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                           Cost-Benefit Analysis of
                           Entergy Arkansas, Inc.
                           Joining the SPP RTO




Prepared By:
Charles River Associates


Date: October 27,2010
CBA of EA1 Joining the SPP RTO

October 27. 2010                                                                                                         Charles River Associates



                                                               f
                                                        Table o Contents


1.    EXECUTIVE SUMMARY ................................................................................................                                        1

      1.1.      m D YM~ODOLOGY             ........................................................................................................             2
      1.2.            ............................................................................................................................
                FINDINGS                                                                                                                                        3
                f.2.1.     EA1 Region Net Benefits. Excluding Transmission Cost Allocation ....................................                                 3
                1.2.2. Allocation of Regional Transmission Expansion Costs to EA!............................................                                   7
                1 2 3 Net Benefits for the SPPlEnteFgy Region ...........................................................................
                 ...                                                                                                                                            8
                1.2.4.     Other Considerations .........................................................................................................       9


2. INTRODUCTION AND BACKGROUND ....................................................................... 11

3. STUDY METHODOLOGY............................................................................................. 12
     3.1.       BASIC!STUDY M ~ O D O L O G ............................................................................................
                                            Y                                                                                                                 12
     3.2.       SEAMS CHARGfS   ..............................................................................................................            13
     3.3.       MODELING                                                          ,
                          APPROACH QFS IN EFmRGY . ..................................................................
                                        FOR                                                                                                               15
                3.3.1. IPP Modeting............................................................................  ........................................ 16
4.    BENEFITS AND COSTS ...............................................................................................                                      16

     4.1.          BENEFKS ..............................................................................................................
               TRADE                                                                                                                    16
                4.'I.I Adjusted Produetion Costs...............................................................................................
                      .                                                                                                                                        17
                4.1.2.     Transmission Revenue..................................................................................................... 18              .
               41.3. Trade Benefit Results....................................................................................................... 20
     4.2.      ADMINISTRATIVECosrs                   ....................................................................................................
                                                                                                                                                  21
                4.2.1.     ICT Costs and RTO Administrative Charges....................................................................                        21
                4.2.2.     FERC Charges................................................................................................................. 22
                4.2.3.     Internal Staffing and Equipment Costs .............................................................................                23
     4.3.      TRANSMISSION EXPANSION ALLOCATION
                                   COST                                                 ..................................................................23
5.   OVERALL COST-BENEFIT RESULTS.........................................................................                                                    24


6. OTHER CONSIDERATIONS ........................................................................................                                              25
     6.1.       SUB-REGIONAL ALLOCATlONS                     ............................................................................................
                                                                                                                                             25
      ..
     62         EMTERGY
                      OPCO       B
                          CAPACIW E N ~ F ~ ~ S                          .................................................................................    26

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      6.3.      ENERGYOPCO         ARRANGEMENT^...............................................................
                          TRAN~MISSION                                                                                                                            26
      6.4.      S E N S K WANALYSES .....................................................................................................
                            ~                                                                                                                                     27
      6.5.      QUALITATIVE ISSUES            .........................................................................................................           28

7. CONCLUStON .............................................................................................................. 28


APPENDIX A: FURTHER QUANTITATIVE RESULT DETAILS ..........................................                                                                        29


APPENDIX B: GE MAPS MODELING ASSUMPTIONS ......................................................                                                                   32
      B.l           nu
                OVERV~         ........................................................................................................................
                                                                                                                                                    32
     8.2                                   .
                SEAMS CHARGESAND WHEELING RS
                                           A                                     ...........................................................................      32




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I. EXECUTIVE SUMMARY

       Entergy Arkansas, Inc. ('EAI' or 'EA1 Opco") officially has given its notice to leave the existing
       Entergy System Agreement I'ESA") by December 19,2013. In May 2009, the Arkansas
       Public Service Commission (UAPSC') directed the Southwest Power Pool ("SPP')l as the
       Independent Coordinator of Transmission ("ICT) for Entergy* to conduct a Cost Benefit
       Analysis ('CBA') of EA1 as well as Entergy joining the SPP RT0.3 Shortly thereaffer, in June
       2009, the Federal Energy Regulatory Commission ('FERC') agreed to fund a CBA to study
       the costs and benefits of Entergy and Cleco Pow& joining the SPP RTO (*SPP-€ntergy
                               n
       CBA"). Subsequently, i August 2009, the APSC directed the SPP to perform within the
       context of the broader SPP-EntergY CBA, an Wl-specific CBA rSPP-€AI CBA') associated
       with EA1 becoming a full "standalone"member of the SPP RTO at the time it would leave the
       €SA. 5

       On September 30,2010, Charles River Associates ('CRA") Resero Consulting issued the
                                                                   and
       final report for the SPP-Enfergy 1 7 8 A . The SPP-Entergy CBA concluded that Entergy and
                                                  ~
       Cleco Power ioining the SPP RTO will yield significant economic benefits to the collective



1                                    s
       Southwest Power Pool, tnc. I a group of 57 members I Arkansas, Kansas. Loulslana, Mlsslsslppl, Mlssoud,
                                                                 n
       Nebraska, New MexIcu. Oklahoma, and Texas that sewe more than fve mllllon atstomers. Membership 1           s
       comprised of Investor-owned utllitles. munldpal syslems. generation and tmnsmlsslon woperatlves, state
       authorities, wholesale generators, power marketers, and Independent transmlsslon cornpanles. SPP5 footprint
       Indudes 29 balancing authorities and 50,575 miles of transmlsslon IInes. SFP w a s dedgnated by the FERC as a
       RTO In 2004. As an RTO, SPP ensures rellabls supplies of power, adequate transmisston Infrastruclure, and
       competitive wholesale prices of electrlcily. SPP Is a North Amedcan Electric Rellablllty Cop. ("ERCY Regional
       Entity.

2      Entergy Arkansas. Ina. Entergy Loulslana. LLC, Entergy Gulf States Loulslana LLC., Entergy Misslsdppl, Inc..
       Entergy New Orleans, Ina. Entergy Texas, Inc. (collectively,"Entergy"). These utility operating wmpanbs sewe 2.7
       mitllon customers In Arkansas. Louisiana. Misslsslppl. and Texas. Entergy is a member of the SERC Regtonal
       Entity.

3      Docket No. OM3C-U. Order No. 'IO.

4      CIecu Power U C I a regulated electric utility company that serves about 277.000 customers am%Loulslana.
                        s
       Clem Power is not atnentty a member of the reglonal market operated by the SPP, but I a member of the SPP
                                                                                             s
       Reglonal Entity.

5      Dodtet No. 0 8 136.U. Order No. 13.

6      See htlp~~.spp.orglpubll~tio~~ERC%2OSPP~20Entergy%20CBA~20Reporf~20Flnal.pdf.SPpEAl      As this
       CBA I a follow-on addendum study, the detalled descriptions of !he CRA rnodellng approach and Input data
             s
       contalned In Ihe SPP-Enlwgy CBA are not fully repeated herein. See the SPf-€nleqy CBA for further detall on
       these Issues.




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      SPPlEntergy r e g i ~ n . ~ net benefits to the Entergy region were highly dependent on the
                              The
      allocation o regional high voltage transmission expansion costs.8 Aside from the allocation
                  f
      of transmission expandon costs, the benefits to the Entergy region of joining the SPP RTO
      were relalively robust across the sensitivity scenarios examined. A number of important
      quatitative considemations were identified as well, with both qualitative benefits and offsetting
      costs incurred by Entergy if it joined the SPP RTO, Further addendum studies are planned to
      analyze additional sensitivity cases related to the SPP-Enfergy CBA.

      CRAg was engaged by SPP to perform the SPP-,541CBA using the models and input
      assumptions developed under the FERC-funded SfP-€ntergy CBA. The SPP-E4/ CBA was
      performed by CRA over a five-month period, and included an open and cotlaborative
      discussion with stakeholders of the study framework, modeling approach, input assumptions,
      and interim results throughout this period. Based on the analysis performed, we conclude
      that EA1 alone joining the SPP RTO, relative to operating on a standalone basis, wilt not yield
      significant economic benefits to the EA1 region or the collective SPWEntergy region.10

 ..
I I STUDY
        METHODOLOGY

      Two different cases were analyzed over the nine-year period from 2014 to 2022:

                I EA1 operates as a “standalone”entity not under the ESA (“HI
                 .                                                          Standalone Case‘),
                and

                2 EA], but not the Rest of Entergy, joins the SPP RTO rE4/ Jobs SPP Case.).
                 .

      In the €AI Standalone Case, the load serving entities in the EA1 region, including the EA1
      Opco, are assumed to be network service customers under the Entergy Open Access
      TransmissionTariff ( “ O A T ) , paying a load ratio share of the Entergy transmission system



7     The SPPIEntergy regton’ refers to all load and ganeraUon In the wnent EnntergySPP-Cleco Power transmission
      system footprint, Including that of merchant generators and cooperative and rnunidpal utilik.

8     The *Entergy reglon’ refers to the area withln the Entergy Lransmlsslon system footprint. and for purposes of the
      SPpEntergy CBA tnduded LouisianaGeneraffng and Loulslana Energy and Power Authority.

9     Prindpal study investigators for CRA were Ralph Lucianl, Bruce TsuchIda and Pablo Ruk. The findings and
      wnduslons contained In thls CBA are solely those of CRA.

lo    The -EA1 regIon‘ refers to all load and genemffon In the E9t tmnsrnlsslon system footprint Including that of merchant
      generators and cooperative and rnunldpal utilities. The ‘Rest of Entergy reglon’ refes to the area wlthh the Entergy
      transrnlsslon system footprlnt excluding the EA1 transmtssion syslem, and for purposes of thls study Includes
      Loulslana Generating and Loutslana Energy and Power Authority. The ‘Clem regfon’ refers to the area within the
      Clew trartsmlsslon system footprint as welt as the Clem Power load served by the Entergy transrntssfon system,
      and for purposes of thls study includes the City of Lafayette. The 5 P P reglon’ refers to the SPP tmnsmlsslon
      system footprint that I currently operating withln the SPP Energy lmbaianee Sewin? market
                            5




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       revenue requirements. A share of Entergy transmission system revenue is distributed to the
       €AI Opco to recover the revenue requirement of the E 1 Opco transmission assets. In the
                                                              A
       €AI Johs SPf Case, EA1 Opco transmission assets become part of the SPP transmission
       system and are transferred to the SPP tariff. Given that there are point-tppoint transmission
       charges applicable for ‘out” transactions (‘wheeling charges’) betweenSPP and Entergy
       today, EA1joining the SPP RTO results in the imposition of transmission wheeling charges
       between EA1 and the Rest of Entergy.

       SPP is assumed to continue in its capacity as ICT for the Entergy transmissionsystem in the
       EAI Standalone Case, and for the Rest of Entergytransmission system in the EA1 Jobs SPP
       Case, As the SPP RTO is working toward instituting a Day 2 market, a Day 2 market is
       presumed to be in place in the SPP RTO throughout the 2014-2022 study period.ll

       CRA analyzedthe impacts on the EAI, Rest of Entergy, Clem Power and SPP regions using
       the General Electric Multi-Area ProductionSimulation Model (‘GE MAPS”) model. GE MAPS
       is a detailed economic dispatch and production costing model that simulates the operation of
       the electric power system taking into account transmissiontopology.

       As a general matter, the greater level of coordinationand the elimination of wheeling charges
       between the SPP and EA1 regions in the €At Joins SPP Case should yield production cost
       savings through a more efficient system commitment and dispatch. However,the imposition
       o wheeling charges between E 1 and the Rest of Entergy in the €AI Jdns SPP Case will
        f                             A
       have an opposing impact. The allocationof any resulting savings to EAI, the Rest of Entergy,
       Clew Power and SPP i assessed by estimatingAdjusted Production Costs (Le., production
                              s
       cost plus purchase costs minus sales revenues) for each of these four regions. In turn, any
       savings in adjusted production costs for the EA1 regionwill be offset by additional
       administrativeand other costs incurred if EA1 joins the SPP RTO.

1.2.   FINDINGS

1.2.1. EAI Reg ion Net Benefits, Excluding Transmission Cost Allocation

       The net benefit for the EA1 region ifE 1 alone joins the SPP RTO, rather than operating on a
                                             A
       standalone basis, is summarized in Table I excluding transmission cost allocation impacts.
                                                   ,
       As shown, the overall net benefitl(cost)i ($127) million (Le.,a negative benefit or additional
                                                s




I
’      A Day 2 market refers to a twMettlement (day ahead and real-firne) energy market uslng hourty locatlonal marginal
       pdces and financial transmission rights (FTR5). Day 2 rnarkels are wrrenUy In place In PJM, t h Midwest ]SO. IS0
                                                                                                       ~
       New England and the New York 150.



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      cost) over the 2014 to 2022 period. In 2010 present value terns, the net benefitl(cost),
      excluding transmission cost allocation impacts, i ($65) milIion.l2
                                                      s
                              Table 1: 2013-2022 Benefits (Costs) to the EA1 RegIon
                        if EA1JoIns the SPP RTO, excludhg TmnsmIssion Cost Allocation
                               (in mlllfonso f doJiam;pos/bve numbers am benefits)


                 I I . Trade Benefits                  I            18
                                                                     .~
                                                                                 I           14
                  2. Capacity Benefits                               0                        0
                  3 Administrative Costs
                  .                                               (145)                     (79)




      As listed in Table Ithe hey costlbenefit measures assessed in this study are: I Trade
                           ,                                                           .
      Benefits, 2. Capacity Benefits, and 3. Administrative Costs. Each category is discussed in
      further detail below. Another key costlbenefit measure. transmission cost allowtion, is
      discussed in the next section.

      ITrade Benefits are comprised of:
       .

           =   Adiusted ProductionCosts, the production costs for the generating units In the EA1
               region (fuel, variable O&M and emission costs) plus purchased power costs net of
               energy sales revenue for the region13 For the EA1 region, adjusted production cost
               in the €AI Joins SPP Case increase by $145 miltion over the 2014-2022 period.
               Much of this increase results from the payment by the EA1 region of wheeling
               charges to SPP on exports to the Rest of Entergy in the €A/ Joins SPP Case.
               However. these SPP collections'wouldbe distributed to EA1 under the terms of the
               SPP tariff (and are accounted for in the transmission revenue step below).

          1    Transmission Revenue. Transmission charges would not be assessed for
               transactions between EA1 and SPP in the EA/Joins S f P Case, but would for
               transactions between WI (as part of SPP) and the Rest of Entergy. Moreover,
               exports from the EA1 region to W A , Associated Electric Cooperative. Inc. ('AECI")
               and the Midwest IS0 woutd be distributed to Wl perthe SPP tariff, rather than
               shared on a Ioad ratio share with the Entergy region. Because of the significant flow
               of power from EA1 to the Rest of Entergy and TVA, the EA1 transmission revenues
               (collected by the SPP RTO. and distributed under the SPP tariff to EAI) would



l2    A present value  rate of 8.0% was applled. An underlying Inflation rate of 2.5% was assumed. Benefits and cosh
      oyer the 2014-2022 pedcd cited In thls report are In 2010 presenl value dollars unless otherwise noled. ngures in
      the tables throughout thls report may not sum due to rounding.

l3    Fixed wsls that do not change between cases, such as depredation are not lnduded In this measure.




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                 increase by $159 million in the €41 Joins S P Case. Combined with the adjusted
                                                            P
                 production cost increase of $145 million noted above, this yields total trade benefits
                 of $14 million.

       2. CawcitV Benefits are comprisedof the savings to the EA1 regionthat woutd result from a
       lower planning reserve marginfor the EIA region in the €AI Joins SPP Case than in the €AI
       Sandalone Case. The ptanning reserve marginfor the EA1 reglon could be approximately
       20% in the EA1 Standalone Case, depending on EA1 region utilities' plans for future
       operations. White the specific planning reserue margin for EA1 region utilities in the ,541 Juins
       S P Case would be determined by the individual utilities, the minimum SPP reserve margin
         P
       requirement for members is currently 13.6%.t4 However, the reserve margin in the I4     31
       region over the 2014-2022 period, inclusive of all load and capacity in the region including
       IPP capacity, is projected to be significantly above 20%. Thus, the reduction in the planning
       reserve margin in the €AI Joins SPP Case would not result in avoiding the construction of
       any new capacity and would not therefore result in any capacity benefit savings to the EA1
       region as a whole during this period.

       Nonetheless, individual load serving entities in the EA[ region likely woutd need to contract for
       less capacity in the EA1 Joins SPf Case than in the EA/ Standalone Case during the 2014 to
       2022 period. As discussed in Section 1.2.4, this would result in a loss of benefitsto the lPPs
       in the EA1 region and an offsetting increase in benefits to the load serving entities in the EA1
       region in the EA1 Joins SPP Case.

       3. Administrative Costs are comprised of:

            .   ICT and RTO Administrative Charses. The estimated ICT charges for EA1 in the €A/
                Standalone Case over the 2014 to 2022 period are $30 million, reflectinga load ratio
                share of the total Entergy ICT charges. SPP estimates that the additional
                administrative cost incurred to include EA1 in the SPP RTO would be no greater than
                the costs that would be incurredto operate the EA1 load ratio share of the Entergy
                ICT in the €AI Standalone Case. fhe resulting EA1 charges under SPP Schedule 1A
                in the €4/ Joins S f P Case are $81 million, After consideration of ICT costs avoided,
                the resulting net additional cost to E1 in the EA/ Joins SPP Case is $51 miltion.
                                                      A

                Other Additional Costs: Over the 2014 to 2022 period, the EA1 region would incur
                $21. million in costs for additional staffing and equipment to interfacewith the SPP




'i4    The 20% figure is based on EAl's "Self-Provide' optlon as dlswssed In the Overview of EA Generation Supply
       Requlrementsand Supply Procurement Plans, EAI. May 2OtO PrelIrnlnary Technlmt Conference Report, page 10.
              s
       EA1 I ako wnsldering other opUons that may have lower resew margin requirements. As part of SPP. E 1 reglon4
       utilities would need io assess the avallablity and deliverabllity of reserves from adjacent regions and other fadots
       before potenUally adoptlng the SPP mlnimum plannlng resem margln.




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                RTO in the €A/ Joins SPP Case.15 In addition, the EA1 region would incur $7 million
                of additional FERC charges in the €AI Joins S f P Case.16

      In sum, as shown in Table j , the benefits of increased trade and capacity benefits do not
      exceed the administrativecost impacts for the EA1 region if EA1joins the SPP RTO relative to
      operating on a standalone basis. See Appendix A for more detail. These results for EA1
      joining the SPP RTO are In contrast to the significant benefits ($364million in 2010 present
      value dollars, excludingtransmission cost allocation) found for the Entergy region in the SPP-
      Enfergy CBA with Entergy and Clem Powerjoinjng the SPP RTO. We attribute the
      difference in results to the following key items:

                This CBA estimates the benefits of EA1joining the SPP RTO in comparisonto a case
                in which the EA1 region operates on a standalone basis. In contrast, the SPP-
                Entewy CBA estimated the benefits to Entergyof joining the SPP RTO in comparison
                to a case in which EA1 is part of the Entergy region.

                The imposition o transmissionwheeling charges between EA1 (as part of SPP) and
                                f
                the Rest of Entergy in the €AI Joins SPP Case, leading to a less efficient dispatch
                betweenthe Rest of Entergy and EA1 generatingassets.

           0    The heavily baseload (nuclear and coal-fired) generatingassets in the EA1 region.
                The commitment and dispatch of these types of facilities tend to be less affected by
                increasedregional integration, resulting in reduced dispatch savings opportunitiesif
                EA1 atone joins the SPP RTO, than if Entergyas a whole joins.

                O the 13 QFsin the Entergy region, only one is in the EA1 region. A5 described in
                 f
                the Sff-Enfergy   CBA, QFs in an RTO are assumed to become firm resources
                allowing for a more efficient commitment process. with only one QF moving to an
                RTO as part of EAI, there are fewer savings than if Entergy as a whole joins the SPP
                RTO.

      These four factors contributeto yield only a modest level of EA1 trade benefits in the €41
      Joins SPP Case. This modest amount of trade benefits is not significant enough to offset the
      payment by the EA1 region of RTO administrative costs.




l5    Based on an SPP assessment performed as part of this study, transmlsslon Improvements already planned for the
      M transmisston system will be suffident to allow the syslem to Integrate Into the SPP RTO without further additlonal
        I
      transmbslon Improvements.

j6       s                                                                                         s
      It I CRA's understandlng that the allocatlon of FERC annuaI charges to jurisdldonal entitles I under review by the
      FERC. For purposes of ihk study, it was assumed the wmnt policy would continue throughout the study period.




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1.2.2. Allocation of Regional Transmission Expansion Costs to EA1

      Projected high voltage transmission expansion costs in the SPP and EA1 regions would be
      allowted in the €AI Joins SPP Case under the 'HighwaylByway" allomtion mechanism
      recently approved by the FERC.17 As part of this study, SPP performed an analysis
      assuming differenttypes of transmission projects are allocable to EAI. The total dollars
      expended on transmission expansion in the SPPIEAI region are projected to be the same
      whether or not EA1joins the SPP RTO, Thus the total cost for transmission expansion to the
      SPPIEAI region as a whole does not change between the Cases. The aggregate allowtion
      results over the 2014-2022 period are captured in Figure 1 for the three different transmission
      cost allocation scenarios assessed by SPP.

       Figure 1 2014-2022 Transrnisdon Cost AlIocaff on Benefits (Costs) to the EA1 and SPP Regions if
               :
                                         EA1Joins the SPP RTO
                     (in mi//ons of ZDfO p s e n t d u e dol/ars;positivenumbers are benefib)




       In SPP Study 1, the EA1 region was assumed to contribute to the regional recovery o SPP
                                                                                            f
       upgrades completed after March 2006, coincident with the first regional recovery in SPP. In
       SPP Study 2, the EA1 region was assumed only to contribute to regional recovery o SPP
                                                                                          f



l7     Under t i approach approved by the FERC on dune 17,20tO, 100% of the costs of lransrnisston llnes of 300 kV and
              hs
       above and 33% of the msls of IInes above 100 kV and below 300 kV are recovered on a regional bask.



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        A

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       upgrades needed afkr a 'bright line" date of January 1,2013 (roughly consistentwith the
       start date of the period analyzed in this study). In SPP Study 3,the EA1 region was assumed
       only to contribute to regional recovery of SPP upgrades needed afler January 1,2013,
       excluding Balanced Portfolio and Priority Projects. The actual allocation would be dependent
       on a negotiated process between SPP and EN.

       About two-thirds o the SPP region's $609 million annual cost for EHV projects is for the
                          f
       Balanced Portfolio and Priority Projects. As a result, as shown in Figure 1, a slgnificant
       amount of costs are transferred to the EA1 region in SPP Study 1 and SPP Study 2,but not
       SPP Study 3 7he need for additional EHV projects in the EA1 region could be the subject of
                    .
       further regional transmission planning analyses. To the extent such projects were approved,
       the costs would be shared with the SPP region in the E41 Joins SPf Case.

       Combined with the benefitd(ms!s) of ($65) rnilIion to EA1 if it joins the SPP RTO described In
       the precedingsection, including the range i the allocation of transmission costs to EN would
                                                   n
       yield a range of net benefitsl(costs)of ($52) to ($372)million.

1.2.3. Net 8enefits for the SPPlEntergy Region

       Shown in Table 2 are the net benefits individuallyto the EAI, SPP, Rest of Entergy and Cteco
       Power regions if EA1 joins the SPP RTO. As shown in Table 2, the net benefits to the SPP
       and Clem Power regions are positive, while those to the EA1 and Rest of Entergy regions are
       negative. The net benefit to the collective SPPEntergy region i somewhat negative as well,
                                                                       s
                                                              s
       while the net benefit to the combined SPPIEAI region i positive.

        fable 2: 2014-2022 Benefits (Costs) to the EAI, SPP, Rest of Entergy and Cleco Power Regions
                                          If EA1Joins the SPP RTO
                   (in ml//ons of 2OfOpresent wiue doifam:positlve numbers are benefit%)



     I Trade Benefits               I      14      I       54        I   ($78)      I     25   1      15    I
      Administrative Costs                (79)             51              0               0         (28)
      Transmission CostAttocation            to
                                        (307) 13       (13) to 307         0               0           0
      Net Benefits


       As shown Table 2:

                Induding transmissioncost allocation, the net benefitl(cost) to the EA1 region in the
                €41 Joins SPP Case ranges from ($372) to ($52) rniltion. The transmission cost
                allocation in which Balanced Portfolioand Priority Projects are excluded provides an
                additional $13 million of benefits to the EA1 region in the HI Joins SPP Case, but
                this is not enough to yield an overall positive measure of benefits for the EA1 region.




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               The SPP region benefits from the sharing of SPP RTO administrative costs with EA1
               in the EA1 Joins S f f Case, yielding a reduced administrative cost burden for the
               existing SPP region. A full sharing of post-2006 regional transmission expansion
               costs would lead SPP region benefits to be as high as $412 million. Given the SPP
               region benefits, the net benefit to the combined SPPIEAI region is a positive $40
               million.

               The Rest of Entergy region is negatively impacted by the loss of the significant
               through and out revenue for transactions that exit the Entergy transmission system
               from the EA1 region. In the EA1 Standalone Case, this revenue is shared on a load
               ratio basis with the rest of the Entergy transmission system. In the €AI Joins SPf
               Case, this revenue largely accrues to the EA1 region under the SPP tariff.

1.2.4. Other Considerations

       SubreqionalAllocations. No furlher sub-allocations of EA1 region benefits were performed in
       this study. Using the detailed GE MAPS results from this study, Entergy i separately
                                                                                s
       performing an assessment of the impact to EA[ and other Entergy operating companies.
       Further suballocation would require development of a simplified allocationmethodology
       relative to the methodology applied by CRA for the EA1 region as a whole.

       Enterqy OPCOCaaacitv Benefits. As part of this CBA, CRA was asked by study stakeholders
       to assess the potential for the E 1 Opco to obtain capacity benefits. As noted above, for the
                                        A
       EA1 region as a whole, there would be no capacity benefits, as the region is well above the
       expected EA1 standalone planning reserve margin. CRA examined the EA1 Opco reseTve
       margin, and determinedthat the EA1 Opco is currently well below the expected standalone
       planning reserve margin.

      With a 20% standaIone reserve margin in the EA1 Standalone Case and a 13.6% reserve
      margin in the €41 Joins SPP Case, we estimate that the E 1Opco would avoid procuring
                                                                  4
      between 300 and 400 MW of capacity during the 2014 to 2022 period if EA1joins the SPP
      RTO. At an estimated 'long market' capacity price of $3l/kW-year, the value of the EA1
      capacity payments avoided in the EA1 Joins SPP Case would be approximately $10 million
      per year, with a present value over the 2014-2022 period of $63 million. In practice, the
      actual price for capacity in the region will depend on how far above the reserve margin the
                                      n
      region is, the capacity needs i bordering regions that could contract for EA1 region
      resources, and negotiations between buyers and sellers of capacity.

       Enterw OPCO   Transmission Arransements: In consuItation with SPP and Entergy
       transmission personnel, the basic framework of the network arrangements that would take
       place i an €AI Sandalone Case was identified. Transmissionequalization under the ESA's
              n
                                                 A n
       MSS-2 would no longer be applicable for E 1 i 2014. Certain aspects of these EA1
       standalone arrangements are not fully formulated by Entergy as yet. Identified issues
       included:




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              Revenue distribution under the current Entergy tariff would be based on a load ratio
              share resulting in the potential for the allocation of Entergy transmission revenues to
              E 1 to differ from the EA1transmission revenue requirement. (As part of SPP,the
               A
              EA[ network transmission charges and the EA1 transmission revenues allocated
              under the SPP tariff would be aligned.)

              The EA1 region’s paymentlreceipt of point-to-point (‘PTp3 transmission charges for
              external designated network resources (“DNRs’) woutd vary between cases. In the
              EA1 Standalone Case, the EA1 region would need to purchase about I 0 0 MW of PTP
              transmission from SPP for EA1 region DNRs located in SPP. In the €41 Joins S P  P
              Case, EA1would need to purchase about 300 MW of PTP transmissionfrom the Rest
              of Entergy for EA1 region DNR’s located in the Rest of Entergy, and the Rest of
              Entergy would need to purchase from E 1 (as part o SPP)about 1,000 MW o PTP
                                                    A             f                         f
              transmission for Rest of Entergy DNRs. On net, this could yield additional
              transmission revenue for the EA1 region in the €AI Joins S f P Case of about $10
              million per year.

      Sensitivitv Analyses. No additional sensitivity cases were run in this CBA. Entergy has
      asked CRA to perform sensitivity cases for this CBA as a follow-on effort. The specific
      assumptions applied in those sensitivity cases will be selected based on discussion with
      study stakeholders.

      Qualitative Issues. The general qualitative consideration of Entergy joining the SPP RTO
      examined in detail in the SPP-Entergy CBA were not reexamined in this CBA, as they would
      be expected to apply to EA1 joining the SPP RTO as well. The qualitative issues examined in
      the SPP-Enfergy CBA included efficiency, competitiveness, transparency and administrative
      burden costs and risks. Substantial qualitative benefits were found to accrue to the Entergy
      region through joining the SPP RTO, including improved operationat transparency, improved
      competiveness via resolution o base case overload issues, improved efficiency through
                                     f
      resolving various ICT and WPP issues, Improved transmission planning and interconnection
      process, and potentiallylower regulation and capacity reseme requirements. However,
      additional costs were also found to accrue to the Entergy region. These include risks and
      costs associated with transmission system access, Day 2 market transitional risks, and the
      imposition of SPP‘s governance structure. The qualitative analysis also recognized that
      some of the impacts associated with joining the SPP RTO may be achieved by continued
      actions of the E-RSC without Entergy’s formal inclusion in SPP.




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2.     INTRODUCTION AND BACKGROUND

       EA1 officially has given its notice to leave the existing ESA by December 7 9,2013 In May
                                                                                         .
       2009, the APSC directed SPP as the ICTfor Entergy to conduct a C8A of EA1as welt as
       Entergy joining the SPP RTO. Shortly thereafier, in June 2009, the FERC agreed to fund a
       CBA to study the costs and benefits of Entergy and Cleco Power joining the SPP RTO (‘SPP-
       Entergy CBA’). Subsequently, in August 2009, the APSC directed the SPP to perform within
       the context of the broader SPP-EntergY CBA, an EAI-specific CBA (“SPP-HICBA”)
       associated with EA1 becoming a full ‘standalone” member o the SPP RTO at the time it
                                                                     f
       would leave the ESA.

       CRA was engaged by SPP to perform the SPP-€AI CBA using the models and input
       assumptions developed under the SPP-Entergy CBA. The SPP-€AICBA was performed by
       CRA over a five-month period, and included an open and coltabomtiue discussion with
       stakeholders of the study framework, modeling approach, input assumptions, and interim
       results throughout #is period.

       The CRA team pioneered some of the original RTO Cost Benefit analytical approaches and
       modeling tools and has applied them in a series of significant regional RTO Cost Benefit
       Studies, to include:
                    2002       RTO West Study of Pacific Northwest

                    2002       Southeast Regulatory Utility CommissionsConference (“SEARUC’)
                               Study of Southeast Region
                    2003       Dominion Vtrginia Power‘sPJM Study
                    2003       U.S. Department of Energy’s SMO Study

           0        2004       ERCOT StakeholdersCost Benefit Study

                    2005       SPP Cost Benefit Study, led by SPP Regional State Committee
           0        2007       Aquila Missouri Cost Benefd Study (Midwest IS0 and SPP)

                    2007       AmerenUE Cost Benefit Study (Midwest ISO, SPP, ICT)

                    2010       Big Rivers Cost Benefit Analysis (Midwest EO)

       In addition, the CRA team utilized similar analytical approaches and modeling tools in the
       conduct of the 2006 U.S. Department of Energy Congestion Study prepared pursuant to the
       2005 Energy Policy Act for the purpose of deslgnating National Interest Electric Transmission
       Corridors.

       CRA used GE MAPS to perform the energy modeling in this study. GE MAPS is a detailed
       economic dispatch and production costing model that simulates the operation of the electric



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       power system taking into account transmission topology. T3e GE MAPS model determines
       the security-constmined commitment and hourly dispatch of each modeled generating unit,
       the loading of each element of the transmission system, and the locational marginal price
       (LMP) for each generator and Joad area. The GE MAPS model was used by CRA i alt of the
                                                                                           n
       prior RTO market cost benefit studies it has performed, as well as to support the US.
       Department of Energy in conducting the August 2006 National Electric Transmission
       Congestion Study.

       The following sections describe the study methodology, results and assumptions. In Section
       3, the study methodology is described. Section 4 describes the individual cost and benefit
       measures assessed in this study. Section 5 summarizes the study's quantitative results, and
       Section 6 discusses other considerations. Appendix A provides additional detail on the study
       results, and Appendix 8 provides further detail regarding the GE MAPS input assumptions.


3.     STUDY METHODOLOGY

3.1.   BASIC    METHODOLOGY
            STUDY

       Two different cases were analyzed over the nine-year period from 2044 to 2022:

               I EA1 operates as a "standalone" entity not under the ESA rEAl Standalone Case"),
                .
               and

               2. EA], but not the Rest of Entergy, joins the SPP RTO r€AI Joins SPf Case").

                                                             n
       In the €AI Standalone Case, the load serving entities i the EA1 region, including the EA1
       Opw, are assumed to be network service customers under the Entergy OATT, paying a load
       ratio share of the Entergy transmission system revenue requirements. A share of the Entergy
       transmission system revenue is distributed to EA1 Opco to recover the revenue requirement
       of the EA1 Opco transmission assets. In the €AI Joins SPP Case, EA1 Opco transmission
       assets become part of the SPP transmission system and are transferredto the SPP tarifF.
       Given that there are point-tepolnt transmission charges applicable for "our transactions
       ('wheeling charges")between SPP and Entergy today, EA1 joining the SPP RTO results in
       the imposition of transmission wheeling charges between E 1 and the Rest of Entergy.
                                                                  A

       SPP is assumed to continue in its capacity as ICT for the Entergy transmission system in the
       €41 Standalone Case, and for the Rest of Entergy transmission system in the €41 Jaolns SPP
       Case. As the SPP RTO is working toward instituting a Day 2 market, a Day 2 market is
       presumedto be in place in the SPP RTO throughout the 2014-2022 study period.

       CRA analyzedthe impacts on the EAI, Rest of Entergy, Clew Power and SPP regions using
       GE MAPS. In this study, GE MAPS was set up to model the Eastern Interconnection of the
       United States and Canada. The GE MAPS analysis was performedfor the years 2013,2016,




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       2019 and 2022, with the results for interveningyears interpolated. CRA used its current GE
       MAPS data base to perform the analysis, supplemented by confidential input data provided
       by stakeholders with respect to generation unit operating characteristics, and other key
       inputs.18

       In the GE MAPS modeling, there i a commitment (next-day) step and a dispatch (real-time)
                                           s
       step, In the commitment process, generating units in a region are turned on or kept on in
       order for the system to have enough generating capacity availableto meet the expected peak
       load in the region for the next day. GE MAPS then uses the set of committed units to
       dispatch the system on an hourIy real-time basis, whereby committed units throughout the
       modeled footprint are operated between their minimum and maximum aperating points to
       minimize total production costs.

       As a general matter, the greater level of coordination and the elimination of wheeling charges
       between the SPP and EA1 regions in the ,541 Joins SPP Case should yield productioncost
       savings through a more efficient system commitment and dispatch. However, the imposition
       of wheeling charges between EA1 and the Rest of Entergy i the E41 Joins SPP Case will
                                                                   n
       have an opposing impact. The allocation of any resulting savings to EAI, the Rest of Entergy,
       Clem Power and SPP is assessed by estimating Adjusted Production Costs (Le., production
       cost plus purchase costs minus sales revenues) for each of these four regions. In turn, any
       savings in adjusted production costs for EA1will be offset by additional administrative and
       other costs incurred if EA1 joins the SPP RTO.

 ..
32     SEAMS CHARGES

       GE MAPS was used to model different impediments to SPP-EAl-Rest of Entergy trade under
       the €AI Standalone Case and the EA1 Joins S f P Case. The impedimentsto trade applied in
       this study include commitment and dispatch seams charges. Seams charges are applied by
       CRA in the GE MAPS model at the 'seam" or border between regions (e.g., between EA1 and
       Rest of Entergy, Rest of Entergy and SPP, Rest of Entergy and Clew Power, SPP and the
       Midwest ISO, and Entergy and Southern Company). In the absence of seams charges, GE
       MAPS will optimize the commitment and dispatch of generation across the entire Eastern
       Interconnect as if it were one balancing authority with traders and operators having perfect
       informationabout all load, resources and transmission congestion, and with no transmission
       wheeling charges payable for regional imports and exports.

       In practice, there are impediments to trade that take place on a real-time basis, inctuding
       wheeling charges and imperfect knowledge regarding flows outside of the control area. CRA
       discussed the seams charges extensively with stakeholders during the course of the SPP-
       Enfergy CBA as described in detail in that study. Dispatch seams charges between SPP,


I*     A full listing of t h GE MAPS modeling Inputs Is provided In Appendix B of the SfPEOtergy CBA. Key GE MAPS
                             ~
       assurnpUons modified for this SPPE4I CBA are mptured In Appendk B In this report.




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       Entergy and Cleco Power were set at applicable non-firm off-peak wheeling rates plus a
       dispatch friction of $31Mwh in the Status Quo Case in that C3A.

       For the SPf-EAICBA, certain modificationsto the seams charges were necessaryto reflect
       EA1 standalone operations, and were discussed with study stakeholders. As shown in Table
       3, in the ,431 SIandalone Case, there i an assumed dispatch friction but not a wheeling
                                             s
       charge between EA1 and the Rest of Entergy. This is because the EA1 region i assumed to
                                                                                      s
       be a network transmission customer of the Entergy transmission system. In the ,541Joins
       SPP Case, the dispatch seams charges between SPP and EA1 were set to zero reflecting the
       elimination of wheeling rates between these regions and the joint RTO real-time energy
       market. In turn, the seam between EA1 and the Rest of Entergy becomes equal to the SPP
       seams charges with the Rest of Entergy.

       Table 3 Dispatch Seams Charges Applied In GE MAPS in the SPPIEAlIRestof Entergy RegIon 19
              :
                              Dispatch Friction + wheeling Charge ($/IMWh)




     1 FromSPP            I          -      I    3+2      1     3+2     I     -      I     3+2      I      0      I
     I From RestofEntergy I         3+3
                                 _____
                                            I     -       I     3+0     I    3+3     I      -       1     3+3     I
                                                          I      -
                            ~~




      From EA1                      3+3          3+0                    I     0            3+2      1      *




       The dispatch seams charges discussed above are applied in GE MAPS to optimize the
       generation of all units in the modeledfootprint that have been already committed to operate in
       the GE MAPS commitment step. In addition, in deciding which units are most economic to
       commit to operate, commitmentseams charges are also applied in GE MAPS. Commitment
       seams charges reflect that a control area with responsibility for retiably committinggenerating
       units for operation the next day cannot fully rely on units outside of the control area over
       which the control area has no direct control.

       To model the commitment process, CRA defines major "commitmentpools' in GE MAPS in
       which units inside the pool are committed to run to ensure reliable service within the
       commitment pool without considerationof edema[ non-firm resources. These major
       commitment pools include, among others, PJM, the Midwest [SO, SPP, Southern Company
       and TVA. To the extent that h e commitment process for regions within a major commitment
       pool is not jointly optimized, CRA applies a $10 per MWh commitment hurdle between these
       regions. That is, generating units in a commitment pool will not be committedto meet load in


Ig     SImllar seams charges were applied between Clew Power, the City of Lafayette. Louisiana Energy and Power
       Authority, and Louhlana Generating inside of the SPP/Entergy region. These seams charges did not change
       belween mses. See Appendix B for further detal.



                                                                                                        Page 14
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        A

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        another region within the same commitment pool unless there i a least a $10 cost advantage
                                                                    s
        over units that would be available within that regionz0

        In the SPP-Entergy CBA and in this study, the SPP1Entergy region was treated as a major
        commitment pool. In the €AI Standalone Case, commitment seams charges were set at
        $IOIMWh between EA[, the Rest of Entergy and SPP. As shown i Table 4, the charge
                                                                        n
        between EA1 and SPP was set at zero in the €AI Juhs SPP Case, reflecting the joint RTO
        commitment process that would take place. See Appendix B for further detail.

         Table 4: Commitment Seams Charges ($IMWh) Applied In GE MAPS in the SPPIEntergy Region




       From SPP                        -               IO             10            -              10             0
       From Rest of Entergy            IO              -              IO            10             I              10
       From EA1                        IO             10              -              0             10             -

3.3.                    FOR QFS IN ENTERGY
        MODELING APPROACH

        There are seventeen QFs modeled with contractual rights to "put"or sell energy into the                       '



        Entergy system at the QFs discretion with respect to timing and amount. However, only one
        of these QFs is located in the EA1 region. QFs serve a host load, and may or may not have
        energy available at any given time to sell into the market. As part of the study process,
                                                                                              n
        Entergy confidentially provided historical QF put sales (MWh) for these QFs to use i CRA's
        GE MAPS modeling.
        As discussed in the SfP-€nfergy CBA, upon joining an SPP Day 2 RTO, FERC may rule,as
        it has in other Day 2 markets,that the Entergy QF put options no longer apply. If so, the PFs
        would have to provide prior notice of self scheduled output to the RTO system operator. That
        is, the QFs would effectivelyoperate as IPPs, albeit with the added limitation of needing to
        serve their host load. In this SPP-EAI CBA, only the single QF lowted in the EA1 region
        would change status between cases.

        €41 Standalone Case: The EA1 region and Rest of Entergy region are committed day-ahead
        without QF energy considered, and then the system i dispatched in rea!-time with QF energy
                                                                s
        included at historical levels. In practice, this means that the system must commit, or turn on,



2o      Modeling commitment pools, rather than applying cornrnltment seams charges behveen all balandng regions In the
                                                              process In GE MAPS.
        Easlem Interconnect. greailyspeeds up the op~rnkazatlon




                                                                                                            Page 15
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        more units than it would if the QFs output were known in advance. This increasessystem
        productioncosts.

        EAI Joins SPP Case: The treatment of the QFs in the Rest of Entergy region is unchanged
        from that of the EA/ Standalone Case. 7he QF in the EA1 region becomes part of the SPP
        RTO and is treated as available for commitment at historical put levels. That is, the QFs
        output at historical put levels i presumed to be scheduled, and thus available for
                                        s
        commitment This reduces the commitment of other generators, and increases market
        efficiency,but also assumes that the QF's output would be identical to historical levels
        despite the existence o a transparent Day 2 market, With QF output the same in both the
                                 f
        EA1 Standalone and EA/ Joins SPP cases, the QF costs would be unchanged.

        The treatment of QFs in the €AI Joins SPP Case is a potentiallyimportant source of benefits.
        CRA understandsthat stakeholders are considering addendum study cases in which the
        treatment of QFs i modeled in alternative ways.
                         s

3 3 1 IPP Modeling
 ..,

        Independent Power Producers ('IPPs') in the EAI, Rest of Entergy and Cleco regions were
        identified with the assistance of study stakeholders. Consistent with the SPP-f ntergy CBA,
        an additional commitment hurdle was put in place for these lPPs in the EA/ Standalone Case
        of $51MWh to reflect the impediments to optimal commitment of these lPPs absent a
        centralized day-ahead market. For those lPPs located in the EA1 region, this IPP
        commitment hurdle was not included i the EAi Joins SPP Case which has the EA1 region
                                                 n
        operating under a RTO market. Once committed, lPPs are dispatched in GE MAPS similarly
        to all other generating units in the region, Le., based on the operating costs (fuel, emissions,
        variable O&M) of the units.


4.      BENEFITS AND COSTS

4.1 *   TRADE BENEFITS

        The GE MAPS cases analyzed in this study will reflect varying degrees of impediments to
        trade between EAI, Rest of Entergy and SPP (e.g., seams charges, QF and IPP commitment
        and dispatch). Reductions in the impediments to trading should generally result in production
        cost savings. Generation productloncosts are actual out-of-pocket costs for operating
        generating units that vary with generating unit output; they are comprised of fuel costs,
        variable O&M costs, and the cost ofemission allowances. By decreasing impediments to
        trading, additional generation from utility areas with lower cost generation replaces higher
                           n
        cost generation I other utility areas. These productioncost savings yield the 'trade benefits"
        referred to in this study.




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         Increases or decreases in production cost in any particular utility area, by themselves, do not
         provide an indication o welfare benefits for that area, because that area may simply be
                                f
         importing or exporting more power than it did under base conditions.

         For example, a utility that increases its exports would have higher production costs (because
         it generates more power that i exported) and would appear to be worse off if the benefits
                                         s
         from the additional exports were not considered. Similarly, a utility that Imports more would
         have lower production costs, but higher purchased power costs. In either circumstance an                    -
                                              -
         Increase in imports or exports an accounting of the trade benefits between buyers and
         sellers must be made in order to assess the actual impact on utility area welfare. Increased
         trading activity provides benefits to both buying parties (purchasesat a lower cost than
         owned-generation cost) and selling padies (sales at a higher price than owned-generation
         cost). In practice, the benefits of increased trade are divided between buying and selling
         parb'es.For example, the 'split-savings' rules that govern traditional economy energy
         transactions between utilities under cost-of-service regulation result in a 50-50 split of trading
         benefits.2'

         In this study, we quantified trade benefits in two categories: 1) Adjusted ProductionCosts,
         and 2) Transmission Revenues. Each is discussed in turn below.

4.1.1.   Adjusted Production Costs

         Traditional cost-of-service regulation differs from a fully deregulated retail market, in which
         individual customers andor load-sewingentities buy all their power from unregulated
         generation providers at prevailing market prices. In such a deregulated mafiet, benefitsto
         load can be ascertainedmosffy in terms of the impact that changes to prevailing market
         prices have on power purchase costs. For the SPPlEntergy region, in which cost-of-service
         rate regulationis in effect, the energy portion of utility rates reflects the production cost for the
         utility's owned generating units, plus the cost of 'off-system' purchased energy, net of
         revenues from 'off-system' energy sales (Le., Adjusted Production Costs). In turn, utility
         customers under cost-of-service regulation pay for the fixed costs of owned-generatingunits
         through base rates. Deriving trade benefits for EA[, the Rest ofEntergy and SPP thus
         requires an analysis of both the production cost o operating the generating plants and the
                                                             f
         associated trading activity (purchases and sales).




21       Consider a slmple hvo-eornpany example. Assume there is a $16 marglnal cost to generate In Company A's control
         area and a $20 marghat cost to generate In Company 6s control area and there I no trade. Now assume through a
                                                                 '                           s
         reduction in tmde Impediments h a 1 1 MW a n be fraded from A to B over the Inter-tie between A and 8. Company A
         will genemfe 1 MW more at a produdon cost of $16, while Company B will generate t M less at a produdon cost
                                                                                                   W
                                                                                 -                         s
         savings of 520. Thus, the total saving In produdlon cost is $4 (I.@.. $16). If the trade p r b I set, for example.
                                                                              $20
                                                                                                 -
         at a 50150 split savings price, Company A will receive 818, for a b d e benefit of $2 ($18 S16). and Company B will
                                                -
         pay $18,for a trade benefit of $2 (520 f18). The tolal trade benefif of f 4 ($2 + $2) will match the total production
         cost saving of $4.




                                                                                                                    Page 17
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       The productioncost of the generating units is derived directly from the MAPS outputs for
       each case.= Note that a simple calculation ofregionalAdjusted Production Costs using
       LMPs will miss the economic impact of price differentials between buying and selling regions
       (Le,, trade benefits). As such, for purposes of deriving the impact of trading with adjoining
       regions, CF7A applies a methodology developedin consultationwith Missouri stakeholders
       during CRA's work in the 2007 RTO cost-benefit studies for Aquila and AmerenUE. In the
       absence of existing FTRs to help evaluate the value received by trading parties resulting from
       these price differentials, CRA captures these impacts through a split-savings methodology.
       Under this methodology, the net hourly GE MAPS tie-line ffows into and out of EAI, the Rest
       o Entergy, SPP and Clew Power are used as a proxy for purchase and sale transactions by
        f
       EAI, the Rest o Entergy, and SPP.
                       f

       In each hour, the net interchangeis derived using EAI, Rest of Entergy, and SPP tieline
       Rows to assess whether EAI, Rest of Entergy, and SPP are net importers (purchasers) or
       exporters (sellers)of power. If a net purchaserin the hour, the net purchase amount is
       multiplied by the weighted average split-savings price for tie-lines with Rows into the control
       area. Similarly, if a net exporter (seller) in the hour, the net sale amount is multiplied by the
       average split-savings price for tielines with outgoing fl0ws.~3 We obtained the tieline prices
       by defining a 'node' in GE MAPS at each end of the tie-line. Similar calculations were
       performed for trading between the other regions adjoining SPP, EA1 and the Rest of Entergy
       (e.g., the Midwest ISO, TVA, and Southern Company).


4.1.2. Transmission Revenue

      A simple calculation of regionalAdjusted Production Costs using LMPs also will miss the
      economic impact of the elimination of wheeling rates on regional transmission rates, and thus
      the net benefits to the EAI, Rest of Entergy, and SPP regions. Adjusted Production Costs in
      the ,541 Joins SPP Case will decrease as a result of the elimination o inter-SPP/EAl wheeling
                                                                             f
      rates (Le., purchase prices will be lower and sales prices will be higher). At the same time,
      Adjusted Production Costs in the EAI Joins SPP Case will increase a s a result of the
      institution of inter-EAllRest of Entergy wheeling rates.

       In turn, wheeling revenues wilt no longer be collected by the SPP and Entergy transmission
                                           A
       provider for transactions between E and SPP, but will be collected by the SPP and Entergy
       transmission providers for transactions between EA1 and the Rest of Entergy. All else equal,



22     The production wsts for lPPs are Included In each reglon's measure of production costs along With that of UtIlily-
       owned generating unlts. Uplift revenues for utililyswned units need no1 be directly considered In the adjusted
       productlon cost wlwlaffon as all fueI wsk are passed through to ratepayers. The uplifl forthe tPPs I essentrally a
                                                                                                            s
       transfer payment between load and the lPPs that Mn impact the sham of benefits a w i n g l o IfPs and load.

       Each regton's share of the output of Jolntly-ownedunki that are physically located outside of fhe reglon are netted
       from the reglon's tle-line flows In determlnlng the reglon's net expo& and Imports.
CBA of EA1 Joining the SPP RTO

October 27,2010                                                            Charles River Associates



       the loss and gain in transmission revenues will result in a corresponding adjustment to
       transmissionrates in order for the transmission providers to recovertheir revenue
       requirement. As such, in assessing regional benefits, the impact of the lost (and gained)
       wheeling revenues are tracked and incorporated into the assessment of the overall costs and
       benefits.

       The tieline Rows in GE MAPS do not lend themselves to a direct calculation of the absolute
       level of transmissionrevenues given that the GE MAPS flows in each hour are actual net
       flows across each tieline (Le., including"loop flow'), and transmissionrevenues are based
       on scheduled transactions. As such, with assistance from SPP, €ntergy and Clew Power
       transmission personnel, the annual transmission revenue collected for point-tepoint
       transactions between SPP, Entergy and Clem Power were assessedfor the four-year period
       from 2006 to 2009. An annual average was then calculated. The historical inter-
       SPPIEntergylCleco Power transmission charges were tracked separately by Point of Delivery
       ('POD") and Point of Receipt ('POR') and then averaged (Le., split 50150). Consistent with
       the use of a split-savingsmethodology to allocate the benefits of purchasekale transactions
       in the adjusted production cost calculation discussed above, these transmissioncharges
       were allocated 50150 between the importing (POR) and exporting (POD) regions. See the
       SPP-Entergy CBA for further detail.

       In the €AI Standalone Case, the EA1 region is allocated a load ratio share (approximately
       26%) of the Entergy system's transmission costs and revenues, given that the load-serving
       entities within EA1 would be network customers of the Entergy transmissionsystem.

       In the €41 Joins SPP Case,

              The revenue from transactions that exit EA1 io external areas (e.g., Midwest ISO,
              AECI, TVA) is no longer shared on a load ratio basis with the Rest of Entergy, and
              instead accrues to EA1 under the SPP tariff. Simitarly, the revenue from transactions
              that exit from the Rest of Entergy is no longer shared with EAI.

              The transactions that exit EN to the Rest of Entergy now accrue wheeling charges
              (as part of the SPP tariff) and these revenuesaccrue to EA1 under the SPP tariff.
              Similarly, the Rest of Entergy collects the wheeling revenue for transactions that exit
              the Rest of Entergy to EAI.

      To estimate the impact of fhese items in the €41 Joins SPP Case, the wheeling revenues and
      costs for transactions between EA[, SPP, the Rest of Entergy, and Clem were calculated for
      each of these regions in both the EA1 Standalone Case and the ,541 Joins SPP Case using
      MAPS tieline Rows. The change in wheeling revenuesand costs between the Cases was
      added to the each region's historical-basedfigures used in the €41 Sfandalone Case to
      estimate each region's transmission revenues and costs in the EAI Jdns SfP Case.

       For the impacts of transmission revenues between SPP,EA1 and Entergy and major
       neighbors such as TJA, the MAPS physicalwheel charges between SPPIEAliEntergyand



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October 27.2010                                                             Charles River Associates



       other major neighbors also were tracked and the change in these wheeling revenues and
       costs between cases are included in the net benefits calculation.

      In the SPP-Enfergy CBA, SPP pe~omed analysis of the allocation of transmission
                                                an
      revenue that would take place in the Join SPP Case if the transmlssion revenues collected by
      the SPP transmission provider were allocated under the terms of the SPP tariff to individual
      transmission owners (e.g., Entergy and Cleco Power in that CBA). A similar analysis for this
      CBA for EA1 as a member of SPP has not been completed as of the issuance of this report:
      however, the impact o this step In the SPP-Entergy CBA was relatively small.
                           f

4.1.3. Trade Benefit Results

      Shown in Table 5 are the trade benefits individualty to the EAI, SPP, Rest of Entergy and
      Clem Power regions if EA1joins the SPP RTO. As shown in Table 5, the trade benefits to
      the EAI, SPP and Clem Power regions are positive, white those to the Rest o Entergy region
                                                                                    f
      are negative. The net benefit to the collective SPPlEntergy region i $15 million.
                                                                          s
        Tabfe 5: 2014-2022 Benefits  (Costs) to the EAI, SPP, Rest of Entergy and CIeeo Power Regions
                                           if EA1 Jolns the SPP RTO
                    (in millions ofZW0presenf value doi/am;positive numbem are benet%)




      Transmission Revenue
      TotaI Trade Benefits
                                         159
                                         14
                                                 - - 2
                                                 (72)
                                                     - -
                                                       54
                                                                       (135)
                                                                        (78)            25
                                                                                                  (46)
                                                                                                  IS


      For the EA1 region, adjusted production ms in the &AI Joins SPP Case increase by $145
                                               ot
      million over the 2014-2022 period. Much of this increase results from the payment by the EA1
      region of wheeling charges to SPP on exports to the Rest of Entergy in the €41 Joins SPP
      Case. However, these SPP collections would be distn'butedto EA1 under the terms of the
      SPP tariff.

      As noted above, transmission charges would not be assessed for transactions between EA1
      and SPP in the €41 Joins SPP Case, but would for transactions between EA1 (as part of SPP)
      and the Rest of Entergy. Moreover, exports from the EA[ region to TVA, AECI and the
      Midwest I S 0 would be distributedper the SPP tariff, rather than shared on a load ratio share
      with the Entergy region. Because of #e significant flow of power from EA1 to the Rest of
      Entergy, TVA and AECI, the EA1 transmission revenues (collected by the SPP RTO, and
      distributed under the SPP tariff to EAI) would increase by $1 million in the &AI Joins S f P
                                                                    59
      Case, Combined with the adjusted production cost increase of $145 million noted above, this
      yields total trade benefits of $14 million.




                                                                                              Page 20
CBA o E 1 Joining the SPP RTO
     f A
October 27.201 0                                                            Charles Rivet Associates



       SPP. the Rest of Entergy and Cleco all have decreases in adjusted productioncosts in the
       EA/ Joins S f f Case. However, the Rest of Entergy has considerable lost transmission
       revenue in large part because much of the transmission revenue for exports to external
       entities accrue to the EA1 region in the €At Joins SPP Case.

       These relatively low trade benefit results far EA1joining the SPP RTO are in contrast to the
       significant benefits ($594 million in 2010 present value dollars, excluding transmission cost
       allocation) found for the Entergy region in the SPf-EntergY CBA with Entergy and Cleco
       Power joining the SPP RTO. We attribute the difference in results to the following key items:

               This CBA estimates the benefits of EA[joining the SPP RTO in comparison to a case
               in which the EA1 region operates on a standdone basis, In contrast, the SPP-
               Entergy CBA estimated the benefits to Entergy of joining the SPP RTO in comparison
               to a case In which H I is part of the Entergy region.

               The imposition of transmission wheeling charges bebeen EA1 (as part of SPP)and
               the Rest of Entergy in the €41 Joins SPP Case, leading to a less effident dispatch
               between the Rest of Entergy and EA1 generating assets.

           0   The heavily baseload (nuclear and coal-fired)generating assets in the EA1 region.
               The commitment and dispatch of these types of facilities fend to be less affected by
               increased regional integration. resultingin reduced dispatch savings opportunities if
               E N alone joins the SPP RTO, than if Entergy as a whole joins.

           0   Of the 17 QFsin the Entergy region. only one is in the EA1 region. As described in
               the SPP-Entergy CEA, QFs in an RTO are assumed to become firm resources
               allowing for a more efficient commitment process. With only one QF moving to an
               RTO as part of EAI, there are fewer savings than if Entergy as a whole joins the SPP
               RTO.

       These factors contribute to yield only a modest level of EA1 trade benefits in the EAI Joins
       SPP Case.

4.2,   ADMINISTRATIVE COSTS

                                                                                  n
       A number of costs must be analyzed in addition to those directly addressed i GE MAPS.
       These include RTO administrative costs. ICT costs, FERC charges and implementation
       costs. The specificcategories of costs addressed in this study are discussed in detail below.

4,2.1. ICT Costs and RTO Administrative Charges

       In the €AI Sfandalone Case, the Entergy transmission system (and thus the EA1 region as
       network customers of the Entergy transmission system) would continue to incur costs
       payable to SPP for SPP to operate as its IndependentCoordinator o Transmission. SPP
                                                                        f




                                                                                               Page 21:
        4
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      provided a projection of these costs over the 201X2022 period, for Entergy as a whole.
      Using a load ratio share, the EA1 region’s allocation of these costs is $30 million.

      f h e SPP RTO incurs significant capital and operating costs to operate its markets, and these
      costs are recovered through administrative charges under SPP Schedule 1A. These charges
      would be payable by E41if it were to become an RTO member. SPP estimates that the
      additional administrative cost incurred to include EA1 in the SPP RTO would be no greater
      than the costs that would be incurredto operate the EA1 Joad ratio share o the Entergy ICT in
                                                                                 f
      the EA/ Standalone Case. The resulting€AI charges under SPP Schedule 1A in the €AI
      Joins SPP Case are $81 million. Afler consideration of ICT costs avoided, the resulting net
      additional cost to EA1 in the €AI Joins SPP Case is $51 million.

      Current SPP members would face lower RTO administrative charges per MWh in the Join
      SPP Case with EA1 as a member, yielding a benefit of $51 million (2010 present value) to the
      SPP region. Because SPP would incur no additional costs (beyond the costs otherwise
      incurred by SPP for E 1 as part of the ICT) in the €A/ Joins SPf Case, the net additionat
                           A
      charges paid by EAt are exactly offset by additional benefits to SPP. See Appendix A for
      further detail,

4.2.2. FERC Charges

      All load-sewing investor-owned utilities must pay annual FERC charges in order for FERC to
      recover its administrative costs. Historically, these FERC charges have been assessed to
      individual investor-owned utilities based only on the quantity of the utility’s wholesale
      transactions (is., those related to interstate commerce). However, the annual FERC charges
      for RTO member load-serving utilities are assessed directly to the RTO,and then in turn
      assessed by the RTO to member companies. Under FERC regulations, the annual FERC
      charge is assessed to all RTO energy for load. FERC charges for RTO members are
      therefore higher than those for non-RTO members.

      As more of the country’s utilities join an RTO, the FERC per-unit charges for energy
      transmitted in interstatecommerce are likely to decrease. Nevertheless, as long as only
      whalesale transactions are assessedthe FERC charge under a non-RTO basis, there will be
      higher FERC charges to RTO members than non-RTO members,all else being equal.

      For purposes of this study, the FERC charges i the €41 Joins SPP Case were projected by
                                                      n
      multiplying the FERC charges estimated by the SPP RTO {on a dollars per load served basis)
      in 2010 by the load in the EA1 region. For the EAI Standalone Case, the average inflatbn-
                                        A
      adjusted FERC charges paid by E 1 In the 2006-2009 period was derived. It was assumed
      that non-FERC jurisdictional cooperatives and municipalitieswould not incur FERC charges
      of this type in the Satus Quo Case. f h e difference in these figures was then escalated at
      inflation and discounted over the I&year study period. Using this approach, the increase in
      FERC fees was projected to be $7 million (2010 present value) for the EA1 region. See
      Appendix A forfurther detail.



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4.2.3. Internal Staffing and Equipment Costs

       RTO market participantswill incur expenditures to participate in an RTO market over and
       above the RTO administrative charges. This will include additional staffing, new computer
       equipment and other items. As part of this study, EA[provided a projection of the addifional
       costs they would likely incur to participate in the SPP RTO. CRA assumed that other entities
       in the EA1 region would incur similar charges on a per MWh of load basis. Over the 9 year
       period, the expected cost is projected to he $21 million (2010 present value) for the !&I
       region. See Appendix A for klrther detail.

4.3.   TRANSMISSION
                 EXPANSION ALLOCATION
                        COST

       Projected high voltage transmission expansion costs in the SPP, Entergy and Clem regions
       would be allocated in the Join SfP Case under the YHighway/Bywarallocation mechanism
       recently approved by the FERC. Under this approach approved by the FERC on June 17,
       2010,100% of the costs of transmission lines o 300 kV and above and 33%of the costs of
                                                     f
       lines above 100 kV and below 300 kV are recovered on a regional basis.

       As part of this study, SPP performed an analysls assuming different types of transmission
       projects are subject to allocation to EA1 in the EA/ Juins SPP Case. The actual allocation
       would be dependent on a negotiated process between SPP and EAI. The aggregate
       allocation results over the 2014-2022 period are captured below for the three different
       transmission cost allocation studies assessed by SPP.

          Table 6 :2014-2022 Transmission Cost Allocation Benefits (Costs) to the SPP,Entergy and
                      Cleco Power Regions if Cleco Power and Entergy JoIn the SPP RTO
                   (in millions of 2070 present value doitam;posltlve numbers a n benefik)



           1    All RegionalCosts                                    307         (307)         0

          2     RegionaICosts beginning Jan. 2013                    209         (209)         0

          3     Regional Costs beginning Jan. 2013 exduding          (13)          13          0
                8alanced Portfolio and Priority Projects


       In SPP Study I EA1 was assumed to contribute to the regional recovery of SPP upgrades
                         ,
       completed after March 2006, coincident with the first regional recovery in SPP. In SPP Study
       2, EA1 was assumed only to contribute to regional recovery of SPP upgrades needed M e r a
       'bright line" date of January 1,2013 (roughly consistent with the start date of Ute study period
       analyzed in this study). In SPP Study 3, EAI was assumed only to contribute to regional




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       recovery of SPP upgrades needed affer January 1.2013, excluding Balanced P o ~ o l i and ~
                                                                                            o~
       Priority Projects25.

       SPP Transmission Expansion Plan ("STEP') projects with Notification to Construct ("NTC")
       dates before January 1.2013 and 2009 STEP Base Plan Funding before January 1.2013 are
       excluded from the cost allocation in both SPP Study 2 and SPP Study 3. Balanced PortFolio
       and Priority Projects are excluded in SPP Study 3. About two-thirds of the SPP region's EHV
       cost is for the Balanced Portfolio and Priority Projects. As a result, as shown in Table 6, a
       significant amount of costs are transferred to the EN region in SPP Study 1 and SPP Study
       2, but not SPP Study 3. The need for additional EHV projects in the EN region could be the
       subject o further regional transmission planning analyses. To the extent such projects were
                 f
       approved, the costs would be shared wt the SPP region in the €AI Joins SPP Case.
                                               ih
       As shown in Table 6, the impact to the SPP and EA1 regions individually is substantially
       different across the three SPP transmission cost allocation scenarios. As such,in this study,
       the benefits and costs for each region are first calculated excluding transmission cost
       allocation impacts, and then the overall net benefits are captured with a range reflecting the
       allocation costs above.


5.     OVERALL COST-BENEFIT RESULTS

       Shown in Table 2 are the net benefits individualty to the EAI, SPP, Rest of Entergy and Clew
       Power regions if EA1 joins the SPP RTO relative to operating on a standalone basis. As
       shown in Table 7, the net benefits to the SPP and Clew Power regions are positive, whiIe



24     The SPP Balanced Portfolio, as approved by SPP In April 2009, includes five new 345 kV lransmlsslon Itnes. a 345
       kV transformer, and a new connection between two existing 345 kV Ilnes. The 250 mile Woodward-Turn' fine
       behveen Hale County, Texas (north of Abemathy) and Woodward, Oklahoma will cwt $229 mlllton. Tha 215 mlle
       'SpeaMlle-Knolt-Me-Axlell'tine between Speam'lfe. Kansas (east of Dodge City); Hays County, Kansas: and Mell,
       Nebraska will cost S237 mlllion. The 100 mile Seminole-Muskwee' line between Seminole County and Muskogee,
       Oklahoma will cost $t31 million. The 36 mlle Sooner-Cleveland* line b m e n Sooner Lake in Noble County.
       Oklahoma and Cleveland, Oklahoma wilt cost $34 milllon. The 30 mile 'latan-Nashua' line between latan and
       Nashua, Mlssouri (north of Kansas Clty) will cost 154 rnlllion. The Anadarko Transformer In Anadarko, Oklahoma wlll
       cost $8 million. The Swlssval&tihuell Tap near Gardner, Kansas will cost 52 rnlllion. The total cost I wrrentry
                                                                                                                s
       projecieed to be 5770 milllon.

25     The Priority Projects. as approved by SPP In April 2010, am a5 follows: A doubiec'rwit 345-kV llna from Spearville,
       Kansas: to Comanche County, Kansas; to Medidoe Lodge, Kansas; to Wchita, Kansas projected to cost 8356
       mllllon. A double-drwl! 345kV line from Comanche County, Kansas, to Woodward. Oklahoma projected to cost
       5108 milllon. A doubledrcuit 345.W llne from Woodward. Oklahoma lo Hachland, Texas projected to cost 5247
       million. A 345-kV line from Nebraska City, Nebraska: to Maryville, Missouri: to Sibley, Mlssouri projected to cost
       $301 rnlllion. A 345-kV line from Vallian!. Oklahoma to Texarkana, Texas projected to cost $131 rnlllion. and new
       equipment in Tulsa County, Oklahoma projected fo cost 4840.000. The total cost to englneer and construct these
       projects I estimated to be $t .15 billion.
                s



                                                                                                                Page 24
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             0                                                                   Charles River Associates



       those to the €AI and Rest of Entergy regions are negative. The net benefit to the combined
       EAIISPP region is positive, and the net benefit to the collective SPPIEntergy region is
       somewhat negative.

         Table 7: 2013-2022 Benefits (Costs) to the EAI, SPP, Rest of Entergy and Cleco Power Regions
                                           if EA1 Jolns the SPP KTO
                    {in mil/ons ofZO?D present wlue dollam; positi~e   numbms am benet&)



                                         ~                   ~         ~                      ~   ~       ~




       Administrative Costs              (79)           51                   0               0           (28)
       Transmission Cost AltocatIan   (307) 13
                                           to            to
                                                     (13) 307                0               0                0
       Net Benefits                   (372)to (52)   92 to 412             I$78)            25           (13)


       As shown in Tabte 7:

                Including transmission cost allocation, the net benefiV(cost) to the EA1region in the
                € A I Joins SPP Case ranges from ($372) to ($52) million. The transmission cost
                allocation in which Balanced Portfolio and Priority Projects are excluded provides an
                                                                     n
                additional $13 million of benefits to the EA1 region i the EAI Joins SPP Case, but
                this I not enough to yield an overall positive measure of benefits for the EA1 region.
                      s                                                                                           '




                f h e SPP region benefits from the sharing o SPP RTO administrative costs with E 1
                                                            f                                    A
                in the €AI Joins SPP Case, yielding a reduced administrative cost burden for the
                existing SPP region. A full sharing of post-2006 regional transmission expansion
                costs would lead SPP region benefits to be as high as $412 million. Given the SPP
                region benefits, the net benefit to the combined SPPEAI region i a positive $40
                                                                                 s
                million.

            0   The Rest of Entergy region is negatively impacted by the loss of the signifimnt
                through and out revenue for transactions that exit the Entergy transmission system
                from the EA1 reglon. In the €AI Standalone Case, this revenue is shared on a load
                ratio basis with the rest of the Entergy transmission system. In the € A I Joins SPP
                Case, this revenue largely accrues to the EA! region under the SPP tariff.


6.      OTHER CONSIDERATIONS

6.1.    SUB-REGIONAL AtLOCATlONS

       No further suballocations of EA1 region benefits were performed in this study. Using the
       detailed GE MAPS results from this study, Entergy is separately performing an assessment of
       the impact to EA1 and other Entergy operating companies.




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       Further sub-allocation would require development o a simplifiedallocation methodology
                                                            f
       relative to the methodology applied by C R A for the EA1 region as a whole ushg tieline flows.

6.2.   ENERGYOPCOCAPACITV
                        BENEFITS

       As part of this CBA, CRA was asked by study stakehorders to assess the potential for the EA1
       Opco to obtain capacity benefits. As noted above, for the EA! region as a whole, there would
       be no capacity benefits as the region is well above the expected EA1 standalone planning
       resenre margin. CRA examined the EA1 Opco resew margin, and determined that the EA1
       Opco i currently well below the expected standalone planning reserve margin.
             s

       Wlth a 20% standalone reserve margin in the EA1 Standalone Case and a 13.6% reserve
       margin in the €AI Joins SPP Case, we estimate that the EN Opco would avoid procuring
       between 300 and 400 MW of capacity during the 2014 to 2022 period if EA1 joins the SPP
       RTO. Given the amount o capacity available in the EA1 region, we valued the capacity
                                 f
       benefit at $3lIKW-year (2010 dollars) based upon recent capacity prices in the Midwest IS0
       Voluntary Capacity Market. Like the EA1 region, the Midwest IS0 region also has more
       available capacity than currenffy needed to meet its planning reserve rnargin26

       At this 'tong market" capacity price of $31IKWyear, the value of the EA1 capacity payments
       avoided in the EA[ Joins SPP Case would be approximately $10 million per year, with a
       present value over the 2014-2022 period of $63 million.*7 In practice, the actual price for
       capacity in the regionwill depend on how far above the resewe margin the region is, the
       capacity needs in bordering regions that could contract for EA1 region resources, and
       negotiations between buyers and sellers o capacity.
                                                  f

6.3.   ENTERGY              ARRANGEMENTS
             QPCO TRANSMISSION

       In consultation with SPP and Entergy transmission personnel, the basic framework of the
       network arrangementsthat would take place in an EA1 Standalone Case was identified.
       Certain aspects of these arrangements are not fully established as yet.

       Based on 2009 data, it was estimated that the E 1 transmission revenue requirement i
                                                      A                                     s
       24.8% o the total Entergytransmission revenue requirement, after netting point-point
              f



26     Monthly prlces have ranged from $0.25 to 51OlkW-monthIn the Mldwest IS0 Voluntary Capacity A u d o n during the
       December 2009 to November 2010 prldng periods. The hlgher p i l e s take place during the summer months. The
       2010 Mldwest IS0 Summer Assessment forewst a reserve margln of 25.9% relative to a Mldwest I S 0 coincident-
       peak reseIve marglo requirement of 15.4%.

27     If the capadty avoided I newly constructed capacity, we esdmate the total benefit over fhe 2014-2022 period would
                              s
       be In the range of $63 million to Si83 million. depending on the specific year in whlch newly constructed capacity
       would be required. See Appendix A for furtherdelalt.




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       revenue. EIA has approximately 27.2% of net transmisston plant, but has a somewhat lower
       formula carrying charge than the transmission assets owned by the Rest of Entergy. Again
       based on 2009 data, the EA1 region load ratio share is 24.1 % of the Entergy transmission
       system. Based on 2009 data, the Entergy PTP rate is not expected fa change materially with
       E 1 Opco as a network customer. Reliability upgrades would continue to be alloated to
        A
       Entergy O A T customer on a load ratio basis, as it is today. As a network customer, Entergy
       Opco would be responsible for the costs associated with new network resources under the
       Entergy OATT.

       Transmission equalization under the ESA's MSS-2 would no longer be applicable for EA1 in
       2014. Revenue distribution under the current Entergy tariff would be based on a load ratio
       share resulting in the potentialfor the allocation of Entergy transmission revenues to EA1 to
       differ from the EA1 transmission revenue requirement. As part of SPP, the EA[ network
       transmission charges and the EA1 transmission revenues allocated under the SPP tariff would
       be aligned.

            A
       The E 1 region's paymentlreceipt of point-tepoint V T ' transmission charges for external
                                                          PP)
       designated network resources ('DNRs") would vary between cases:

           0    In the E41 Standalone Case, the EA1 region would need to purchase about 100 MW
                of PTP transmission from SPP for EA1 region DNRs located in SPP.

               In the EAI Joins SPP Case, EA1 would need to purchase about 300 MW of PTP
               transmission from the Rest of Entergy for EA1region DNR's located in the Rest of
               Entergy, and the Rest of Entergy would need to purchase from EA1 (as part of SPP)
               about 1,000 MW of PTP transmission for Rest of Entergy DNRs.

       On net, this could yield additional transmission revenue for the EA1 region in UII Joins SPP
       Case of about $10 million per year.28

6.4.   SENSITIVITY
              ANALYSES

       No additional sensitivity cases were nm in this C3A. Entergy has asked CRA to perform
       sensitivity cases for this CBA as a follow-on effort. The specific assumptions applied in those
       sensitivity cases will be selected based on discussion with study stakeholders.




28     Based on a net receipt of an addiUonal600 MW of PTP revenue In the EAIJdns SPP Case (1000 MW- 300 MW in
       the    Jolns SPP Case- 700 MW In the E4f Slandahe Cese) at the Enfergy hnsmtsslon rate of %'i.37per kW-
       month. Some of these network agreementsexpire during h e 2014 to 2022 time pedcd.




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C8A of E 1 Joining the SPP RTO

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6.5.   QUALITATIVE ISSUES

       The general qualitativeconsideration of Entergy joining the SPP RTO examined in detail in
       the SPP-Entergy CBA were not reexaminedin this CBA, as they would be expected to apply
       to EA1joining the SPP RTO as well. The qualitative issues examined in the SPP-EnfergY
        CBA included efficiency, competitiveness, transparency and administrative burden costs and
       risks. Substantial qualitative benefitswere found to accrue to the Entergy region through
       joining the SPP RTO, including improved operationat transparency. improved competiveness
       via resolution of base case overload issues, improved efhcieney through resolving various
        ICT and WPP issues, improvedtransmission planning and interconnection process, and
       potentiallylower regulation and capacity reserve requirements. However, additional costs
       were also found to accrue to the Entergy region. These include risks and costs associated
       with transmission system access, Day 2 market transitional risks, and the imposition of SPP's
       governance structure. The qualitative analysis also recognized that some of the impacts
       associatedwith joining the SPP RTO may be achieved by continued actions of the E R S C
       without Entergy's formal inclusionin SPP.


7.     CONCLUSlON

       Based on the analysis performed, we conclude that EA1joining the SPP RTO, relative to
       operating on a standalone basis, will not yield significant economic benefitsto the €AI region
       or to the collective SPPlEntergy region. The net benefit to EA1 and SPP is highly dependent
       on the allocation of regional high voltage transmission expansion costs.

       These results for EA1joining the SPP RTO are in contrast to the significant benefits found for
       the Entergy region in the SPP-EnfergyCBA with Entergy and Cleco Powerjoining the SPP
       RTO. We attribute the difference in results to the difference in the case to which joining the
       SPP RTO is compared ( M I standalone vs. part of the Entergy region), the imposition of
       transmission wheeling charges between EA1 (as part of SPP) and the Rest of Entergy in the
       EAI Joins SPP Case, the heavily baseload generating assets in the EA1 region, and that only
       1 of the 13 QFs in the Entergy region is i the EA1 region. These factors contribute to yield
                                                  n
       only a modest level of EA! trade benefits in the EAI Joins SPP Case. This modest amount of
       trade benefits is not significant enough to offset the payment by the EA1 region of RTO
       administrative costs.

       Additional addendum studies are contemplated by stakeholders to further assess the costs
       and benefits of M I joining an RTO under alternative assumptions using the models and
       assumptions developed under this study as the basic framework.




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APPENDIX A: FURTHER QUANTITATIVE RESULT DETAILS

The net benefit to the E 1 region of joining the SPP RTO, relative to operating on a standalone basis,
                        A
i captured in Table 8.
s

                        Table 8: Net Benefit to the EA1 RegIon if EA1J o f s the SPP RTO

 In Millions of Nominal Asspent Dollars                                     t ntlation                 2.5%
 Benefits are shown aspcrsitive figures. costs as negalive figures          Discount Rate              8.0%
                                                                                                                    __
                                                                                                                    2mo
                                                                                                                      ..
                                            2Qi4    2015    2016     2017     2018       2019   2020   2021 2022 PrValue
 EAl REGION 1N SPP RTO
 Trade Benefits
 + DecreaseIn Adjusted Prod Casts
 + Lnst T&O Trans Revenue
 = Subtole1 Trade Bene&
 + Reserve Margin Benefits
 Adminlsttatlve Costs
 + Avolded ICT Charges
 + RTO Adrninhlmtive Charges
 f   FERCCharges
 + Internal Capitabbor
 = SubtefalAdminlCapital
 SubTotal
 f  Transmisslon Cost Allocation
              study 1
              Study2
              Study 3
 Net Benefits
              wlStudy I
              wlStudy 2
              wIStudy 3




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Further detail regarding the net benefits to each of the regions if EA1joins the SPP RTO, relative to
operating on a standalone basis, is captured in Table 9.

      Table 9: Net Benefifs to the Rest of Entergy, Cleco and SPP RegIons If EA1Joins the SPP RTO

 In M J h s of Nomine1As-spentnl D o l l m                                 Inflation                  25%
 Benefits are shown BS positive figures, msls as negative ~ @ ~ m s        Diswunt Rate               8.0%
                                                                                                                      2010
                                          2014    2 m     2016    2017       2018      2019   2020    2021   2022 ~ t v a ~ u e

 IMPACT ON REST OF ENTERGY
 Trade Benefits
 + Decrease irt Adlusted Prod cosls         t4      12     11         9         7        6     I1      t6     21




 IMPACT ON CLECO REGION
 Trade Benefits
 + Decrease h Adiusted Prod Costs            4       5      5         6         6        6      5       3       1       23
 + Lost T ~ Trans Revenue
              O                              0       I      I         0         0        0      0       0      (0)       2
 = Sublotel Tmde Benefits                    4       5      6         6         6        7      5       3       1       25
 Admhlslrative Costs                         O       Q      O          O         O        O       0      0       0       0
 Net Benefits                                4       5      6         6         6        7      5       3       1       25

 IMPACT ON EXISTING SPP REGION
 Trade Benefits
 + DecreasalnAdjustedProdCosts              25      25      26     25          24       23   25        28     30       126
 + Last T&O Trans Revenue                  (15)    ($5)    (16)   (15)        (14)     ($3) (13)      (14)   (14)      V2)
 = Subtol8l Trade Benels                    IO      10       9        10       10       10     12      14     36        54
 + RTO Admlnlshtive Charges                 10      10     I0         10       IO       10     11      11     11        51
 SubTotal                                   20      19     19         19       20       21     23      25     28       105
 + Transmlsslon Cost Allocatron
              Study 1                       35      72     60         68       68       65     65      66     68       307
              Study 2                       18      44     43         51       47       46     46      47     48       209
              Study 3                        4      m                  1       (3)      (3)    (3)     13)     13)     (13)
 Net Benefits
              wSuy 1
               ltd                          55      91     ao         87       88       86     aa      92     96       412
              wlStvdy 2                     38      63     63         70       67       67     69      72     76       314
              wlStudy 3                     24      i3     ~2         20       t7       ia     20      zz     1
                                                                                                              2
                                                                                                              .         92

 SPP-ENTERGY-CLECO Net Benefits
 Trade Benefits
 + Oeerease In Adjusted P r d Costs         19      18      18        13        7        0      5      10     15        61
 + Lwt T&O Trans Revenue                   (12)    (13)    (13)   (11)         (8)      (6)    (5)     (5)    (5)      (46)
 = Subtotal Trade Benefits                   6       6       5      2          (2)      (6)    (I)      4     10        15




                                                                                                                              Page 30
CBA of EA1 Joining the SPP RTO

October 27,201 0                                                                                           Charles River Associates




Further detail regarding the value of the reduction in the €AI region planning reserve margin in the
,541 Joins SPP Case i captured in Table I O .
                       s

       Table I O : Value of Reduction in EA1 Region Plannhg Reserve Margin in EA! Joins SPP Case




                               7,485      7.745      0.0t4         8292        WE?        8.473       8.566     8,685     &=         8,929
                              11.292     11,292      1
                                                    1m            11252       11,292     11292        1m
                                                                                                     1.        11352     11382      11.232

                                                                                                                         282%       26.5%

                                                                                                                            724        576
                                                                                                                          1.284      1.145
                                                                                                                              0          0
                                                                                                                              0          0     0.0
                                                                                                                              0          0     0.0


EAI Opco Rnews Margln                                         O
                            6Note: Of@ relclvant to E n t w ~ y    m s u b ~ & n a ! a k g h ana&&
c m n l P&     LOd             4.827      4.595      5,168         5.34        5.408      5,465       6524      5.601     5.678      5759
Gmeratbn                       5m7        5.067      5m
                                                      .            $067        5.067      5m7         Emf       5w.       5,067      5.067

Res%NeMa?gh                      50%       1.4%      -2Mc          &3K        -53%         73
                                                                                          -.%         -9.3%     -9.5%    -ma%      -12o.n
MW M @ o W ) :
 Standah                                  (927)     (1.1%)        (1.351)    (1.420)     (1,491)     (1.552)   (1.655)   (1,7491    (1.844)
 SPP                                      (€031      (BE)         (1.010)    (1.076)     (3.143)     (1211)    (iB69B)   (f.W       WT7)
Mw Avoided h Joh 5PP Case                   318       329            340        244         348         352       356      361         366
C8Sl A
     -
C8sl A
           -
         M New
           -  m
                      (MS2OfO)
             L g Markel (M12UiO)
                                           23
                                            8
                                            9.B
                                                      2.
                                                       92
                                                      102
                                                                    302
                                                                    10.5
                                                                                30.5
                                                                                10.6
                                                                                            N.8
                                                                                            10.6
                                                                                                       312
                                                                                                       10.9
                                                                                                                 3I.6
                                                                                                                 It0
                                                                                                                           320
                                                                                                                           112
                                                                                                                                      325
                                                                                                                                      11.3

Innabn Fadw                               1.W        1.131         1.160       t.189       130        1249      12Bo      1.312      1.245

                                           3.1        33.0          35.0        362         37.6       38.9      40.4      420        43.7    1824
                                           10.9       11.5          12.2        127         13.1        36
                                                                                                       1.        14.1      14.7       15.3     6%7




                                                                                                                                   Page 31
CBA of E 3 1 Joining the SPP RTO

October 27.2010                                                           Charles River Associates



APPENDIX 8 : GE MAPS MODELING ASSUMPTIONS



       This appendix summarizes the key inputs to the GE MAPS Iocational price forecasting model
       that are different than those applied in the SPP-Entergy CBA. Assumptionswere not
       modified for generating unit operating parameters, fuel costs, emission costs,and
       transmissiontopology. 7he MW of required Entergy spinning reserve in the FERC SPP-EA1
       study was divided between EA1 and the 'Rest of Entergy' on a peak load basis. Refer to
       Appendix 8 of the SPP-EnfergYCBA report issued September 30,201 0 for details.

B.2 SEAMS                  RATES
        CHARGES N D WHEELING
              A

       Seam charges are "per M W charges for moving energy from one control area to another in
       an electric system. In MAPS, seams charges are applied to net interregionalpower flows and
       are used by the optimizationengine in determining the most economically efficient dispatch of
       generating resources to meet load in each model hour. Seams charges are considered for
       both commitment and dispatch of generating units: however, the charges between any two
       areas may be different for commitment than for dispatch. For the current analysis,
       commitment is done on a pool by pool basis, and dispatch is done by the system as a whole,
       subject to seams charges. The seams charges modeled for dispatch include both the actual
       wheeling rates defined in transmbsion tariffs, and a second value, which i referredto as
                                                                                 s
       friction, representing the hurdles caused by market inefficiencies. The wheeling rates are
       based on the non-firm hourly rates.

       Table-Bl gives an overview of the seams charges used for dispatch beween SPP, EAI, Rest
       of Entergy, and other neighboring control areas in the S f P €AI CBA. The SPP, Entergy and
       AECl regions are treated as one commitment pool with a $1OlMWh commitment hurdle
       between EA[, SPP and the Rest of Entergy (and others) in the €41 Standalone Case.




                                                                                            Page 32
CBA of EA[ Joining he SPP RTO

October 27,2010
                                                   Charles River Associates


      Table-31: Seams Charges in SPP EA1 CBA




                                               2   3       5        1    Q
                                               2       3        5       (ClW2piWoed
                                               0   3       3        1    0
                                               3   3       6        1    0
                                               3       5        B       (C)
                                               3   3       0        1     0
                                               3       5        8       {e]
                                               0       0        0        5

                                               3   s       a        i    o
                                               2   5       7        1    0
                                               4   5       B        1    0
                                               4   5       9        1    0
                                               5   3       8        t    O
                                               5   3       8        1    0
                                               6       5       It       10
                                               3   5       8        1    0




                                                                              Page 33
CBA of EA1 Joining the SPP RTO

October 27,2010                                           Chartes River Associates


       Table-61: Seams Charges in SPP EA1 CBA

             Frwn Commltmenl   Ta Conunllmmt    1DlSp.lch Seam ChugE         I
             PWl               Pool                      Frletioq
            aau 2
        I MIS0                 PJM                   0          2           2
          M1SD                 MMher                 5          3           8
        2 PJM                  MlSO                  0          2           2
          PJM                  MmW                   3    3                 6
        3 SPPlEntpSw           AI                     se%Mr#
        4     M                NY                    0    3                 3
          NE                   MMW                   7    3                 10
        5NY                    NE                    0    3                 3
             Mi                no                    2          3           5
             ?if               OH                    4          3           7
             NY                PJM                   5          3           8
            -2.
        6 V   W          m     All                   1          5            7
        7fRCc                  All                   3          5            0
        a m                    AI                    2          5            7
        9          m           a                     5          5           10
       10 TVA                  M                     3          5            0
       11 OH                   M                     1          5            8
       12 Ha                   Ap                    0          5           13
       13 NBMaf&kr!aS          AIl                   3          5            0




                                                     3      3       6            1    0
                                                     0      3       3            1    0
                                                     0      3       3            1    0
                                                     3      3       B            1    0
                                                     3          5           B        (C)
                                                     0      3       3            1    0
                                                     3      3       8            1    0
                                                     3          5           8        Icl
                                                     2          3           5        10SUFAwkdrale
                                                     2          3           5        wwzpranned
                                                     3      3       6            3    0
                                                     3      3       6            1    0
                                                     0      3       3            1    0
                                                     3          5           a        {ci   milsmm
                                                     0          0            0        5
                                                     0          0            0        5
                                                     3      3       6            1   0
                                                     3      3       8            t   O
                                                     3          5       8        I    d

                                                     2      3       5            1    0
                                                     2          3           5        gwplanned
                                                     0          3           3
                                                     3      3       6            3    0
                                                     3          5           8        IC)
                                                     3      3       6            T    O
                                                     3          5           8        IC)
                                                     0          0            0        5
CBA o EA[ Joining the SPP RTO
     f
October 27.2010                                                                        Charles River Associates



                                                  n
      To reflect the likely dispatch of IPP units i the Entergy region, an additional commitment
      hurdle rate of $SIMWh was included i the EN Standalone Case for JPPs in the Entergy and
                                              n
      Clem regions without long-term (through at least 2016) firm transmission service in place.
      Those IPPs in the EAI, Rest of Entergy and Clem region without lang-term firm transmission
      service are shown in Table-B2 below. In the ,541 Joins SPP Case, the commitment hurdte for
      the €At lPPs is eliminated.

      Table-BZ: lPPs In the EAI, Rest o Entergy and Cleco regions
                                       f
       MI
            Duke Hot Springs 1
            Hot Springs flractabel)
            Robert Ritchle 2
                         -
            Union Power Panda Energy
       Rest of Entergy
            Cawille CogenerationEnergy
            Cottonwood CC 1 & 2 (Intergen)
                            .
            Duke-Hinds
            Cogentrix BatesvilIe (MS) (a)
       Clem
            Clew EvangeIine

       (a) Located outside of Entergy in the Entergy power ROW, and thus accounted for in Rest of Enterqy Imports
                                         FILED




                        Cost-Benefit Analysis of
                        Entergy and Clem Power
                        Joining the SPP RTO
                        Addendum Study




Prepamd By:
Charles R'mr kssocaes


Date: December 8,2010
CBA of Entergy and Clem Joining the SPP RTO -Addendum Study

December 8. 2010                                                                                                 Charles River Assodates



                                                      Table o Contents
                                                             f


1. INTRODUCTION.............................................................................................................                      1


2. STUDY METHODOLOGY ...............................................................................................                              2


3 . FINDINGS .......................................................................................................................              3

      3.1.       SPP-ENERGYCBA BASESCENARIO     ...................................................................
                                          RESULTS                                                                                                 3
      3.2.       SPP-ENERGY CBA SENslTIWWANALYStS RESULrS             ..........................................................                  3
      3.3,       SPP-EKTERGY
                           C                w ADDENDUM STUDY SENSmWTlES........................................................                   4
                 3 3 1 Seams Charge and QFTreatrnent Addendum Sensitivities...............................................
                  ...                                                                                                                             5
                 3 3 2 Delayed SPP Day 2 Addendum Sensitivity ........................................................................
                  ...                                                                                                                             9
                 3 3 3 Carbon Addendum Sensitivity ..........................................................................................
                  ...                                                                                                                             ~0


4 . CONCLUSION ..............................................................................................................                    10


APPENDIX A: ADDENDUM SENSITIVITY INPUT ASSUMPTIONS ...................................                                                           11




                                                                                                                                                Papi
CBA of Entergy and Cleco Joining the SPP RTO -Addendum Study

December8,2010                                                                           Charles River Associates




1.     INTRODUCTION

      On September 30,2010, Charles River Associates ( " C W ) Resero Consulting issued the
                                                                    and
      final report for the SPPEnteW CBA.1 The SPP-Entergy CBA concluded that Entergy2 and
      Cleco Power3joining the Southwest Power Pool ('SPP") 4 regional transmission organization
      ('RTO') wilt yield significant economb benefits to the collective SPPlEntergy region.5 The
      net benefits to the Entergy and Cleco Power regions are highly dependent on the allocation of
      regional high voltage transmission expansion costs.6 Aside from the allocation o   f
      transmission expansioncosts, the benefits to the Entergy region ofjoining the SPP RTO were
      relatively robust across the sensitivity scenarios examined. A number of important qualitative
      considerationswere identified as well, with both qualitative benefits and offsetting costs
      incurred by Entergy and Cteco Power if they joined the SPP RTO.

      During the course of the SPP-Entergy CBA, potentially important parametersworthy of
      additional analysis were identified by study stakeholders, including seams charges and the


1     See http~~.spp.org/pubIication~ERC0/620SPP%2O~tergyS620CBA~~Repo~%ZO~~aI.pdf. is a                   As Ws
      fnllow-on addendum study. the detalled desciipSons of the CRA modelng approach and input data contained In the
      S f P h t e g y CBA are not fully repeated hereln. See h e SPPEntergy CBA for further detail on these tssues.

2     Entergy Mamas. tnc. Entergy Loulslana, LLC, Enkrgy Gulf States Loulslana LLC.. Entergy Mlsslsslppl, Inc,
      Entergy New Orleans, Inc, Entergy Texas. Inc. (collectively, 'Entergy"). These utility operating companks 5ewe 2.7
      mtllion customers In Arkansas, toulsiana. Misslsslppl. and Texas.

3                    s
      Clew Power LLC I a regulated electrlc utilily m p a n y that selves about 277,000 customers a m s s Loulsiana.

4     Southwest Power Pool, Ink is a group of ! ' members in Arkansas, Kansas. Loulslana, Mlsslsslppl, Missouri.
                                                   Z
      Nebraska. New Mexico, Oklahoma. and Texas that selve more than five million customers. Membership I           s
      urrnprised of Investor-owned vtllitles, rnunldpal systems, generatlon and transmission coopemks, state
      authoriBes, wholesale generators. power marketers, and Independent transrnlsslon companies. SPP's footprint
      indudes 29 balancing authorities and 50,575 mlles of transmission tines. SPP was deslgnated by the FEAC as a
      RTO In 2004. As an RTO, SPP ensures reliable suppties of power, adequate transmission infrastruclure, and
      competitive wholesale prlces of eIectrieity. SPP I a North American Electric ReliabiIity Corp. (WERC") Reglonal
                                                       s
      Entity. Clem Power is not currently a member of the reglonal market operated by the SPP, but Is a member of the
      SPP Reglonal Entity. Eokrgy I a member of the SERC Regional Entity.
                                    s

5     The 'SPPIEntergy region' refers to all load and genemuon In the current Entergy-SPP-Cleco Power transmlsslon
      system footprint, Including that of merchant generators and woperaUve and munlupal utilities.

6     The *Entergy reglon" refers to the area withln the Entergy transmlsslon system foolpdnt. and for purposes of the
      SPpEntergy CBA Included Loulslana Generating and Louislana Energy and Power Authority. The *Clem reglon"
      refers to the area within the Clew tmnsmlsslon system footprint as well as the Clew Power load served by the
      Entergy transmlsslon system, and for purposes of thIs study Includes the Clty of Lafayette. The SPP region' refers
                                                       s
      to the SPP transmlsslon system footprint that I wrrenUy operating within the SPP Energy Imbalance Sewice
      market.




                                                                                                                 Page 1
                                                       -
CBA of Entergy and Clem Joining the SPP RTO Addendum Study

December 8.2010                                                                         Chartes River Associates


      treatment of Entergy QFs. In response, CRA7 was engaged by Entergy to perform an
      addendum study rSPP-€ntergy CBA Addendum’) to analyze additional sensitivity cases
      using the models and input assumptions developed under the SPP-Entergy CBA. This
      addendum study was performed by CRA over a three-rnonth period, and included an open
      and collaborative discussion with stakeholders of the sensitivity analyses to conduct,
      modeling approach, input assumptions, and interim results throughout this period. Based on
      the addendum sensitivity analyses performed, we continue to conclude that Entergy and
      Cleco Power joining the SPP RTO will yield significant economic benefits to #e collective
      SPPlEntergy region.

      An additional addendum study is being conducted by CRA to assess the costs and benefits of
      Entergy andlor Clem Power joining the Midwest ISO, but otherwise using the models and
      assumptions developed under the SfP-Entergy CBA as the basic framework.


2.    STUDY METHODOLOGY

      In the SPP-€nfergy CBA, two different cases were analyzed over the I O year period from
      201 3 to 2022:

                I Entergy and Cleco Power continue to operate as they do today (Ttafus Quo
                 .
                Case”), and

               2. Entergy and Cleco Power join the SPP RTO (“JoinS f f Case”).

      In the Sfalus Quo Case, SPP i assumed to continue in its capacity as Independent
                                  s
      Coordinator ofTransmission (“ICP)for the Entergy transmission system. As the SPP RTO is
      working toward instituting a Day 2 market, a Day 2 market is presumed to be in place in the
      SPP RTO throughout the 2013-2022 study              CRA analyzed the impacts on the
      Entergy, Cleco Power and SPP regions using the General Electric Multi-Area Production
      Simulation Model (“GE MAPS) model. GE MAPS is a detailed economic dispatch and
      production costing model that simulates the operation of the electric power system taking into
      account transmission topo!ogy.

      As described in the SPP-Entergy CBA, a base scenario analysis was conducted, along with a
      number of sensitivity studies. Using the same study methodology and basic set of input




7     PrinclpaI study Investigators for CR4 were Ralph Ludanl, Bwee TsuQlda and Pablo R u k The findlngs and
      condusions urnlalned In thIs CBA are solely those of CR4.

8     A Day 2 market refers to a two-settlement (day ahead and rea[-ffrne)energy market uslng hourly locational marginaI
      pdces and finandal transmlsslon rlghts (FTRs). Day 2 markets are atrredly In place In PJM. the Mldwesl ISO, I S 0
      New England and the New York ISO.



                                                                                                               Page 2
CBA of Entergy and Cleco Joining the SPP RTO -Addendum Study

Decembet 8.2010                                                                  Charles River Associates



         assumptions, a number of additional sensitivity studies were conducted in this addendum
         study.


3.       FINDINGS

         The findings of the SPP-Entergy CBA are summarized below, followed by the results o the
                                                                                            f
         additional addendum sensitivities conducted as part of this addendum study.

3.1.               CBA BASE
         SPP-ENTERGY             RESULTS
                          SCENARIO

         Shown in Table I the overall net benefits for the base scenan'o as presented in the SfP-
                             are
         Entergy CBA. As shown, the overall net benefit for the SPPlEntergy region is $739 million
         (2010present value) over the 2013 to 2022 period. The net benefits to the SPP,Entergy and
         Cleco Power regions individually are substantially positive prior to altocation of regional
         transmission expansion costs: $43 million for the Cleco Power region, $332 million for the
         SPP region, and $364 for the Entergy region. However, afier consideration of the allocation
         of transmission expansion costs, the range o net benefits to the Cleco and Entergy region is
                                                     f
         partially in the negative range. See the SPP-Enfergy CBA for further detail.

                  Table q: 2013-2022 Benefits (Costs) to the SPP, Entergy and CIeco Power Regions
                                   I f CIeco Power and Entergy J o h the SPP RTO
                      {inmillons of2010presenf wlue dol1arS;positivenumbers are benefib)


       Trade Benefits                                         143           80           594        I     817




                                                                                       +
       Admin Costs: RTO Administrative Costs net of   1       189
       Avoided ICT Charges                                                                          I


       Admtn Costs: FERC & CapilaYLaborCosts                   0
       SubTotal Net Benefits                                  332           43           364              739
       Transmission Expansion Cost Allocation              (5) to 895    (93)lo (18)   (8021to23    I       o
       Total Net Benefits (Costs)                         327 to 1,226   [49) to 25    (438)to38t   I     739




3.2.               CBA SENSITIVITY
         SPP-ENTERGY                    RESULTS
                                 ANALYSIS

         In the SPP-Entergy CBA, a number of sensitivity analyses were performed including high and
         low gas prices, high and tow regional load growth, and additional wind power construction in
         SPP. Finally, a "copper sheet"sensitivity was performed in which transmission and reliability
         must run constraints in the SPPEntergy region's transmission system were eliminated
         Results are summarized in Table 2. As shown, the benefits for the coltective SPPIEntergy




                                                                                                        Page 3
CBA of Entergy and Clem Joining the SPP RTO -Addendum Study

December 8.2010                                                                         Charles River Associates



       region remain substantially positive across the sensitivity scenarios examined. See the SPP-
       E n t e w CBA for further detail.

                          TabIe 2: 2013-2022 Benefits (Costs) to the SPPlEntergy Reglon
                                     if CIeco Power and Entergy J o h the SPP RTO
                      (lnmlffions of2010 present valrre dollars, positive numbets a n bene&)

                                                   .   .

          1 Base                                                   739        I                       1
            Sensiliviiy Scenarios:
                   LowlHigh Gas Prices                          540 I858                  -199/*119
                   HighLow Load Growth                          7131758                    -26/+19
              0    IncreasedWind in SPP                            595                        -144
              rn   'Copper Sheer                                   601                        -738




3.3.   SPP-ENTERGY ADDENDUM
                 CBA          SENSITIVITIES
                          STUDY

       During the course of the SPP-Enlergy CBA, other potentially important parametersworthy of
       additional analysis were identified, including seams charges and the treatment of Entergy
       QFs. In consultation with stakeholders,a number of GE MAPS sensitivity cases were
       identified to be conducted. As trade benefits are a key determinant in the overall benefits, the
       impact on 2013 trade benefits resulting from alternative assumptions in 2013 were the main
       focus of these addendum stt~dies.~

       The hey sources o trade benefits between the Status Quo Case and the Join SPP Case are
                          f
       the etimination of commitment and dispatch seams charges, the elimination of IPP
       commitment hurdles, and the treatment of QFs as firm resources. The assumptions applied
       in the SPP-Energy CBA are summarized in Table 3, and discussed further below.




9      Trade Benefits am comprised of the change between the Status Quo and Joln SPP eases for: 3) Adjusted
       Production Costs, the produdon cosls forthe generatlng unlts In the SPP,Clem and Entergy regions (fuel, variable
       08M and emlsslon cosls) plus purchased power costs net of energy sales revenue for each reglnn, and 2) 'Losf
       Tmnsmlsslon Revenue, as hnsmlsslon charges would not be assessed for bansadions between SPP. h-dergy and
       Clem In the Jdn SPP Case yleldlng reduced or 'lost- Iransmlsslon revenue that would have l o be compensated for
       by Increased charges to cuslomers. See !he SPP-Entergy CBA for further detail.




                                                                                                              Page 4
CBA of Entergy and Cleco Joining the SPP RTO -Addendum Study

December 8,2010                                                           Charles River Associates


                        Table 3: Key Input Assurnpffons used In the SPP-Entergy CBA




       Status Quo Case In SPP-Entergy CEA        10            3 +wheel           5       Non-firm
      Join SPP Case In SPP-Eotergy CBA           0                0               0         Flrm


       Seams Charaes. In the SPP-Entergy CBA, GE MAPS was used to model different
       impedimentsto SPP-Clecc-Entergy trade in the Status Quo Case and the Join SPP Case
       using commitment and dispatch seams charges. In the Stalus Quo Case, commitment
       seams charges were set at $1O / M W l between the SPP RTO and Cleco Power and Entergy.
      These were set at zero in the Join SPP Case, reflecting the joint RTO commitment process
      that woutd take place. In the Status Quo Case, dispatch seams charges between SPP,
      Entergy and Cleco were set at $3IMWh plus the applicable wheeling rate. In the J d n SfP
      Case, these dispatch seams charges were set to zero reflectingthe elimination of wheeling
      rates between these regions and the joint RTO real-time energy market.

      IPP Commitment Charqe. In the SPP-Enfergy CBA, for IPPs in Entergy and Cleco,
      commitment hurdles were set at $5/MWh in the SfafrrsQuo Case to reflect the impediments
      to optimal commitment of these lPPs absent a centralized day-ahead market. This hurdle
      was set to zero in the Join SPP Case.

                                    n
      QF Treatment. As discussed i the SPP-Entergy CBA, upon joining an SPP Day 2 RTO,
      FERC may rule, as it has in other Day 2 markets, that the Entergy PF put options no longer
      apply, Ifso, the QFs would have to provide prior notice of self scheduled output to the RTO
      system operator. That i ,the QFs would effectively operate as IPPs, albeit with the added
                              s
      limitationo needing to serve their host load, To model this, In the Status Quo Case, the
                 f
      Entergy QFs were treated as 'non-firm", meaning that the Entergy region is committed day-
      ahead without QF energy considered. In the Join SPP Case, the Entergy QFs were treated
      as "firm', meaningthat the QFs were treated as available for commitment.

                                                                                      o
       See the SPP-Entergy CBA for further detail regarding these input assumptions. T help
       understandthe impact on trade benefits resultingfrom these three input assumptions, a
       number ofaddendum sensitivitieswere performed that modified these assumptions in whole
       or in part, as described in the following section.

3.3.1. Seams Charge and QF Treatment Addendum Sensitivities

      Six addendum sensitivitieswere performedi which an input assumption related to the
                                                n
                                                           % ' Case was modified from the
      seams charges or the QF treatment in the Status Quo ( a )
      assumptions used in the SPP-Entergy CBA. The assumptionsused in these sensitivities,
      numbered SQI through SQ6, are described in Table 4.




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                     Table 4 Seams Charge and PF Treatment Addendum Sensitivities (SOf-SUq
                            :




          - SQf: No Seams Charges                         0                   0                0              Non-firm
          -   $92: Entergy QFs Flnn                       10              3 +wheel             5               Rrm
          -   543: Reduced commltment Charfles            3               3 +wheel             3              Non-firm
     1    -   Sa4: Roduced CommltlDtspatch Charges    I   3        I      2*wheel        I     3          I Non-firm I
          -   545: No Entergy-Cleco Wheel Charges         10           3 (+wheel tdfmm
                                                                           SPP only)
                                                                                               5              Non-firm

          - SQ6: No SPP-Entargy Wheel Charges             10           3 (+wheelt f r
                                                                                dm n           5              Non-firm
                                                                         Clem only)
         J ~ l SPP Case in SPPEntergY CBA
               n                                          0
                                                                   I         0
                                                                                         1     0          I    Finn


         A GE MAPS analysis for 2013 was conducted for each of these cases to determine the trade
         benefits that would accrue to the SPPlEntergy region if Entergy and Clew Power joined the
         SPP RTO. Results are summarized in Table 5

                 Table 5: 2013 Trade Benefits by Region if Entergy and Cleco Power Jofn the SPP RTO
                               (in millons of 2010 dojlats, positive numbers are benefib)


                  SPP-Entergy CBAKesutfs                  22       107        Q)         127
                  SQ7: No Seams Charges                   10       34         31         75        (52)
                  SQZ: Entergy QFs Flrm                   26       50         (21)       56         1
                                                                                                   a1
                  543: Reduced Commltment Charges         22       63         32         1j6       (17)


                  SQ5: No Entergy-Cleco Wheat:Charges     20       103            i      122       15)
                  SQ6: No SPP-Entergy Wheel Charges       21       109        (5)        126       If)



         As shown, the 2013 trade benefits remain positive across these sensitivity cases for the
         SPPIEntergy region as a whole (from $56 to $126 million), as well as for the SPP region ($10
         to $21 million) and Entergy region ($34 to $109 million). The impact on the Cleco region
         varies, as discussed further below.

         The first two addendum sensitivities (SQ7 and SQ2) are designed to assess what share of
         the trade benefits found in the SPf-EnfergY CBA come from the seams chargesllPP hurdles
         assumption in comparison to the Entergy QF treatment.

         SQI: No Seams Charses in Status Quo Case. This sensitivity has no seams changes or IPP
         hurdles within the SPP-Entergy region in both the Stalus Quo Case and the doin SPP Case.




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December 8.201 0                                                                    Charles River Associates


      Thus, only the QF treatment is different between the two cases. With only this QF treatment
      difference, the benefits to the SPP-Entergy region are $75 million. This indicates that the
      seams chargesllPP hurdtes contribute about $52 million of the $127 million of2013 trade
      benefits in the SPP-fnfergyCBA and the QF treatment the remaining $75 million.

                                                                                         im
      SQZ: Enterqy PFs Firm in Status Quo Case. This sensitivity has QFs treated as fr in both
      the Slafus Quo Case and Join S f f Case. Thus only the seams chargesllPP hurdles are
      different between the two cases. Wlth only this difference, the benefits to the SPP-Entergy
      region are $56 million. Consistentwith the results of SQ? above, this indicates that the
      seams chargesllPP hurdles contribute about $56 million o the $127 million of the 2013 trade
                                                                f
                n
      benefits i the SPP-Entergy CBA and the QF treatment the remaining $71 rnillion.30

      Based on the results of SQI and SQ2, QF treatment is a significant contributorto the SPP-
      Entergy region trade benefits. To the extent that the Entergy QF puts can be modified to be
      "firm' in the absence of joining an RTO, this would significantly reduce the benefits of Entergy
      joining the SPP RTO. The elimination of inter-regionaltrading frictions is also a major, but
      less significant contributing factor.

      The next two addendum sensitivities cases (SQ3 and SQ4) are designed to assess whether
      the seams chargesllPP hurdles assumed to be in place in the Status Quo Case were in
      practice closer to that of the Join SPP Case. This would serve to reduce the trade benefits of
      Entergy and Cteco Power joining the SPP RTO.

      SQ3: Reduced Commitment Charqes in Stafrrs Quo Case. This sensitivity has reduced
      commitment seams charges and IPP commitment hurdles in the Status Quo Case, meaning
      that the elimination of commitment charges in the Join SPf Case wilt be less beneficial than
      assumed in the SPP-Enfergy CBA. However, as shown in Table 5, the 2013 trade benefits to
      the SPPlEntergy region o Entergy and Clem Powerjoining the SPP RTO remain substantial
                                f
      at $1 million.
           16

      SQ4: Reduced Commitment and Dispatch Charqes in Status Quo Case. This sensitivity i      s
      the same as SQ3, except the dispatch seams charges in the Status Quo Case are reduced
      as well, However, results are similar to those o SQ3, with 2033 trade benefits of $111 million
                                                      f
      to the SPP1Entergy region.

      The results of these SQ3 and SQ4 sensitivitiesindicate that even a moderate level of
      commitment and dispatch seams charge reductionfrom joining the SPP-RTO provide
      significant benefit to the SPPlEntergy region.




lo    bewusa of dlfferent starflng polnls and lnterdependendes between the assumpuons, the order In whlch the seams
      chargesJPP hurdles and QF treatment assumptions are rnadified wtll Impact the results. Thus, the a!locaUon of
      benefits between seams ChargedPP hurdles and QF treatmentwill not match exactly betweenSQl and S Q 2




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December 8,201 0                                                           Charles River Associates



      The 2013 trade benefitsfor Clem Power swings from roughly neutral in the SfP-Entergy
      CBA to negative in SQ2 and positive in SQI,SQ3 and SQ4. Based on these results, it
      appears that the Cleco region benefits from the Entergy QFs becomingfr resources, but
                                                                                im
      that the elimination of seams chargesllPP hurdles can have a negative impact on Cleco trade
      benefits depending on the assumed starting level. As noted in the SPP-Entergy CBA, Cteco
      Power is a smaller region with extensive transmission interties with the Entergy regions and
      'swings" more on a percentage basis throughout the anaIyses conducted.

      fhe next two addendum sensitivity cases (SQ5 and SQS) are deslgned to assess whether
      elimination (Le., depancaking) of the existing wheeling charges between Clem and Entergy
      or SPP and Entergy in the Status Quo Case,would substantially reduce the benefits of
      joining the SPP RTO.

      SQ5: No Wheelins Charqes between Enterqv and Cleco i sfatus Quo Case. This
                                                                 n
      sensitivity eliminates the Entergy-Cleco wheeling charges in the Status Quo Case. However,
      as shown in Table 5, even if this took place, 2013 trade benefits would continue to be
      substantia! if Entergy and Cleco Powerjoined the SPP RTO.

      SQ6: No Wheeling Charqes between SPP and Enterqy in Status Quo Case. This sensitivity
      eliminates the Entergy-SPP wheeling charges in the Status Quo Case. However, as shown
      in Table 5, even if this took place, 2013 trade benefits would continue to be substantial if
      Entergy and Cleco Power joined the SPP RTO.

      The results of these SQ5 and SQS sensitivities indicate that depancaking in and of itself will
      not provide significant benefits to the SPP-Entergy region. We attribute this to the lost
      revenue that accrue when wheeling charges are reduced. There is a decrease in supply
      costs (as wheeling charges for purchases are reduced), but there is also a loss in wheeling
      revenue to the transmission providers that must be made up through additional charges to
      load.

      GE MAPS runs for 2022 were completed for SQf, SQ2 and SQ3 as well. Results are
      summarized in Table 6. As shown,the results are generally similar in nature to those for
      2013, QF treatment has a larger impact in 2022 than in 2013, white the seams and IPP
      charge elimination has a correspondingly smaller impact.




                                                                                               Page 8
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December 8,2010                                                                Charles River Associates



           Table 6: 2022 Trade Benefits by Region if Entergy and Cleco Power JoIn the SPP RTO
                         fin mi//ons of2010 doifam, posXve numbers are benetis)



           1 SPP-Eniemv CBA Results                                                                  I
            SQf: No Seams Charges                       12      36        34        a3       (321
            SQ2: Entergy QFs F l m                      $1      20        (5)       26       (89)
            SQ3: Reduced commitment Charges             20      43        37        101      (141




3.3.2. Delayed SPP Day 2 Addendum Sensitivity

      One addendum sensitivity was performed in which there was a change to the Join SPf TJS)
      Case from that used in the SPP-Enfergy CBA. fn this sensitivity, a delay in the Day 2 market
      for SPP was assumed to take place, TOmodel this for 2013, the commitment seams charges
      between SPP, Entergy and Cteco Power in the Join SPP Case were teff at $1OlMWh (no joint
      day-ahead commitment in place in the SPP RTO with a delayed Day 2). while the dispatch
      seams charges remained at zero (reflecting the Energy Imbalance Service market currently in
      place in the SPP RTO), as shown in Table 7.
                             Table 7: Delayed Day 2 Addendum Sensitivity (JS4)




      Join SPP Case in SPFEntergy CBA               0                0                   0           r
                                                                                                    nm
       - JSf: Delayed SPP Day 2                   IO                 0                   5          Firm

      The results of this run in comparison to the SPP-Enfergy CBA results are shown in Table 8.

           Table 8: 2013 Trade Benefits by Region if Entergy and Cleco Power JoIn the SPP RTO
                         (in miffionsof 20 f0 doilaB, positive numbers are benefits)


                                     ..
            SPP-Entergy CBA Results                     22     107       (2)       127
            Jsl: Delayed Day 2 In SPP                   0       69       23         92       (351


      As shown,the 2013 trade benefits of Entergy and Cleco Power joining the SPP RTO with a
      delay in Day 2 continue to be substantial. However. it is important to note that a significant
      portion ofthe 201 3 trade benefits likely comes from the assumption that the Entergy QFs
      would stilt become 'firm" even if SPP i not yet a Day 2 market. It is CRA's understanding
                                              s
      that this i less certain in me absence of a Day 2 market.
                s



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3.3.3. Carbon Addendum Sensitivity

       On final addendum study was conducted in which a carbon adder of $20lton of C02 was
       applied to the generating unit fuel costs in both the Status Quo Case and Join S f f Case.
       For purposes of this study, no other corresponding assumption changes were made that
                            ih
       might be consistent wt the institution of national climate change legislation, such as
       changes in coal and gas prices, changes to demand, etc.

      As shown in Table 9,2013 trade benefits continue to be significant for the SPP-Entergy
      region with this additional carbon cost.41 Because it is assumed that no additional capacity
      expansion (e.g., wind) fakes place by 2013,t i wse is similar to a 'low gas' case in that the
                                                     hs
      increased cost for gas fuel plants is lower than that incurred by coal-fired facilities. Results
      for an out-year in which there might be a capacity response could be different,

            Table 9 2013 Trade Benefits by RegIon if Entergy and Cleco Power JoIn the SPP RTO
                   :
                         ( n mi//ions of 2010 dollam, posiiYve numbers are bene&)
                         X




4.     CONCLUSION

      Based on the additional addendum analyses performed, we continue to conclude that
      Entergy and Cleco Power joining the SPP RTO will yield significant economic benefits to the
      collective SPPlEntergy region. The portion of the benefits that result from treating QFs as
      firm resources in the Join SPP Case are significant, with the elimination of inter-regional
      trading frictions also a major, but less significant contributing factor. The trade benefits
      remain positive across the sensitivity cases examined for the SPPlEntergy region as a whole,
      as well as for the SPP region and the Entergy region. Consistent with the SPP-EnfegyCBA,
      the impact on the Cleco region varies across the sensitivity cases. As discussed in the SPP-
      fntergy CBA, the net benefits to the individual Entergy, SPP and Cteco Power regions is also
      highly dependent on the allocation OF regional high voltage transmission expansion costs.




      The m b o n adder was assumed no! to impact the QF put quantities. A post-processing slep was mad@to Indude a
      a r b o n ad&r to the QF sales quantitles in both the Status Quo Case and Jofn SPP Case.



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December 8,2010                                                             Charles River Associates



APPENDIX A: ADDENDUM SENSITIVITY INPUT ASSUMPTIONS
Further detait regarding addendum sensitivity input assumptions are captured in in Table 10.

              Table I O : Net Benefit to Entergy, Cleco and SPP Regions of Join SPP Case
                                                w
                                            FILED




                           Cost-Benefit Analysis of
                           EntergylCleco Power ur
                           Entergy Arkansas Joining
                           the Midwest I S 0
                           Addendum Study




Prepamd By:
Charles River Associates


Date: Mareh10,ZOII
Join MISO CBA Addendum
March 10.2011                                                                                                           Charles River Associates



                                                      Table of Contents


1.    INTRODUCTION.............................................................................................................                                      1


2. ENTERGY AND CLECO IN THE MIDWEST IS0 OR SPP RTO ....................................                                                                              3
     2.1.       STUDYM                   F             ~            o             D.....................................................................
                                                                                                 O                 ~                                                 3
                2.1.1.                 .................................................................................................................. 4
                           Seams Charges
                2.1.2. Midwest [SO Demand, NewWind Capacity and Transmission Expansion ........................ 8
                2.1.3. Summary of Modeting Changes .........................................................................................               9
                2.1.4. Joint Operating Agreement ................................................................................................          9
      ..
     22         FINDINGS-  ENTERGYAND CLECO I N M E MIDWEST Is0 OR SPP RTO ...............................                                               10
                2.2.1. Summary of Resul ts .........................................................................................................      IO
                2.2.2. Trade Benefts .................................................................................................................. 12
                2 2 3 Administrative Costs......................................................................................................... 1
                 ...                                                                                                                                       6
                2.2.4. Transmission Cost Expansion ..........................................................................................             17


3.    EA1 IN THE MIDWEST IS0 OR SPP RTO ...................................................................                                                         18

      3.1.      STUDY METHODOLOGY E V A L ~ A T ~ O ~ )
                               (EA1                                           .........................................................................
                                                                                                                                                   18
                3.1.1.     Seams Charges (EA! Evaluation)..................................................................................... 20
                3.1.2.     Transmission (Wheetlng) Revenue and Costs Methodology (EA1 Evaluation).................21
                3.1.3.     Summary of Modeling and Assumption Changes (EA1 Evaluation) .................................. 23
      32
       ..       FINDINGS-    IN SPP OR MIS0 ..................................................................................... 24
                3.2.1. Summary of Results for EA1 in RTO................................................................................. 24
                                      H Evaluation) .......................................................................................
                3 2 2 Trade Benefits ( I
                 ...                                                                                                                                                26
                3 2 3 Administrative Costs (EA1 Evaluation)..............................................................................
                 ...                                                                                                                                                28
                3.2.4.     Transmission Expansion Cost (EA1 Evaluation)                         ...............................................................     29


4 . OTHER ISSUES ........................................................................................................... 30


5.    CONCLWSION .............................................................................................................                                      30

APPENDIX A: ENTERGYlCLECO IN RTO FURTHER RESULTS ......................................                                                                             32
      A.1       ENTERGYICLECO RTO ..........................................................................................
                           IN SPP                                                                                                                                   32
      A.2       ENTERGYICLECO tN THE MIDWEST                       I 0..............................................................................
                                                                    s                                                                                               34


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     A.3     EA1 IN SPP RTO ..............................................................................................................                   35
     A4                          Is0
                    IN THE MIDWEST                   ..................................................................................................      36

APPENDIX 8: TRADE BENEFITS IN GE MAPS CASES ....................................................                                                             37
     6.1     ENTERGYELECO  IM RTO C A ~ E S                       .......................................................................................
                                                                                                                                        37
     8.2     EAI IN RTO CASES...........................................................................................................38
APPENDIX C:FURTHER DETAIL 201912022 POW€R FLOW...........................................                                                                    39




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I.    INTRODUCTION

      Charles River Associates ('CRA") has previously issued three cost-benefit analyses ('CBAs')
      regarding the potential membership in the Southwest Power Pool ("SPP')l regional
      transmission organization I'RTO') of Entergyz and Cleco Power3 on a combined basis, or the
      separate membership of EntergyArkansas ('EAI").

      SPP-Enfemv CBA. On September 30,2010, CRA and Resero Consulting issued the final
      report for the SPP-Enfergy CBA sponsored by the Federal Energy Regulatory Commission
      ('FERC").4 The SPP-Entergy CBA concluded that Entergy and Cleco Power joining the SPP
      RTO wit1 yield significant economic benefits to the collective SPPlEntergy regim5 The net
      benefits to the Entergy and Clem Power regions were highly dependent on the allocation o  f
      regional high voltage transmission expansion costs.6 Aside from the allocation of
      transmission expansion costs, the benefits to the Entergy region of joining the SPP RTO were
                                                                               f
      relatively robust across the sensitivity scenarios examined. A number o important qualitative



      Southwest Power Pool, Inc. Is a group of 57 members in Arkansas, Kansas, LouIstana, Missfssippl, Mlssoud.
      Nebraska, New Mexlm. Oklahoma. and Texas that 5erve more than five rnIlIion customers. Membership I         s
      comprised of Investor-awned utilities, munlcipal systems, generation and transmlsslon cooperatives, state
      authorities. wholesale generators. power rnarkelers, and Independent Iransrnlssion wmpanles. SPP5 footprint
      Indudes 29 balancing authorities and 50.575 miles of tmnsmisslon lines. SPP was designated by the FERC as a
      RTO In 2004. As an RTO, SPP ensures fellable supplies of power. adequate transmlsslon Inhslructure, and
      competitive wholesale prices of eledridty. SPP Is a North Amedcan Electric Reliabllily C o p rNERC7 Reglonal
      Entity. Clew Power I not wrrenffy a member of the regional market operaled by the SPP, but Is a member of the
                           s
      SPP Regional Entity. Enlergy is a member of the SERC Reglonal Entity.

      Enlergy Arkansas, tnc., Enlergy Loulslana. LLC, Entergy Gulf States Loulslana L.LC., Entergy Mississippi. Ink.
      Enlergy New Orleans, Inc., Entergy Texas, Inc (wlteetively, "Enkrgyy.These utility operating companies serve 2.7
      mllllon customers In Arkansas, toulsiana, Mississlppl. and Texas.

      Clem Power U C Is a regulated erectric utility company that s e w s about 277.000 customers amoss Loulslana.

      See http~~.spp.orglpubll~~onslFERC%20SPP~20Entergy%20CBA%20Report%20Rnal.pdf. lhts I a           As        s
      follow-on addendum study, the detalled descriptions of the CRA modellng approach and Input data eontalned in the
      SPpEntergy CBA are not fully repealed hereln. See the SPPEnlergy C8A for further detail on these Issues.

      The 'SPPEntergy reglon" refers to all load and generation In the wrrent Entergy-SPP-ClewPower transmlsslon
      syskm footprint. Indudlng that of merchant generators and cooperative and rnunldpal utilities.

      The 'Ennlergy reglon' refers to the area withln the Entergy transmlslon system footprint, and for purposes of the
      SPPEntergy CBA included Loulslana Generattng and Louklana Energy and Power Authority. The 'CIem reglon"
      refers to the area within the Clem transmission system footprint as well as h e Clem Power Ioad served by the
      Entergy transmlsslon system, and for purposes of t i study indudes the Clty of Lafayette. The ISPP reglon' refers
                                                         hs
      to the SPP transmlsslon system footprint that Is wmntly operating withln the SPP Energy Imbalance Service
      market.




                                                                                                               Page 1
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March 10,201 I                                                                           Charles River Associates



      considerations were identified as well, with both qualitative benefits and offsetting costs
      incurred by Entergy and Cteco Power if they joined the SPP RTO.

      SPP-MI CBA. The Arkansas Public Service Commission (*APSC') directed the SPP to
      perform within the context of the broader SPP-€nfergy CBA, an EAI-specific CBA ('SPP-EAI
      CBK) associated with EA1 becoming a full "standalone' member o the SPP RTO at the time
                                                                          f
      it would leave the Entergy System Agreement rESA7.7 CRA was engaged by SPP to
      performthe SPP-EAI CBA using the models and input assumptions developed under the
      FERC-funded SPf-€ntergy CBA. The SPP-€41 CBA report issued on October 27,2010
      concluded that EA[alone joining the SPP RTO, relative to operating on a standalone basis,
      will not yield significant economic benefits to the EA[region or the collective SPPlEntergy
      region.8

      SPP-Entemv C8A Addendum. During the course of the SPP-Entergy CBA, parameters
      worthy of additional analysis were identified by study stakeholders, including seams charges
      and the treatment of Entergy QFs. In response, CRA was engaged by Entergy to perform an
      addendum study to analyze additional sensitivity cases using the models and input
      assumptions developed under the SPP-Entergy CBA. Based on the addendum sensitivity
      analyses performed, the SPP-Entergy CBA Addendum report issued on December 8,2010
      continuedto conclude that Entergy and Cteco Power joining the SPP RTO will provide
      significant economic benefits to the collective SPPIEntergy region.

      In this Join MISO CBA Addendum, the potential membership in the Midwest IS0 of Entergy
      and Cleco Power or, alternatively, EA1 is evaluated. CRA9 was engaged by Entergy to
      evaluate the costs and benefits of:

                1. Entergy and Clem Powerjoining the Midwest I S 0

                2. EA1joining the Midwest IS0 relative to operating as a standalone entity

      This Join MIS0 CBA Addendum uses the models and assumptionsdeveloped under the
      SPP-Entergy CBA and SPP-EAI CBA as the basic framework. As described in detail betow,
      certain modifications to the modeling assumptions and framework were required to evaluate
      the join Midwest IS0 option. As such, for consistency, the costs and benefits of



7     Docket No. 08;136U, Order No. 13.

8     The'EAl reglon'refers to all load and generaffonIn the EA1transmlsslonsystem footprint includingthat of merchant
      generatorsand cooperative and municipal utilities. The 'Rest of Entergy region' refers to the area withh the Entergy
      transrnldon system footprint excludlng the EA1 iransmlsslon system, and for purposes of this study Includes
      Loulslana Generating and Loulslana Energy and PowerAuthority.

9     Pn'ndpal study InvesUgators for CRA were Ralph Ludani. Bruce Tsuchlda and Pablo R u L The findlngs and
      conduslons wntalned In thIs CBA are solely those of the CRA team.
Join MISO CBA Addendum

March I O , 201 I                                                                        Charles River Associates



        EntergylCleco Power or EA1 joining the SPP RTO were reevaluated in this CBA using this
        same modified assumptions and framework. The evaluation of the costs and benefits of
        Entergy and Cleco Power joining the Midwest IS0 or SPP RTO is summarized in Section 2.
        The evaluation of the costs and benefits of E1 joining the Midwest IS0 or SPP RTO is
                                                     A
        summarized in Section 3 j
                                .0

       As discussed in detail in the following sections, we continue to find that there wilt be
       significant benefitsfor the Entergy region to join an RTO, but these benefits are or can be
       more than offset by the allocation to the Entergy region o RTO transmission expansion costs.
                                                                 f
       We continue to find that the benefits of EA1 joining an RTO are more limited, and these
       benefits also are or mn be more than offset by the allocation to the EA1 region of RTO
       transmission expansion costs.


2.      ENTERGY AND CLECO IN THE MIDWEST IS0 OR SPP RTO

2.1.    STUDY METHODOLOGY

        Three different cases were analyzed over the IO-year period from 2013 to 2022:

                 1- Entergy and Cleco Power continue to operate as they do today (‘Sfafus Quo
                 Case”)

                 2 Entergy and Clem Powerjoin the SPP RTO (“Join SPP Case‘)
                  .

                 3. Entergy and Cleco Powerjoin the Midwest IS0 (‘Join MISO Case’)

        In the Slatus Quo Case, SPP is assumed to continue in its capacity as Independent
        Coordinator of Transmission (“ICT)for the Entergy transmission system. As the SPP RTO i    s
        working toward instituting a Day 2 market, a Day 2 market is presumedto be in place in the
        SPP RTO throughout the 2013-2022study period.” The Midwest IS0 already has a Day 2
        market i place.
                 n

        CRA analyzed the impacts on the Entergy, Clew Power and SPP regions using the General
        Electric Multi-Area Production Simulation (%E MAPS) model of the entire Eastern
        Interconnection. A separate evaluation of the specific costs and benefits to the existing




        A Day 2 market refers to a hvo-settlement (day-ahead and real-time) energy market using hourly lomtional marginal
        prlces and financial transdsslon rights (FIRS).Day 2 markets are wmntly In place in PJM. the Mldwest ISO, IS0
        New England and the New York EO.




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        Midwest IS0 region was not performed. GE MAPS is a detailed economic dispatch and
        production costing model that simulates the operation of the electric power system taking into
        account transmission topology. GE MAPS runs were performedfor the years 2013,2016,
        2019 and 2022, with intervening years interpolated.

        The same model input assumptions applied and described in the Sff-EnfefgyCBA are used
        in this addendum study. However, certain modeling assumptions had to be modified to
        assess the Midwest IS0 option, including seams charges and Midwest I S 0 demands, new
        wind capacity and transmission expansion. These modifications are described in detail
        below.

     I Seams G harges
2.1 . .

        In the GE MAPS modeling, there is a commitment (nextday) step and a dispatch (real-time)
        step. In the commitment process, generating units in a region are turned on or kept on in
        order for the system to have enough generating capacity available to meet the expected peak
        load in the region for the next day. GE MAPS then uses the set of committed units to
        dispatch the system on an hourly real-time basis, whereby committed units throughout the
        modeled footprint are operated between their minimum and maximum operating points to
        minimizetotal production costs.

        As discussed in the SPP-EnfergyCBA, GE MAPS was used to model different impediments
        to SPP-Clem-Entergy trade under the sfatus Quo Case and the Job SPP Case. The
        impediments to trade applied include commitment and dispatch seams charges. Seams
        charges are applied by CRA in the GE MAPS model at the *seamu border between regions
                                                                       or
        (e.g., between Entergy and SPP, Entergy and Cleco, SPP and the Midwest ISO, and Entergy
        and Southern Company). In the absence of seams charges, GE MAPS wilt optimize the
        commitment and dispatch of generation across the entire Eastern Interconnection as if it were
        one balancing authority with traders and operators having perfectinformation about all load,
        resources and transmission congestion, and with no transmission wheeling charges payable
        for regional imports and exports.

        For this Join MIS0 CBA Addendum, the seams charges were modified to incorporate the Join
        MISO option as discussed below.

        1000 MW Contract Path. The principal interconnection between the Midwest IS0 and
        Entergy is located at New Madrid, Missouri,where Ameren (a member of the Midwest BO),
        Associated Electric Cooperative, Inc. ('AECI'), and Entergy share 1500 MW of tie-line
        apacity.12 The 1500 MW o capacity is shared betweenAECI, Ameren and Entergy in
                                     f
        equal thirds, with any two ofthe parties able to use the sum of their shares. The net effect of



l2                                       -                    -                            -
        Thls Is the Lrrtesville345kV (Ameren) Essex345kV (AECI) New Madrid 3451500kV (AECI) Dell 500kV (Entergy)
        line.




                                                                                                        Page 4
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March I O . 201 1                                                                         Charles River Associates



        this agreement is the availability of a I000 MW contract path between the Midwest I S 0 and
        Entergy V I 000 M W Contract Path').

        For purposes of the SPP-Entergy CBA, this contract path arrangementwas not specifically
        addressed for modeling purposes. The path was treated simply as an interconnectionwith
        hurdles between Entergy and AECI, and a separate interconnectionwith hurdles between
        AECl and the Midwest [SO.      However, for this Join MIS0 CBA Addendum, the 1000 MW
        Contract Path represents the key means by which Entergy and the Midwest IS0 could
        optimlze commitment and dispatch of operations if Entergy were to join the Midwest IS0.13
        To reflect this, in the Join MISO Case, the seams charges are eliminated entirety on the 1000
        MW Contract Path (Le,, both the Entergy tolfrom AECl leg and the AECllAmeren leg).

        Dispatch Seams Charqes. The dispatch seams charges applied in this Join MISO CBA
        Addendum are summarized in Table 1. These are the same dispatch seams charges applied
        in the SPP-EnfergYCBA. In the Sfatus Quo Case and the Join SPP Case, the hurdle on the
        1000 M Contract Path is comprised of the MISO tolfrom AECI dispatch seams charges.
                W
        and the AECl tolfrom Entergy dispatch seams charges.l4 In the Join MIS0 Case. both of
        these seams charges are eliminated on the I000 MW Contract Path.




l3             s
        There I no direct path bemeen Clem Power and the Mldwest ISO, thus, Clem Power would Interconnect with tha
        Mldwest I S 0 only through En!ergy if Entergy and Clew Paver were to joIn the Midwest ]SO. It Is our understanding
        that the transmlsslon arrangement between AECI, Ameren, and Entergy is currently set to explre in 2013, with
        discussionsbehveen the parties expected to take place pdor to that time regarding an extenston or a replacement
        arrangement with slmilar terms. It is assumed In thIs Join MISO CBA Addendum that the 1000 M Contract Path I
                                                                                                       W                 s
        In place throughout the study period.

l4      The AECI to Entergy dlspatch seams charge I $3 for wheeling and $3 for trading fridon. A possible refinement to
                                                       s
        the GE MAPS analyses In thls study would be to mn the slatus Quo Case and Jdn SPP C8se with Only a Single
        hurdk from the Mldwest I S 0 to Entergy on the 1000 MWContrad Path.




                                                                                                                 Page 5
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March 10,2011                                                                           Charles River Associates



             Table I :Dbpatch Seams Charges in GE MAPS In the SPPlEntergylMtSORegIon q5
                              Dispatch Friction + Wheeling Charge ($/MWhJ
                                            Status Oua Case


                                                                                    .
                       From Entergy           3+3             -             3+3            3+3
                       From Cleco             3+3           3+3              -               -
                       From MISO              3+5       3+5                  -               -
                                             Entemv-Cleco Join SPP Case

                       From SPP                -              0               0            3+2
                       From Enterqy            0              -               0            3t.2
                       From Cleco              0              0              -               -    .
                       From MISO              3t.5          335              I               I




                                             Entemv-Cleco Join MISO Case




                       From Cleco        I    3+3     1       0              I
                                                                                             0


      commitment Pool. As described i the SPP-Entergy CBA, to model the commitment
                                        n
      process, CRA defines major 'commitment pools" i GE MAPS I which units inside the pool
                                                         n             n
      are committed to mn to ensure reliable service within the commitment pool without
      considerationof external non-firm resources. These major commitment pools include, among
      others, PJM,Southern Company and W A . To the extent that the commitment process for
      regions within a major commitment pool i not jointly optimized, CRA applies a 510 per MWh
                                               s
      commitment hurdle between these regions. That is, generating units in a commitment pool
      will not be committed to meet load in another region within the same commitment pool unless
      there i at least a $10 cost advantage over units that would be available within that region.16
             s
      ln the SPP-fntetgy CBA, the SPP, Entergy and Cleco regions (along with AECI) were
      assumed to be in a single commitment pool. The Midwest IS0 was i a separate
                                                                        n
      commitment pool. This commitment pool arrangement was ideal for a focused analysis on
      Entergy and Cleco Power joining the SPP RTO. However, having the Midwest I S 0 in a
      separate commitment pool in GE MAPS does not allow for the optirnitatlon of the RTO
      commitment process if Entergy and Cleco Power were to join the Midwest ]SO.

      As such, a commitment pool that includes the Midwest ISO, SPP RTO, Entergy and Cleco
      Power was applied i all EE MAPS runs i this Join MIS0 CBA Addendum. As shown in
                           n                    n
      Table 2, other than inclusion of the Midwest I S 0 in the SPPIEntergy Commitment pool with a



l5    See the SPpht8rgy CBA for a summary of the Saarns cbarges applied throughout the Eastern Intemnnec!.

j6    Modeling commitment pools, rather than applylng cornrnltrnent seams charges between all balancing reglons In the
      Eastern Interconnect, greatly speeds up the optimlzaffon process In GE MAPS.




                                                                                                              Page 6
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March 10,2011                                                             Charles River Associates



      $1OlMWh hurdle, there were no other changes to the commitment hurdles from those used in
      the SPP-EnfergyCBA. In the Status Quo Case and the Join SPP Case, the hurdle on the
      1000 MW Contract Path i comprised of the MISO tolfrom AECt $10/MWh commitment
                             s
      seams charges, and the AECl tolfrorn Entergy $1OlMWh commitment seams charges. In the
      Enlergy-ClecoJoin MISO Case, both of these seams charges are eliminated on the 1000
      MW Contract Path.

        Table 2: CommitmentSeams Charges ($/MWh) in GE MAPS in the SPP1EnfergylMlSO RegIon
                                            Status Quo Case




      The change in the commitment pod modeling to include the Midwest IS0 in the SPP-Entergy
      region commitment pool required changes in the modeling of losses in GE MAPS. For the
      SPP-Entergy CBA, marginal losses were used in the GE MAPS optimization process for both
      the commitment and dispatch steps. In this Join MIS0 CBA Addendum, average losses are
      used in the modelingo the commitment step, while marginal tosses are used, as before, in
                             f
      the dispatch step. All else equal, the use of average losses for the commitment step will tend
      to result in the commitment of more distant units to meet load. As a result, this change wilt
      contribute to differences in results from those of the FERC-sponsored SPP-Enfergy CBA.

      The change in loss modeling for the commitment step was implementedbecause o the    f
      significant computational effort o performing commitment with marginal losses across such a
                                        f
      large commitment pool foofpnnt. Using marginal losses requires an iterative process where
      loss factors are updated to adjust for changes in transmission flows. Wrth the Midwest IS0 in
      the SPP-Entergy commitment pool, the processingtime required to iterate the commitment
      step with marginal losses made it difficult to ensure the modelingwas working correctly in the
      time available for this study. In addition, it is CRA's understandingthat the Midwest IS0 uses
      fixed loss factors that are estimated based on marginal loss-based historical values in its




                                                                                             Page 7
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March IO,201 1                                                                          Charles River Associates



         commitment optimization. GE MAPS sirnitarty uses fixed loss values with the average loss
         commitment step used in this CBA.17

2.1.2.   Midwest IS0 Demand,             New Wind Capacity and Transmission Expansion
         In the SPP-EnfergY CBA, at1 regions in the Eastern Interconnection outside of the SPP-
         Entergy region had their energy demand and generation expansion frozen in GE MAPS after
         2013 As noted in the SPP-EntergY CBA, this was performedto mhimize uncertain external
              .
         impacts on the analysis of the SPP-Entergy region. For this Join MISO CBA Addendum,
         Midwest IS0 energy demand and generation expandon after 2013, along with additional
         Midwest IS0 transmission expansion, are also taken into account.

         The increase in MISO energy demand aRer 2013 is taken from the most recent Midwest I S 0
         forecasts. The Midwest IS0 region is currently above its target reserve requirement, and
         additional wind capacity is the major type of new capacity that likely will be constnrcted i the
                                                                                                     n
         Midwest IS0 region during the study period. Table 3 shows the total wind capacity modeled
         in the SPP region and in the Midwest IS0 in this Join MISO CBA Addendum. The SPP wind
         capacity is the same as that used in the prior CBAs.

                                Table 3 Wind Capacity I SPP and the Midwest I S 0 (GI47
                                       :               n



                                      SPP                 4.0       4.0      5.5      7.0
                                      MldwestISO          10.0      15.0     15.0    19.4


         The increase in Midwest IS0 wind capacity is related to the contemplated expansion of the
         Midwest I S 0 transmission system to incorporate the often remote locations of likely wind
         capacity expansion. These Midwest IS0 'Multi-Value Projects' OF 'MVPs' represent a
         significant expansionof the Midwest I S 0 transmission system, and are designed to 1) meet
         public policy goals such as renewable portfotio standards, 2) provide widespread economic
                                              of
         benefits, or 3) provide a cornbina~on widespread economic and reliability benefits.

         A portfolio of approximately $4.4 billion of Multi-ValueProject expansionhas been developed
         by the Midwest I S 0 for development within the next 5 to 10 years.18 Based on input from the
         Midwest ISO, these Mutti-Value Projects are includedin the power flow used in the 2019 and




l7       Entergy is arrrentry a member of the SPP reserve sharing group. In this CBA and In all prior CBAS, the Entergy
         reglon's splnnlng reserves requlrement Is assumed to rernaln the same In all cases, as this requlrement already
         reflects the benefits of M n g a member of a resem sharing group.

         Midwest IS0 Ttansmissidn &st PJlOeafion forEnlergy. Mar& 3,2011, Midwest ISO.




                                                                                                                Page a
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March I O , 2011                                                                               Charles River Associates



             2022 GE MAPS runs in this Join MISO CBA Addendum.1gWhile a portion of the Multi-Value
             Projects may corne on-line in the 2013 to 2016 period, these are expected to be relatively
             small and were ignored for purposes of the GE MAPS modeling in this CBA. As discussed
             further below, the corresponding costs allocated by the Midwest IS0 to Entergy and Clem for
             Multi-Value Projects was captured in this CBA.

2.1.3. Summary of Modeling Changes

             Because of the change in the commitment pool modeling as well as inclusion of additional
             demand, wind capacity and transmission expanslon in the Midwest ISO, the results for the
             Status Quo Case and Join SPP Case would be expected to change from those of the SPP-
             Entergy CBA. The differences in modeling assumptions between the SPP-Enlergy CBA and
             this Join MISO C8A Addendum are summarized in Table 4.
                                          Table 4 Summary of Modellng Assumption Changes


         ?OM1 MW Contract Path            Hurdles behveen Entergy-AECl     Same for Sfatus Quo and Join SPP Cases. Hurdles
                                          and AECI-Ameren In Status Quo    belween Eotergy-AECI and AECI-Ameren on the 1000
                                          and Joln SPP C6ses.               W
                                                                           M Contmct Path ellmlnated In Joln M E 0 Case.
         Commltment Pool                  SPPIEnlergylCleco region, with  SPPEntergylClecolMISOreglm, with average Iosses In
                                          marginal losses In wmmllment    wmmltment step, and rnarglnal losses In dlspatch step.
                                          step and dispat& step. No       $loIMwh wrnmlbneot hurdle between SPP and MISO In
                                          commitment optimlration between all wses. and between EntergylCIew and MISO In
                                          MISO and SPPEnlergylCleco.      Status Quo and Join S f P Cases.
                                                                           lnmaslng throughout study period. MISO wind capaaty
         New Wlnd Capaclty                                                 lnmeases from t 0 GW In 2013 to 39.4 GW In 2022.
         Mldwest IS0 MVP                  Not included In GE W S runs      lnduded In 20t9 and 2022 GE MAPS runs for all cases.
         Transrntsslon Expandon                                            M P cost alocatlon to Enlergy and Clem assessed in
                                                                             V
                                                                           Join MISO Case.

     I   SPP TransrnIssIon
         ExnansIon Cost Allocation
                                      I   September 2010 estlrnale         February 2011




2.1.4.       Joint Operating Agreement

             It i CRA's understandingthat under the Joint Operating Agreement eJOA*) between the
                s
             Midwest IS0 and the SPP RTO, there may be additional ability to coordinate flows between
             the Midwest IS0 and the Entergy and Cleco regions (as members of the Midwest EO) than




             See Power FIow Case Update prepared by the Midwest ISO. A number of 2019 and 2022 GE MAPS runs were
             completed and discussed with study slakeholderspdor to the Urn0 that the modifiatlon of the 2019 and 2022 power
             flow in GE W S was wmpleted. The trade benefif results of these runs are lnduded In Appendix. 8. Also see
             Appendix C for further detail on new 345 kV lines lnduded In the modified 2019 and 2022 power ff ow.

*O           See Sedlon 2 2 4 for a disasslon of the SPP-provlded update t Its transmission expansion cost allocation.
                                                                          o




                                                                                                                         Page 9
Join MISO CBA Addendum
March 10.201I                                                                   Charles River Associates



        captured in this CBA. It i also CRA’s understanding that the potential coordination that could
                                 s
        take place under the JOA is a subject of disagreement between the Midwest IS0 and the
        SPP RTO.

        To help assess the potential benefits of the JOA to coordinate operations between the
        Midwest I S 0 and the Entergy and Clem regions, CRA performed GE MAPS runs to estimate
        the impact on trade benefits if certain lines between Ameren and Entergy through TVA and
                                                                                n
        through SPP were converted into ‘interfaces” and retieved of hurdles i the Join MIS0 Case.
        These trade benefit results were provided to stakeholders during the course of this CBA.
        However, setting up these interfaces in GE MAPS, and ensuring that the associated modeling
        changes were resulting in appropriate consequences for trade and flows in the region of
        study, was not fully feasible in the time availabte for this CBA. As such, the results of those
        GE MAPS runs are not included in the overall costs and benefit results presented in this CBA.
        The trade benefit results of these and other GE MAPS runs prepared during the course of this
        CBA are summarized in Appendix B       .

2.2.            -
         FINDINGSENTERGY CLECO IN THE MIDWEST 0 OR SPP RTO
                       AND                  IS

                f
2.2.1. Summary o Results

        Enterqv-Clem in SPP. Shown in Table 5 are the overall net benefits to the SPPlEntergy
        region of Entergy and Cleco joining the SPP RTO using the modeling assumptions and
        updated cost assumptions i this Jon MIS0 CEA Addendum. As shown,the overall net
                                   n
        benefit for the SPPlEntergy region is $779 million (2010 present value) over the 2013 to 2022
        period. See Appendix A for more detail.

                Table 5: 2013-2022 Benefits (Costs) to the SPP, Entergy and Cleco Power RegIons
                                  ifC l e m Power and Entergy JoIn the SPP RTO
                     (in millons af ZOfD present value doilats; positive numbem are benet&)


       Tmde Benefits                                                                   891:      I   857
       Admin Costs: RTO Adminishffve Costs net of
       Avoided ICT Charges
                                                        189         I    (25)

       Admin Costs: FERC & Capitaflabor Costs
       SubTofal Net Benefits                            171         I    (54)          661       I   779
                                                                    I (104)to (18)
       Transmission Expansion Cost Allocation
       Total Net Benefits (Costs)
                                                     (5) to 1,034
                                                    166 to 1,206    I (158) to (72)   &
                                                                                      (937) 23
                                                                                           to




        This $779 million compares to the $739 million found for the same case in the FERC-
        sponsored SPf-Entergy CBA. The only changes in Table 5 in comparison to the results
        shown in Table I 2 of the SPP-Enfergy CBA are to the trade benefits (based on the GE MAPS
        modeling changes discussed above) and an SPP-provided update to the transmission
        expansion cost allocation (see Section 2.2.4).



                                                                                                 Page 10
Join MISO CBA Addendum

March I O , 2011                                                                Charles River Associates


       In contrast, the net benefits to the individual SPP, Entergy and Clem Power regions change
       more significantly from those in the SPP-Enfergy CBA. The benefitsfor the Entergy region
       are higher, while those for the SPP regions and Cleco Power regions decrease. The trade
       benefit impacts that yield these regional changes are discussed further in Section 2.2.2.

       Entersv-Cleco in MISO. For Cteco Power and Entergy joining the Midwest ISO, the net
       benefit results are summarized in Table 6. As shown, the net benefitsl(costs) to the Entergy
       region are ($254)million and for the Cleco Power region are ($133) million. See Appendix A
       for more detail.
                   Table 6: 2013-2022 Benefits (Costs) to the Entergy and CIeeo Power Regions
                                  IfCleco Power and Entergy Join the Midwest I S 0
                     {in millions d 2 i W O present value dollars; positive numbers am benefrfs)


                   I TmdeBenefits                                   I   (32)     I    737      I
                    Adrnin Costs: RTO Administrative Costs net of       (23)         (143)
                    Avoided ICT Charges
                    Admin Costs: FERC & CepifeVLebor Costs              (12)           61
                                                                                      I5
                   I SubTotal Net Benefits                          I   (67)    I     529      I
                    Transmission Epansion Cost Allocation               (66)         (782)
                    Total Net Benefits (Costs)                          (133)        (254)

       The impact on the existing Midwest IS0 was not evaluated, as the Midwest IS0 trade
       benefitswere not specifically evaluated as discussed above. As such,an aggregate total is
       not presented in Tabte 6. Aside from trade benefit impacts, the Midwest IS0 would benefit
       from reduced administrative and transmission expansion costs with Entergy and Cleco paying
       a pro rata share of these costs.

       As shown in Table 5 and Table 6, there are significant trade benefitsto the Entergy region
       whether joining the SPP RTO or the Midwest ISO. As noted in prior CBAs, the assumption
       that Entergy QFs become firm resources in an RTO is a key driver o trade benefits in any
                                                                            f
       join RTO scenario for the Entergy region. Including administrative costs, but prior to the
       allocation of transmission expansioncosts,the benefits to the Entergy region of joining the
       SPP RTO are about $d 30 million higher than joining the Midwest IS0 assuming a Day 2
       market is in place for the SPP RTO by 2013. After atlocation of transmission expansion
       costs,the net benefits to the Entergy region are negative in the Join MIS0 Case, and range
       from equally negative or significantly positive in the Join SPP Case, depending on the
       transmission cost allocation that would be applied upon joining the SPP RTO.

       The net benefit to Cleco Power of joining the SPP RTO or Midwest IS0 is negative. In
       contrast, the net benefit of Clew Power joining the SPP RTO was roughly neutral in the SPP-
       Enfergy CBA (depending on the transmission expansion cost allocation). The net benefit to




                                                                                                   Page I 1
Join MIS0 CBA Addendum

March I O , 201 I                                                             Charles River Associates



                                                                                                ih
        the SPP region of Entergy and Cleco joining the SPP region continues to be positive, wt the
        range significantly affected by the transmission cost altocation that would be applied.

        Each cost-benefit measure is discussed in greater detail below.

2.2.2. Trade Benefits

        As described in the SPP-Entergy CBA, the calculation of trade benefits for each region is
        based on the difference in costs in each case for five basic components:
            I Productioncosts of the generating units in the region (e.g., fuel, variable O&M)
              .
            2. Purchase costs for the region (hourly flows in at split-savings prices)
            3 Sales revenue fot the region (hourly Rows out at split-savings prices)
             .
            4. Transmissioncosts incurred by the region for Purchases and Sales (50% of the hourly
              wheeling charges paid by the purchasing region and 50% by the selling region).
            5. Transmissionrevenuecoltected by the region for Sales (3 00% of the hourly wheeling
              revenue collected by the selling region’s transmissionprovider).
        The first four components comprise adjusted production costs, and the Iast component is the
        correspondingtransmission revenue impact on the region’s transmissionprovider. The
        differencesbetween cases (e.g., Status Quo and Join SPP) in these five components
        representtrade benefits as referencedin this CBA. See the SPP-Enfergy CBA for more
        detail.

        Lost Tmnsmission Revenue and Avoided Costs Based on Historical Tansactions

        In the SPP-EnfegyCBA, the impact on wheeling costs incurred and wheeling revenue
        collected for transactions between SPP,Entergy and Clew in the Join SPP Case was
        assessed by SPP, Entergy and Cleco Power using historical transmissiontransaction dah.
        SPP then performed an analysis of the amount o total SPP transmissionrevenue that would
                                                        f
        be altocated between Entergy, SPP, and Cleco under the SPP OAIT using this same
        histonml data. For this CBA, a similar analysis was performedby Entergy and the Midwest
        IS0 using historical data for tmnsactions betweenthe Midwest ISO,Entergy and Clew
        regions.

        As shown in Table 7, the net annual benefitl(cost) from eliminating intra-RTOwheeling
        charges. based on historical data, i ($9) million for the Entergy region and $6 million for the
                                            s
        Cleco regionwhen joining the SPP RTO.21 Similarly, as shown in Table 8, when joining the
        Midwest ISO, the net annual benefitl(cost) is ($23million) for the Entergy region and $3
        million for the Cleco region, Much of the difference results from the allocation of transmission
        revenues under the SPP and Midwest I S 0 O A T S .




21      See the SPPEntergy CBA for additlonal detalt.




                                                                                                 Page 12
Join MISO CBA Addendum

March I O . 201 1                                                                         Charles River Associates



                    Table 7: Annual Benefits (Costs) to the SPP, Entergy and CIeco Power Regions
                     If PTP Wheeling Charges were ElIminated between SPP, Entergy and Cleco
                                (in miMons of doltam, positive numbers are benet&)



               Transmission Revenues Lost                           I        til)         (3)     1      2I
                                                                                                        (1
                - SPP Tariff Allocation l m ~ a con Revenues
                                                 t                  1        (11           3             (21




                      Tmnsmisslon Costs Avoided                          I          5     I       IO
                      Transmisston Revenues Lost                                    (11          (25)
                       - MtSO Tariff Allocation Impact on Revenues       1          0     I       (91
                      Net Benefit                                        t          3            (231

        These annual transmission costs avoided and transmission revenues lost were applied
        throughout the study pen'od in the derivation of the wheeling cost and wheeling revenue
        component of trade benefits.

        For the wheeling cost and wheeling revenue impacts with other major neighbors not in the
        RTO (e.g., TVA), the GE MAPS physiwl wheel charges were tracked and the resulting
        change in these wheeling revenues and wheeling costs between cases were included in the
        trade benefits calculation. The significantly higher Midwest IS0 wheel-out rate ($51Mwh)i  n
        comparison to that of the SPP RTO ($21MWh) leads to significantly increased wheeling
        revenues across these 'non-RTO" seams for the Entergy region in the Join MIS0 Case in
        comparison to the Join S f P Case. This "additional sharing' of this increased Entergy region
        wheeling revenue would not be captured i the historical wheeling revenue analysis. As
                                                   n
        such,based on the Entergy analysis of the revenue sharing that would take place under the
        Midwest IS0 O A T , it was assumed that h e Entergy region would retain 59% of the amount
        by which the wheeling revenue in the Join MISO Case exceeds that of the Status Quo Case
        across non-RTO seams.=

        Adjusted Production Costs and 7 . d e Benefits

        Summarized in Table 9 are the adjusted production costs and lost transmission revenue for
        the SPP,Entergy and Clew regions if Entergy and Clew join the SPP RTO. Similarly,




22      As In prlnr CBAs, a slrnilarfador was not applied to the Entergy reglon's non-RTO wheeling revenue In the Jdn SPP
        Case, as them was not a material difference In the Entergy reglon's non-RTO wheel revenue In the Juln SPP CBSe
        relative to the Sfatus Quo Case.




                                                                                                               Page 13
Join MISO CBA Addendum

March I O , 201 1                                                               Charles River Associates



        summarized in Table I O are the adjusted production costs and lost transmission revenue for
        the Entergy and Cleco regions if they join the Midwest ISO.

                  Table 9: 2013-2022 Benefits (Costs) to the SPP, Entergy and Cleco Power RegIons
                                     If Cleco Power and Entergy Joln the SPP RTO
                       {in millions of 20 f0 present value doliats;positive numbers are benefifs)


          I DecreaseinAdjustedProdudionCosts I            69       I   1,056    1    (22)    I       1,103    I
            Lost Tmnsrnission Revenue                    (86)          I1W             5              (246)
            Total Trade Benefits                         (17)           891          (17)             857

                    Table I O : 2013-2022 Benefits (Costs) to the Entergy and Cfeco Power RegIons
                                    if CIeeo Power and Entergy Joln the Mldwest IS0
                      (in mill/ons of20fOpresent d u e doliam;posltivenumbers am benefih)


                     I Decrease in Adjusted ProdudionC   o s t ? 7 6 r - -      I    (21)        1
                      Lost TransmissionRevenue                          (13 1
                                                                           1         (10)
                      Total Tmde Benefits                               737          (321

        As shown, significant trade benefits accrue to the Entergy region in joining an RTO, with the
        benefits of joining the SPP RTO about $1 million higher (about 20%) higher than those for
                                                   50
        the Midwest EO,assuming a Day 2 market i in place for the SPP RTO by 2013 The trade
                                                      s                                    .
        benefits for Cteco Power are somewhat negative injoining either RTO. As discussed in the
        SPP-EnfergY CBA, a significant portion of the SPP-Entergy region trade benefits accrue to
        the Entergy region largely because of the greater mix of higher cost gas-fired generationin
        the Entergy region that is displacedin the Join S f f Case and Join MIS0 Case. In addition,
        there are a significant number of Qualifying Facilities (‘QFs”) in the Entergy regionthat
        become firm resources in the Join SPP Case and Join MISO Case.

        As noted above, there is a significant loss in transmission revenue for Entergy when joining
        an RTO, based on the analysis of historical transmission revenue. The higher lost
        transmissionrevenuesfor Entergy i the Join SPP Case ($164 million) than in the Join MIS0
                                            n
        Case ($131 million) result from additionalwheel revenues being collected by the Entergy
        region when joining the Midwest EO, The Midwest I S 0 has a higher wheet-out charge than
        does the SPP RTO (SSIMWh for the Midwest IS0 and $21MWh for the SPP RTO in this
        study).

        To help better assess the difference in trade benefits (before wheeling cost or revenue
        impacts) between the Join SPP Case and Join MISO Case, a comparison of the generation,
        purchases and sales in the Join S P Case and Join MIS0 Case for the Entergy region in
                                          P
        2013 i shown in Table 11. As shown, the Entergy region generation is higher in the Join
               s
        MIS0 Case than in the Job SPP Case, but the additional cost of thls generationi not fully
                                                                                           s
        offset by reduced purchase costs andlor increasedsales revenues.



                                                                                                       Page 14
Join MISO CBA Addendum
March 10.2011                                                                 Charles River Associates



       Table 'll: 2013 Entergy RegIon Generaffon, Purchases, Sales In JoIn SPP and JoIn MISO Cases
                                   (20f dollam, posiffve doflars are cosfs)
                                       0

                            I TWH JoinM$ $IMWh I I TWHJoinM$ $/MWh I p TWHE M$
                                       SPP                MISO          ii iq
           Generation       128.1 3,139        24.5      128.6 3,172          24.7      0.6       33
           Purchases         40.0 1,496        37.4       40.0 1,491          3.
                                                                               73      (0.0)      (5)
           Sales            (18.2) (718)       39.4      (18.8) (723)         38.5     (0.6)      (5)
           Total            149.9 3,918        26.1      149.9 3,940           63
                                                                              2.       (0.0)      22

      As shown in Table 12, the source of the additional generation in the Entergy region in the
      Join MIS0 Case i gas-fired generation, while coal-fired generation is actually reduced.
                         s
      Additional gas-fired generation for a net-purchasing region typically means the cost of
      generation is higher, and purchases and sales activity are less economic, leading to higher
      adjusted production costs.

      Table 32: 2013 Entergy Reglon Gas- and Coal-ffred Generaffon in JoIn SPP and JoIn MISO Cases
                                  (2010 doifas, posiive ddiats are costs)


                        I        Join SPP             I 1     Join MISO              1 pGzi-I
                             TWH      M$ $/MWh              TWH   M$ $IMWh             'MIH   MS
          Gas-fired            26 1,381     53.0             27 1,425   52.7                1.043
          Coat-fired           46 1,440      17
                                            3.               45 1,430   31.7             -0.3 -10
                               72 2,822     39.4             72 2,855   39.5              0.7 33

      Differencesin Join S f P Tmde Ben&& fromthe S P f -Entergy CEA

      In comparison to the SPP-Enfergy CBA, the trade benefits for the SPP-Entergy region are
      similar ($857 million in comparison to $817 million) in the Join SPP Case. However, in this
      Join M/SO CBA Addendum, significantly more of the trade benefits accrue to the Entergy
      region. In reviewing the differences, we note the following (focusing on the 2013 trade benefit
      results).

      In the Join SPf Case in this CBA, Entergy increases its coal generation more, and decreases
      the generation from its combined-cycle and steam gas units significantly more &an in the
      SPP-Enfergy CBA. The reduced generation is replaced largely with increased imports from
      SPP, and to a lesser extent from AECl and TVA (pathways to Entergy from MISO), as shown
      in Table 13.

        Table 13: Increase in 2013 EntergyRegion imports in the J ~ SPf Case In Compan'son to the
                                                                     R
            Status Quo Case in the SPP-EnfergyCBA and the Join MIS0 CSA Addendum (GWh)


     From SPP                             1,916         I            2,692              I         776
     From AECl                             444                        773                         329




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Join MISO CBA Addendum

March 10.2011                                                            Charles River Associates



      As shown in Table 14, despite increasing Entergy purchases, the average purchase costs for
      Entergy decrease in both the Status Quo and Jojn SPP Cases (e.g., from $37.2to $36.6for
      EA1 and from $42.1 to $41.5 for Entergy Louisiana in the Join SPP Case), indicating that
      Entergy is able to purchase its imports at lower prices in this CBA than i the SPP-Entergy
                                                                               n
      CBA. As a purchaser, Entergy benefits from lower prevailing prices, and particularly so when
      it is able to better optimize its commitment when joining the SPP RTO with the larger
      commitment pool and thereby increase its purchases further (as shown in Table 13).

       Table I& Avenge Area Prices ($/MWh) In the Joh SPP Case In Comparison to the SCatus
              2013
                Quo Case in the SPP-Enfergy CBA and the Join MSO CBA Addendum




      AEP West         33.5         34.7           1.2          33.6         34.1           0.5
      AECI             36.6         37.4           0.8          36.4         36.8           0.4
      TVA              38.7         39.8           1.I          38.0         38.6           0.6
      Entergy AR       3.
                        63          37.2           1.l          35.6         36.6           1.0
      Entergy LA       3.
                        98          42.1            .
                                                   23           39.1         41.5           2.4

      In converse, in SPP the prices (using AEP West) are similar in the Status Quo Case, but do
      not increase as much with the larger commitment pool in this CBA (a similar impact takes
      place for AECI and WA). As an exporter, the lower prices sales in SPP and in Entergy in the
                                n
      Join SPP Case yield less i the way of benefits to SPP in the Join S f P Case despite the
      additional exports made to Entergy.

                                                     n
      Overall, we attribute the Join SPP Case change i trade benefits (higher for Entergy, lower
      for SPP)i this CBA relative to the SPf-EntergY CBA to a more efficient commitment of the
                n
      Entergy units under average loss commitment along with inclusionof MISO in the
      commitment pool in this CBA. The decrease in sales prices for sales to Entergy from SPP
      result I a decline in the benefits for SPP.
             n

2 2 3 Administrative Costs
 ...

      Based on its current forecast of administrativecharges under Schedules I O , 16 and 17, the
      Midwest IS0 provided an estimate of the administrativecharges that would be incurred by
      Entergy and Cleco if they were to join the Midwest ISO. This analysis took into account the
      economies of scale that the Midwest IS0 would obtaln by spreading its costs over a larger
      footprint.

      The Midwest I S 0 administrativecharges estimates are close to, but somewhat below those
      estimated by SPP for Entergy and Clew to join the SPP RTO. Over the 2013-2022 period,
      the Midwest IS0 admjn1shtive costs are about $2 million lower for the Cleco region and $21
      million for the Entergy region than those estimated to be incurred as members of the SPP
      RTO. See AppendixA for more detail, The SPP cost estimatesare from September 201 0
      and those from the Midwest I S 0 are from February 2011. Given the long-termsimilarity in the



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March PO, 2011                                                               Charles River Associates



         RTO markets assumed, it is likely that costs would be roughly comparable between the two
         RTOs, with a key differentiatingfactor being the size of the RTO footprint over which the RTO
         costs can be allocated. The impact on RTO administrativecosts of other parties potentially
         leaving or entering the RTO adds additional uncertaintyto the SPP and Midwest IS0
         estimates.

         The additional FERC fees that would be paid as members of an RTO by Clew and Entergy
         are assumed to be the same whelher joining the SPP RTO or the Midwest ISO. Similarly,
         the internal costs incurred by Cleco and Entergy to interface with an RTO are assumed to be
         the same whether joining the SPP RTO or the Midwest [SO. In the Join MISO Case, the
         revenueslost by SPP from Entergy no longer having an ICT are assumed to be exactly offset
         by costs avdded by SPP in no longer operating the ICT (yielding no impact on SPP with
         respect to administrativecosts).

2.2.4.   Transmission Cost Expansion

         For this CBA, SPP provided an updated Entergy and Clew region transmission expansion
         cost allocation for Study I, (Study 3 is unchanged) based on updated transmission
                                    2
         expansion cost infomation since September2010. The updated results are shown in Table
         15. See the SPP-Entergy CBA for further detail on SPP Study 1,2 and 3.

              Table 15 :2013-2022 Transmisdon ExpansIon Cost Allocation Benefits (Costs) to the SPP,
                  Entergy and Cleco Power RegIons if Cleco Powerand Entergy Join the SPP RTO
                       (Inmlllons of2MO p m e n t wfue doJJam: positive numbers are bene&)




         13   I   Regional Costs beghnlng Jan. 2013 excluding Balanwed
                  Portfolio and Pnoritv Proieets

         In this update, for the Entergy region. costs increasedfrom $802 million to $937 million for
         Study Iand from $614 million to $666 million for Study 2. For the Clem region, costs
         increased from $93 to $104 millionfor Study 1 and from $68 to $80 million for Study 2. Study
         3 results are unchanged.

         For the Join MIS0 Case, the Midwest IS0 provided the allocation of Entergy and Cleco
         region transmissionexpansion costs, which are predominatelydue to the Multi-Value Projects
         discussed in Section 2 1 2 The costs for these Multi-Value Projects are shared largely on an
                                ...
         energy-for-load basis across the Midwest IS0 footprint, and there i a four-year phase-in for
                                                                           s
         new RTO members. As shown in Table 16, there is a significant allocation oftransmission
         expansion costs to the Entergy and Clew regions when joining the Midwest [SO.For the
         Entergy region. the atlocated transmissionexpansion costs in the Join MISO Case are $805




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March 10,2011                                                                           Charles River Associates



       million more than SPP Study 3,$116 million more than SPP Study 2, and $155 million less
       than SPP Study 1.23

        Table 16 :2013-2022Transmission ExpansIon Cost Allocation Benefits (Costs) to the Entergy
                 and Cleco Power Regions if Cleco Power and Entergy JoIn the Midwest I S 0
                  (in milhns of 2010presenf miue d0llars;;Positive numbers are benefib)


                 I Midwest I S 0 Transmission Expansion Cost Altoeation             I   (66)   I   (782)     I
       The correspondingbenefit to the existing Midwest IS0 of the allocation of the $4.4 billion of
       Multi-Value Projects across a larger footprint is not captured in this study. The $4.4 billion
       initial set of Multi-Value Projects does not include any projects in the Entergy or Cleco
       regions.


3.     EAI IN THE MIDWEST IS0 OR SPP RTO

3.1.                (EA1
           METHODOLOGY EVALUATION)
       STUDY

       Three different cases were analyzed over the nine-year period from 2014 to 2022:

                 1. E 1 operates as a "standalone" entity not under the ESA ("EA!Standalone Case'),
                     A
                2. H I , but not the Rest o Entergy, joins the SPP RTO ('€A/
                                           f                                              Joins SPP Case').
                3. EAI, but not the Rest of Entergy, joins the Midwest I S 0 ('HIJobs MISO Case.)

       In the €AI Standalone Case, the load serving entities in the Wl region, including the Wl
       Opco, are assumed to be network service customers under the Entergy Open Access
       TransmissionTariff ("OAT), paying a load ratio share of the Entergy transmission system
       revenue requirements. A share of Entergy transmission system revenue is distributedto the
       EA1 Opca to recover the revenue requirementof the EA1 Opco hnsmission assets.

       In the €AI Joins SPP Case, EA1 Opco transmissionassets become part of the SPP
       transmissionsystem and are transferred to the SPP tariff. Given that there are point-bpoint
       transmissioncharges applicable for 'out' transactions ("wheeling charges') between SPP and
       Entergy today, EA1joining the SPP RTO results in the imposition of SPP RTO transmission
       wheeling charges between EA1 and the Rest of Entergy.



23     WhIle the Midwest IS0 did no! provide a range of fransmlsslon expansion mst estimates, the ultimate number of new
       Multi-Value Pro]eets and their associated cost alomtion will depend on futute Midwest IS0 planning approvats and
       FERC dedslons regarding the Midwest I S 0 ttansmlsslon cost allomtlon process.




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         Similarly, in the LV Joins MIS0 Case, EA! Opco transmission assets become part of the
         MISO transmission system and are transferred to the MISO tariff. Given that there are point-
         bpoint transmission charges applbable for 'our transactions between MISO and Entergy
         today, EA1joining the Midwest I S 0 results in the imposition of Midwest IS0 transmission
         wheeling charges between EA1 and the Rest of Entergy.

         SPP i assumed to continue in its capacity as ICT for the Entergy tmnsmissIon system in the
              s
         €AI Standalone Case, and for the Rest of Entergy transmission system in the €A/ Joins SPf
         Case and €AI Jobs MIS0 Case. The key differences between the modeling assumptions in
         the SPP-Entergy CBA issued in September 2010 and the SPP-€A/ CBA issued in October
         2010 are captured in Table 20.
          Table 17: Summary of Modeling Differences between #e SPP-Entergy CBA anti SPP-EA1 CBA

              ..         ~-
  Regions JoInInq the SPP RTO    Entergy and Cleeo                             EA1
  I 3 and R%stof Entergy         Treated as one mmblned region                 Treated as separate regions in Base Case;
  RelaUonshlp                                                                  EA1fohs SPP In Join SPP Cas8
  Commltment Seams Charges       BiOIMWh behveen SPP. Entergy and              $-
                                                                                1         between SPP, EAI, Rest of Entergy
  In Base Case                   #em                                           and Clew
  Dlspatch Seams Charge In       Wheeling and tradlng friction charges         Wheeling and trading frlctlon chargw behveen
  Base Case                      behveen SPP. Enlergy and cleco.               SPF. EAI. Rest of Entergy and Clew, exeept
                                                                               the EA1 and Rest of Entergy charge does not
                                                                               lndude a wheeling darge.
  Commltment Seams Charges
  fn Joln SPP Case
                                 $ O m behveen SPP.Entergy and Clew
                                                                           1   SolMWh between SPP and EN. SiOIMwh
                                                                               between SPFIEAI. Rest of Entergy and Clem.
  Dispatch Seams Charges In      No wheeling or W i n g friction Fharges       No wheeling or tradlng friction charges
  JoIn SPP Case                  between SPP, Entergy and Clem.                between SPP and MI. Wheeling and tiadlng
                                                                               friction charges between SPPIEAl and Rest of
                                                                               Entergyand Clem
  Entergy PF Treatment In Base   Nowfirm resources                             Non-firm resources
  Case


  Entergy QF Treatment In Joln   Firm resources                                firm resources for lPPs In EAI region: non-
  SPP CasB                                                                     firm resoums for lPPs In Rest of Entergy
                                                                               regIon
  Lost TransmIsslon Revenue      Historid hnsmfsslon data analysis for   Change In wheelhg charges on GE MAPS
  from Joining SPP RTO           SPP-Entergy-Cleco knsactlons. Change physlml flows for all reglons.
                                 In wheellng charges on GE MAPS physlcal
                                 flows for other nelahbodng reglons
  TransmIsslon Expanslon Cost    Allocated to Entergy and Clew                 Mlocated to EA1onty
  Allocatlon In JoIn SPP Case


         In this Join MIS0 CBA Addendum, to evaluate the EA1 RTO alternatives,corresponding
         changes were made to the GE MAPS modeling as described in detail in Section 2.1 for
         Entergy and Cleco Power joining the Midwest EO. The 1000 MW Contract Path through
         AECl between the Entergy region and the Midwest IS0 discussed in Section 2.1.1 is
         assumed to transfer to EA1 i f EA1 i separated from the Rest of Entergy. In addition, the
                                            s
         same assumptions described in Section 2.1.2 were used for Midwest IS0 demand, new wind



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March I O , 201 I                                                                      Charles River Associates



        capacity, and transmission expansion. The specific seams charges applied in this CBA for
        the EA1 RTO alternatives are summarized below. Changes were also required with respectto
        wheeling costs and wheeling revenues, as also described below.

3.1.1. Seams Charges (EA1 Evaluation)

        The dispatch seams charges applied in this Join MIS0 CBA Addendum to evaluate the E 1 A
        RTO alternatives are summarized in Table 18. These are the same dispatch seams charges
        applied in the SPP-EA1CBA. As in the SPP-Ecll CBA, i the EA/ Standalone Case and the
                                                             n
        €AI Joins SfP Case, the hurdle on the 1000 MW Contract Path is comprised of the MISO
        tolfrom AECI dispatch seams charges, and the AECl tolfrorn EAl.24 In the €A/ Joins MISO
        Case, both of these dispatch seams charges are eliminated on the 1000 MW Contract Path.
           TabIe 18 :Dispatch Seams Charges AppIIed in GE MAPS in the SPPlEntergylMlSOR e g 1 0 n ~ ~
                                 ohpatch FdctfDnt. Wheeling Charge ($IMWh)
                                                  EA1 Standalone Case




                                                  EA1 Jolns MISO Case




        As shown in Table 19, other than inclusion of the Midwest IS0 in the SPWEntergy
        Commitment pool with a $1OIMWh, there were no other changes to the commitment huidles
        from those used in the SPP-EA1CBA.




24      A posslble refinement to the   GE MAPS analyses In thls sludy would be to run the Slatus Quo Case and Jah SPP
                                                                                                               s
        Case with only a single hurdle on the 1000 MW Contract Path. The AECl to EA1 dispatch seams charge I $3 for
        wheeling and $3 for iradlcq frIctlon.

        See the SPPEAI CBA for the seams charges applied throughout tha Eastern Interconnect.




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Join MISO CBA Addendum

March 10,201: 1                                                           Charles River Associates



         Table 19: Commitment Seams Charges ($nvIWh) in GE MAPS in the SPPIEntergylMISO Region
                                         EA1Standalone Case




                                                     -. . ----
                                           €AI Jalns SFP C a a ~




                                           EA1JoIns MISO Case




3.1 2. Transmission (Wheeling) Revenue and Costs Methodology (EA1 Evaluation)

       As discussed above, the impacts on wheeling costs incurred and wheeling revenue coIlected
       between SPP,Entergy and Cleco in the Enfegy-Cleco Jojn SPP Case and between the
       Midwest ISO, Entergy and Cteco in the Enfergy-Clem Join MISO Case were assessed uslng
       historical data. As discussed in the SPP-€AI CBA, a similar historical analysis could not be
       performed for the EA1 RTO alternatives given that there is no specific historical data
       identifying whether an Entergy transmission transaction is using the €AI or the Rest of
       Entergy transmission system.

       As such, the impact on wheeling revenues and costs for EA1 i assessed using the change
                                                                    s
       between cases in GE MAPS physical flow wheeling revenues and wheeling costs. In doing
       so, key related assumptions indude: I how wheeling costs and revenues are shared
                                               )
       between EA1 and Rest of Entergy in the €41 Sfandalone Case, 2) how wheeling revenue is
       shared between EA1 and the RTO when EA1 joins the Midwest I S 0 or SPP RTO, and 3) how
       wheeling costs are assessed for the I 0 0 0 MW Contract Path. Each i discussed i turn
                                                                          s            n
       below.

       EA1 Transmission Revenue and Cost Sharins when Standalone. In the SfP-€AI CBA, in the
       €AI SfandaloneCase it was assumed that both the wheeling revenue and wheeling costs
       collected by the Rest of Entergy and EA1were aggregated and shared on a load ratio basis.
       Upon further review, in this CBA, only the wheeling revenues are shared on a load ratio




                                                                                            Page 21
Join MISO CBA Addendum

March 10.201:
            1                                                                             Charles River Associates



      basis.26 This assumption change shifls about $20 million per year in wheeling costs from the
      Rest ofEntergy to EA1 in the €Ai Standalone Case, thereby increasingthe benefits of EA1
      joining the SPP RTO or Midwest

      €AI Transmission Revenue Sharinq in RTO. Based on an analysis of the Midwest IS0
      O A T , Entergy estimated that 52% of wheeling revenue collected on the EA1 seams (as
      modeled in GE MAPS) would be retained by EA[ with the remainder allocated to the rest of
      the Midwest ISO. Similarly, it was estimated that 56% of wheeling revenue on the EA1 seams
      would be retained by E 1 as a member of the SPP RTO. In addition, EA1 was assumed to
                            A
      share 5.6% of the existing SPP regionwheeling revenue in the EA1 Joins SPP Case and
      2.5% of the existing MISO region wheeling revenue in the €41 Joins MISO Case.28

      In the SPP-€41 CBA, in the €AI Jobs SPP Case, it was assumed the wheeting revenue
      allocated by EA1 to SPP would be fulty offset by an allowtion of SPP transmissionrevenue to
      EAI. In contrast, using the sharing factors above in this CBA, reduces the EA1 wheeling
      revenue by about $12 million per year in the €A/ Joins SPP Case and by about $38 million
      per year in the     Joins #/SO Case,29 The much higher revenue sharing in the €Ai Joins
      MIS0 Case results from the significantly higher wheel-out rate for the EA1 region in the Join
      MISO case ($51MWh) in comparison to the €Ai Joins SPf Case (WMWh).

      EA1 Wheel Costs for the 1000 MW Contract Path. For consistency across wses, in the trade
      benefit post-processingcalculations in this Join MISO CBA Addendum, the wheeling charge
      on flows on the 1000 MW Contract Path were assessedfor the wheeling charges on both
      legs of the Contract Path. In the S f f - € A / CBA, only the wheellng charges on the AECI-



26    WheeIlng costs on the GE MAPS physical flows are asslgned 50% to the selling reglon (generators) and 50% to Ihe
      purchaslng region (load). In the SfP54I CBA, It was assumed hat a network tmnsmisslon arrangement beween
      Entergy and Rest of Entergy would result In the sharing of both wheeling revenues and wheeling cosls. The ultimate
      treatment of wheeling wsts and revenues with EA1 as a standalone entity will depend on the specifics of the
      transmbslon arrangements between EA1and the Entergy transmissionpmvider.

27    For 2013, h e GE MAPS-based wheeling c o s t for Rest of Entergy am $43 million, and for EA1 are $45 milllon In the
                                                            s
      EA/ Standalone Case. The Rest of Entergy reglon I about 74% of the load In the Entergy reglon, while the EA1
      reglon I 26%. An allodlon of wheeling costs would yleld EA1wheeling costs of $23 million [(43+45)’26%]. wtth no
              s
      allocatlon. as In thls C6A. the MIwheeling costs are $45 million,whlch is 522 mflllon hfgher.

28    Since G E - W S based wheeling revenues were not calculated for the Midwest I S 0 In lhis study, these percentages
      were applied to the annual Midwest I S 0 and SPP wheeling Evenu# from the historical wheeling revenue analysis

29                                                                                           ns
      For 2013,the GE MPS-based wheeling revenue for EAI i $36 rnlllion in the EA/ ~ ~ lSPP case, of wtttch 5ij% is
                                                               s
                                                                                      -
      assumed to be retained by EA1 to yield net E 1 wheeling revenue of 520 rniIlion a decrease of 516 million. The
                                                    4
      wheeling revenue for EA[ I 583 million In the EAIJoins MlSO Case. of which 52%I assumed to hretained by M
                                 s                                                     s                            I
      to yield net EA1 wheeling revenue of $43 mlllion - a deaease of S40 mlIlIon. The wrrespondlng sharing of edsling
      RTO revenues with E ! adds $3.5 mllllon per year to EA1 wheellng revenue for the E I Joins SPP Case and $3.5
                             A                                                            4
      rnllion per year for he EAI Jdns MIS0 Case.




                                                                                                               Page 22
Join MISO CBA Addendum
March I O , 2011                                                                                  Chartes River Associates



          Entergy path were assessed in the trade benefit post-processing catculations. This
          assumption change does not impact the EA! Joins SPP Case trade benefits materially as the
          wheeling charges on the 1000 MW Contract Path are in place in both the €41 Standalone and
          ,541 Join SPP Cases. It increases the €A/ Join MISO Case benefits by about $12 million per
          year, because the wheeling charges on the I000 MW Contract Path are eliminated in the EA/
          Joins MISO Case.30

3.1.3. Summary of Modefing and Assumption Changes (EA1 Evaluation)

          The modeling and assumption changes between the SPP-€At CBA and the Join MISO CBA
          Addendum discussed above are summarized in Table 20.
                                 Table 20: Summary of EA1 Modeling Assumpffon Changes


     I000 M Contract Path
           W                           Hurdles between EM-AECI and             Same for St~tus and Jdn SPP Cases. Hurdles
                                                                                             Quo
                                       AECI-Ameren In Status Quo and           between EAI-AECIand AECCAmeren elhlnated In
                                       Joln SPP Cases.                                    s .
                                                                               Join MIS0 a #
     Commltmsnt Po01                   SPP-Entergy-Clem reghn. with            SPP-Entergy-Clec+MISO region, with average losses
                                   I marginat lossesin commitmentstep          In mrnmitmentstep. and rnarglnal losses In dlspatcb
                                   '   and dispatch step. No commitment        step. SIOIMwh commitment hurdle bebeen SPPlRest
                                       opffmizatlonbehveen MISO and            of EntergylClew and MtSO In all cases, and between
                                       SPPEntergylClew   .                     EA1 and MtSO In Status Quo and Joh SPf Cases.
     Midwest IS0 Demand and            Frozen at 2013 levels                   lncreashg throughout study period. 1O'GW of MISO
     New Wind Capacity                                                         wind capacity In 2013 Increaslng to 19.4GW In 2022
     Mldwest IS0 MVP                   Not induded                             lnduded in 2019 and 2022 GE MAPS runs. M P cost
                                                                                                                        V
     Transmlsslon Expandon                                                     allocated to EA[In ~ W J o l n MISO Case
                                                                                                              s
     EN Transmlsslon Revenue           EA1 and Rest of Entergy wheeling        EA1 and Rest of Entergy wheeling revenues s h a d on
     and Cost Sharing In               revenues andwheeling costs shared       a load ratio basls. Wheeling costs kept by region ihat
     Standalone Case                   on a load ratio basis.                  Incurred them
     EAI Transmlsslon Revenue          EA1 wheellng wsts and wheeling          EA1wheeling costs not shared. EA1 hnsmlsslon
     and Cost Sharing In Joln          revenues not shared.                    revenus shared with RTO (keep 56% In SPP, keep
     RTO Case                                                                  52% In MISO). M s t i n g SPP (5.6%) and MISO (2.556)
                                                                               wheel revenues shared with EAI.
     1000 MW Contract Path             Wheeling costs induded for EA1on                                    4
                                                                               Wheeling costs lnduded for E1 on both EAt-AECI and
     Tmnsmisslon Costs                 EAI-AECI leg for EAI Standalone         AECI-Ameren leg for UII Sfanda!meCase and Join
                                       Cese and Jdn SPP Cese.                  SPP Case In post-processlngof trade benefils.
     Joln SPP fransrnlsslon
     Expansion Cost Allocatton
                                   I               estimate
                                       ~eptember2010                       I   February 2011 E ~ t h n a t e ~ ~




30        The AECI to EA1 dlspatdl wheel charge Is S3IMWh and !hsAmeren to AECl wheel charge is SSIMwh, 50% of which
                                                                                                      I
          I assumed to be assessed to EA1 for flows on the 1000 MW Contrad Path from Ameren to M . This yields an
          s
          e f f e c h wheel cost of $41Mwh (SOW(53+$5))               I
                                                       from Ameren to W on this path. Based on an averaga flow of about
          550 M from AECl to EA1 on the 1000 M W Contract Path, this change yields an increase In the EA1 wheeling costs
                   W
                                                                                              -
          I the M I Standalone Case and me EAIJolns S f P Case of about $12 mllllon [($4 50%'$3)'550'8760] In 2013.
           n
31        See Section 32.4 for a discussion of the SPPprovided update to the bansmIslon expansion mst aIlomUon.




                                                                                                                      Page 23
Join MISO CBA Addendum
March 10.2011                                                                              Charles River Associates



           -
3 2 FINDINGSEA1 IN SPP OR MISO
 ..

3.2.1.    Summary o Results for EA1 in RTO
                   f
         Shown in Table 21 are the overall net benefits of EA1joining the SPP RTO using the
         modeling assumptions and updated costs assumptions in this Join MISO CBA Addendum.
         As shown, the overall net benefit (cost) for the EA1 region is ($371) to $29 million (2010
         present value) over the 2014 to 2022 period. This compares to the ($372) to ($52) million
         found for €AI in the SPP-€AI CBA. The net benefitslwsts to the SPP-Entergy region are $37
         million, In comparison to the ($13) million found in the SPP-EAI CBA. 327312trade benefit
         impacts that yield these regionaI changes are discussed further in Section 3.2.2.
          fable 21: 2014-2022 Benefits (Costs) to the EAI, SPP, Rest of Entergy and Cleco Power RegIons
                                            if EA1Joins the SPP RTO
                      (in mNions ofllfopresentwfue dol/a~;positive       numbets are benefits)


         Trade Benefits                          95              65               (5121)               26           65
         Administrative Costs                   (79)             51                    0                 0         (28)
         Transmission CostAttocation              to
                                             (386) 13           to
                                                             ($3) 386                  0                 0           0
         Net Benefits                       (371) to 29      I 0 3 to 502          ($123)               26          37

         Entemv-Clew in MISO. For EA1joining the Midwest ISO, the results are as summarized in
         Table 22. As shown, the net benefi!d(costs)to the EA1 region are ($201) million and for the
         Rest of Entergy region are ($144) million.

                     Table 22: 2014-2022 Benefits (Costs) to the EA1 and Rest of Enfergy Regions
                                            If EA1Joins the MIdwest IS0
                      (in miiJ;ons oFZOfOpresenfvalue dotfars; posiiYve numbers at??  benefib)




                             Administrative Costs
                                                               - 0
                                                               (75) -
                             Transmission Cost Allocation             (255)                 0



          Note that the impact on the existing Midwest I S 0 was not evaluated, as the Midwest IS0
          trade benefits were not specifically evaluated as noted above. As such, an aggregate total is
          not presented in Table 22. Aside from the trade benefit impacts, the Midwest IS0 would


32        The onty changes In Table 21 in mmpadson l o the results of the SPFE4I C5A are to h e trade benefits (based on
          the GE MAPS modeling changes discussed above) and an SPP-provided update to the transmlsslon expanslon cost
          allocation (seeSection 32.4).




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        benefit from reduced administrative and transmission expansion costs with EA1 paying a pro
        rata share o these costs.
                    f

                   n
       As shown i Table 21 and Table 22, there are positive trade benefits to the EA1 region
       whether joining the SPP RTO or the Midwest ISO. Including administrative costs, but prior to
       the allocation of transmission expansion costs, the benefits to the EA1 region of joining the
       Midwest IS0 are about $35 million higher than joining the SPP RTO. After allocation o    f
       transmission expansioncosts, the net benefits to the EA1 region are negative in the EAI Joins
       MISO Case, and mnge from significantly negative to somewhat positive in the EA1 Joins SPP
       Case, depending on the transmission cost allocation that would be applied uponjoining the
       SPP RT0.33 The corresponding benefits to the Rest of Entergy region are negative in both
       EA/ Joins RTO cases. The net benefit to SPP of EA1joining the SPP RTO i positive, with the
                                                                                    s
       range significantly affected by the transmission cost allocation that would be applied.

        As discussed in the SPP-€AICBA, four factors limit the amount of trade benefits that would
        take place for EA1 if it were to join an RTO.
                   The smaller size of EA1 in joining an RTO relative to the entire EntergylCleco region.

                   fhe imposition of transmission wheeling charges between E1 (as part of SPP or
                                                                                4
                   MISO) and the Rest of Entergy, leading to a less efficient dispatch between the Rest
                   ofEntergy and EA1 generating assets.
            +      The heavily baseload (nuctear and coat-fired) generating assets in the EA1 region.
                   7he commitment and dispatch of these types of facilities tend to be less affected by
                   increased regional integration, resulting in reduced dispatch savings opporlunities if
                   EA1 alone joins an RTO, than if Entergy as a whole joins.

                   O the QFs in the Entergy region, only one i in the EA1 region. As described in Ute
                    f                                        s
                   SPP-Entergy CBA, QFs in an RTO are assumed to become firm resources allowing
                   for a more efficient commitment process. Wth only one QF moving to an RTO as
                   part o EAI, there are fewer savings than if Entergy as a whole joins the SPP RTO.
                         f

       These four factors contributeto yield only a modest level of EA1 trade benefits in the €41
       Joins SPP Case and EA/ Joins MIS0 Case. This modest amount of trade benefits is not



33     & dlscussed In the S W E A l CBA, the resew@margin In Ihe EAI reglon over the 2014-2022 period, lndusive of all
       load and capacity in the reglon Indudlng IPP wpacily. I pmjeeted to be slgnlbntly above 20%. Thus, a reduction
                                                             s
       In the E1 planning reserve margln In the €41 Jolns SPP Case or the EA/ Jdns MISO Case would not result in
               4
       avoldlg the construction of any new Eapaeity and would not therefore result In any capacity benefit savings to the
       EA1reglon as a whole during this period. See the SPPEAl CBA for a diseusslon of the potential eapacily benefits for
       the EA1 Opco. Also see the SPPEAI C5A for a discussion of the potential addMona1 transmlsslon revenues that
       would be recelved by the E 1 reglon If It were to joln an RTO for the net paymentrrecelpt of polnt-bpolnt
                                     A
       bnsrnlsslon charges with the Rest of Entergyfor deslgnated nehvorlc resources.




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      significant enough to offset the payment by the EA1 region of RTO administrative costs and
      RTO transmissionexpansion costs, with the exceptionof the SPP Study 3 allocation.

      The Rest of Entergy region is negativelyimpactedby the loss of the significant through and
      out revenue for transactionsthat exit the Entergy transmission system from the EA1 region.
      In the EA1 Standalone Case, this revenue is shared on a load ratio basis with the rest of the
      Entergytransmissionsystem. In the EAI Joins RTO cases, this revenue largely a c m e s to
      the EA1 region under the RTO tariff. Moreover, the institution of wheeling charges for
      purchases by the Rest of Entergy region from the EA1 region in the E41 Joins RTO cases
      further negatively impacts the Rest of Entergy region, which is a net purchaser from the EA1
      region.

      Each cost-benefit measure is discussed in greater detail below.

3 2 2 Trade Benefits (EA1 Evaluation)
 ...

      As described in Section 2.2.2, trade benefits in joining an RTO are comprisedo the decrease
                                                                                    f
      in a region's adjusted productioncosts (generation productioncosts plus purchase costs
      minus sale revenues and wheeling costs) and the increase in the region's wheeling revenues.
      Summarized in Table 23 are the adjusted productioncosts and lost transmission revenue for
      the EA1 region if EA1 joins the SPP RTO or Midwest [SO.

                           Table 2 : 2013-2022 Benefits (Costs) to the EA1 Region
                                  3
                                  if EA1JoInsthe SPP RTO or Midwest IS0
                   (in milhns of 2010presenf value dollam; positive numbers a@ benetib)


    Decrease In Adjusted Prod Costs, exel. Wheeling Costs            34                         3
                                                                                               I1
    Decrease in Wheeling Costs                                        3                       (54)
     Subtotal: Decrease in Adjusted Production Costs                 37                       (57)
    Lost Transmission Meelina) Revenue                               58                       185
   1 TotaI Tmde Benefits                                    I        95           t           129

      Unlike the Entergy-Cleco Join RTO results, there are significant benefits in wheeling
      revenuesfor EA1joining an RTO for the following reasons.

      1. In the E4l Standalone Case, the EA1 and Rest of Entergyregions are assumed to share
         their wheeling revenues on a load ratio share basis. However, based on GE MAPS
         physical flows, the E 1wheeling revenues are nearly three times those of the Rest of
                              A
         Entergy region. As a result, the revenue sharing results in EA1 "re-allocating' significant
         wheeling revenue to the Rest o Entergy in the €A/ Sfandalone Case.
                                        f

                            A
      2 In contrast, when E 1 joins an RTO, it no longer has to share these wheeling revenues
       .
         with the Rest of Entergy. But, E 1 must share its wheeling revenues with the RTO in
                                         A
         accordance with the RTO O A T . At the same time, EA1 also gets to share a portion of
         the existing RTO's wheeling revenue. For EA1joining the SPP RTO, the net wheeling



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           revenue impact is a benefit to the EA1 region of about $10 million per year (yielding the
           $58 million shown i Table 23)-
                              n
       3. The significantly higher Midwest IS0 wheel-out rate ($SIMWh) in cornpaison to the SPP
          RTO ($ZMWh) leads to significantly increased wheeling revenues for E 1in the Join
                                                                               4
           MISO Case in comparison to the Join SPP Case. As a result, for EA1 joining the
           Midwest ISO, the net wheeling revenue impact is a benefit to the EA1 region of about $30
           million per year (yielding the $185 million shown in Table 23).

      4. However, the increased E 1 wheel-out rates in the €AI Joins MISO Case also contribute
                                   A
         to an increase in EA1 regionwheeling costs. Wheeling costs are assumed to be shared
         50150 between the importing region (load) and the exporting region (genemtors). As
         shown in Table 23, the impact on wheeling costs is close to zero when €AI jolns the SPP
         RTO. However, when EA1joins the Midwest ISO, the net additional cost i about $10
                                                                                   s
         million per year on average, yielding the $54 million of increased EA[ wheeling costs
         shown in Table 23.

       In sum, the net wheeling cost and revenue benefits total to about $61 million for the EA1
       region when joining SPP, and about $131 million for the EA1 regionjoining the Midwest ISO.
       Correspondingly, the net benefits of the remaining components of adjusted productioncosts
       (productioncosts plus purchases,costs net of sales revenues) are $34 millionfor the EA1
       region when joining SPP, and ($3) millionfor the EA1 region when joining the Midwest ISO.

      To help better assess the difference in trade benefits (before wheeling cost or revenue
      impacts) betweenthe €AI Joins SPP Case and €Ai Joins MIS0 Case, a comparisono the     f
      generation, purchases and sales in the €AI Joins SPP Case and EA1 Joins MlSO Case for
      the €41 region in 2013 is shown in Table 24.= As shown, the WI region generationi lower
                                                                                            s
      in the €AI Joins MIS0 Case than i the €AI Joins SPP Case, but the savings from this
                                         n
      reduced generation i offset by increased purchase costs and particularly reduced sales
                           s
      revenues,

       Table 24: 2013 EA1 Region GenerationlPurchaseslSalesin EA1 Joins SPP and Joins MIS0 Cases
                                  (2010 dollars, positive dolfats a e costs)

                              I TWH JoinM$ $IMWh1 1 TWHJoinM$ $IMWh [ pGzi-l
                                        SPF                MISO
                                                                      TWH M$
            Generation           43.5       947        21.8         41.2       872       21.1         (2.3) (75)
            Purchases            12.0        467       39.0          13.0   476           36.7        -1.0 - 8
            Sales               (18.2)      (678)      37.3         (16.8) (605)          36.0         1.4   73
            TotaI                37.4       736        19.7         37.4      742         19.9         0.0    6




34     As In the S P P U l C8A. the GE MAPS model was run for 2013 to Interpolate results forthe years 2014-2015.




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        As shown in Table 25, the reduced generation in the E 1 region in the €41 Joins MIS0 Case
                                                                 A
        relative to the ,541 Joins SPP Case i mostly coal-fired. With low-cost coal-fired capacity
                                              s
        available in the Midwest ISO, it is not surprising that EA[ coaI-firedgeneration would decline
        in a Join MIS0 Case. Indeed, the imports through AECI to EA1 increase by 0.8 TWH in the
        EA1 Joins MISO Case In comparison to the €AI Joins SPP Case. While this reduces EIA's
        production costs, the lost EA1sales revenue more than offsets this in 2013. EA1 exports
        decrease by 0.9 fwh to TVA and by 0.4 TNh to the Rest of Entergy in the EA1 Jaolns MIS0
        Case in comparison to the €AI Joins SPf Case, and the sales that remain are at a lower
        average price.

          Table 25: 2013 EA1 RegIon Gas-and Coal-fired Generatlon in JoIn SPP and Join MISO Cases
                                   ( Z N O doifam, positive dollam are costs)

                             I    TWH
                                        Join SPP
                                             M$ $IMWh
                                                               1 1    TWH
                                                                           Join MISO
                                                                                 M$ $IMWh
                                                                                                  1 piiiiq
                                                                                                    TWH M$
            Gas-fired               3.1       156       49.9             2.9     146       50.6          -0.2 -10
            Coal-fired             22.2       705       31.7           20.1      641        19
                                                                                           3.            - . -64
                                                                                                          21
                                   25.4       a61       34.0           23.0      787       34.2          -2.4 -74

        In sum, the somewhat higher trade benefits for EA1joining the Midwest IS0 relative to the
        SPP RTO appear largely driven by wheeling cost and wheeling revenue impacts.35

3 2 3 Administrative Costs (EA1 Evaluation)
 ...

        Based on its current forecast of administrative charges under Schedules I O , I6 and 17, the
        Midwest IS0 provided an estimate of the administrativecharges that would be incurred by
        E 1 if it were to join the Midwest ISO. This analysis took into account the economies of scale
         A
        that the Midwest IS0 woutd obtain by spreading its costs over a larger footprint. The Midwest
        IS0 administrative charges estimates for EA1 are about $4 million (2010 present value) below
        those estimated by SPP for EA1 to join the SPP RTO over the 2014-2022 period. See
        Appendix A for more detail. As discussed previously, it is likely that Day 2 RTO costs will be
        roughly similarly among RTOs, with the key differentiating factor between RTOs being the
        size of the footprint to which the costs can be assigned,

        The additional FERC fees that would be paid as members of an RTO by EA1 are assumed to
        be the same whether joining the SPP RTO or the Midwest ISO. Similarly, the internal costs
        incurred by EA1 to interface with an RTO are assumed to be the same whether joining the
        SPP RTO or the Midwest ISO. In the Join S f f and Join MIS0 Cases, the revenues lost by
        SPP from EA1 no longer participating in the Entergy ICT are assumed to be exactly offset by




        whlle not evaluated In thls study, if E 1were to pursue jolning an RTO. It may be that the RTO mtght be required by
                                               4
        FERC to wake wheellng charges to the Res1 of Entergy across the EAllRest of Entergy seam, if such charges dld
        not exkt prior to EA1folnlng the RTO.




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      costs avoided by SPP in operating the ICT (yietding no impact on SPP with respect to
      administrative costs).

3.2.4. Transmission Expansion Cost (EA[ Evaluation)

      For this CBA, SPP provided an updated EA1transmission expansion cost allocation for Study
        ,
      I2 (Study 3 is unchanged) based on updated transmission expansion cost information since
      September 2010. The updated results are shown in Table 15. See the SPP-€41 CBA for
      further detail on SPP Study 1,2 and 3. In this update, for the EA1 region, costs increased
      from $307 million to $386 milllon for Study 1 and from $209 million to $291 million for Study 2.
      Study 3 results are unchanged.
       Table 26 :2014-2022 Transmission Cost Allocation Benefits (Costs} to the SPP and EA1 Regions
                                            If EA1Join the SPP RTO
                  (in miifions of 20 f0 present wiue dollas; positive numbers a2 benet%)
                                                                               r3




                    Regional Costs beginning Jan. 2014 exduding



      For the €AI Joins MIS0 Case,the Midwest I S 0 provided the allocation of EA[transmission
      expansion costs, which i predominately due to Multi-Value projects, The costs for these
                                s
      Multi-Value Projects are shared largely on an energy-for-load basis across the Midwest IS0
      footprint, and are phased in over a four-year period. The share that would be altocated to EA1
      if it joined the Midwest IS0 is shown in Table 27. As shown,the allocation would be $268
      million more than SPP Study 3, $36 milllon less then SPP Study 2, and $131 million less than
      SPP Study 1.

         Table 27 :2014-2022 Transmission Cost Allocation Benefits (Costs) to the EA1 Region if EA1
                                          Joins the Midwest I S 0
                  (in milfions ofZ0IOpresent miue doila~;positive  numbem are benefk)



                    I Midwest I S 0 Transmission Expansion Cost Allocation I   (255)   I
      The correspondingbenefit to the existing Midwest IS0 of the allocation of the $4.4 billion of
      Multi-Value Projects across a wider footprint is not captured in this study. The $4.4 billion
      initial set of Multi-Value Projects does not include any projects in the EA1 region




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4.     OTHER ISSUES

       The general qualitative considerationof Entergyjoining the SPP RTO examined in detail in
       the SPP-Entetgy CBA were not reexamined In this CBA, as they would be expected to apply
       a s a general matter to EntergylClecoor EA1joining the Midwest IS0 as well. One related key
       uncertainty is the timing and ultimate level of costs associatedwith the upcoming transition by
       SPP to a Day 2 market, whereas the Midwest IS0 has a Day 2 market in place already.
       Other key uncertaintiesinclude:

           +   The ability to extend the 1000 MW Contract Path arrangementbetween Entergy,
               Ameren, and AECl over the Iong-tern is an uncertaintyin EntergylClecoor EA1
               joining the Midwest ISO.

               The ability to which the SPP-Midwest I S 0 JOA muld be used to better coordinatethe
               operations of EntergylCleco or EA1 in the Midwest IS0 than modeled herein is an
               uncertaintydependent on the result o potential discussions between SPP and the
                                                    f
               Midwest ISO.

           0   The assignment of SPP transmission expansion costs to EntergylCleco or EA1 if
               joining the SPP RTO (Le., Study I 2 or 3) is uncertain.
                                                ,

               The amount of additional RTO transmissionexpansion needed in the future to
               support renewable portfolio standardslincreasedwind power is an uncertaintyfor
                                                    ih
               both SPP and the Midwest ISO, along wt the ultimate mechanism that may be used
               to allocate these costs to RTO members.

               The ultimate size of each RTO over the long-term i a key uncertainty, as the RTO
                                                                    s
               footprint size is a key driver of the administrativecharges each RTO assesses.

           0   The exact transmissionarrangementsbetween E1 and Rest of Entergy with EA1 on
                                                              A
               a stand-alonebasis is an uncertaintyfor assessing the benefits of EA1 joining an
               RTO.

               Whether FERC would allow the institution of wheeling charges on an EAllRest of
               Entergy seam is an uncertainty associatedwith EA1 joining an RTO.


5.     CONCLUSION

       As discussed in deiail above, we continue to find that there will be signifiwnt benefits for the
       Entergy region to join an RTO, but these benefits are or can be more than offset by the
       allocationto the Entergy region of RTO transmissionexpansioncosts. We continue to find
       that the benefits of EA1joining an RTO are more limited, and these benefits also are or can
       be more than offset by the aIlocation to the EA1 region of RTO transmissionexpansion costs.




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                                                                                  ie



        There are a number of key uncertainties associated with these findings, including the Day 2
        market evolution in SPP, the oowdination that could take place under the SPP-Midwest IS0
        JOA, the extension of AECI-Entsrgy transmission arrangements, the future footprint of each
        RTO, and, perhaps most importantly,the ultimate amount and allocation of RTO transmission
        expansion costs.




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APPENDIX A: EMTERGWCLECO IN RTO FURTHER RESULTS
          A.4                IN SPP RTO
                  ENTERGY~CLECO

fhe net benefit to each region including the impact of transmission mst allocation is captured in
Table 28.

                  Table 28: Net Benefrt to Entergy, Cleco and SPP RegIons of Join SPP Case

          In M U I m af Nmina! &spent odlars                                   lntlalbn          2.5%
          Benefits am shown 8s posrbb ffgvres,
                                             wsts as negalive figures          Dkcwnl Rale       8.0%
                                                                                                                              2010
                                                 2013    2014 2015      2016    2017      2018   2019   2020   2021   2022 PIValus
     1 ENTERGY REGlON IN SPP RTO
     2 Tmde Bensflts                              is   165      in   182         165      147    127    131    135    139     891
     3 Adrnlnlstmtive Costs                       (36) (39)     (39) (39)        (39)     (40) (41)     (43)   (44) (45)      (23Dk
     4 SubTotal                                   121 126       135 143          126      107     86     88     91     94     661
     5 + TmnsrnlsshCost Allmatkn
     6                 Sludy 1
     7                 Study 2
     8                 Study3
     9 Net Benefits
    10                 wmudy 1
    11                 wmudy2
    12                 wmdy3
     13
    14 CLECO REGION IN SPP RTO
    15 TradeBeneft
    16 AdmSnIstmth Casts
    17 SubTofal
    l a + Transrnlssbn CostAll=tion
    19                 Study 1
    20                 Shrdy 2
    Zt                 Study 3
    22 Net BenefItg
    23                 wEtudy 1
    24                 wlStudy 2
    25                 wlSludy 3
    26
    27 IMPACT ON WISTtNG SPP
    28 Trade BeneriB                               (2)   (14)   (27)    (40) (20)           2     24     27     29     31      (17)
    29 AdmJnlsaativ% Casts                        30      33     32      32       31       32     34     35     36     37     189
    30 SubTotal                                   27      19      5      (8)      11       34     58     62     65     68     171
    31 + lmnsmisskn Cost Ahcatan
    32             study 1                        92     Mo     16s     159      213      209    202    199    2W     210    1,034
    33             study 2                        38     146    ftl     106      160      157    149    147    151    154      726
    34                 study 3                     6       5    (10)    (14)       7        5     (2)    (3)    (3)    (3)      (3
    35 N0t Bmaflfs
    36                 wlStudy 1                 $19     2t9    170     15t      224      243    260    261    269    278    1,206
    37                 wmudy 2                    65     165    lt6      9B      171      191    207    209    218    223     SS7
    38                 wlStudy 3                  33      24     (5)    (22)      18       39     56     69     62     65     I66
    39
    40 SPP-WTERGY-CLECO Net EEn&S
    41    r m ~ m m ~                            147     142    1%      130      139      148    in     165    173    iai     857
    42 Admlnlstmtive Costs                        (12)   (12)   (13)    (13)     (14)     (34)   (15)   (15)   (15)   (16)    08)
    43 Net Benaflts                              If6     130    123     117      125      133    142    150    W7     165     779
    44




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Further detail regarding the net benefits to each of the regions prior to considemtion of transmission
cost altocation i captured in Table 29.
                 s
Table 29: Net Benefit of EntergylClecoJohlng the SPP RTO, excluding TmnsrnIssion Cost Allocation

         In Muons ofNominlAs-spentDotYaners                                 tnhtlon         25%
         Banefts rn shorn as poJllinr ~~QUIRS, as negative n p m s
                                            &                               D h n t Rata    8.0%
                                                                                                                          2010
                                               2013   2014 20.15 2016        2017 2018      2019    2020    2021   2022 PrValue
     1 ENTERGY REGlON IN SPP RTO
     2 Tmde Bensllfs
     3 + DecrearshAdhstedPmdCasls
     4 + lost T60 Trans Revenue
                                               183    192
                                                        .    201
                                                             .
                                                             .       2tO
                                                                     - .      193
                                                                              .. .   176
                                                                                      ..       ?.
                                                                                            4. .3   161
                                                                                                    .. .    166
                                                                                                            .-.    171
                                                                                                                   .. .   -.---
                                                                                                                          1.056
                                               (26)   (27)   (27J    (28)     (29)   (29)   (30)    (30) (31)      (32)   (IW)
     5 = Subtotal TmdB &1?8fik                 is6    ISS    in      182      165    147    127     131 1%         139     891
     6
     7
     8
     9
    10
    11
    12
    13
    14
    15
    18
    I?
    18
    19
    20
    21
    22
    23
    24
    25
    26
    27
    2a
    29                                                                                                                     (861
    30   .
         I   S ~ b h t aTmd8 Benefits
                        l                       (2)   (14)   (2f)    (40)     (20)    2      24      27      29     31     (17)
    3f
    32 + RTO A d r n h l s M Charges            30     33     32     32        31    32      34      35      36     37     189
    33 SubTotat                                 27     19      5      (6)      I3    34      58      62      65     68     171
    34
    35
    36
    37                                                                                      _ _     .
    38   +   Lost Til0 Tran; Revenue           (39) (40)     (41)    (41)     (43) (44)     (45)     (46)   147)   (48)   (2462
    39       Subtotal Tmde Benefits            t47    142    138     130     139     ia     1-      IW      n
                                                                                                            i      181     aw
    40
    41
    42
    43
    44
    45
    46
    47
    48




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        A.2 ENTERGYICLECOTHE MIDWEST 0
                        IN         IS

                   Table 30: Net Benefit to Entergy and Cleeo Regions of JoIn MISO Case

  In Millions of NomhalAs.spent Dollars                              InflaUon        2.5%
  Benefitsam shown asPos&e rigures, costs asnegalive &WITS           Olscount Rate   8.0%
                                                                                                                    2010
                                        20t3    2014   2015   2016    2017    2018   2019   2020   2024   2022    PrValue
  ENTERGY REGION IN MISO
  Trade Benefits
  + DeereaselnAd~ustedProdCosts         145     151    157    I63      155    147 139       144    150    156       068
  + Lost T&OTrans Rwenus                (20)    (21)   (2t)   (22)     (23)   (23) (24)     (25)   psi     (27)     (131)
  = Subtotal Tmde Benefits              125     130    135    141      132    124    115    119    124    129        737
  Admlnlslralive Casts
  + AvoidedICT Charges                    20     21     22  23    24    25    26    27    27                28       138
  + RYO Adrninisimtive Charges           (44)   (45)   (46)(47)  (48) (49)   (51) (52)   (W                (56)     (279)
  + FERCChargeS                           (5)    (5)  (5)   (5)   (5)    (6)  (6)   (6)   (6)               (8)      (32)
  + Internal CapiVLabor                    5)    (5)  (6)   (6)   (6)    (6)  (6)   (7)   (7)               (7)      (34)
  = SubtotaIAdmlrCapilal                 (33)   (34) (36)  (361  (36) (371 (381 (38) (39)                  (41)     (ZaS)
  SubTotal                                92     96  100   105    95    87    77    82    85               88        529
  + TransmlsslonCost Allocation          {4)    (21) (80) (122) (125) (203) (227) (254) (261)             (267)     1782)
  Net Benefits                           88      75   t9   (17)  (29) (t45) (150) (173) (176)             (179)     (254)




                                                                                                                   Page 34
Join MISO CBA Addendum
March 10,2011                                                                    Charles River Associates



      A.3 EA1 I NSPP RTO

                  Table 31: Net Benefitto Entergy-Clem Regions of EA1 Jolns SPP Case


                                                                                         2010

       l3l REGION IN SPP RTO
       Tralle Ben#t8
       + Deueaseb~ladProrlCwu         1015     20    t5     9   3    (2)    m     (14)    37
       + h1TilOTranrRevemm            1211      11   11    11   I2  12      12     13     5a
       f  S u b t W Trade Benefits   2 1 2     6 3    1   ~ 6   1 4 t      O 6      1     95    158
                                      0  0       0    0     0    0   0       0      0      0      0

                                      5    5    6    6     6     6    7      7      7




                                      0    0    0    0     0    1    1       1      1      2
       = SubbtdatT&Benedh             5    5    5    5     5    5    5      6      6      26
       AdmlnlsLraLR9 Costs            0    0    0    0     0    0    0      0      0       0
       Net Benotlta                   5    5    5    5     5    5    5      6      6      26




                                                                                                      Page 35
Join MISO CBA Addendum
March 10,2011                                                                                      Charles River Associates



       A.4 EA1 IN THE MIDWEST
                            IS0

                  Table 32: Net Benefit to Entergy-CIeco RegIons of EA1Joins MISO Case

  In Mittions d Nominal As-spent Dollars                                     Inflation                   25%
  Benefits ara shown as posiliva figures, msts as negalive @sums             D m n t Rate                8.0%
                                                                                                                          2010
                                           2014    2015       2016    2017    2018       2019    2020    2021    2022   PrVatue
  E 1 REGION IN MISO
   A
  Trade Benefits
  +                                                                    VI
     Decrease in Adjusted Prod Costs
  + Lost T&O Trans Revenue
  = Subtotal Trade Benefits
                                             (8)
                                             35
                                             21
                                                    (6)
                                                    35
                                                    29
                                                               2
                                                               32
                                                                       37
                                                                       30
                                                                                ($0)
                                                                                 38
                                                                                28
                                                                                         (13)
                                                                                          39
                                                                                          26
                                                                                                 (17)
                                                                                                  39
                                                                                                  22
                                                                                                         (22)
                                                                                                          40
                                                                                                          18
                                                                                                                 (27)
                                                                                                                  41
                                                                                                                  t4
                                                                                                                           157)
                                                                                                                           185
                                                                                                                           129
  f Reserve Margin Benefits                   Q          O       O       O        0         0       0      0       0         Q
  A dmlnlstrative Costs
  + Avolded ICT Charges                       5       5         6       6         6         6       7       7      7        30
  + RTO Administrative Charges              (14)    (14)      (15)    (15)      (W       (161    (16)    (171    (18)      (76)
  + FERCCharges                              (1)        (1)     (1)    (1)       11)       (1)     (2)     12)    12)       (7)
  + lntemal CapitaUlabor                     [}
                                              4         (4)    (4)     (4)       (4)       (4)     (4)    (5)     (5)      (21)
  = SubtotalAdm;~apif8l                     (14)    (14)      (15)    (15)      (15)     (16)    (16)    (16)    (17)      1751
  SubTotal                                   13      15        17      15        13       10        6      2      (31       5rl




                                            . .     -          . _ ..            ..      . .      --      -.      --
  + lost T&O Trani Rewnue                   (24)    (Z) (21)          (21)      (21)     (20)    (19)    (18)    (16)     (io$
  = Subrotel Tmde Benefits                  (37)    133)      (28)    [29)      (30)     (31)    (27)    (22)    (17)     (144)
  Administrative Costs
  Net Benefits

  IMPACT ON CLECO REGION
  Trade Benefits
  + Decrease kt Adjusted Prod Costs           8         7       6       6         5        5       6       7       7        32


  Admlnistrathra Cos&                         O         O       O       O         O        O       Q       O       O         0
                                                                                                                                  3
  Net Benefits                                8         1       6       6        6         6       8       7      8         33

  IMPACT ON EXISTING SPP REGION
  Trade senefits
  + Decrease In Adjusted Prod Costs          (0)        1       3       6       10        13      15      16      18        39
  + Lost T&O Trans Revenue                    0         0       f       0        0        (0)     (0)     (0)     (0)        0
  = Sublotel Trade Benefits                  (0)        2       4       7       10        13      15      16      16        4Q
  + RTO AdmlnMratim Charges                   0         0       0       0        0         0       0       0       0         0
  Net Benefits                               (0)        2       4       7       10        13      15      16      18        40




                                                                                                                          Page 36
Join MISO CBA Addendum

March 10,2011                                                           Charles River Associates



      APPENDIX 8 : TRADE BENEFITS IN GE MAPS CASES

      8.1 ENTERGYICLECQRTU CASES
                      tN

                Table 33: Trade Benefits In Entergy-Cleco Join RTO GE MAPS Cases




                                                                                         Page 37
    Join MISO CBA Addendum

    March I O , 2011                                                                          Charles River Associates



             B.2 EA[ I N RTO CASES
                       TabIe 34: Trade Benefits in EA1Joins RTO GE MAPS Cases




W Only Jdns UT0                      2013            1 1          2p16        I I          lot9          1 1          1021         1 Not.
                             WP   REEB   130   W   Tat     SPP REES Cf. EAl To1     SPP R E S clr W   'Io1     SPP REES CY E4l   TO!




                                                                                                                        Page 38
      Join MISO CBA Addendum
      March IO, 201I                                                           Charles River Associates



             APPENDIX C: FURTHER DETAIL 20f912022 POWER FLOW

      Table 35: 345 kV Lines Added In the 2019 and 2022 Power Flow Used In GE MAPS in thIs Join MISO CBA
                                     Addendum in comparison to prior CBAs




Asc   uc     Ikrbwuelo S m Greeo to M n d 345 kV. " AGos
                                                    I                                          1     345WI
                        ~
             La C r w s to Nulh MaQsmto Wind 345 kV                                            1     M5WI




                                                                                                   Page 39
                                               Summary of CBA Modeling Differences
                               SPP-Entergy CBA, SPP-EA1 CBA and Join MISO CBA Addendum


The differences in modeling assumptions between the SPP-Entergy CBA arid the Join MIS0 CBA Addendum are summarized in Table 4 of the
Join MISO CBA Addendum (also shown below).


                Table 4 Summary of ModeIlng Assumptlon Changes between the SPP-Entergy CBA and Joln MISO CBA Addendum
                       :


               qOD0 MW Contract Path



               Commltment Po01
                                            Hurdles bshvean Enlergy-AECI and
                                            SPP Cases.

                                            SPPIEnlargylCIewreglon, with
                                                                            1
                                            AECI-Ameren In Sfatus Quo and Join



                                            marglnat losses In wmmllment slep
                                                                                 Same for Slefus Quo and Joln SPP Cases. Hurdles behvean
                                                                                 Entargy-AECI and AECI-Ameren on lhe 1000 MW Contract Path
                                                                                 ellmlnated In Joh MISO Cese.

                                                                                 SPPEnlergylClemlMlSO region, wilh average losses In
                                                                                 commllment step, and rnarghal losses In dispatch step.
                                                                                                                                       1
                                            and dlspatch step. No commllmenl     SlOIMWh comrnltrnent hurdle between SPP and MISO In all
                                            optimlzatIonbehveen MISO and         cases, and between EnlergyICleco and MISO In Slelus Quo and
                                            SPPIEntergylClew.                    Join SPP Cases.


               Midwest IS0 Demand and New   Frozen at 2013 lavels                lnueaslng throughout study period. MISO Mnd capadly
               Wind Capaclty                                                     Increases from t 0 GW In 2013 lo 19.4 GW In 2022.

               Mldwest I S 0 MVP            Not Included In GE MAPS runs         Included In 2018 and 2022 GE MAPS runs lor all ca5es. MVP
               Tmnsmlsslon Expanslon                                             cost allocation to Enlergy and Clew assessed in Joh MIS0
                                                                                 Case.
                                                                                                                                                                 P‘
                                                                                                                                                        =    f i s
               SPP TranemlssIon Expanslon
               Cost Allocatfon
                                            Seplember 2010 estimate              February 2011 Estimate                                                 -;
                                                                                                                                                        g
                                                                                                                                                        -
                                                                                                                                                             m   x
                                                                                                                                                             Q - d
                                                                                                                                                             g
                                                                                                                                               7
                                                                                                                                               CI
                                                                                                                                                             n
                                                                                                                                                             <
                                                                                                                                                             3
                                                                                                                                                             n
                                                                                                                                                             0
                                                                                                                                                             0   n    .
                                                                                                                                                             E   a
                                                                                                                                                             F   F
                                                                                                                                                                 f
CIinrIes River Associates                                                                                                                           1
The key differences between the modeling assumptions in the SPf-€nfergy CBA issued In September 2010 and the SPP-EA1 CBA issued in
October 2010 are captured in Table 17 of the Join MlSO CBA Addendum (also shown below).
                               Tableq7: Summary of Modellng Differences between the SPP-Entergy CBA and SPP-EA1 CBA


                   Reglons Jolnlng the SPP RTO           Enlergy and Cleco
                   EA1 and Rest of Entergy               Treated as one cornblned region                 Treated as sepamla refllons In Base Casa; EA1
                   Relatlons hlp                                                                         jolns SPP in Joh S f P Case

                   Base Case
                                                                                                         SlOIMwh between SPP, EN,Rest of Enbrgy and
                                                                                                         Cleco
                                                                                                         Wheellng and trading frlctlon charges batween
                                                                                                                                                           I
                                                         SPP. Enbrgy and Cleco.                          SPP,EAI, Resl of Enlergy snd Cleco, exmpt the
                                                                                                         EN and Rest of Enlergy charge does not lnduda
                                                                                                         a wheellng charge.
                                                                                                         SOIMWh betweenSPP and EAI. SlOIMWh
                   Joln SPP Case                                                                         behveen SPPEAI, Rest of Entergy and Clew.
                                                                                                         No wheellng or tradhg fdcllon charges between
                   SPP Case                              between SPP, Ennlergy and Clem.                 SPP and EAI. WheelIng and lradlng MctIon
                                                                                                         charges between SPPIWI and Res1 of Entergy



               I
                                                                                                         and Cleco

                   Entergy QF Treatment In 3 a s ~       Non-firmresources                               Non-Rnn resources
                   Case


                   Entergy QF Treatment In Joln          Flrm resources                                  Flrm resources lor lPPs in EA1 regIon; non-firm
                   SPP Casa                                                                              resources for lPPs In Resl of Entergy reglon

                   Lost fransmbslon Revenue from         Hlslodcat transrnlsslondata analysls for SPP-   Change In whsellng cbarges on GE MAPS
                   Jolnlng SPP RTO                       Entergy-Clem imnsactlons. Change In             physlcal iows lor all reglons.
                                                         wheellng charges on GE MAPS physlcal flows
                                                         for other nelghbodng reglons
                                                                                   -


               I   TransmLsIon Expanslon Cost
                   Allmation In Joln SPP Case        I   Allocaled to Enlergy and Clew                   Allocaled lo EA1 only




Charles River Associates                                                                                                                                       2
The modeting and assumption changes between the SPP-€AI CBA and the Joh MIS0 CBA Addendum discussed above are summarized in Table
20 of the Join MIS0 CBA Addendum (atso shown below):
             Table 20: Summary of EA1 Modellnp Assumptlon Changes between the SPP-EA1 CBA and the JoIn MISO CBA Addendum


             1000 M C o n t r a c t Path       Hurdles balween EAlAECl and AECI-        Same for Status Quo and Jdn SPP Cases. Hurdles behveen
                                               Ameran in Slefus Quo and J d n SPP       EAl-AECt and AECt-Ameren ellmlnated In Jdn #/SO Case.
                                               C85eS.

             Cornmttment Pool                  SPP-Enlargy-Clecoreglon, wlth marglnal   SPP-EntergyCleur-MIS0 reglon, wlth average losses In
                                               losses In commitment step and dlspatch   commllment step, and marglnat losses In dlspalch step.
                                               step. No commltment opttmlzetlon         SIOlMWh commllrnenthurdle batween SPPlRest of
                                               between MISO and SPPlEnlergylCleco.      EnlergylCleco and MISO In all cases, and between EA[ and
                                                                                        MISO In Slatus Quo end k l n SPP Cases.

             Mtdwest IS0 Demand and N0w        Frozenat 2013 levels                     lncreaslng throughoul study perlod. 10 GW of MISO wlnd
             Wlnd Capaclty                                                              capacity In 2013 lncreaslng to 19.4GW In 2022
                                                - . .-
                                                  . .         .. -.   -
             Mtdwest I S 0 MVP Transmlsslon    Nol Included                             Included ln201D and 2022 GE MAPS runs. MVP wst
             Expanslon                                                                  allocated to EA1 In EAI h i m #/SO Case

             EAI Transmtsston Revenue and      I
                                               M and Rest of Entergy wheellng           EA1and Rest of Entergy wheellng revenues shared on a load
             Cost Sharlng In Standalone Case   revenues and wheellng costs shared on    rallo basls. Wheellng wsls kepi by reglon lhal Inwned them
                                               a load ratlo basls.

             EAI Tranerntsston Revenue and     E 1wheellng wsls and wheeling
                                                4                                       EA1 wheellng costs not shared. EA1transmlsslon revenues
             Cost Shartng in Joln RTO Case     revenues not shared.                     shared wlth RTO (keep 56% In SPP, keep 52% In MISO).
                                                                                        Exlsting SPP (5.6%) and MIS0 (2.5%) wheel revenuesshared
                                                                                        with EAI.

             1000 MWcontract Path                                                  I
                                               WheelIng costs Included for EA1 on M - Wheeling costs Included for EA1 on both EM-AECI and AECI-
             Transmlealon Coats                AECI leg for MI Steodelone Case and    Ameren leg for EA/ Slendalone Csse and Joln SPP Cese In
                                               Join SPP CRSe.                         post-processlng of trade benefits.

             Joln SPP Transmlsslon             September2010 esthato                    February 201t Esllmata
             Expandon Cost Allocatlon




Charles River Associates                                                                                                                             3

				
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