apsc filed time: 7/12/2011 10:30:53 am: recvd 7/12/2011 … · n1 staff‐eai 18‐24 other bas...

Exhibits List ‐ 7‐3 v1.xls

# DR or other source Subject HSPI? CommentA MISO 11/10 presentation to ERSC WG MISO‐Entergy economic tranactions ExcerptB AG‐SPP 4‐1 to 4‐3 Firm transmission capacityC AG‐SPP 2‐15c Limits on MISO‐EAI power flowsD MISO 11/10 presentation to ERSC WG MISO‐Entegy loop flow estimates Excerpt (differs from A)E Staff‐SPP 19‐1 AECI would charge for loop flowE1 Staff‐SPP 19‐7 Example from MISO‐PJM utilitiesE2 SWEPCO‐EAI 2‐4 EAI would not hold harmless others for loop flow!F Staff‐EAI 20‐5 No one charges for loop flowG not usedH Staff‐SPP 11‐22 JOA needs renegotiating in either RTO scenarioI AG‐MISO 1‐4 Entergy would operate Entergy system reliablyJ AG‐MISO 2‐5 & 6 Entergy would become LBA (2‐5); so would EAI (2‐6)K not usedL Staff‐EAI 18‐58 EAI to operate in MISO separate from OpCosM Staff‐EAI 18‐3 LBAs part of EAI's visision or Entergy's vision Excerpt from attachmentN Staff‐EAI 18‐53 EAI concerned about reliability benefits in MISO Y Objection! Excerpt from attachmentN1 Staff‐EAI 18‐24 Other BAs within EntergyO AG‐SPP 2‐8 & 9 SPP relations within ARP Staff‐EAI 20‐2 & 3 Benefits to non‐Entergy partiesQ AG‐EAI 13‐6 But EAI doesn't know whyR Staff‐EAI 24‐18 MISO & Ent. Wheeling out costsS Staff‐SPP 15‐9 Added costs to SPP‐MISO seamT Entergy pres. To ERSC LMPs in Entergy area ExcerptU Staff‐EAI 24‐20 EAI to operate alone in MISOV not usedW Staff‐EAI 24‐21 But not clear how EAI will participate in MISOX Staff‐EAI 18‐61 Two GFAs for EAIY Staff‐EAI 12‐1 EAI will let PCITSA expireZ AG‐SPP 2‐6 Amount of SPP‐EAI capacityAA Staff‐SPP 22‐21 REES could join SPP w/o EAIBB Staff‐MISO 21‐16 REES could join MISO w/o EAI, w/ tx pathCC AG‐EAI 6‐4 Details on EAI's QF contracts Y AttachmentDD Staff‐EAI 18‐15 EAI has no plan to pursue QF benefitsEE Staff‐EAI 18‐14 but EAI must file FERC application to get themFF AG‐EAI 13‐8 EAI QF termination dates Y AttachmentGG AG‐EAI 12‐13 MISO settlement rules provide reliefHH AG‐EAI 13‐9 SPP settlement rules do not provide relief, yet

APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513

EXHIBIT KDW‐A


1

November 17, 2010

Midwest ISO Presentation to Entergy Regional State Committee Working Group

4/20/2011 MISO Response to 4/5/2011 AR AG's First Set of Data Requests: 001468


m02014

Typewritten Text

EXHIBIT 4A

Transfer Study Results• To illustrate the relationship between the tie line physical

flows and the economic transactions, consider the scatter charts on the following pages• Each dot represents one hour out of the year• The data on the X-axis reflects the level of the economic

transaction between Entergy and the Midwest ISO during a given hour

• The data on the Y-axis represents the total physical flows on 2 Madrid Transformers during that hour

• The maximum level of economic transaction produced from the security constrained economic dispatch is approximately 4,000 MW



-1600

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Economic Transaction and Tie Line Flow Chart: From 2010 Entergy In MISO Case



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EXHIBIT KDW‐B


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Arkansas Public Service Commission Docket No. 10-011-U

In the Matter of a Show Cause Order Directed to Entergy Arkansas, Inc. Regarding its Continued Membership in the Current Entergy System Agreement,

or any Successor Agreement Thereto and Regarding the Future Operation and Control of its Transmission Assets

SOUTHWEST POWER POOL, INC.

RESPONSE TO DATA REQUEST AG-04 4-1) Provide the “total transfer capability” for each of the six sets of transmission lines

identified in Attorney General Data Request Questions 3-1 to 3-6. Response: The “total transfer capability” (“TTC”) is defined1 as the total amount of electric power that can be moved or transferred reliably from one area to another area of the interconnected transmission systems by way of all transmission lines (or paths) between those areas under specified system conditions, not limited to a set of transmission lines. The TTC is measured along a path from source to sink. The TTC is limited by the capacity of either equipment (such as transformer, transmission lines, equipment of substations) or interfaces (collection of transmission lines). The limiting element that determines the TTC does not necessarily need to be a tieline between the two areas. It can be any transmission line, transformer or substation equipment of either the source area, the sink area, or a neighboring area impacted by the parallel flow that is moved from the source area to the sink area. The calculation performed to determine the TTC between 2 areas, considers a single contingency of any of the elements of the transmission system impacted by the flow that is moved from the source area to the sink area. Accordingly, the TTC for a set of transmission lines is not a calculation that can be performed without specifying the rules of such a calculation. The TTC is the total amount of electric power that can be moved or transferred reliably from one area to another area of the interconnected transmission systems by way of all transmission lines (or paths) between those areas under specified system conditions, not limited to a set of transmission lines. The details of the calculation of TTC are specified in the Modeling, Data and Analysis (“MOD”) Reliability Standards posted on the North American Electric Reliability Corporation (“NERC”) web site (www.nerc.com). SPP is the Transmission Service Provider (“TSP”) of the entities that are under the SPP Tariff. As a TSP, SPP is required to comply with the MOD Standards. One of the requirements of the MOD Standards is for the TSP to select a methodology to calculate the available transfer capability between areas of the Bulk Electric System (see Standard MOD-001-1a). There are three methods from which to choose: Available Flowgate Capability, Area Interchange Methodology or Rated System Path Methodology. SPP utilizes the Available Flowgate Capability methodology to calculate the available transfer capability between areas of the Bulk Electric System. The requirements for this methodology are specified in MOD-030-02.2 This MOD standard describes what type of

1 This definition is posted on the NERC web site (www.nerc.com) under “Glossary of Terms Used in Reliability Standards”. 2 Details of “total transfer capability” (TTC) calculation are specified in MOD-028-1 and MOD-029-1a for those TSPs that utilize the Area Interchange Methodology or Rated System Path Methodology.


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calculations need to be performed by the TSP and what results have to be posted and made available to the customers. The TTC does not have to be calculated by the TSP. SPP calculates and post the available transfer capability between areas of the Bulk Electric System posted. The details of this calculation are specified in R11 of MOD Standard MOD-030-02. For the purpose of providing information in connection with this response, SPP calculated TTC and TTC minus Generation to Load Impact (“GenToLoad”) for 5 transfers listed below. The TTC assumes no pre-loading of the transmission system, which means it assumes no load served by generators. The full transmission system is assumed to be available for the transfer between the two listed areas. SPP only considered the limiting elements of the SPP Transmission system in the TTC and TTC minus GenToLoad calculations and not the limitations of elements of the transmission system in Entergy area, Associated Electric Cooperative, Inc. (“AECI”) area or other areas on the path of the transfer. The TTC minus GenToLoad assumes pre-loading of the transmission system with the flow as result of generators providing power to the load of the areas without any transfer flow between the areas. SPP is of the opinion that the TTC minus GenToLoad calculation could be close to the definition of FCTTC, which is defined herein and the subject of SPP’s Response to AG-04, Request 4-2. The TTC minus GenToLoad is “available” for transfers between areas of the Bulk Electric System and the capability need to be shared by all entities based on the priority granted by the Tariffs of the Transmission Service Providers of the Bulk Electric System.

May-June 2011 TTC (MW) TTC – GenToLoad (MW)

CSWS --> EES 5000 2000 - 2500

OKGE --> EES 3000 1500 - 2000

MEC --> EES 5000 1000 - 1200

AMIL --> EES 6500 4000

EES --> OKGE 3500 750 - 1500 Note: CSWS = American Electric Power West (formerly Central and South West Services) EES = Entergy OKGE = Oklahoma Gas & Electric Services AMIL = Ameren Illinois MEC = MidAmerican Energy Company Iowa

Prepared by: Carl A. Monroe, Executive Vice President and Chief Operating Officer Submitted to: Shawn McMurray, Senior Assistant Attorney General Date: June 2, 2011


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RESPONSE TO DATA REQUEST AG-04 4-2) Provide the following information regarding the term “first contingency total transfer

capability” (“FCTTC”) mentioned by Richard C. Riley in his Supplemental Direct Testimony of May 12, 2011, in APSC Docket No. 10-011-U:

a. Does the SPP use the term FCTTC, or a similar term or concept, in its market

operations and/or its transmission planning and operations? If so, define the term and describe and document its calculation.

Response: The term first contingency total transfer capability (“FCTTC”) was at one time part of the NERC Reliability Standards, but is no longer included in such. SPP is of the opinion that the MOD Standards referred to in SPP’s Response to AG-04, Request No. 4-1 replaced FCTTC. SPP does not consider FCTTC in operations or planning and does not perform any calculations that would provide FCTTC values in these arenas. As described in SPP’s Response to AG-04, Request No. 4-1, SPP TSP utilizes the Available Flowgate Capability methodology to calculate the available transfer capability between areas of the Bulk Electric System. SPP does use the term FCITC (First Contingency Incremental Transfer Capability) in a collaborative transmission planning study called the Eastern Interconnection Reliability Assessment Group (ERAG) Inter-Regional Transmission Assessment. NERC defines FCITC as “the total amount of electric power (net of normal base power transfers plus first contingency incremental transfers) that can be transferred between two areas of the interconnected transmission systems in a reliable manner …” This planning study does not consider transfer capability between balancing authorities and instead only looks at regional and sub-regional planning area transfers. The areas for which the total first contingency incremental transfer capability (FCITC) is calculated by ERAG are not the traditional Balancing Authority areas or Market areas, those are larger regional areas often a combination of several Balancing Authority areas and or Market areas. EES also participates in the ERAG Inter-Regional Transmission Assessment.

b. When SPP used the phrase “total transfer capability” in responding to Attorney General Data Requests 3-1 to 3-6, did SPP mean the term FCTTC or a similar term or concept? If not, please define the term “total transfer capability” and describe and document its calculation.

Response: SPP’s usage of the term “total transfer capability” in its response to AG-03, Requests Nos. 3-1 to 3-6, SPP did not mean FCTTC. SPP meant “total transfer capability,” as defined and


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described in detail in SPP’s Response to AG-04, Request No. 4-1. Also, as is further described in SPP’s Response to AG-04, Request No. 4-1, SPP utilizes the Available Flowgate Capability methodology to calculate the available transfer capability between areas of the Bulk Electric System.



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RESPONSE TO DATA REQUEST AG-04 4-3) Provide the following information regarding the following statements made by

Richard C. Riley in his Supplemental Direct Testimony of May 12, 2011, in APSC Docket No. 10-011-U: a. State whether SPP agrees with EAI’s statement that “There are only nine ties with

the SPP market, with 4,343 MW of thermal capacity” (10:19-20). If so, please identify those ties. If not, please state SPP’s belief as to the number of ties between the SPP market and the Entergy Operating Companies.

Response: SPP agrees that there are nine ties between Entergy and current SPP Market participants. The nine ties between Entergy and current SPP Market participants are identified in lines 71-77, 86 and 95 of Exhibit 1 to SPP’s Responses to AG-02. Seven of those ties are between EAI and current SPP Market participants. Besides those 9 ties between Entergy and the SPP Market, there are 33 more ties between Entergy and SPP Members that are not participating in the SPP Market at this time:

• Eleven ties between Southwester Power Administration and Entergy (6 ties are generation ties and 5 are transmission ties with a total capacity of 954 MW)

• Two ties between City of Lafayette, Louisiana and Entergy (total capacity of 370 MW)

• Twenty five ties between CLECO and Entergy (total capacity of 8389 MW) If at some time in future one or more of the 3 listed entities participate in the SPP Market, the number of ties to the SPP Market would increase accordingly.

b. State whether SPP agrees with EAI’s statement that the “The first contingency

total transfer capability (“FCTTC”) from the SPP market to the [Entergy] Operating Companies is about 1,100 MW, while the FCTTC in the other direction is about 1,500 MW” (11:9-11). If so, please describe how these FCCTC figures were computed. If not, please state SPP’s belief as to the FCTTC between the SPP market and the Entergy Operating Companies and explain how these figures were computed.

Response: Please see SPP’s Response to AG-04, Request Nos. 4-2.a and 4-2.b. SPP can neither confirm nor provide other values for the FCTTC from the SPP Market to the Entergy Operating Companies. SPP does not consider FCTTC and does not perform any calculations that would provide FCTTC values. As described in greater detail in SPP’s Response to AG-


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04, Request No. 4-1, SPP utilizes the Available Flowgate Capability methodology to calculate the available transfer capability between areas of the Bulk Electric System. For the purpose of providing information in response to this request, SPP calculated TTC and TTC minus GenToLoad for 5 transfers listed in its Response to AG-4, Request No. 4-1. Please refer to the chart included in SPP’s Response to AG-4, Request No. 4-1 and the explanation in the paragraph immediately preceding such chart. In the current transmission planning 2011 ERAG Inter-Regional Summer Transmission Assessment study, the SPP FCITC import capability from Entergy/AECI (Delta sub-region defined in the ERAG assessment) was found to be limited by Entergy facilities and tie lines at 550 MW. However, without these Entergy limits the limit was found to be 2100 MW. The ERAG study report also shows the SPP FCITC export capability to Entergy/AECI to be limited by Entergy facilities at 2200 MW. Without these Entergy limits the study did not see a limit up to the transfer cap of 3000 MW.



EXHIBIT KDW‐C


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SOUTHWEST POWER POOL, INC. RESPONSE TO DATA REQUEST AG-02

2-15) Provide the following information regarding the statement SPP made in response to APSC Data Request 11-24 “The use of that tie to integrate the operations of MISO and Entergy would significantly impact both the SPP and TVA grids. SPP estimates that for each 100 megawatts of flow across the physical tie that there will be 150 – 200 megawatts flowing north to south over the SPP grid and a comparable amount flowing over the TVA grid. These parallel flows have the potential to cause reliability and operational issues for utilities in Arkansas, Nebraska, Kansas, Missouri, Oklahoma, Tennessee, Mississippi and Kentucky”.

a. State the basis for this conclusion.

Response:If EAI or Entergy joins MISO the exchange of power between MISO and Entergy will be mainly north to south flow on the SPP Transmission System. For every 100 MW exchange of power between MISO and Entergy less than 9% will flow on the MISO-Entergy interface. SPP expects that 30% of the power exchange between MISO and Entergy will flow on the SPP Transmission System, 17% on the AECI Transmission System and 42% on the TVA Transmission System. A map showing the flows on the interfaces is attached hereto as Exhibit 12. The original testimony concluded that for each 100 MW on the physical MISO-Entergy tie (as result of a transaction from MISO to Entergy) approximately 150 – 200 MW would flow over the SPP grid, as well as a comparable amount over the TVA grid. This was based on an analyses related to the flows on a few tie lines between SPP and EES and between TVA and Entergy. SPP Staff performed a separate, new assessment taking all tie lines2 into account and the results showed that a 1250 MW power transfer between MISO and Entergy will result in a 100 MW flow on the MISO-Entergy tie (8%), a 375 MW flow over the SPP transmission system (30%), a 200 MW flow over AECI Transmission system (17%), and a 525 MW flow over the TVA transmission system (42%).

2 Specifically, tie lines between the following were included: SPP and Entergy, AECI and Entergy (includes the Entergy-MISO shared contract path), TVA and Entergy, and Southern Company and Entergy.


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This conclusion was derived by taking the flow over the MISO-Entergy interface and determining the amount of flow on the SPP transmission System. Therefore, a 100 MW flow on the MISO-Entergy interface, which is a result of the exchange of power between MISO and Entergy, represents a 1250 MW transfer of power from MISO to Entergy. (8% of the 1250 MW transfer will flow on MISO-Entergy interface.) From this 1250 MW transfer, 30% (approximately 375 MW) will flow through the SPP Transmission system, 17% (approximately 200 MW) will flow through the AECI Transmission System and 42% (approximately 525 MW) will flow through the TVA transmission system. See SPP’s Response to Data Request 2-5 for additional information on this calculation.

See also, maps attached hereto as Exhibits 11 and 12.

b. Provide any studies or analyses that support this conclusion.

Response:Reliability Coordinators in the Eastern Interconnect use the NERC IDC Application hosted and maintained by OATI to call TLR events, if necessary, to mitigate congestion on the Bulk Electric System. This tool models the Eastern Interconnect transmission system. It is capable of calculating the impact of any transaction on the transmission system between 2 different Balancing Authority areas. SPP Staff used the NERC IDC tool to calculate the impact of a 100 MW transaction from MISO to Entergy. NERC IDC indicates that less than 9% of the transaction will flow on the tie line between MISO and Entergy and 90% will flow on other transmission facilities, causing undesired parallel flow impacts on the other transmission systems between MISO and Entergy based on the path of the lowest resistance (impedance).

c. State what flows currently now occur between MISO and Entergy through this existing physical interconnection, what impacts such flows have on other systems, whether such impacts are managed now, and if so, how such impacts are managed now.

Response:MISO and Entergy can exchange power presently; however that power exchange can only occur if transmission rights are acquired under both the Entergy Tariff and MISO Tariff. This would be limited to the 1000 MWs of contract path capability on the one contract path, not the up to 4000 MWs stated by MISO last year. To acquire additional transmission rights requires an evaluation of available transmission capacity of all impacted transmission facilities between Entergy and MISO by both the MISO Tariff and the Entergy Tariff. This evaluation considers SPP facilities, AECI facilities and TVA facilities that are impacted more than 3% by such a transaction.


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The transmission rights are not granted if any of the impacted flow gates are sold out. This reduces congestion on the transmission system. If congestion occurs, the NERC TLR procedure will be used by the Reliability Coordinators to mitigate congestion.

Prepared by: Carl A. Monroe, , Executive Vice President and Chief Operating Officer Submitted to: Emon Mahony, Assistant Attorney GeneralDate: April 20, 2011


EXHIBIT KDW‐D


1

November 17, 2010

Midwest ISO Presentation to Entergy Regional State Committee Working Group



m02014

Typewritten Text

EXHIBIT 4A

Loop Flow Estimation• PROMOD does not provide the exact loop flow for each transaction,

but we can roughly estimate the total amount of loop flow through other regions in each hour by making the following assumptions:– If the economic transaction and the tie line flow are in the same direction

and the economic transaction is larger than the tie line flow, the difference between these two is the loop flow in that hour. Otherwise, the loop flow is 0.

– If the Midwest ISO /Entergy economic transaction and the Midwest ISO /Entergy tie line flow have the same directions, we assume all flow on the tie line is contributed by the MISO/Entergy economic transaction.

– If the Midwest ISO/Entergy economic transaction and the Midwest ISO/Entergy tie line flow have different directions, there still are loop flows through other systems. But as the MISO/Entergy economic transaction provides counterflow on MISO/Entergy tie line, we assume the loop flow is not harmful for other interfaces either



Loop Flow Through Other Regions for MISO to Entergy Economic Transactions

Loop Flow Through Other Regions for Entergy to MISO Economic Transactions

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847

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5256

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Flow

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Max: 3936 MW

Max: 3450 MW

Loop Flow Duration Curve: From 2010 Entergy In MISO Case

18



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Max: 4497 MW

Max: 4315 MW



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Max: 3725MW

Max: 4155MW

29



EXHIBIT KDW‐E


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In the Matter of a Show Cause Order Directed to Entergy Arkansas, Inc. Regarding its Continued Membership in the Current Entergy System

Agreement, or any Successor Agreement Thereto and Regarding the Future Operation

and Control of its Transmission Assets

SOUTHWEST POWER POOL, INC. RESPONSES TO DATA REQUEST APSC-019

INFORMATION REQUESTED:

1) With regard to SPP’s estimate of the approximately 17% power flow from MISO to Entergy, which NERC’s IDC calculated would flow through the Associated Electric Cooperative Inc. system (see SPP’s Response to AG-2-11), please provide an estimate of what AECI would charge for these flows through their Firm Point-to-Point Transmission rate, based on their current OATT tariff.

a. If SPP believes that AECI would charge for these flows on some other basis, please explain the basis for that belief and provide an estimate of what the potential charges would be under this arrangement.

Response:Southwest Power Pool, Inc. (“SPP”) is of the opinion that it would be reasonable to assume that Associated Electric Cooperative, Inc. (“AECI”) would charge for these flows, but does not have direct knowledge of such or of the amount of the potential charges. SPP’s Response to Data Request No. 7 provides information on an apparently analogous set of circumstances in the 2003 decisions of ComEd and the AEP Operating Companies to join the Midwest ISO (“MISO”), which were resolved through a negotiated settlement. AECI would be the appropriate party to provide information on its specific situation.

Prepared by: Carl A. Monroe Submitted to: Diana Brenske, Arkansas Public Service Commission Staff Date: June 6, 2011


EXHIBIT KDW‐E1


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In the Matter of a Show Cause Order Directed to Entergy Arkansas, Inc. Regarding its Continued Membership in the Current Entergy System

Agreement, or any Successor Agreement Thereto and Regarding the Future Operation

and Control of its Transmission Assets



7) In its May 9, 2011 comments filed at FERC in Docket No. EL11-34, SPP stated the following on pages 20 – 21:

“In 2003, when Commonwealth Edison Company (“ComEd”) and the operating companies of American Electric Power Company (“AEP”) chose to join PJM rather than MISO, the Commission held that MISO utilities had to be “held harmless” from the loop flow effects of ComEd’s and AEP’s choices. The Commission explained that the “purpose of the hold harmless condition is to protect [MISO] utilities from the financial impacts associated with loop flows and congestion created by ComEd’s and AEP’s RTO choices, essentially making [MISO] utilities whole for those impacts.”

What is SPP’s understanding or knowledge of the actions taken and / or payments required that held MISO utilities harmless from the affects of Loop Flow caused by ComEd and AEP joining PJM? Please describe such remedies in as much detail as possible.

Response:In conditionally allowing AEP and ComEd to join PJM, the Federal Energy Regulatory Commission (“FERC”) directed AEP, ComEd, PJM and MISO to devise “a solution which will effectively hold harmless utilities in Wisconsin and Michigan from any loop flows or congestion that results from the proposed configuration” – i.e., the hold harmless condition. Alliance Cos., 103 FERC ¶ 61,274, at P 21 (2003). The FERC required that the hold harmless condition compensate the Wisconsin and Michigan utilities for “any adverse operational and financial impacts related to loop flow and congestion resulting from ComEd’s and AEP’s choosing to join PJM.” Commonwealth Edison Co., 106 FERC ¶ 61,250, at P 5 (2004). The FERC specified that the financial harms, which largely result from the operational harms, “include changes in congestion uplift, locational prices, or changes in level and/or frequency of TLR procedures, and any other


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significant commercial impacts that can be reasonably identified and quantified.” Alliance Cos., 102 FERC ¶ 61,214, at P 7 (2003). The FERC found that the baseline for determining adverse financial impacts was the situation that would have existed had AEP and ComEd joined MISO and loop flows were internalized within a single RTO. Id. at P 10; see also Commonwealth Edison Co., 106 FERC ¶ 61,250, at P 40 (“the baseline for comparison should be what would have occurred had those companies joined Midwest ISO”).

SPP’s understanding of the actions taken following the decisions of AEP and ComEd to join PJM is based on documents from the FERC proceedings, which are publicly available. SPP is generally aware the parties pursued settlement discussions following the issuance of FERC’s orders and that compensation issues between AEP, ComEd and the affected utilities in Wisconsin and Michigan were addressed through negotiated settlement agreements.



EXHIBIT KDW‐E2


ENTERGY ARKANSAS, INC.ARKANSAS PUBLIC SERVICE COMMISSION Docket No. 10-011-U MISO Transition Discovery

Response of: Entergy Arkansas, Inc. to the Second Set of Data Requests of Requesting Party: Southwestern Electric Power Company Filed: 6/27/11

Question No.: SWEPCO 2-4 Part No.: Addendum:

Question:

Has Entergy performed any loop flow analysis on energy transfers between MISO and Entergy on the adjacent transmission systems? If so, please provide a copy of the study, models and scenario assumptions?

a. Is Entergy willing to hold adjacent transmission systems harmless for loop flows resulting from their integration with MISO?

Response:

No. See EAI’s response to STAFF 18-19.

a. No. See also EAI’s responses to STAFF 20-5 (b) and STAFF 20-6.

10-011-U TH1047

APSC FILED Time: 6/27/2011 3:36:05 PM: Recvd 6/27/2011 3:34:37 PM: Docket 10-011-U-Doc. 469


EXHIBIT KDW‐F



Response of: Entergy Arkansas, Inc. to the Twentieth Set of Data Requests of Requesting Party: Arkansas Public Service Commission General Staff Filed: 6/9/11

Question No.: STAFF 20-5 Part No.: Addendum:

Question:

Regarding SPP, AECI, or any other transmission entities that may be impacted by flows between MISO and EAI (other than on the 1,000 MW contract path):

a. Has CRA or EAI estimated the potential congestion costs on the SPP and AECI systems that would result from Loop Flows on these systems?

b. If neither CRA nor EAI has estimated the potential congestion costs on the SPP and AECI systems that would result from Loop Flows, what assurance does EAI have that its estimated higher benefits from joining MISO rather than SPP would not be reduced if EAI had to pay for such congestion costs?

Response:

a. The Operating Companies reviewed the results provided by CRA for the “Top 40” congested flowgates. See the affidavit of Michael Schnitzer filed in FERC Docket No. EL11-34-000, which was attached to EAI’s response to Staff 18-19. The results of that analysis suggest that, while the “Join MISO” case would result in a modest increase in congestion costs on SPP flowgates, the “Join SPP” case would result in a slightly larger increase in congestion of MISO flowgates. Overall, the “Join MISO” case had a smaller congestion impact on third party systems than the “join SPP” case.

b. The analysis assumes that 1,000 MW of seamless market flow between the Entergy Transmission System and the rest of the MISO Balancing Authority is available to the MISO market operator, based on the interconnection. Today, 1,000 MW of service can be, and is, sold in either direction on that path, and there are loop flows associated with those transactions just as there are with any transaction on the interconnected grid. Indeed, up to 1,000 MW of service could be sold today from any set of generators in MISO to any loads in the Entergy Region, and vice versa. Given that this level of loop flow

10-011-U SS3950



Question No.: STAFF 20-5

can occur today, the conversion of this to market flow does not require a loop flow study.

As to the suggestion that SPP might seek to charge for loop flow (although it has never previously sought to do so), it is difficult to estimate the net effect on EAI were it to join MISO and then SPP succeeded in having its position adopted. If SPP could charge for loop flows on SPP facilities caused by MISO market flows, then presumably MISO could charge for loop flows on its facilities caused by SPP market flows. Furthermore, if SPP’s position were to prevail, MISO would likely take the position that it could also be compensated for loop flows on the MISO system (including EAI transmission facilities) caused by market flows within the TVA or Southern Company systems. Also TVA and Southern Company could take a similar position. All of these would affect the net charges or credits that would accrue to MISO and to EAI. For these reasons the question requires speculation and cannot be answered.

10-011-U SS3951



EXHIBIT KDW‐G

Not Used


EXHIBIT KDW‐H


of 58






22) Please identify and explain the issues regarding the interpretation and implementation of the JOA with MISO that SPP believes would need to be addressed in a Join MISO case. Please provide a copy of the JOA.

Response:

It is SPP’s position that under Section 3.1 of the JOA, that in either a “Join MISO” case or a “Join SPP” case that the current JOA would be renegotiated to address the integration of Entergy into either system because the flows to either system would change dramatically, with consequences to system congestion, planning, and associated cost responsibilities.

Section 3.1 of the JOA provides:

The Parties expect that these systems and technology applicable to these systems and to the collection and exchange of data will change from time to time throughout the term of this Agreement. The Parties agree that the objectives of this Agreement can be fulfilled efficiently and economically only if the Parties, from time to time, review and as appropriate revise the requirements stated herein inresponse to such changes, including deleting, adding, or revising requirements and protocols. Each Party will negotiate in good faith in response to such revisions the other Party may propose from time to time.

(emphasis added).

Prepared By: Carl A. Monroe Served To: Diana Brenske, Arkansas Public Service Commission Staff Date: March 18, 2011


EXHIBIT KDW‐I


1-4) Please provide the following information regarding the statement in the March 18,2011, Direct Testimony of Richard Doying at 13:14-18 " ... the single directinterconnection with Ameren, an existing MISO transmission owner, is sufficient toreliably and efficiently balance Entergy resources and loads in the MISO markets, and to transfer energy for both emergency and economic reasons throughout the combined transmission systems":

a. State the basis for this conclusion.b. Provide any studies or analyses that support this conclusion.

RESPONSE:

a. The existing Entergy Balancing Authority has reliably and efficiently balanced regional loads and resources for many years. Upon integration into the MISO Balancing Authority, Entergy will become a Local Balancing Authority, responsible for the local control of generation within the Entergy region (its Local Balancing Authority Area). Joint dispatch of the combined MISO-Entergy region by the MISO Balancing Authority will increase the utilization of the direct interconnection capacity between MISO and Entergy, enhancing reliability and efficient dispatch for both MISO and Entergy.

During periods when economic or emergency conditions indicate the need for interchange greater than the capacity available via the direct interconnection, other agreements exist that provide expanded transfer capability. While this additional interchange capacity is not required to reliably and efficiently balance resources and loads in the Entergy region, its utilization will enhance the benefits of Entergy's membership in MISO.

MISO presented the attached study to the Entergy State Regional Committee Working Group in November 2010. The study contains an analysis of the physical flows on the direct interconnection and the flows through other neighboring systems.

b. Exhibit 4A attached hereto is a document entitled “Midwest ISO Presentation to Entergy Regional State Committee Working Group”

1-5) Please provide the following information regarding the statement in the March 18,2011, Direct Testimony of Richard Doying at 14:9-11 that " ... the 2004 SPP agreement is a commitment to 'share' physical paths between the RTOs to a common operating entity":

a. Verify that the "2004 SPP agreement" being referenced is the MISO-SPP Joint Operating Agreement (JOA) cited at 14:1.

b. Provide a copy of the JOA.c. State which language within the JOA constitutes the "commitment"

cited in sub-part 'a' above.


EXHIBIT KDW‐J


4

2-5) Provide the following information regarding the cited portions of the MISO’s response to AG Data Request 1, Question 4:

a. Define the term “Local Balancing Authority” as used in MISO’s response to subpart ‘a’ of AG Data Request 1, Question 4.

b. Compare and contrast the responsibilities of a MISO “Local BalancingAuthority” as compared to the “MISO Balancing Authority” with regard tomanaging generation and load in and near real-time. In particular, state whichof these authorities has primary responsibility for meeting ControlPerformance Standards 1 and 2 or their successors.

c. The MISO’s response refers to a “Joint dispatch of the combined MISO Entergyregion by the MISO Balancing Authority”. If Entergy joins MISO,will the MISO Balancing Authority also be responsible for a joint “unitcommitment” – that is, decisions on which generating units should be turnedon and off – of the combined MISO-Entergy region? If not, which entity(ies)will be responsible for committing units within the MISO and Entergyregions?

d. What “other agreements exist that provide for expanded transfer capability” –that is, expanded beyond the “capacity available via the directioninterconnection” – other than the MISO-SPP Joint Operating Agreement(JOA)? If other such agreements exist, provide a list of such agreements identifying the counterparties thereto and describing generally how and underwhat conditions such agreements “provide expanded transfer capability”.Provide copies of all such agreements.

RESPONSE:

a. As used in the Balancing Authority Agreement:

LOCAL BALANCING AUTHORITY (“LBA”). An operational entity or Joint

Registration Organization, as defined in the NERC Rules of Procedure, which is

(i) responsible for compliance to NERC for the subset of NERC

Balancing Authority Reliability Standards defined in this Amended

Agreement for their local area within the Midwest ISO Balancing

Authority Area, (ii) a Party to this Amended Agreement, excluding

the Midwest ISO, and (iii) shown in Appendix A to this Amended

Agreement.

b. The MISO and its Balancing Authorities (BAs) have entered into an agreement which

delineates the responsibilities of each with regard to NERC standards. The whole

document is available at :


5

https://www.midwestiso.org/Library/Tariff/Pages/RateSchedules.aspx.

Generally speaking, the LBAs retain responsibility for metering and certain emergency

actions such as load shedding responsibilities as well as certain CIP obligations. Details

on a standard-by-standard basis are available as the referenced hyperlink above. Under

the terms of this BA agreement, MISO has responsibility for meeting NERC Control

Performance Standards.

c. The market participant registered in the MISO market for the Entergy Generating units

will make offers for generation in accordance with terms of Module C of the MISO

OATT. The MISO security constrained economic dispatch process, that is made up of

and is part of its Day-ahead Market and its Reliability Assessment Commitment

processes, commit the necessary units per the terms of the MISO Tariff utilizing these

generator offers as well as many other input data such as load, transmission toplogy, etc.

Note that in addition to MISO processes committing the units in accordance with the

terms of the tariff, one of the potential options available to generators in Entergy’s

circumstances is to self-commit their unit(s).

d. None that MISO is aware of.

2-6) Would MISO’s answers to AG Data Request 1, Question 4 and AG Data Request 2,Question 5 change if only Entergy Arkansas, Inc. (EAI) were to join the MISOwithout any of the other Entergy Operating Companies? If so, provide such changed answers, including an explanation of why the answers differ between the “All of Entergy Joins MISO” and “Only EAI Joins MISO” scenarios.

RESPONSE: No, the answers would not change.

2-7) Provide the following information regarding the data provided in the followingworksheets of Exhibit 6A to the MISO’s response to AG Data Request 1, Question 6:

a. In the worksheet titled “Regulation,” the values shown in lines 7 (Regulationas pct of Peak Load), 10 (Regulation Reduction) and 13 (Production CostSavings per MW) and cells E19:F31 (Savings per MW).

b. In the worksheet titled “Spinning Reserve,” the values shown in lines 9(Reduction in Spin requirement) and 12 (Production Cost Savings per MW)and cells E18:F30 (Savings per MW).

c. In the worksheet titled “Improved Reliability,” the values shown in lines 7(RTO TSAI), 8 (Non-RTO TSAI) and 10 (Cost of Outage $/MWh) and cells


EXHIBIT KDW‐K

Not Used


EXHIBIT KDW‐L


AP

SC

FILED

Time: 6/7/2011 8:10:01 A

M: R

ecvd 6/6/2011 8:48:59 PM

: Docket 10-011-U

-Doc. 401


EXHIBIT KDW‐M


Dra

ft pr

esen

tatio

n –

Prel

imin

ary

View

–N

umbe

rs a

re ro

ugh

estim

ates

and

sub

ject

to c

hang

e In

tegr

ated

tim

elin

e of

cur

rent

RTO

PM

O p

roje

ct a

ppro

ach;

M

aint

aini

ng o

ptio

nalit

y fo

r Pat

h 1+

2+3

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

2011

2012

2013

-Sys

tem

s re

ady

for u

ser

Ove

rall

Set

-up

LBA

and

conn

ectG

MS

and

Coo

rdin

ate

effo

rt, tr

ack

prog

ress

and

man

age

com

mun

icat

ions

with

key

sta

keho

lder

s

Exe

cute

filin

g pr

oces

s ac

ross

juris

dict

ions

Neg

otia

te n

on-O

ATT

GFA

and

arr

ange

men

ts a

roun

d co

-ow

ned

faci

litie

s

Neg

otia

te o

ther

lega

l/com

mer

cial

arr

ange

men

ts

Det

aile

d

test

ing

an tr

aini

ng

Cut

over

Path

1:

All

ETR

O

pCos

to

MIS

O

Pla

nnin

g an

d sc

opin

g ac

tiviti

es fo

r All

ETR

OpC

os to

MIS

O

Set

up L

BA

and

con

nect

GM

S a

nd

EM

S s

yste

ms

with

MIS

O

Hire

new

sta

ff, e

.g. F

TR e

xper

ienc

e, a

nd tr

ain

all s

taff

Exe

cute

MIS

O T

OA

with

ETR

Det

aile

d pl

anni

ng

Acq

uire

new

sof

twar

e, e

.g.

shad

ow s

ettle

men

t too

ling

Pla

n cu

t-ove

rIm

plem

ent n

ew s

oftw

are

Path

2: E

AI

to M

ISO

fir

stP

lann

ing

and

scop

ing

activ

ities

for E

AI t

o M

ISO

Mod

ify G

MS

and

EM

S s

yste

ms

and

conn

ect E

AI w

ith M

ISO

Acq

uire

new

sof

twar

e, e

.g.

shad

ow s

ettle

men

t too

ling

Hire

new

sta

ff fo

r EA

I ope

ratio

ns, e

.g. c

ompl

ete

new

dis

patc

h re

al ti

me

oper

atio

ns,

and

train

all

staf

f

Pla

n cu

t-ove

rIm

plem

ent n

ew s

oftw

are

Det

aile

d pl

anni

ng

Path

3: E

AI

stan

d

Exe

cute

MIS

O T

OA

with

ETR

Mod

ify G

MS

and

EM

S s

yste

ms

for t

wo

BA

s

Pla

n cu

t-ove

rD

efin

e el

ectri

cal i

nter

face

and

met

erin

g fo

r sep

arat

ion

of E

AI

Det

aile

d pl

anni

ng

Def

ine

elec

trica

l int

erfa

ce a

nd m

eter

ing

for s

epar

atio

n of

EA

I

Page

0

stan

d al

one

in

ICT

Pla

nnin

g an

d sc

opin

g ac

tiviti

es fo

r EA

I sta

nd a

lone

in IC

T w

/new

E

AI B

A

Hire

new

sta

ff fo

r EA

I ope

ratio

ns, e

.g. n

ew s

uppo

rt en

gine

er to

de

tail

all n

ew p

roce

sses

for E

AI B

A, a

nd tr

ain

all s

taff

Get

BA

NE

RC

cer

tifie

d

Dev

elop

new

bill

ing

and

settl

emen

t pro

cess

es

10-011-U STAFF 18-3 Add 2 KH13

APSC FILED Time: 7/11/2011 11:49:42 AM: Recvd 7/11/2011 11:48:55 AM: Docket 10-011-U-Doc. 508APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513

Dra

ft pr

esen

tatio

n –

Prel

imin

ary

View

–N

umbe

rs a

re ro

ugh

estim

ates

and

sub

ject

to c

hang

e

RTO

PM

O im

plem

enta

tion

activ

ities

for P

ath

1 S

lide

2 of

2

Pl

anni

ngan

dsc

opin

gac

tiviti

es(e

gS

truct

ure

toop

erat

e

2011

2012

2013

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Them

eK

ey A

ctiv

ities

Gen

erat

ion

Ope

ratio

ns fo

r R

TO p

roje

ct

Pl

anni

ng a

nd s

copi

ng a

ctiv

ities

(e.g

. Stru

ctur

e to

ope

rate

M

ISO

real

tim

e di

spat

ch, d

efin

e an

d m

odify

pro

cess

es a

nd

IT re

quire

men

ts)

B

egin

con

trac

ting

proc

ess

to a

cqui

re n

ew m

odul

e so

ftwar

e an

d sy

stem

s

Dep

loy

and

test

sof

twar

e an

d sy

stem

s:–

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ify G

MS

, dep

loy

Als

tom

mod

ule

, dev

elop

and

test

in

terfa

cew

ithM

ISO

jin

terfa

ce w

ith M

ISO

–O

ther

IT m

odifi

catio

ns, e

.g. m

odify

OTS

, TR

AD

ES

, de

ploy

FTR

/AR

R, L

oad

bidd

ing

and

Gen

offe

ring

tool

ing

Sy

stem

s re

ady

for s

taff

to tr

ain

for M

ISO

pro

cedu

res

H

ire a

nd tr

ain

staf

f for

EAI

ope

ratio

ns

Prep

are

cuto

ver

Pl

anni

n g a

nd s

copi

ng a

ctiv

ities

(Def

ine

and

mod

ify

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smis

sion

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pera

tions

gp

g(

ypr

oces

ses

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IT re

quire

men

ts)

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t-up

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and

inte

rfac

e w

ith M

ISO

–M

odify

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S ,

depl

oy A

lsto

m m

odul

e , d

evel

op a

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st

inte

rface

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er IT

mod

ifica

tions

, e.g

. mar

ket a

nd p

lann

ing

appl

icat

ions

Sy

stem

s re

ady

for s

taff

to tr

ain

for M

ISO

pro

cedu

res

Bac

k-of

fice

Tr

ain

staf

f and

test

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O p

roce

dure

s

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are

cuto

ver

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anni

ng a

nd s

copi

ng a

ctiv

ities

(e.g

. Det

erm

ine

settl

emen

ts v

erifi

catio

n st

ruct

ure

and

IT re

quire

men

ts)

M

odify

exi

stin

g se

ttlem

ent s

yste

ms

(e.g

. Fue

l , W

hole

sale

an

d Tr

ansm

issi

on s

ettle

men

ts)

Dl

ITl

tif

hd

ttlt

dth

IT

Page

3

Bac

kof

fice

oper

atio

ns

Dep

loy

IT s

olut

ion

for s

hado

w s

ettle

men

t and

oth

er IT

pr

oces

ses

H

ire a

nd tr

ain

staf

f for

new

set

tlem

ents

pro

cess

Pr

epar

e cu

tove

r

Not

e: IT

wor

k is

incl

uded

in o

pera

tions

wor

k

Key

Mile

ston

e:

10-011-U STAFF 18-3 Add 2 KH16


Dra

ft pr

esen

tatio

n –

Prel

imin

ary

View

–N

umbe

rs a

re ro

ugh

estim

ates

and

sub

ject

to c

hang

e

Path

1 e

stim

ated

tran

sitio

n/im

plem

enta

tion

cost

s ~$

105M

US

$ 3

(M)

150

2011

2013

2012

Cos

t est

imat

es d

o no

t inc

lude

G

FA re

solu

tion

C

apac

ity a

dditi

on c

osts

C

osts

ass

ocia

ted

with

risk

man

agem

ent t

ools

and

ana

lysi

sM

ain

cost

driv

ers

incl

ude

125

100

104

11

gy

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xten

ded

regu

lato

ry li

tigat

ion

R

even

ue c

lass

met

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g fo

r gen

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ion

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trans

ition

cos

ts

Mai

n co

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s in

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e

MIS

O in

terfa

ce c

osts

1

IT

Har

dwar

e an

d su

ppor

t

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ting

up th

e LB

A

Labo

r (S

PO

/OpC

os)

–in

clud

ing

hirin

g

100 75

245

11

20M

ain

cost

driv

ers

incl

ude

E

xter

nal R

eg./L

egal

su

ppor

t

Labo

r (S

PO

/OpC

os)

FE

RC

fillin

gco

sts

Mai

n co

st d

river

s in

clud

e

Labo

r (S

PO

/OpC

os)

E

xter

nal C

onsu

ltant

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42

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filli

ng c

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n co

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s in

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e

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O in

terfa

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osts

1

&

Mai

n co

st d

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s in

clud

e

MIS

O in

terfa

ce c

osts

1

IT

Har

dwar

e &

sup

port

La

bor (

SP

O/O

pCos

)–

incl

udin

g hi

ring

3725 0

Pat

h1

tota

lcos

tP

MO

/Oth

er2

Com

mun

icat

ions

Bac

k-of

fice

Tran

smis

sion

Gen

erat

ion

Com

mer

cial

and

Reg

ulat

ory

Mai

n co

st d

river

s in

clud

e

Ext

erna

l Reg

./Leg

al s

uppo

rt

Labo

r (S

PO

/OpC

os)

IT

Har

dwar

e &

sup

port

La

bor (

SP

O/O

pCos

) –

incl

udin

g hi

ring

Page

4

Path

1 to

tal c

ost

PM

O/O

ther

Com

mun

icat

ions

Bac

kof

fice

Ope

ratio

nsTr

ansm

issi

onO

pera

tions

Gen

erat

ion

Ope

ratio

nsC

omm

erci

al a

nd

Lega

l Agr

eem

ents

Reg

ulat

ory

Coo

rdin

atio

n

1. M

ISO

inte

rface

cos

ts a

lloca

ted

acro

ss G

ener

atio

n O

pera

tions

40%

, Tra

nsm

issi

on O

pera

tions

40%

and

BO

20%

2. O

ther

s in

clud

e P

MO

man

agem

ent,

HR

cos

ts, c

ompl

ianc

e an

d ex

tern

al s

uppo

rt 3.

num

bers

incl

ude

50%

con

tinge

ncy

for u

nide

ntifi

ed c

osts

due

to b

eing

ear

ly in

the

proc

ess

Not

e: A

ll nu

mbe

rs m

ay n

ot fo

ot d

ue to

roun

ding

10-011-U STAFF 18-3 Add 2 KH17


Dra

ft pr

esen

tatio

n –

Prel

imin

ary

View

–N

umbe

rs a

re ro

ugh

estim

ates

and

sub

ject

to c

hang

e

RTO

PM

O im

plem

enta

tion

activ

ities

for P

ath

1+2

Focu

s on

add

ition

al a

ctiv

ities

to m

aint

ain

optio

nalit

y on

top

of P

ath

1

B

egin

con

trac

ting

proc

ess

to a

cqui

re n

ew s

oftw

are

syst

ems

–M

ake

sure

EA

I per

spec

tive

is in

clud

ed

2011

2012

2013

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Them

eK

ey A

ctiv

ities

pp

D

eplo

y an

d te

st s

oftw

are

and

syst

ems:

–S

epar

ate

GM

S fo

r EA

I and

Res

t of E

TR O

PC

Os

–D

eplo

y A

lsto

m m

odul

e fo

r EA

I –

Mod

ify fo

reca

st m

odel

and

pro

cedu

res

for E

AI

–D

evel

op F

TR/A

RR

, Loa

d bi

ddin

g an

d G

en o

fferin

g to

olin

g an

d pr

oced

ures

for E

AI

–M

odify

WP

P a

nd m

onth

ly e

nerg

y pl

an fo

r EA

I/Res

t ETR

OP

CO

sS

td

ft

fft

ti

fd

Gen

erat

ion

Ope

ratio

ns fo

r R

TO p

roje

ct

Syst

ems

read

y fo

r sta

ff to

trai

n fo

r new

pro

cedu

res

H

ire a

nd tr

ain

staf

f for

new

EA

I in

MIS

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roce

dure

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Com

plet

e ne

w s

taff

need

ed fo

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erat

ions

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ratio

ns

inte

ract

ions

with

MIS

O

Prep

are

cuto

ver

D

uplic

ate

and

deve

lop

new

pro

cedu

res

for E

AI L

BA

in M

ISO

an

dne

wco

ntro

lare

a(R

esto

fETR

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Os)

and

new

con

trol

are

a (R

est o

f ETR

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Os)

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ansm

issi

on m

eter

ing

stud

y, if

requ

ired

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hase

and

inst

all

new

met

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g eq

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ent f

or n

ew s

yste

ms

ties

Se

t-up

EAI L

BA

and

its

inte

rfac

e w

ith M

ISO

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epar

ate

EM

S fo

r EA

I and

Res

t of E

TR O

PC

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eplo

y A

lsto

m m

odul

e fo

r EA

I –

Cre

ate

and

test

EM

S in

terfa

ce w

ith M

ISO

for E

AI

–D

efin

e el

ectri

cal i

nter

face

, brin

g an

d te

st s

yste

m ti

es in

EM

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smis

sion

O

pera

tions

,g

y,

and

deve

lop

disp

lays

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ther

IT m

odifi

catio

ns ,

e.g.

mar

ket a

nd p

lann

ing

appl

icat

ions

Sy

stem

s re

ady

for s

taff

to tr

ain

for n

ew p

roce

dure

s

Trai

n st

aff a

nd te

st n

ew E

AI i

n M

ISO

pro

cedu

res

Pr

epar

e cu

tove

r

M

odify

exi

stin

g se

ttlem

ent s

yste

ms

for R

est o

f ETR

OPC

Os

Page

10

Not

e: IT

wor

k is

incl

uded

in o

pera

tions

wor

k

(e.g

. Fue

l , W

hole

sale

and

Tra

nsm

issi

on s

ettle

men

ts)

D

evel

op s

ettle

men

t pro

cess

bet

wee

n EA

I and

ETR

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Os

A

djus

t off-

the-

shel

f IT

solu

tion

for s

hado

w s

ettle

men

t for

EA

I

Trai

n st

aff f

or n

ew s

ettle

men

ts p

roce

ss

Prep

are

cuto

ver

Bac

k-of

fice

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ratio

ns

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ston

e:

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ft pr

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tatio

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View

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M

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Ext

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uppo

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Set

ting

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11

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Path

1+2

to

tal c

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on

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Sop

tiona

lity

cost

1. M

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inte

rface

cos

ts a

lloca

ted

acro

ss G

ener

atio

n O

pera

tions

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nsm

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on O

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tions

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BO

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ther

s in

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e P

MO

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agem

ent,

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cos

ts, c

ompl

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e an

d ex

tern

al s

uppo

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num

bers

incl

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50%

con

tinge

ncy

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nide

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eing

ear

ly in

the

proc

ess

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e: A

ll nu

mbe

rs m

ay n

ot fo

ot d

ue to

roun

ding

10-011-U STAFF 18-3 Add 2 KH24


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ft pr

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n –

Prel

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ary

View

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rs a

re ro

ugh

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Path

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impl

emen

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sts

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sults

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Page

16

Pat

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optio

nalit

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ulat

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optio

nalit

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ther

Path

1

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l cos

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ack

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pera

tions

1. M

ISO

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rface

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ts a

lloca

ted

acro

ss G

ener

atio

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pera

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nsm

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pera

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ther

s in

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e P

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agem

ent,

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cos

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num

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ly in

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ess

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e: A

ll nu

mbe

rs m

ay n

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10-011-U STAFF 18-3 Add 2 KH29


Dra

ft pr

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tatio

n –

Prel

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View

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II)

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ctiv

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Bi

tti

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2013

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Q3

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ctiv

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ion

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r

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atio

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stem

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d pr

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e op

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ify fo

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oced

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an, a

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AI

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reat

e an

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st E

MS

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r EA

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elop

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oad

bidd

ing

and

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offe

ring

tool

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and

proc

edur

es fo

r EA

I

Syst

ems

read

y fo

r sta

ff to

trai

n fo

r new

pro

cedu

res

H

ire a

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ain

staf

f for

new

EA

I pro

cedu

res

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e cu

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l new

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ms

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ff to

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m ti

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er IT

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ifica

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m m

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ate

and

test

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ain

staf

ffor

new

proc

edur

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Page

20

Tr

ain

staf

f for

new

pro

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G

et N

ERC

cer

tific

atio

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Sy

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taff

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cuto

ver

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wor

k is

incl

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pera

tions

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k

Key

Mile

ston

e:

10-011-U STAFF 18-3 Add 2 KH33


Dra

ft pr

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Prel

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View

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umbe

rs a

re ro

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Path

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Page

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10-011-U STAFF 18-3 Add 2 KH35


EXHIBIT KDW‐N


EXHIBIT KDW‐N1



Response of: Entergy Arkansas, Inc. to the Eighteenth Set of Data Requests of Requesting Party: Arkansas Public Service Commission General Staff Filed: 6/6/11


Question:

On page 44 of the Evaluation Report filed May 12th, 2011, it states that the Entergy Region includes 13 balancing authorities and 8 different load serving entities. Please list the name of each of the 13 balancing authorities and 8 load serving entities.

Response:

The 13 Balancing Authorities within the Entergy Region are as follows: Batesville (BBA)1

Benton Utilities Balancing Authority (BUBA) City of Conway (CNWY) City of West Memphis (WMUC) Cleco2

Duke Energy North Little Rock (DENL) Duke Energy Ruston (DERS) Entergy (EES) Louisiana Electric Power Association (LEPA) Louisiana Generating, LLC (LAGN) Osceola Municipal Light and Power (OMLP)Plum Point (PLUM)3

Union Power Partners (PUPP)4

1 Generation only Balancing Authority. 2 Partially serves load on the Entergy Transmission System. 3 Generation only Balancing Authority. 4 Id.



Aside from the load-serving entities above that are also Balancing Authorities, the following eight companies also serve load within the Entergy footprint.

AECCAEP-West Ameren BrazosETECMEAMMDEASRMPA


EXHIBIT KDW‐O


of 33





2-8) Provide the following information regarding the statement in the March 18, 2011, Supplemental Direct Testimony of Carl A. Monroe at 15:11-19 that a number of entities are “tightly interconnected with EAI”:

a. Define the term “tightly interconnected”.

Response:“Tightly interconnected” refers to number and depth of facilities that connect those entities embedded within EAI. The Entergy Balancing Authority (“BA”) Area has 8 small BA Areas within the EAI Transmission System. The delivery of energy from any generation and load that is not local to each requires the use of the transmission system of EAI. A map showing the locations of the 8 BA Areas is attached hereto as Exhibit 10.

BA Areas tightly interconnected with EAI and Entergy BCA Batesville Generation Station BUBA City of Benton, AR CNWY City of Conway, AR WMUC City of West Memphis, AR NLR City of North Little Rock OMLP City of Osceola, AR PLUM Plumpoint Generation Station PUPP Union Generation Station

SPP is the Reliability Coordinator of the listed BA Areas. The requirements of the Reliability Coordinator function are specified in the NERC Standards.


of 33

b. Identify what “activities necessary to ensure reliable operations” (15:24) are provided for each of the “tightly interconnected” entities listed at 15:14-19.

Response:Each of the entities listed in SPP’s Response to Data Request 2-8.a are served by and share interconnections with EAI. Also, some of the entities have significant load or generation in SPP. There are current coordination for parallel flows and operations within SPP as SPP is the Reliability Coordinator for both Entergy through the ICT and for SPP members. Adding an additional seam will increase the administrative burden to ensure that the operation of the Bulk Electric System will be reliable. NERC defines the Reliability Coordinator as the entity which is the highest level of authority who is responsible for the reliable operation of the Bulk Electric System, has the Wide Area view of the Bulk Electric System, and has the operating tools, processes and procedures, including the authority to prevent or mitigate emergency operating situations in both next-day analysis and real-time operations. The Reliability Coordinator has the purview that is broad enough to enable the calculation of Interconnection Reliability Operating Limits, which may be based on the operating parameters of transmission systems beyond any Transmission Operator’s vision. The areas of coordination that the RC is responsible for include particularly, without limitation: outage scheduling, transaction scheduling, transmission service provision, blackstart restoration, transmission planning, and cost allocation of transmission expansion facilities.

Prepared by: Carl A. Monroe, Executive Vice President and Chief Operating Officer Submitted to: Emon Mahony, Assistant Attorney GeneralDate: April 20, 2011


of 33





2-9) Provide the following information regarding the statement in the March 18, 2011, Supplemental Direct Testimony of Carl A. Monroe at 15:19-22 that a number of entities are “highly interconnected with the rest of Entergy”:

a. Define the term “highly interconnected”.

Response:“Highly interconnected”1 refers to facilities that are embedded within Entergy. The Entergy BA Area has 13 small BA Areas within its Transmission System. The delivery of energy from any generation and load that is not local to each requires the use of the transmission system of Entergy. A map showing the locations of the 13 BA Areas is attached hereto as Exhibit 10.

BA Areas highly interconnected with Entergy BCA Batesville Generation Station BUBA City of Benton, AR CNWY City of Conway, AR DERS City of Ruston, LA WMUC City of West Memphis, AR CLEC CLECO Power Louisiana LAGN Louisiana Generation NLR City of North Little Rock OMLP City of Osceola, AR PLUM Plumpoint Generation station PUPP Union Generation Station LAFA City of Lafayette, Louisiana LEPA Louisiana Energy & Power Authority

SPP is the Reliability Coordinator of the listed BA Areas. The requirements of the Reliability Coordinator function are specified in the NERC Standards.

1 The terms highly and tightly are not meant to be terms of art. Rather, both are used to be descriptive of the number of interconnections.


of 33

b. Identify what “activities necessary to ensure reliable operations” (15:24) are provided for each of the “highly interconnected” entities listed at 15:19-21.

Response:Each of the entities listed in SPP’s Response to Data Request 2-8.a are served by and share interconnections with Entergy. Also, some of the entities have significant load or generation in SPP. There are current coordination for parallel flows and operations within SPP as SPP is the Reliability Coordinator for both Entergy through the ICT and for SPP members. Adding an additional seam will increase the administrative burden to ensure that the operation of the Bulk Electric System will be reliable. NERC defines the Reliability Coordinator as the entity which is the highest level of authority who is responsible for the reliable operation of the Bulk Electric System, has the Wide Area view of the Bulk Electric System, and has the operating tools, processes and procedures, including the authority to prevent or mitigate emergency operating situations in both next-day analysis and real-time operations. The Reliability Coordinator has the purview that is broad enough to enable the calculation of Interconnection Reliability Operating Limits, which may be based on the operating parameters of transmission systems beyond any Transmission Operator’s vision. The areas of coordination that the RC is responsible for include particularly, without limitation: outage scheduling, transaction scheduling, transmission service provision, blackstart restoration, transmission planning, and cost allocation of transmission expansion facilities.



EXHIBIT KDW‐P



Response of: Entergy Arkansas, Inc. to the Twentieth Set of Data Requests of Requesting Party: Arkansas Public Service Commission General Staff Filed: 6/9/11


Question:

For the case in which EAI joins SPP, please list all reasons for the difference between EAI’s trade benefits as estimated in CRA’s original analysis and the same benefits calculated by Entergy in the Evaluation Report filed May 12, 2011 ($49 million per Attachment TA-4, page 1 of 15). For each reason listed, please provide an estimate of the magnitude of the change. Please itemize the components of these trade benefits results (components as specified in Exhibit 7, page 17).

Response:

CRA did not estimate the trade benefits of EAI joining SPP. It estimated the trade benefits of the EAI Region joining SPP. EAI’s load and generation represent only a portion of the total load and generation within the EAI Region. The task of determining what the costs and benefits for EAI customers would be from joining SPP was carried out by Entergy Services, Inc. (“ESI”), on behalf of the Entergy Operating Companies, who used the same methodology that was developed (at FERC’s directive) to take the results of the CRA s analysis of the Entergy and Cleco Regions joining SPP or MISO and allocate the results among the Entergy Operating Companies. The methodology was reviewed with the ERSC Working Group. The Company would expect that the benefits for the EAI Region (as measured by CRA) would be different than the benefits for EAI (as calculated by ESI based on the detailed results of the CRA modeling of the EAI Region), and this is in fact what the results demonstrate. The table below highlights the requested components underlying each analysis. Please note that CRA “purchases” represent imports to the EAI Region and “sales” represent exports from the EAI Region. The analysis of “purchases” for EAI includes imports from other regions and purchases from IPP/QFs within the EAI Region. The analysis of “sales” for EAI includes exports to other regions.

10-011-U SS3944




CRA analysis of EAI Region joining SPP

Entergy analysis of EAI OPCO when EAI Region joins SPP

Generation -35 Generation -19

Purchases (Imports) -30 Imports & IPP purchases 3

Sales (Exports) 100 Exports 21

Wheeling costs 3 Wheeling costs 7

Wheeling revenues 58 Wheeling revenues 37

Trade Benefits 96 Trade Benefits 49

10-011-U SS3945




Response of: Entergy Arkansas, Inc. to the Twentieth Set of Data Requests of Requesting Party: Arkansas Public Service Commission General Staff Filed: 69/11


Question:

For the case in which EAI joins MISO, please list all reasons for the difference between EAI’s trade benefits as estimated in CRA’s original analysis and the same benefits calculated by Entergy in the Evaluation Report filed May 12, 2011 ($105 million per Attachment TA-4, page 1 of 15). For each reason listed, please provide an estimate of the magnitude of the change. Please itemize the components of these trade benefits results (components as specified in Exhibit 7, page 17).

Response:

CRA did not estimate the trade benefits of EAI joining MISO, it estimated the trade benefits of the EAI Region joining MISO. EAI’s load and generation represent only a portion of the total load and generation within the EAI Region. The task of determining what the costs and benefits for EAI’s customers would be from joining MISO was carried out by Entergy Services, Inc. (“ESI”), on behalf of the Entergy Operating Companies, who used the same methodology that was developed (at FERC’s directive) to take the results of the CRA s analysis of the Entergy and Cleco Regions joining SPP or MISO and allocate the results among the Entergy Operating Companies. The methodology was reviewed with the ERSC Working Group. ESI would expect that the benefits for the EAI Region (as measured by CRA) would be different than the benefits for EAI (as calculated by ESI based on the detailed results of the CRA modeling of the EAI Region), and this is in fact what the results demonstrate. The table below highlights the requested components underlying each analysis. Please note that CRA “purchases” represent imports to the EAI Region and “sales” represent exports from the EAI Region. The analysis of “purchases” for EAI includes imports from other regions and purchases from IPP/QFs within the EAI Region. The analysis of “sales” for EAI includes exports to other regions.

10-011-U SS3946




CRA analysis of EAI Region joining MISO

Entergy analysis of EAI OPCO when EAI Region joins MISO

Generation 454 Generation 68

Purchases (Imports) 159Imports & IPPpurchases

3

Sales (Exports) 298 Exports 68

Wheeling costs 54 Wheeling costs 10

Wheeling revenues 185 Wheeling revenues 118

Trade Benefits 128 Trade Benefits 105

10-011-U SS3947



EXHIBIT KDW‐Q



Response of: Entergy Arkansas, Inc. to the Thirteenth Set of Data Requests of Requesting Party: Attorney General’s Office Filed: 6/20/11

Question No.: AG 13-6 Part No.: Addendum:

Question:

Answer the following questions regarding the results of Entergy’s adaptation of Charles River Associates’ Cost-Benefit Analysis (CRA CBA) to estimate the trade benefits to Entergy Operating Companies (OpCos), as summarized at slide 5 of the presentation Entergy made at its May 26 Technical Conference in Little Rock, Arkansas:

a. Explain why the “Decrease in Adjusted Prod Costs” fell so much more between the “CRA Analysis” and the “OAA” of the “SPP” case than of the “MISO” case.

b. Explain why the “Decrease in Adjusted Prod Costs” for Entergy OpCos appears so similar in the “OAA” analysis of the “SPP” and the “MISO” cases.

c. Explain why the “Decrease in Adjusted Prod Costs” to entities other than the Entergy OpCos is apparently much higher in the “CRA Analysis” of the “SPP” case than the “MISO” case.

Response:

a. The Entergy Operating Companies were provided with the details from CRA’s analysis to estimate the production costs in each RTO scenario for the Operating Companies, not for other entities that operate within the Entergy Region. Based on this information, the OAA estimates that the production costs of the Entergy Operating Companies fall by a similar amount in the Join MISO case as compared to the Join SPP case. This result is not surprising given that one of the main benefits of joining an RTO -- whether MISO or SPP -- is the Day 2 Market benefit of an integrated commitment and dispatch of all resources located within the Entergy and Cleco Regions. The details of CRA’s analysis show that the impact on the Entergy Operating Companies’ resources is similar with regard to the amount of displacement of generation when the Entergy

10-011-U EC603



Question No.: AG 13-6

Operating Companies join either RTO. Subtracting the Entergy Operating Companies’ results from the CRA results for the Entergy Region indicates that the adjusted production costs of other entities within the Entergy Region (i.e. IPPs and other load-serving entities) fall by more under the Join SPP case than the Join MISO case. The Entergy Operating Companies do not have sufficient information from CRA to describe why the adjusted production costs of other entities within the Entergy Region fall by more under the Join SPP case than the Join MISO case.

b. See the response to (a) above.

c. See the response to (a) above.

10-011-U EC604



EXHIBIT KDW‐R



Response of: Entergy Arkansas, Inc. to the Twenty-Fourth Set of Data Requests of Requesting Party: Arkansas Public Service Commission General Staff Filed: 6/21/11


Question:

Do you expect that if EAI joins MISO, its wheeling rate for generation located within EAI and being delivered to SPP will be significantly greater than the current Entergy wheeling rate charged for this service?

Response:

The transmission wheeling rate applicable to generation EAI is selling into SPP would depend on the transmission service being taken. For example, the current OATT rate for monthly firm transmission service out of the Entergy Region is currently $1,540/MW-month. Equivalent service under the MISO OATT (Drive-Through and Out rate - Schedule 7) is currently $2,453/MW-month. This difference was captured in the CRA analysis by using a $3/MWh transmission wheeling charge for all “out” flows from the Entergy Region (including EAI) was used in the Status Quo case; and, a $5/MWh wheeling charge was used for all “out” flows from the MISO Region (including EAI only or all Entergy Operating Companies) in the “Join MISO” cases.

10-011-U LR16527



EXHIBIT KDW‐S


of 17






9. Referring to page 14-15, if EAI were to join MISO, you indicate that SPP would incur costs due to the expanded seams between SPP and MISO. Please indicate whether there would be any cost implications to EAI customers associated with this issue.

Response: An expanded and complex seam creates an increased administrative burden for

both SPP and MISO. EAI, as a part of MISO would be paying its share of this administrative cost. SPP would also have an increased administrative burden because of the expanded and complex seam, which would result in SPP customers, including those in Arkansas, facing an increased administrative cost as well.

Prepared by: Carl A. Monroe Submitted to: Diana Brenske, Arkansas Public Service Commission Staff Date: April 13, 2011


EXHIBIT KDW‐T


Strategic Transmission Projects –Screening with LMPs

Michael Schnitzer (on behalf of Entergy)(on behalf of Entergy)

February 17, 2011

1


AECC $47.66

2013 On-Peak

$47.66

OGE $38.78

SWPA $67.69

$65.93

$68.00

EAI $40.64

$57.67

$59.73

$61.80

$63.87

ELI$47 06

EMI$41.78AEPW

$37.58$49.40

$51.47

$53.53

$55.60

$47.06

CLECO

MS POWER $43.56

$41.13

$43.20

$45.27

$47.33

$42.77

EGSL$46.07

ETI $52.28

ETEC $53.61 $37.00

$39.07

5

ENO $49.42


AECC $53.79

2022 On-Peak

$53.79

OGE $52.58

SWPA $56.35

$64.07

$65.00

EAI $55.18

$60.33

$61.27

$62.20

$63.13

ELI$61 67

EMI$56.11AEPW

$51.23$56.60

$57.53

$58.47

$59.40

$61.67

CLECO

MS POWER $55.41

$52.87

$53.80

$54.73

$55.67

$56.19

EGSL$60.61

ETI $61.74

ETEC $64.83 $51.00

$51.93

6

ENO $64.26


AECC $35.71

2013 Off-Peak

$35.71

OGE $32.13

SWPA $39.10

$43.13

$44.00

EAI $34.13

$39.67

$40.53

$41.40

$42.27

ELI$37 57

EMI$34.88AEPW

$31.99$36.20

$37.07

$37.93

$38.80

$37.57

CLECO

MS POWER $36.96

$32.73

$33.60

$34.47

$35.33

$35.84

EGSL$37.95

ETI $42.25

ETEC $43.83 $31.00

$31.87

7

ENO $38.55


AECC $42.33

2022 Off-Peak

$42.33

OGE $40.01

SWPA $43.13

$53.93

$55.00

EAI $42.00

$49.67

$50.73

$51.80

$52.87

ELI$46 93

EMI$43.12AEPW

$39.75$45.40

$46.47

$47.53

$48.60

$46.93

CLECO

MS POWER $43.24

$41.13

$42.20

$43.27

$44.33

$44.45

EGSL$47.36

ETI $50.88

ETEC $54.14 $39.00

$40.07

8

ENO $48.90


EXHIBIT KDW‐U





Question:

What other responsibilities will EAI be shifting to MISO?

a. How will the settlement process work in the Day 2 Market? Will EAI remain a direct MISO market participant for settlement purposes? Will there be any adjustments made to MISO settlement numbers to account for any impacts of the other Entergy operating companies joining MISO? If there are adjustments made to the Day 2 Market settlement that MISO provides EAI, under what current or anticipated agreement or basis would they be made.

b. Please estimate the date at which MISO would take over responsibility for transmission planning of EAI transmission facilities and footprint. Which organization will have responsibility for EAI transmission planning until MISO takes over transmission planning responsibility for the EAI facilities? Please provide the department and reporting structure of the area that will have the interim responsibilities, clearly defining whether the responsibilities reside within EAI or another Entergy organization.

Response:

a. The settlement process would entail MISO rendering bills for each of the services enumerated in the MISO tariff to EAI individually because it is currently expected that EAI will join MISO as a separate load serving entity. It is expected that MISO will render a bill that lists the specific costs for which EAI will be responsible for, and that bill would not require adjustments related to the impacts of other Operating Companies or any other entity joining MISO.

10-011-U LR16537




b. MISO would assume responsibility for EAI’s transmission planning upon joining MISO. As discussed in more detail in the May 12, 2011 Evaluation Report, although the ultimate responsibility for transmission planning would lie with MISO, EAI and the other Operating Companies would continue to play a role in such planning, including, for example, developing projects to address the applicable reliability standards as part of MISO’s “bottom up” approach to reliability planning.

10-011-U LR16538



EXHIBIT KDW‐V

Not Used


EXHIBIT KDW‐W





Question:

Please provide more details on EAI’s role in MISO governance when EAI joins MISO.

a. Will EAI be an independent entity, or will Entergy Holding Company be the participating/voting member?

b. Which sector will EAI join?

c. Will the individuals participating in MISO governance and other committees on behalf of EAI be employed by EAI or would they be part of other Entergy organizations?

Response:

a.-c. These structural issues for participation in MISO have not been determined at this time.

10-011-U LR16536



EXHIBIT KDW‐X


AP

SC

FILED

Time: 6/7/2011 8:10:01 A

M: R

ecvd 6/6/2011 8:48:59 PM

: Docket 10-011-U

-Doc. 401


EXHIBIT KDW‐Y


ENTERGY ARKANSAS, INC.

ARKANSAS PUBLIC SERVICE COMMISSION Docket No. 10-011-U

Response of: Entergy Arkansas, Inc. to the Twelfth Set of Data Requests of Requesting Party: Arkansas Public Service Commission General Staff

Filed: 3/17/11 Question No.: STAFF 12-1 Part No.: Addendum: Question: Please provide a copy of the Power Coordination, Interchange, and Transmission Service Agreement (PCITSA) with AECC and provide the following: a. EAI’s or Entergy’s current plans for terminating or extending this agreement beyond 2018. b. Any reports or analyses conducted by or for EAI or Entergy on the historical or projected benefits and costs of the PCITSA. c. Any reports or analyses conducted by or for EAI or Entergy on the benefits and costs of terminating the PCITSA. Response:

a. Consistent with Article IX, Section 3 in the attached Power Coordination, Interchange and Transmission Service Agreement (PCITSA), EAI currently plans to exercise its right to terminate the agreement at the earliest time provided for by the agreement.

b. See the record for FERC Docket No. EL05-15.

c. See EAI’s response to (b) above.

10-011-U STAFF 12-1 TH616


EXHIBIT KDW‐Z


of 33





2-6) Provide the following information regarding the reference in the March 18, 2011, Supplemental Direct Testimony of Carl A. Monroe at 10:7 to“…the seven connections between SPP and EAI ”:

a. Describe and identify with particularity the specific connections being referenced in this phrase.

Response:The seven connections between SPP and EAI are identified in Columns B-F and L of the spreadsheet attached hereto as Exhibit 1.

b. Provide a map showing the locations of these specific connections identified in sub-part ‘a’ above and identify the entities that own or manage such facilities and the related scheduling or transmission rights.

Response:Maps showing the locations of these specific connections identified in sub-part ‘a’ above and the entities that own or manage such facilities and the related scheduling or transmission rights are attached hereto as Exhibits 6-8.

c. State the individual transfer capacity transfer capability between SPP and EAI of each connection identified in sub-part ‘a’ above.

Response:The individual capacity between SPP and EAI of each connection identified in sub-part ‘a’ above is set forth in Column M of the spreadsheet attached hereto as Exhibit 1.


of 33

d. State the aggregate transfer capability between SPP and EAI of the combined connections identified in sub-part ‘a’ above.

Response:The aggregate capability between SPP and EAI of the combined connections identified in sub-part ‘a’ above is 3196 MW, as set forth in Column M, line 130 of the spreadsheet attached hereto as Exhibit 1.



EXHIBIT KDW‐AA


of 30






21) If EAI does not join SPP:

a. Is it feasible for any of the other Entergy Operating Companies to Join SPP?

Response: Yes, it is based on the transmission connections that are available from the SPP transmission system to the other Entergy Operating Companies.

b. How would the economic benefits of joining SPP be affected for the other Entergy Operating Companies?

Response:No analysis was performed to determine the benefit to the other Entergy Operating Companies, if EAI does not join SPP.

c. How would the planning and operating requirements change for the other Entergy Operating Companies that join SPP?

Response:SPP has not completed any analyses to determine how planning and operating requirements would be affected under these potential scenarios. The planning and operating requirements will depend upon which of the Entergy Operating Companies joined SPP and that will be a function of timing and the details of the desired integration.



EXHIBIT KDW‐BB


c. Regulating Reserves must be fully deployable both upward and downward within 5minutes.

Regulating Reserves must be able to respond to ICCP setpoint instructions.

Contingency Reserves must be fully deployable within 10 minutes. Spinning Contingency Reserves must be able to respond to ICCP setpoint instructions, or XML instructions if they are a DRR Type 1 resource. Supplemental Contingency Reserves must be able to respond to XML instructions.

Further clarification of capacity requirements is available in MISO Tariff – Module E Resource Adequacy, which can be found at https://www.midwestiso.org/Library/Tariff/Pages/Tariff.aspx

21-15. Please describe how the MISO transmission cost allocation process will be conducted for the Entergy Operating Companies that join MISO, under the follow scenarios: a. All Entergy Operating Companies join MISO; b. Only EAI joins MISO; c. EAI does not join MISO, all other Entergy Operating Companies join MISO;

Response: Currently in MISO there are five cost allocation methodologies utilized to share in the cost of transmission investment: participant funded, Generation Interconnection Project, Market Efficiency Project, Baseline Reliability Project, and Multi Value Project. The type of cost allocation method assigned to a transmission project will depend on the business case of that project to assure that the allocation of costs is commensurate with expected benefits.The MISO Cost Allocation process is applied the same way to all MISO members. So, in all three scenarios described in question 21-15 the transmission cost allocation process will be conducted in the same way, the only difference would be the size of the footprint that the cost allocation is applied to.

21-16. If EAI does not join MISO: a. Is it feasible for any of the other Entergy Operating Companies to Join MISO? b. How would the economic benefits of joining MISO be affected for the other Entergy Operating Companies? c. How would the planning and operating requirements change for the other Entergy Operating Companies that join MISO?

Response:a. Yes, it is still feasible for other Entergy Operating Companies to join MISO.


b. If a sufficient transmission path were maintained between MISO and the other Entergy Operating Companies, the economic benefits would only be minimally impacted due to the difference in scale of the market with and without EAI.

If no transmission path were maintained between MISO and the other Entergy Operating Companies, there would be a significant impact on economic benefits. From a market perspective, the other Entergy Operating Companies would be “islanded” from the rest of the MISO system and hence would be operated as a separate commitment and dispatch pool. The “islanded” region would see benefits from operating all assets in the region as a single commitment and dispatch pool, as opposed to several (the multiple balancing areas) that currently exist in the region. However, this condition would likely only exist for a short period of time, as the economics would quickly drive for the creation of a transmission connection between the regions which would enable a single commitment and dispatch. This transmission connection could be achieved through reservations on an existing path or construction of new transmission between the areas.

c. Please refer to the answer provided above in 21-16b.

21-17. Based on MISO’s presentation to the Entergy Regional State Committee on May 19 20 entitled “Presentation to Entergy Regional State Committee” (slide 10): a. How long will the transition period be during which Entergy or EAI will not be responsible for MVPs at all? b. What specific requirements must be met for the MISO North and South regions

to be declared to have met “comparability requirements” during the transition period? Please define and provide any analyses of comparability requirements in MISO’s possession. c. If there is congestion in the Northern MISO region, will Entergy be allocated transmission costs to relieve such congestion?

Response:a. The transition period will last a minimum of 5 and a maximum of 10 years. During

that time Entergy will not receive any costs associated with MVP’s.

b. The comparability assessment ultimately is about ensuring that the transmission investment profiles of the Northern and Southern Planning Regions are on an equal footing on a going forward basis. Basically, comparability seeks to avoid inappropriate wealth transfers between the two Planning Regions. Comparability is achieved by planning and building both systems based on common reliability, market efficiency, and MVP planning criteria. The common application of these criteria in an open and transparent manner through an Order No. 890-compliant planning process should ensure the systems are sufficiently comparable to enable the combined Planning Regions to move forward as a single system.


EXHIBIT KDW‐CC


EXHIBIT KDW‐DD


ENTERGY ARKANSAS, INC.ARKANSAS PUBLIC SERVICE COMMISSION

Docket No. 10-011-U

Response of: Entergy Arkansas, Inc. to the First Set of Data Requests of Requesting Party: Arkansas Public Service Commission General Staff Ending Sequence No.


Question:

The “Regional Transmission Organization Frequently Asked Questions” available from Entergy’s website (http://entergy.com/rto/faq.pdf) states “The Evaluation Report explains that this level of production cost benefits from QFs would likely be realized in a Day 2 market even absent formal abolition of the QF put right”. Does Entergy anticipate that its obligation to accept QF put will cease upon all the OpCos joining MISO? If all the OpCos joined SPP instead, would Entergy anticipate its obligation to accept QF put would cease?

Response:

Joining an RTO will not terminate the obligation to accept QF puts. That obligation can only be terminated upon an order of the FERC. Regardless of whether QFs continue to have the option of putting energy to the Operating Companies, the Operating Companies’ customers can benefit from participating in MISO’s Day 2 Market, particularly if the calculation of avoided cost is revised to reflect MISO settlement charges including QF-specific LMPs. This would provide an incentive for QFs to submit bids or schedules to the RTO’s day ahead market.

Even without any revisions to the avoided cost calculation, however, the MISO RTO operates a single Balancing Authority and provides ancillary services to it, and the size and diversity of energy swings in that market would reduce the need for and cost of maintaining reserves to mitigate the effect of swings in the delivery of QF put energy. This opportunity to reduce the effect of swings in unscheduled QF put energy on the Operating Companies’ customers is more readily available in the MISO Day 2 Market than in the current SPP RTO, which has neither a day ahead market nor a consolidated Balancing Authority. At such point as SPP has an established Day 2 Market, then one would expect the opportunity would be similar.


EXHIBIT KDW‐EE


ENTERGY ARKANSAS, INC.ARKANSAS PUBLIC SERVICE COMMISSION

Docket No. 10-011-U

Response of: Entergy Arkansas, Inc. to the First Set of Data Requests of Requesting Party: Arkansas Public Service Commission General Staff Filed: 6/6/11


Question:

The “Regional Transmission Organization Frequently Asked Questions” available from Entergy’s website (http://entergy.com/rto/faq.pdf) states “To the extent that local regulators modify the avoided cost rate to reflect the QFs’ effect on the MISO net charges to the EOCs, this should provide an incentive for QFs to schedule or bid in the RTO day-ahead energy market, or enter into bilateral contracts.”

a. Which local regulators would need to modify their avoided cost rates in order to incent QFs to bid into the day-ahead market?

b. On what timeline does Entergy anticipate this regulatory change could happen?

c. If approved, how long after all the Entergy OpCos join MISO does Entergy anticipate it will receive all the expected QF benefits?

d. If the Entergy OpCos joined SPP instead of MISO, would the timing discussed in parts b and c differ? If so, how?

Response:

a. The APSC, LPSC, and PUCT.

b. No decision has been made on this.

c. The benefits associated with the change in the avoided cost calculation would be realized when that change is implemented. Other benefits of a Day 2 Market would be realized upon entry to that market. As explained in response to STAFF 18-14, certain benefits associated with QF puts would be realized as a result of the fact that the MISO would be responsible for ancillary services.

d. See EAI’s response to STAFF 18-14.


EXHIBIT KDW‐FF


ENTERGY ARKANSAS, INC.

ARKANSAS PUBLIC SERVICE COMMISSION Docket No. 10-011-U MISO Transition Discovery

Response of: Entergy Arkansas, Inc. to the Thirteenth Set of Data Requests of Requesting Party: Attorney General’s Office Filed: 6/20/11 Question No.: AG 13-8 Part No.: Addendum: Question: Provide the following information regarding each of the EAI contracts with Qualifying Facilities (“QFs”) identified in response to EAI’s response to Attorney General Data Request 6-4: a. When does each of these EAI QF contracts expire? b. If the FERC provides EAI relief from the requirement to enter new QF contracts pursuant to Section 210(m) of the Public Utility Regulatory Policies Act (i.e., the “QF Put” obligation) before the above expiration dates, does EAI believe it would have a requirement to enter a new QF contract with such QFs? If so, please explain why EAI believes it would have such a requirement. c. Has EAI had discussions with any of the owners of these projects regarding the extension or renegotiation of the current QF contract and/or the negotiation of a new “non-QF” contract? If so, please summarize the status of these discussions, including specific terms regarding contract capacity, delivery flexibility and pricing. Response: This response contains Highly Sensitive Protected Information and is being provided pursuant to the Arkansas Public Service Commission’s Interim Protective Order No. 4 in this Docket dated February 24, 2010.

a. The terms and conditions regarding the expiration of the contracts are set forth in the highly sensitive attachment.

b. No. c. Cross Oil: No

Pine Bluff Energy: No

10-011-U AAG 13-8 TH846



Potlatch-Forest: No

Little Rock Wastewater Utility: No

Bean Lumber Con Inc.: n/a Company closed; QF terminated on 10/22/2010

West Fraser (International Paper Co.): No

10-011-U AAG 13-8 TH847


ENTERGY ARKANSAS, INC. ARKANSAS PUBLIC SERVICE COMMISSION

DOCKET NO. 10-011-U

DATE REQUESTED: June 3, 2011 DATE PROVIDED: June 20, 2011 DATA REQUEST: AAG 13-8 REQUESTING PARTY: Attorney General COMPANY CONTACT: Tucker Raney [email protected] 501-377-4372

CONFIDENTIAL INFORMATION COVER SHEET

Requested Information Company’s Response 1. Document Title Attachment 1 (summarizing QF contracts) 2. Description of the document

containing the Confidential Information

Summary of contract information for EAI contracts with certain Qualifying Facilities.

3. Identification of each item of Confidential Information contained in the document

All of the information in the above-cited exhibit is Highly Sensitive Protected Information.

4. The applicable category of Confidential Information listed in the IPO under which each item of the Confidential Information falls

The information meets part 2 of the standard definition of HSPI in the IPO and Category (O) for contracts containing explicit confidentiality provisions including, but limited to, competitively sensitive negotiated contract prices and terms.

5. A description of why the Confidential Information within the document should be protected including the Company’s reasons for claiming that each item of the Confidential Information is consistent with the description provided by the Company in its request for an IPO

6. A description of why any specific item of Confidential Information identified above is claimed by the Company to be Highly Sensitive Protected Information (HSPI) and how such Confidential Information fits within the Commission’s definition of HSPI

The document is designated as HSPI because it includes contractual information pertaining to contracts that specify that the terms of the contract are confidential, which meets part 2 of the standard definition of HSPI in the IPO in this Docket as well as Category O. The release of this information to EAI’s competitors would result in competitive damage to EAI and, ultimately, to Arkansas retail ratepayers and would violate the terms of the contract.

10-011-U AAG 13-8 TH848


7. Has the Confidential Information been previously disclosed? If so, when and in what context?

No

8. What is the period of time that the Confidential Information should remain confidential?

Indefinitely.

9. Have both a redacted and non-redacted version of the document containing the Confidential Information been provided?

No

10-011-U AAG 13-8 TH849


EXHIBIT KDW‐GG



Response of: Entergy Arkansas, Inc. to the Twelfth Set of Data Requests of Requesting Party: Attorney General’s Office Filed: 6/8/11


Question:

Provide the following information regarding the statements made in the document titled “Frequently Asked Questions” that Entergy Louisiana, Inc. and Entergy Gulf States, Inc. filed with the Louisiana Public Service Commission (“LPSC”) on May 12, 2011, in LPSC in Docket No. U-28155:

a. Provide documentation for the statement that “…the main benefit in both scenarios came from the application of the Day 2 market to the commitment and dispatch of generation in the Entergy footprint, not from importing cheaper power from elsewhere”, in which “both scenarios” referred to the MISO scenario and the SPP scenario (Question 1).

b. Explain, and provide detailed example(s) of, how “…current MISO settlement rules reflect those costs”, where “those costs” refers to “…all the costs associated with those unscheduled or uninstructed injections of energy” from Qualifying Facilities (Question 18).

Response:

a. See the attached workpaper. The information in blue comes from CRA Attachment 1 information. This information was included in the workpapers provided with the May 12 Evaluation Report (see the “[Year] Trade Benefits” tabs of “HSPM_ESI_Analysis_Att A Ent-Cle Join SPP Big Pool Costs-Benefits.xlsx” for Join SPP information, “HSPM_ESI_Analysis_Att A Ent-Cle Join MISO Costs-Benefits Summary.xlsx” for Join MISO information, “HSPM_ESI_Analysis_Att A EAI Only in SPP Big Pool Costs-Benefits Summary.xlsx” for SPP Status Quo information, and “HSPM_ESI_Analysis_Att A EAI Only in MISO Costs-Benefits Summary.xlsx” for MISO Status Quo information).

b. The MISO settlement rules reflect the cost imposed by unscheduled or uninstructed energy. For instance, in certain cases MISO commits units after the day ahead market to ensure that there is sufficient capacity available to

10-011-U AG 12-13 SS3902




ensure reliability. If one of these units does not fully recover fuel and other variable costs expended during the commitment period, then MISO will issue a “make whole payment” to ensure the unit does not operate unprofitably. These make whole payments are recovered through “real time revenue sufficiency guarantee charges,” which in some cases are assessed on generators whose output deviates significantly from setpoint instructions.

Another example includes what is referred to as the “real time excessive deficient energy deployment charge.” Under this charge, a resource which deviates by more than 4% from the level instructed by MISO for four consecutive five minute intervals will be assessed a regulation charge.

The “real time revenue sufficiency guarantee” and “real time excessive deficient energy deployment” charges are examples of MISO settlement rules which reflect the cost imposed by unscheduled or uninstructed energy, and which if incorporated into avoided cost rates, should provide an incentive for QF facilities to follow dispatch instructions.

10-011-U AG 12-13 SS3903



EXHIBIT KDW‐HH



Response of: Entergy Arkansas, Inc. to the Thirteenth Set of Data Requests of Requesting Party: Attorney General’s Office Filed: 6/20/11


Question:

In response to Question 18 of the document titled “Frequently Asked Questions” that Entergy Louisiana, Inc. and Entergy Gulf States, Inc. filed with the Louisiana Public Service Commission (“LPSC”) on May 12, 2011, in LPSC in Docket No. U-28155, Entergy said “Entergy believes the current MISO settlement rules reflect those costs”, where “those costs” referred to “…all the costs associated with those unscheduled or uninstructed injections of energy” from Qualifying Facilities. Please state:

a. Whether Entergy believes that the SPP’s current market settlement rules reflect such costs. Explain why or why not Entergy believes this to be the case.

b. Whether Entergy believes the SPP’s settlement rules expected to be adopted pursuant to SPP’s Integrated Marketplace (i.e., its “Day 2” market) will reflect such costs. Explain why or why not Entergy believes this to be the case.

Response:

a. The first part of the response to Question 18 of the “Frequently Asked Questions” states, “The CRA studies assumed that if the Operating Companies join a Day 2 RTO, the level of energy provided by QFs would not change, but that QFs would schedule the energy in the Day Ahead market.” The current SPP market structure does not include a Day Ahead Market. That is significant because the basis of the projected QF savings in the Day 2 Market is not the change in avoided cost payments to reflect the Day 2 settlements; it is that the change in avoided cost payments provides the QFs with an incentive to schedule their energy in the Day Ahead Market. By scheduling the QF deliveries in the Day Ahead Market, the Day Ahead unit commitment of other generation changes – (a) it takes the QF deliveries into account and (b) it does not have to provide flexible capability specifically to deal with that amount of QF put.

10-011-U EC605




SPP does not currently have a Day Ahead Market. Changing the avoided cost calculation to reflect SPP’s current market settlement charges would not cause QFs to schedule their put quantity in an SPP Day Ahead Market, because one does not exist. Further, if the Entergy Operating Companies were to join the SPP Day 1 Market, they would continue to be a separate Balancing Authority responsible for their own unit commitment and provision of ancillary services and flexible capability to deal with any QF puts. Under the current SPP market structure, not only would the QF put not move to a Day Ahead Market, the Entergy Operating Companies would continue to be responsible for ensuring that enough flexible capability is present to deal with swings in QF energy.

b. Even though SPP’s Day 2 Market is still under development, there is no reason to believe that the settlements in SPP’s Integrated Marketplace, if reflected in avoided cost calculations, would create any different incentives for QFs than the MISO settlements. CRA modeled the QFs in the same manner in both the “Join MISO” and “Join SPP” cases that were the basis of its Cost-Benefit analysis and that were subsequently used to determine benefits in Entergy’s May 12 Evaluation Report.

10-011-U EC606



apsc filed time: 7/12/2011 10:30:53 am: recvd 7/12/2011 … · n1 staff‐eai 18‐24 other bas...

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