Upload
trinhkhanh
View
215
Download
2
Embed Size (px)
Citation preview
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
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
134/20/2011 MISO Response to 4/5/2011 AR AG's First Set of Data Requests: 001480
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
-1600
-1100
-600
-100
400
900
-5000 -4000 -3000 -2000 -1000 0 1000 2000 3000 4000 5000
<- Transaction from MISO to Entergy
Tie
Line
s Flo
w fr
om E
nter
gy to
MIS
O -
>
_________________________________________________________________________________________________ <-Ti
e Li
nes (
2 Tr
ansf
orm
ers)
Lim
it (1
500M
VA)
-------------------------------------------------------------------------------------------------------------------------------------------------- <-M
ISO
/Ent
ergy
Allo
catio
n on
tie
Line
s (1
000M
VA)
Transaction from Entergy to MISO ->
<-Ti
eLi
nes F
low
from
MIS
O to
Ent
ergy
Economic Transaction and Tie Line Flow Chart: From 2010 Entergy In MISO Case
144/20/2011 MISO Response to 4/5/2011 AR AG's First Set of Data Requests: 001481
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
-1600
-1100
-600
-100
400
900
-6000 -4000 -2000 0 2000 4000 6000
<- Transaction from MISO to Entergy
Tie
Line
s Flo
w fr
om E
nter
gy to
MIS
O -
>
_________________________________________________________________________________________________ <-Ti
e Li
nes (
2 Tr
ansf
orm
ers)
Lim
it (1
500M
VA)
-------------------------------------------------------------------------------------------------------------------------------------------------- <-M
ISO
/Ent
ergy
Allo
catio
n on
tie
Line
s (1
000M
VA)
<-Ti
eLi
nes F
low
from
MIS
O to
Ent
ergy
Transaction from Entergy to MISO ->
Economic Transaction and Tie Line Flow Chart: From 2020 Entergy In MISO Case
154/20/2011 MISO Response to 4/5/2011 AR AG's First Set of Data Requests: 001482
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
-1600
-1100
-600
-100
400
900
-6000 -5000 -4000 -3000 -2000 -1000 0 1000 2000 3000 4000 5000
<- Transaction from MISO to Entergy
Tie
Line
s Flo
w fr
om E
nter
gy to
MIS
O -
>
_________________________________________________________________________________________________ <-Ti
e Li
nes (
2 Tr
ansf
orm
ers)
Lim
it (1
500M
VA)
-------------------------------------------------------------------------------------------------------------------------------------------------- <-M
ISO
/Ent
ergy
Allo
catio
n on
tie
Line
s (1
000M
VA)
<-Ti
eLi
nes F
low
from
MIS
O to
Ent
ergy
Transaction from Entergy to MISO ->
Economic Transaction and Tie Line Flow Chart: From 2015 Entergy In MISO Case
284/20/2011 MISO Response to 4/5/2011 AR AG's First Set of Data Requests: 001494
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‐B
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 1 of 6
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.
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 2 of 6
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
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 3 of 6
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 4-2) 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
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 4 of 6
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.
Prepared by: Carl A. Monroe, Executive Vice President and Chief Operating Officer Submitted to: Shawn McMurray, Senior Assistant Attorney General Date: June 2, 2011
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 5 of 6
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 4-3) 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-
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 6 of 6
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.
Prepared by: Carl A. Monroe, Executive Vice President and Chief Operating Officer Submitted to: Shawn McMurray, Senior Assistant Attorney General Date: June 2, 2011
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‐C
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 26 of 33
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-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.
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 27 of 33
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.
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 28 of 33
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
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‐D
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
174/20/2011 MISO Response to 4/5/2011 AR AG's First Set of Data Requests: 001484
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Loop Flow Through Other Regions for MISO to Entergy Economic Transactions
Loop Flow Through Other Regions for Entergy to MISO Economic Transactions
-4000
-3000
-2000
-1000
0
1000
2000
3000
4000
5000
123
847
571
294
911
8614
2316
6018
9721
3423
7126
0828
4530
8233
1935
5637
9340
3042
6745
0447
4149
7852
1554
5256
8959
2661
6364
0066
3768
7471
1173
4875
8578
2280
5982
9685
33
Flow
(MW
)
Hours
Max: 3936 MW
Max: 3450 MW
Loop Flow Duration Curve: From 2010 Entergy In MISO Case
18
4/20/2011 MISO Response to 4/5/2011 AR AG's First Set of Data Requests: 001485
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
-5000
-4000
-3000
-2000
-1000
0
1000
2000
3000
4000
5000
123
947
771
595
311
9114
2916
6719
0521
4323
8126
1928
5730
9533
3335
7138
0940
4742
8545
2347
6149
9952
3754
7557
1359
5161
8964
2766
6569
0371
4173
7976
1778
5580
9383
3185
69
Flow
(MW
) Hours
Loop Flow Through Other Regions for MISO to Entergy Economic Transactions
Loop Flow Through Other Regions for Entergy to MISO Economic Transactions
Loop Flow Duration Curve: From 2020 Entergy In MISO Case
Max: 4497 MW
Max: 4315 MW
4/20/2011 MISO Response to 4/5/2011 AR AG's First Set of Data Requests: 001486
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
-5000
-4000
-3000
-2000
-1000
0
1000
2000
3000
4000
5000
123
847
571
294
911
8614
2316
6018
9721
3423
7126
0828
4530
8233
1935
5637
9340
3042
6745
0447
4149
7852
1554
5256
8959
2661
6364
0066
3768
7471
1173
4875
8578
2280
5982
9685
33
Flow
(MW
)
Hours
Loop Flow Through Other Regions for MISO to Entergy Economic Transactions
Loop Flow Through Other Regions for Entergy to MISO Economic Transactions
Loop Flow Duration Curve: From 2015 Entergy In MISO Case
Max: 3725MW
Max: 4155MW
29
4/20/2011 MISO Response to 4/5/2011 AR AG's First Set of Data Requests: 001495
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‐E
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 1 of 18
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. 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
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‐E1
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 9 of 18
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. RESPONSES TO DATA REQUEST APSC-019
INFORMATION REQUESTED:
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
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 10 of 18
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.
Prepared by: Carl A. Monroe Submitted to: Diana Brenske, Arkansas Public Service Commission Staff Date: June 6, 2011
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‐E2
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
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‐F
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
ENTERGY ARKANSAS, INC.ARKANSAS PUBLIC SERVICE COMMISSION Docket No. 10-011-U MISO Transition Discovery
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
APSC FILED Time: 6/9/2011 4:35:28 PM: Recvd 6/9/2011 4:31:16 PM: Docket 10-011-U-Doc. 428
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
APSC FILED Time: 6/9/2011 4:35:28 PM: Recvd 6/9/2011 4:31:16 PM: Docket 10-011-U-Doc. 428
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‐G
Not Used
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‐H
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 51 of 58
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. RESPONSES TO DATA REQUEST APSC-011
INFORMATION REQUESTED:
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
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‐I
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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.
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‐J
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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 :
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
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‐K
Not Used
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‐L
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
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‐M
APSC 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 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:–
Mod
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
Tran
smis
sion
O
pera
tions
gp
g(
ypr
oces
ses
and
IT re
quire
men
ts)
Se
t-up
LBA
and
inte
rfac
e w
ith M
ISO
–M
odify
EM
S ,
depl
oy A
lsto
m m
odul
e , d
evel
op a
nd te
st
inte
rface
with
MIS
O–
Oth
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
MIS
O p
roce
dure
s
Prep
are
cuto
ver
Pl
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
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
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
E
xten
ded
regu
lato
ry li
tigat
ion
R
even
ue c
lass
met
erin
g fo
r gen
erat
ion
P
ost 2
013
trans
ition
cos
ts
Mai
n co
st d
river
s in
clud
e
MIS
O in
terfa
ce c
osts
1
IT
Har
dwar
e an
d su
ppor
t
Set
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
s
42
50
17
536FE
RC
filli
ng c
osts
Mai
n co
st d
river
s in
clud
e
MIS
O in
terfa
ce c
osts
1
&
Mai
n co
st d
river
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
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+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
O p
roce
dure
s–
Com
plet
e ne
w s
taff
need
ed fo
r EA
I gen
erat
ions
ope
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
OPC
Os)
and
new
con
trol
are
a (R
est o
f ETR
OPC
Os)
Tr
ansm
issi
on m
eter
ing
stud
y, if
requ
ired
purc
hase
and
inst
all
new
met
erin
g eq
uipm
ent f
or n
ew s
yste
ms
ties
Se
t-up
EAI L
BA
and
its
inte
rfac
e w
ith M
ISO
–S
epar
ate
EM
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 –
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
S,
Tran
smis
sion
O
pera
tions
,g
y,
and
deve
lop
disp
lays
–O
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
OPC
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
Ope
ratio
ns
Key
Mile
ston
e:
10-011-U STAFF 18-3 Add 2 KH23
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
Path
1+2
est
imat
ed tr
ansi
tion/
impl
emen
tatio
n co
sts
Mai
ntai
ning
Pat
hs re
sults
in ~
$30M
incr
emen
tal c
osts
; mos
t inc
urre
d in
late
201
2 an
d 20
13
131
19
US
$3(M
)
150
1
Mai
n co
st d
river
s in
clud
e
Add
ition
al h
iring
nee
ds
IT H
ardw
are
and
supp
ort
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
s
104
131
19
24
1
125
100
811
Mai
n co
st d
river
s in
clud
e
Mai
n co
st d
river
s in
clud
e
Labo
r (S
PO
/OpC
os)
E
xter
nal C
onsu
ltant
s
gy
E
xten
ded
regu
lato
ry li
tigat
ion
R
even
ue c
lass
met
erin
g fo
r gen
erat
ion
P
ost 2
013
trans
ition
cos
ts
53
24
20
510
0 75
11
Mai
n co
st d
river
s in
clud
e
Ext
erna
l Reg
./Leg
al
supp
ort
M
ISO
inte
rface
cos
ts1
IT
Har
dwar
e &
sup
port
La
bor (
SP
O/O
pCos
) –
incl
udin
g hi
ring
Mai
n co
st d
river
s in
clud
e
MIS
Oin
terfa
ceco
sts1
Mai
n co
st d
river
s in
clud
e
Met
erin
g
Add
ition
al h
iring
nee
ds
Set
ting
up B
A it
self
IT
Har
dwar
e an
d su
ppor
t
55
4217
536
50
2011
supp
ort
La
bor (
SP
O/O
pCos
)
FER
C fi
lling
cos
ts
Mai
n co
st d
river
s in
clud
e
MIS
O in
terfa
ce c
osts
1
ITH
dd
t
M
ISO
inte
rface
cos
ts1
IT
Har
dwar
e &
sup
port
La
bor (
SP
O/O
pCos
)–
incl
udin
g hi
ring
55
37
Tran
smis
sion
Com
mer
cial
Pat
h1+
2B
ack-
offic
eR
egul
ator
yC
omm
sP
MO
/Oth
er2
Gen
erat
ion
25 0B
ack-
Gen
erat
ion
Path
1Tr
ansm
issi
on2013
2012
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 an
d su
ppor
t
Set
ting
up th
e LB
A
Labo
r (S
PO
/OpC
os)
–in
clud
ing
hirin
g
Page
11
Tran
smis
sion
Ope
ratio
nsC
omm
erci
al
and
Lega
l Ag
reem
ents
Path
1+2
to
tal c
ost
Bac
kof
fice
Ope
ratio
nsR
egul
ator
y C
oord
inat
ion
Com
ms.
P
MO
/Oth
erG
ener
atio
nO
pera
tions
Bac
kof
fice
OP
Sop
tiona
lity
cost
Gen
erat
ion
OP
Sop
tiona
lity
cost
Path
1
tota
l cos
tTr
ansm
issi
on
OP
Sop
tiona
lity
cost
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 KH24
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
Path
1+3
est
imat
ed tr
ansi
tion/
impl
emen
tatio
n co
sts
Mai
ntai
ning
Pat
hs re
sults
in ~
$20M
incr
emen
tal c
osts
; mos
t inc
urre
d in
late
201
2 an
d 20
13
US
$3(M
)
150
Mai
n co
st d
river
s in
clud
e
Add
ition
al h
iring
nee
ds
IT H
ardw
are
and
supp
ort
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
s12
51
1412
5
100
246
104
11M
ain
cost
driv
ers
incl
ude
Mai
n co
st d
river
s in
clud
e
Labo
r (S
PO
/OpC
os)
E
xter
nal C
onsu
ltant
s
gy
E
xten
ded
regu
lato
ry li
tigat
ion
R
even
ue c
lass
met
erin
g fo
r gen
erat
ion
P
ost 2
013
trans
ition
cos
ts
5020
75100
245
11
Mai
n co
st d
river
s in
clud
e
Ext
erna
l Reg
./Leg
al
supp
ort
M
ISO
inte
rface
cos
ts1
IT
Har
dwar
e &
sup
port
La
bor (
SP
O/O
pCos
) –
incl
udin
g hi
ring
Mai
n co
st d
river
s in
clud
e
MIS
Oin
terfa
ceco
sts1
Mai
n co
st d
river
s in
clud
e
Met
erin
g
Add
ition
al h
iring
nee
ds
Set
ting
up B
A it
self
IT
Har
dwar
e an
d su
ppor
t
42
550
17
36
2011
supp
ort
La
bor (
SP
O/O
pCos
)
FER
C fi
lling
cos
ts
Mai
n co
st d
river
s in
clud
e
MIS
O in
terfa
ce c
osts
1
ITH
dd
t
M
ISO
inte
rface
cos
ts1
IT
Har
dwar
e &
sup
port
La
bor (
SP
O/O
pCos
)–
incl
udin
g hi
ring
5137
Pat
h1+
3Tr
ansm
issi
onR
egul
ator
yG
ener
atio
n
25 0Tr
ansm
issi
onB
ack-
Com
mer
cial
Com
ms
Gen
erat
ion
PM
O/O
ther
2Pa
th1
Bac
k-of
fice
2012
2013
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 an
d su
ppor
t
Set
ting
up th
e LB
A
Labo
r (S
PO
/OpC
os)
–in
clud
ing
hirin
g
Page
16
Pat
h 1+
3 to
tal c
ost
Tran
smis
sion
O
PS
optio
nalit
y co
st
Reg
ulat
ory
Coo
rdin
atio
nG
ener
atio
n O
pera
tions
Tran
smis
sion
O
pera
tions
Bac
kof
fice
OP
Sop
tiona
lity
cost
Com
mer
cial
an
d Le
gal
Agre
emen
ts
Com
ms.
G
ener
atio
n O
PS
optio
nalit
y co
st
PM
O/O
ther
Path
1
tota
l cos
tB
ack
offic
eO
pera
tions
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 KH29
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+2+
3 (I/
II)
Focu
s on
add
ition
al a
ctiv
ities
to m
aint
ain
optio
nalit
y on
top
of P
ath
1
Bi
tti
ti
ftd
t
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
nsfo
r
B
egin
con
trac
ting
proc
ess
to a
cqui
re n
ew s
oftw
are
and
syst
ems
–M
ake
sure
EA
I per
spec
tive
is in
clud
ed
Mod
ify G
ener
atio
n sy
stem
s an
d pr
oced
ures
–S
epar
ate
GM
S p
latfo
rm fo
r EA
I and
Res
t of E
TR O
PC
Os
–D
uplic
ate
real
-tim
e op
erat
ions
pro
cedu
res
and
proc
esse
s–
Mod
ify fo
reca
st m
odel
and
pro
cedu
res
for E
AI
–Ad
just
oth
er m
odel
s pr
oced
ures
and
pro
cess
es, e
.g. W
PP
, an
dm
onth
lyen
ergy
plan
and
prod
uctio
nco
stm
odel
Ope
ratio
ns fo
r R
TO p
roje
ctan
d m
onth
ly e
nerg
y pl
an, a
nd p
rodu
ctio
n co
st m
odel
–
Dep
loy
Als
tom
mod
ule
for E
AI
–C
reat
e an
d te
st E
MS
inte
rface
with
MIS
O fo
r EA
I –
Dev
elop
FTR
/AR
R, L
oad
bidd
ing
and
Gen
offe
ring
tool
ing
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
nd tr
ain
staf
f for
new
EA
I pro
cedu
res
Pr
epar
e cu
tove
r
Tr
ansm
issi
on m
eter
ing
stud
y, if
requ
ired
purc
hase
and
in
stal
l new
met
erin
g eq
uipm
ent f
or n
ew s
yste
ms
ties
H
ire a
nd tr
ain
new
sta
ff to
ope
rate
EAI
BA
Se
t-up
two
BA
s an
d m
odify
pro
cedu
res
for n
ew c
ontr
ol
area –
Sep
arat
e E
MS
for E
AI a
nd R
est o
f ETR
OP
CO
sD
fil
tili
tf
ti
dd
fTr
ansm
issi
on
Ope
ratio
ns
–D
efin
e el
ectri
cal i
nter
face
, met
erin
g an
d pr
oced
ures
for
sepa
ratio
n of
EAI
and
con
figur
e ne
w s
yste
m ti
es in
EM
S–
Oth
er IT
mod
ifica
tions
, e.g
. mar
ket a
nd p
lann
ing
appl
icat
ions
Se
t-up
EAI L
BA
and
its
inte
rfac
e w
ith M
ISO
–D
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
Tr
ain
staf
ffor
new
proc
edur
es
Page
20
Tr
ain
staf
f for
new
pro
cedu
res
G
et N
ERC
cer
tific
atio
n fo
r new
BAs
Sy
stem
s re
ady
for s
taff
to tr
ain
for n
ew p
roce
dure
s
Prep
are
cuto
ver
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 KH33
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
Path
1+2
+3 e
stim
ated
tran
sitio
n/im
plem
enta
tion
cost
s M
aint
aini
ng P
aths
resu
lts in
~$3
5M in
crem
enta
l cos
ts; m
ost i
ncur
red
in la
te 2
012
and
2013
141
US
$3(M
)
150
222
Mai
n co
st d
river
s in
clud
e
Add
ition
al h
iring
nee
ds
IT H
ardw
are
and
supp
ort
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
s
11
13
25
104
125
100
Mai
n co
st d
river
s in
clud
e
Mai
n co
st d
river
s in
clud
e
Labo
r (S
PO
/OpC
os)
E
xter
nal C
onsu
ltant
s
gy
E
xten
ded
regu
lato
ry li
tigat
ion
R
even
ue c
lass
met
erin
g fo
r gen
erat
ion
P
ost 2
013
trans
ition
cos
ts
55
7520
511
100
24
Mai
n co
st d
river
s in
clud
e
Ext
erna
l Reg
./Leg
al
supp
ort
M
ISO
inte
rface
cos
ts1
IT
Har
dwar
e &
sup
port
La
bor (
SP
O/O
pCos
) –
incl
udin
g hi
ring
Mai
n co
st d
river
s in
clud
e
MIS
Oin
terfa
ceco
sts1
Mai
n co
st d
river
s in
clud
e
Met
erin
g
Add
ition
al h
iring
nee
ds
Set
ting
up B
A it
self
IT
Har
dwar
e an
d su
ppor
t
61
42
505
17
36
2011
supp
ort
La
bor (
SP
O/O
pCos
)
FER
C fi
lling
cos
ts
Mai
n co
st d
river
s in
clud
e
MIS
O in
terfa
ce c
osts
1
ITH
dd
t
M
ISO
inte
rface
cos
ts1
IT
Har
dwar
e &
sup
port
La
bor (
SP
O/O
pCos
)–
incl
udin
g hi
ring
37
Path
1G
ener
atio
n
25 0Tr
ansm
issi
onB
ack-
Bac
k-of
fice
Reg
ulat
ory
Com
ms
Tran
smis
sion
Pat
h1+
2+3
Com
mer
cial
PM
O/O
ther
2G
ener
atio
n
2013
2012
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 an
d su
ppor
t
Set
ting
up th
e LB
A
Labo
r (S
PO
/OpC
os)
–in
clud
ing
hirin
g
Page
22
Path
1
tota
l cos
tG
ener
atio
nO
pera
tions
Tran
smis
sion
O
PS
optio
nalit
y co
st
Bac
kof
fice
OP
Sop
tiona
lity
cost
Bac
kof
fice
Ope
ratio
nsR
egul
ator
y C
oord
inat
ion
Com
ms.
Tran
smis
sion
Ope
ratio
nsPa
th 1
+2+3
to
tal c
ost
Com
mer
cial
an
d Le
gal
Agre
emen
ts
PM
O/O
ther
Gen
erat
ion
OP
Sop
tiona
lity
cost
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 KH35
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
EXHIBIT KDW‐N
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‐N1
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
ENTERGY ARKANSAS, INC.ARKANSAS PUBLIC SERVICE COMMISSION Docket No. 10-011-U MISO Transition Discovery
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 No.: STAFF 18-24 Part No.: Addendum:
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.
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Question No.: STAFF 18-24
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
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‐O
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 12 of 33
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-02
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.
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 13 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
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 14 of 33
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-02
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.
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 15 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.
Prepared by: Carl A. Monroe, Executive Vice President and Chief Operating Officer Submitted to: Emon Mahony, Assistant Attorney GeneralDate: April 20, 2011
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‐P
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
ENTERGY ARKANSAS, INC.ARKANSAS PUBLIC SERVICE COMMISSION Docket No. 10-011-U MISO Transition Discovery
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 20-2 Part No.: Addendum:
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
APSC FILED Time: 6/9/2011 4:35:28 PM: Recvd 6/9/2011 4:31:16 PM: Docket 10-011-U-Doc. 428
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Question No.: STAFF 20-2
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
APSC FILED Time: 6/9/2011 4:35:28 PM: Recvd 6/9/2011 4:31:16 PM: Docket 10-011-U-Doc. 428
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
ENTERGY ARKANSAS, INC.ARKANSAS PUBLIC SERVICE COMMISSION Docket No. 10-011-U MISO Transition Discovery
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 No.: STAFF 20-3 Part No.: Addendum:
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
APSC FILED Time: 6/9/2011 4:35:28 PM: Recvd 6/9/2011 4:31:16 PM: Docket 10-011-U-Doc. 428
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Question No.: STAFF 20-3
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
APSC FILED Time: 6/9/2011 4:35:28 PM: Recvd 6/9/2011 4:31:16 PM: Docket 10-011-U-Doc. 428
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‐Q
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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 13-6 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
APSC FILED Time: 6/20/2011 3:41:17 PM: Recvd 6/20/2011 3:28:32 PM: Docket 10-011-U-Doc. 455
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
APSC FILED Time: 6/20/2011 3:41:17 PM: Recvd 6/20/2011 3:28:32 PM: Docket 10-011-U-Doc. 455
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‐R
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
ENTERGY ARKANSAS, INC.ARKANSAS PUBLIC SERVICE COMMISSION Docket No. 10-011-U MISO Transition Discovery
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 No.: STAFF 24-18 Part No.: Addendum:
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
APSC FILED Time: 6/21/2011 4:26:16 PM: Recvd 6/21/2011 4:25:20 PM: Docket 10-011-U-Doc. 458
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‐S
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 14 of 17
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. RESPONSES TO DATA REQUEST APSC-015
INFORMATION REQUESTED:
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
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‐T
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Strategic Transmission Projects –Screening with LMPs
Michael Schnitzer (on behalf of Entergy)(on behalf of Entergy)
February 17, 2011
1
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
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‐U
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
ENTERGY ARKANSAS, INC.ARKANSAS PUBLIC SERVICE COMMISSION Docket No. 10-011-U MISO Transition Discovery
Response of: Entergy Arkansas, Inc. to the Twenty-Fourth Set of Data Requests of Requesting Party: Arkansas Public Service Commission General Staff Filed: 6/22/11
Question No.: STAFF 24-20 Part No.: Addendum:
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
APSC FILED Time: 6/22/2011 4:29:36 PM: Recvd 6/22/2011 4:27:40 PM: Docket 10-011-U-Doc. 462
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Question No.: STAFF 24-20
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
APSC FILED Time: 6/22/2011 4:29:36 PM: Recvd 6/22/2011 4:27:40 PM: Docket 10-011-U-Doc. 462
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‐V
Not Used
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‐W
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
ENTERGY ARKANSAS, INC.ARKANSAS PUBLIC SERVICE COMMISSION Docket No. 10-011-U MISO Transition Discovery
Response of: Entergy Arkansas, Inc. to the Twenty-Fourth Set of Data Requests of Requesting Party: Arkansas Public Service Commission General Staff Filed: 6/22/11
Question No.: STAFF 24-21 Part No.: Addendum:
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
APSC FILED Time: 6/22/2011 4:29:36 PM: Recvd 6/22/2011 4:27:40 PM: Docket 10-011-U-Doc. 462
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‐X
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
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‐Y
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
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‐Z
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 9 of 33
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-02
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.
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 10 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.
Prepared by: Carl A. Monroe, Executive Vice President and Chief Operating Officer Submitted to: Emon Mahony, Assistant Attorney GeneralDate: April 20, 2011
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‐AA
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Page 30 of 30
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. RESPONSES TO DATA REQUEST APSC-022
INFORMATION REQUESTED:
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.
Prepared by: Carl A. Monroe Submitted to: Diana Brenske, Arkansas Public Service Commission Staff Date: June 9, 2011
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‐BB
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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.
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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.
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‐CC
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‐DD
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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 No.: STAFF 18-14 Part No.: Addendum:
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.
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‐EE
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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 No.: STAFF 18-15 Part No.: Addendum:
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.
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‐FF
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Question No.: AG 13-8
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
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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
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‐GG
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
ENTERGY ARKANSAS, INC.ARKANSAS PUBLIC SERVICE COMMISSION Docket No. 10-011-U MISO Transition Discovery
Response of: Entergy Arkansas, Inc. to the Twelfth Set of Data Requests of Requesting Party: Attorney General’s Office Filed: 6/8/11
Question No.: AG 12-13 Part No.: Addendum:
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
APSC FILED Time: 6/8/2011 3:55:25 PM: Recvd 6/8/2011 3:50:45 PM: Docket 10-011-U-Doc. 416
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Question No.: AG 12-13
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
APSC FILED Time: 6/8/2011 3:55:25 PM: Recvd 6/8/2011 3:50:45 PM: Docket 10-011-U-Doc. 416
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‐HH
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
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 13-9 Part No.: Addendum:
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
APSC FILED Time: 6/20/2011 3:41:17 PM: Recvd 6/20/2011 3:28:32 PM: Docket 10-011-U-Doc. 455
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513
Question No.: AG 13-9
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: 6/20/2011 3:41:17 PM: Recvd 6/20/2011 3:28:32 PM: Docket 10-011-U-Doc. 455
APSC FILED Time: 7/12/2011 10:30:53 AM: Recvd 7/12/2011 10:25:27 AM: Docket 10-011-U-Doc. 513