the level shown for June 2002 on EAI's chart.

Projected Fund Balances Ms. Fricke testifies that current projections (Exhibit KF-1) for ANO Unit 1 fund balances, assuming no further ratepayer recovery, reflect $653 million in over-collections.

For Unit 2, Ms.

Fricke measured the ratepayer and fund-balance impact of extending zero collection for one additional year under two separate assumptions: (a) Unit 2 is granted a 20-year licence extension, and (b) Unit 2 is not granted an extension. Ms. Fricke testifies that, even with no further collections, with a 20-year life extension, expected Unit 2 over-collections would exceed $1 billion. Alternatively, should there be no extension, Ms. Fricke testifies that a one year moratorium on recovery would increase future revenue requirements for ANO Unit 2 by less than $1 million annually,. That amount, Ms. Fricke advises, has a per residential ratepayer impact of approximately 8 cents per month. Ms. Fricke concludes that "(w)hen compared to the required revenue requirements for the remaining years of the current license as shown on Exhibit KF-3, the risk of over-collection (by $1 billion) clearly outweighs any adverse impact (assuming no extension) of increased future revenue requirements."

DOCKET NO. 87-166-TF PAGE 5 Report to the Nuclear Regulatorv Commission Ms. Fricke also responds to EAl's statements regarding NRC regulations4 and appropriate interpretation of those regulations. Ms. Fricke testifies that the NRC's regulation, Section 50.75

...establishes requirements for reporting to the NRC on reasonable assurance of decommission funding. This is a reporting regulation imposed on all nuclear plants by the NRC. This regulation shows deference to the rate setting authority, in this instance of the Arkansas Public Service Commission. The required report includes a formulaic calculation of decommissioning costs compared to actual fund balances. The utility makes the report and the NRC Staff makes the reasonable assurance finding based on the information provided in the report.

The most current NRC Staff report on funding adequacy for all licenced nuclear plants, including both units of ANO, indicates that all such plants appear "compliant with the provisions of 10 CFR Section 50.75." Witness Fricke has included a copy of that report as Exhibit KF-5. Ms. Fricke concludes that there is no inconsistency between NRC regulations and Rider M26 calculations and that year-to-year suspension of collection under M26, subject to annual Commission review, does not "jeopardize the ultimate recovery of decommissioning costs."

Recommendation Witness Fricke recommends that "the Commission order a revenue requirement of zero and suspend collections forRiderM26 during 2003" and approve EAI's Attachment A, filed onNovember 1, 2002, as Attachment 1. That recommendation, she testifies, is based upon analysis using current licensing periods, with consideration given to the significant risk over-collections of $1 billion could occur compared to the "negligible adverse risk of increased future revenue requirements...." Further, 410 CFR Section 50.75

DOCKET NO. 87-166-TF PAGE 6 Ms. Fricke notes that her recommendation, given current funding levels and this Commission's annual scrutiny, "should not adversely impact the company."

The Commission finds Ms. Fricke's recommendation reasonable and appropriate, pursuant both to prior Commission findings and to the most current evidence available. As indicated by KF-1, the ANO Unit I fund balance indicates significant ($653 million) over-collection from ratepayers.

Assuming no status change for ANO Unit 2, a one year suspension in collection would increase revenue requirement by less than $1 million, with a residential ratepayer impact ofjust $.08 per month.

However, should Entergy Operations obtain a license extension for Unit 2, and the preponderance of evidence in this Docket indicates that it will, ratepayers will have over-funded that unit's decommissioning costs by $1 billion.

As fully explained in Order 32, the Commission is obligated to weigh the risks inherent in and the ratepayer impact of continuing rate recovery balanced against a one-year, temporary cessation of collections, assuming either scenario. The Commission finds that a one-year suspension of collections results in de minimus rate impact when balanced against the possibility that over-collections could by in excess of $1 billion..Further, the Commissionfinds that a one-year suspension of collection neither jeopardizes appropriate decommissioning cost recovery nordoes it negatively impact EAI, particularly in view of Commission-ordered annual reviews and periodic cost-projection updates.5 The Commission also finds no inconsistency in the operation and implementation of Rider M26 and NRC regulations..The annual filings for Rider M26, coupled with the periodic cost-updates, are 5As noted in the 2002 Rider M26 filing, EAI will file its third Commission-ordered estimate for ANO decommissioning costs in March 2003.

DOCKET NO. 87-166-TF PAGE 7 designed to elicit the most current information available and, based upon that information, timely make rate changes as needed to ensure recovery of appropriate decommissioning costs. EAI advises the Commission on page 2 of its 2002 M26 Update that the purpose of Entergy Operations' 10 CFR 50.75(f) annual filing with the NRC is "part of (its) obligation to provide 'reasonable assurance that funds will be available for the decommissioningprocess "'forANO. Such purposes of each regulatory body are wholly consistent.

Therefore, pursuant to the recommendation of StaffWitness Fricke, Rider M26 collections shall be suspended during 2003 and Attachment A, shown as Attachment 1 of the 2002 M26 Update, is, hereby, approved. Further, the Commission also orders EAI to provide to the NRC, concurrently with Entergy Operations' next 10 CFR 50.75(f) annual filing, a copy of this order.

BY ORDER OF THE COMMISSION.

This __

day of December 2002.

Sandra L. Hochstetter, Chairman Bette Betty C. Dekey, Commissioner Daryl E. Bassett, Commissioner Diana K. Wilson of the CommissionI hereby r

-erisur Secretary ofythehCommisseon i

rued

-5

-mm has beenservuu c

fli

,.. record this thea US m:!

ithPo;'IafV-prepaid, using offcia dcke fie.pan as indicated in the iaaK Wilson Secretary of the rlss-on,{