Regional Transmission Organization Frequently Asked Questions

Transcription

1 1. The CRA analysis showed greater trade benefits to the Entergy region from joining SPP rather than joining MISO. Did Entergy re-do the CRA analysis? No. The CRA analysis was a key component of the Entergy Operating Companies analysis and was used as the initial building block. CRA estimated trade benefits for the Entergy region, on a present value basis, of $891 million for the Entergy Region Joins SPP scenario and $737 million for the Entergy Region Joins MISO scenario. As part of the Operating Companies own analysis, three additional pieces of analysis were done for both the SPP and MISO scenarios, which resulted in total estimated production cost benefits of about $1.4 B for the SPP scenario and $1.6 B for the MISO scenario. First, CRA by design did not analyze the savings to the Entergy Operating Companies ( EOCs or OpCos ) of joining either RTO. Rather, CRA estimated the trade benefits that would accrue to the total Entergy region, including other load serving entities and merchant generators (but not including the Cleco region, which CRA analyzed separately.) FERC determined that Entergy would be responsible for identifying the trade benefits that would accrue to the EOCs. Entergy developed an analytical tool that took the CRA outputs in the status quo and change cases, and calculated the trade benefits for each Operating Company for each case; these were summed to arrive at the trade benefits for the Operating Companies as a whole for that scenario. This methodology, which was reviewed with the E-RSC Working Group before it was used, was a bottom up approach to calculating the savings to the EOCs, not a top down allocation of total benefits between the EOCs and the other entities in the Entergy region. The same methodology was applied to the results of both the MISO and SPP scenarios. Total trade benefits accruing to the EOCs in the two scenarios were similar, $619 million in the MISO scenario and $589 million for the SPP scenario. This similarity was not surprising, since 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. Second, an adjustment was made to the base case or status quo case used by CRA for both the SPP and MISO scenarios. The status quo case underestimated the trade benefits of joining a Day 2 RTO, because it did not take into account the separation of EAI from the generation pool of the rest of the Operating Companies that would occur as of December 2013 in the absence of all Operating Companies joining a Day 2 RTO. However, in another scenario that CRA ran, the scenario where EAI alone goes to an RTO, CRA ran a status quo case that modeled the effect of the separation of EAI. When this more realistic status quo case is used in the all companies to an RTO scenarios, the trade benefits for both scenarios go up -- MISO trade benefits for all OpCos are $817 million and SPP trade benefits for all OpCos are $747 million. (There was no status quo case run by CRA that modeled the effect of the separation of EMI from the rest of the Operating Companies when EMI leaves the System Agreement in In that sense all of the estimates of production cost benefits from going to a Day 2 market are potentially understated, relative to a status quo world in which EAI and then EMI leave the generation pool that operates through the System Agreement.) Third, additional production cost benefits that were not captured in the CRA analysis were identified and quantified for both RTO scenarios. In 2007, MISO went through an exercise of identifying all the quantifiable benefits from its Day 2 market, in order to determine the value received by its members in return for the MISO administrative fees. This is called the MISO Value Proposition. When MISO reviewed the initial results of the CRA cost benefit studies (the methodology for which was developed

2 before MISO became a recognized alternative for the EOCs) it pointed out that a number of categories of benefits were not captured in the CRA modeling. While MISO developed an estimate of these benefits for the Entergy region, Entergy did not use the MISO estimates. Instead, Entergy reviewed the categories of additional production cost benefits identified by MISO, and used some, but not all, of them, and applied them to both the join MISO and join SPP scenarios. This added $770 million in production cost benefits for the EOCs in the MISO scenario, and added $646 million in production cost benefits for the SPP scenario. The additional benefits are primarily in ancillary services and reserve costs, in which scale economies play a major role; the higher level of benefits for MISO was largely due to scale differences between the two markets. (The MISO Day 2 market with the EOCs included would be at least 50% larger than an SPP Day 2 market with the EOCs included.) With these three additional pieces of analysis, the gross production cost benefits for the SPP scenario on a ten year NPV basis were approximately $1.4 billion; the gross MISO benefits were almost $1.6 billion. This is explained in detail in the Evaluation Report which the EOCs have filed with their retail regulators. 2. Were the additional categories of production cost benefits considered in the original CRA CBA methodology? No, and MISO and SPP both agree that total production cost benefits are not fully captured in the trade benefits analysis. The CRA trade benefits analysis used a production cost simulation model, GE MAPS, to project the fuel and dispatch cost related benefits that would arise as the result of the Operating Companies joining an RTO with a Day 2 market. An operating reserve requirement was modeled but was held constant between the base and change cases. As such, no quantification of the possible reduction in the quantity and cost for providing these services were captured in the CRA trade benefits analysis. CRA noted that installed reserve requirements could possibly decrease as a result of joining an RTO. However, the CRA analysis did not evaluate this benefit for the cases in which the entire Entergy region joined SPP or MISO. The Entergy analysis looked specifically at the impact on the combined EOCs installed reserve requirement as a result of joining a Day 2 market. 3. Were the additional categories of production cost benefits included in the qualitative benefits analysis that accompanied the original CRA FERC study? No. The purpose of that analysis was to identify non-quantifiable benefits such as transparency and independence. It was not designed to identify additional quantifiable production cost benefits. The additional production cost benefits can be and have been quantified for both the existing MISO Day 2 market and the proposed SPP Day 2 market, using a methodology that is described in the technical appendix to the Evaluation Report. 4. Are the anticipated MISO benefits that you cite dependent on the JOA dispute being resolved in MISO s favor? No. The analysis relies on CRA modeling runs that did not assume the existence of a JOA. CRA modeled the Join MISO case by removing wheeling charges and other impediments to trade (referred to as hurdle rates) between MISO and Entergy only on the 1000 MW contract path representing the existing Entergy/Ameren/AECI interconnection. CRA also performed preliminary

3 modeling of the JOA; Entergy did not use those results in its analysis. 5. If Entergy s analysis does not depend on any JOA interpretation, what is the significance of the JOA dispute and why should it be resolved by FERC now? h There are two main reasons. First, regardless of the modeling, there is a JOA in place between MISO and SPP and it is therefore important, even apart from benefits calculations, for the parties to understand the manner in which it will be applied upon the integration of Entergy. Second, as to benefit calculations specifically, the analysis has conservatively assumed that no JOA is in place, but if the MISO's position is accepted, we believe the benefits to joining MISO will be even greater, a point that would be relevant to Entergy's retail regulators in their review of the EOCs proposal to join MISO. 6. How did Entergy estimate the RTO administrative costs that would be allocated to the EOCs as a result of participating in a Day 2 RTO? First, it should be noted that CRA did not estimate administrative costs for the two RTOs; it was given estimates by SPP and MISO. Entergy adjusted both the SPP and the MISO estimates, based on an analysis of the ongoing operating cost of existing Day 2 markets. Based on this analysis, estimates were made for what the ongoing operating cost of the Day 2 market would be for both scenarios, and how much would be allocated to the EOCs, if the EOCs join the MISO, or if the EOCs join the SPP and SPP operates a Day 2 market. In addition, an estimate of the development cost for the SPP Day 2 market based on prior experience of other Day 2 RTOs, was included in the SPP administrative cost estimate. The development cost for the MISO Day 2 market was not an issue because that market is already in place and the costs are known, and in any event will have been largely amortized by the time the EOCs would join. 7. Is it a change of course for the Operating Companies to support joining a Day 2 Market? No. The Operating Companies interest is not new, and is not sudden. Discussion of the benefits of a Day 2 Market goes back as far as 2000, when the Operating Companies sought to establish a Day 2 market within SPP. The Operating Companies also proposed a Day 2 market as part of the SeTrans RTO initiative in Entergy has often explained that the market-driven congestion management of a Day 2 market makes sense for Entergy, given the level of merchant generation in its territory. 8. Why is it called a Day 2 market? The terms Day 1 and Day 2 refer to RTO requirements from FERC Order No There, the FERC required that an RTO must have effective protocols for managing congestion on the first day of operations ( Day One ) and must develop market mechanisms to manage transmission congestion no later than one year after it commences initial operation ( Day 2 ). Although the time frame was later relaxed, Day 2 became a shorthand reference for market-based congestion management including a centralized day ahead energy market.

4 9. SPP s web site says there are 41 physical ties (~14,100 MW capacity) between SPP members and Entergy and 9 physical ties (~4,400 MW capacity) between Entergy and SPP market participants. If MISO has only one direct transmission connection with the Operating Companies, shouldn t SPP be the preferred RTO for the Operating Companies? No. First, the SPP RTO does not have 41 interconnections with the Entergy Operating companies. The cited 41 interconnections with SPP members uses a broad definition of SPP members that includes utilities that are not SPP RTO members and do not take service under the SPP RTO tariff, such as Lafayette Utilities System (LUS) and Cleco. Entergy is an SPP member under that definition. There are 9 interconnections between the Operating Companies and actual RTO market members, and three of these account for 78% of the cited 4,400 MW capacity. Second, regardless of the number of interconnections 41 or 9 adding up their individual thermal capabilities is not meaningful. The sum of thermal ratings is not a measure of transfer capability (i.e., the maximum feasible power transfer from one region to another.) The actual transfer capability between SPP and Entergy is nowhere near 14,000 MW or even 4,400 MW for that matter. Third, even transfer capability by itself is not a particularly meaningful measure. The real question is whether that transfer capability would create savings for EOC customers in a Day 2 market and the measure of that is whether Entergy joining that market would result in increased use of the transfer capability. Based on the results of the CRA studies, average hourly transfers from SPP to the Operating Companies in the status quo case are about 450 MW; in the join SPP change case, that figure goes up to about 650 MW/hour. The fact that there would be little increased usage of the interconnections between SPP and Entergy if the Operating Companies were to join the SPP RTO and participate in a future Day 2 market indicates that transfer capability is not a key driver of benefits for the Operating Companies. 10. In MISO, how do the retail regulators participate in the decision making process, relative to the role of retail regulators in the SPP RSC? The formal structures for regulator participation are different between the two RTOs. The SPP Regional State Committee has specific authority under the SPP tariff on matters having to do with Section 205 filings regarding transmission cost allocation and other allocation-related issues. The retail regulators for the MISO members have an organization, the Organization of MISO States ( OMS ), that is advisory only. In MISO the retail regulators have a vote on the senior committee reporting to the board, the MISO Advisory Committee. Voting rights on that committee are allocated to 9 separate sectors, including IPPs, transmission owners, and transmission-dependent utilities. Retail regulators are one of the nine sectors, with two retail regulators sitting on the Advisory Committee. The OMS provides input to those regulator representatives on Advisory Committee.

5 11. What will happen to the E-RSC if the Operating Companies move to MISO? This scenario is specifically addressed in Attachment X of the Entergy OATT. The E-RSC will terminate if all the Operating Companies join an RTO. If the Operating Companies move to MISO, the Entergy retail regulators will become eligible for membership in the OMS and for election to the MISO Advisory Committee, which has two voting representatives from retail regulators. 12. Is MISO membership shrinking? No. Over the past 5 years, three members of MISO have left that RTO, while an additional 20 have joined. 13. Is Ameren considering leaving MISO? Ameren regularly prepares studies that evaluate the costs and benefits of remaining a MISO member, in part because the Missouri Public Service Commission requires them to do so on a periodic basis. The results of those past studies, the most recent dated November 1, 2010, show a benefit to remaining in MISO. There is no indication that Ameren is leaving MISO. 14. If Ameren decides to leave after the Operating Companies have joined MISO, could the OpCos remain in MISO? Yes. If Ameren withdraws from MISO after the Operating Companies join, the withdrawal would be subject to FERC review and approval. The OpCos would have several alternatives available, including acquiring a transmission contract path. 15. The Operating Companies are presenting this recommendation to all of their retail regulators for approval; does this mean that each regulator has a veto on whether every Operating Company goes to MISO? The Operating Companies believe that each of their regulators will recognize the benefits to customers of moving to MISO, and the advantages of moving together as a system. At this point there is no need to speculate on what would happen if their retail regulators do not all agree on the same course of action. 16. Is MISO heavily influenced by the views and requirements of members who have retail open access (ROA)? Although several MISO members operate in an ROA environment, most operate in traditional, vertically-integrated environments. Of note, both members who have recently left or announced they are leaving MISO for PJM (FirstEnergy and Duke Energy Ohio/Kentucky) operate in an ROA jurisdiction (Ohio.) In contrast, Duke Energy Indiana (Cinergy), which is not in an ROA state, is staying in MISO. Once the departing members leave, 4 MISO Transmission Owners will operate in ROA environments, representing less than 25% of the energy transactions within the MISO region.

6 17. How can the Operating Companies be sure their retail customers will see the benefits of a Day 2 Market? While it is impossible to predict with certainty the level of benefits to be obtained in a Day 2 market, the report discusses the extensive quantitative, qualitative, and conceptual bases for the Operating Companies conclusion that there will be material benefits to their customers from moving to a Day 2 market. All of the production costs benefits estimated in the Entergy calculations presented in the report for both RTOs, if realized, would accrue to the EOCs customers. The fact that MISO has an established, proven Day 2 market, whereas SPP s is still under development, is a key reason that the Operating Companies believe that there is far greater certainty in achieving those benefits by moving to MISO. 18. Do the benefits calculations assume that QF put rights would be eliminated if the EOCs join the MISO market? No. 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 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, as long as the compensation to QFs that choose to continue to put energy to the system reflects all the costs associated with those unscheduled or uninstructed injections of energy. Entergy believes the current MISO settlement rules reflect those costs. 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. 19. What will happen to wholesale customers under the current Entergy OATT, including interconnected generators and network customers if the Operating Companies move their transmission facilities to an RTO? Current OATT transmission customers and interconnected generators will still be interconnected to the Entergy Transmission System. The FERC tariff under which the Entergy System operates will shift from the Entergy OATT to the MISO Transmission Tariff. Conversion of service from one tariff to another is FERC jurisdictional; the provisions must be just and reasonable. 20. What will happen to transmission customers that have "Grandfathered Agreements if the Operating Companies join MISO? As with service under the Entergy OATT, conversion of grandfathered transmission agreements ( GFAs ) will be a FERC jurisdictional matter. MISO has extensive experience with Transmission Owners joining the Day 2 market with GFAs. Entergy Transmission and the Operating Companies intend to work with MISO and the GFA counterparties under those agreements to determine how best to honor the GFAs under the MISO transmission tariff.

7 21. If the Operating Companies move to MISO, are you creating a new seam? The move would actually eliminate a seam. Right now Entergy has a seam with SPP and a seam with MISO. If the Operating Companies join MISO, one of those seams -- the MISO/Entergy seam will be eliminated. Likewise, SPP currently has a seam with Entergy and seam with MISO; if the Operating Companies join MISO, that will become one seam between SPP and MISO. 22. MISO has more wind potential than the rest of the country. Does the MISO wind buildout, and in particular the resulting transmission costs, create risk for the Operating Companies customers? The transmission cost allocation methodology that MISO has proposed addresses this issue explicitly. MISO has identified a number of Multi Value Projects (MVPs) to address the windrelated needs of the states in its current footprint. MISO has recognized that these MVP projects were not planned in conjunction with the EOCs and cannot be assumed to provide benefits to the Entergy region. This is reflected in the transmission cost allocation proposal that MISO has prepared for Entergy. Under this proposal, no costs of the already-identified MVP projects would be allocated to the Entergy region for at least the first five years after Operating Companies join MISO; after that, the cost of the already-identified MVP projects can be allocated to the Entergy region Companies only if additional MVP projects are identified that provide enough benefits to the region to justify an allocated share of the costs of both the additional MVP projects and the already-identified MVP projects. 23. The materials accompanying the Entergy press release of April 25, 2011 said that MISO s transmission cost allocation proposal to Entergy was based on costcausative principles and was less risky for Entergy s customers than SPP s transmission cost allocation proposal. What does this mean? MISO and SPP have different methodologies with respect to the allocation of transmission costs. SPP s Highway/Byway methodology automatically socializes the cost of all transmission projects above a certain voltage threshold, while MISO uses 100% socialization only for its MVP projects, which have region-wide benefits. Further, the MISO transmission cost allocation proposal to Entergy recognizes that the already-identified MVP projects were not planned with Entergy in mind and would not provide benefits to the Entergy region sufficient to justify allocating Entergy a share of the costs. Under the MISO proposal, Entergy will not be allocated any share of costs of the already-identified MVP projects unless and until additional MVP projects are identified and placed in service that provide benefits that are large enough to justify the allocation of costs of the previously planned MVP projects as well. In contrast, the SPP transmission tariff has provisions (the Highway/Byway policy) that would allocate certain costs automatically to the Entergy zone, regardless of economic benefit or cost causation. Under this policy, the Entergy region would be allocated a load ratio share of new transmission projects of 300 kv voltage or higher. For lower voltage additions, 1/3 of the costs are socialized and 2/3 are charged to the situs utility zone (the utility building the transmission upgrades on its system.) The SPP proposal to Entergy did not alter this basic policy. Although SPP s proposal

8 focuses on the fact that Entergy would not be responsible for the costs of projects that have already been built or planned, such as the Balanced Portfolio projects, the fact remains that the Entergy region will automatically pick up a load ratio share of future >300 kv projects that come out of the SPP planning process. In addition, under the situs provisions of the Highway/Byway policy, the SPP methodology would potentially charge EOC customers with the bulk of the transmission costs required to make merchant generation on the Entergy system deliverable to network customers elsewhere in SPP. By contrast, under MISO s allocation methodology, the cost of such upgrades would generally be assigned solely to the requesting party. 24. If the EOCs join MISO, will they have to pay a termination fee under the SPP reserve sharing agreement to which they currently belong? No, the SPP Reserve Sharing Agreement does not include any provisions for exit or termination fees. 25. Does joining an RTO mean that the Entergy Region will sever its transmission ties with any surrounding transmission systems? No. The Operating Companies participation in one RTO does not entail the severing of ties with the other RTO or with any other transmission owner with whom the EOCs are interconnected. Joining an RTO with a Day 2 Market does not automatically result in any system topology change. Upon integration, the RTO s transmission planning process will determine if existing tie lines should be upgraded or if additional ties should be constructed. At this time, both SPP and MISO have indicated that no upgrades are necessary in order for the Operating Companies to join the respective RTOs, and thus no additional ties will be required as a result of RTO membership. 26. In your analysis did you assume that the Operating Companies are still part of the Entergy System Agreement? Yes. Entergy s analysis assumes that the System Agreement continues in existence as follows: For study year 2013, the analysis includes participation of all six Entergy OpCos in the System Agreement. In 2014 and 2015, the analysis assumes all OpCos except EAI are members of the System Agreement. From 2016 through 2022, the analysis assumes all OpCos except EAI and EMI are members. The analyses compare a status quo case to several Join an RTO cases. In the status quo case, when an OpCo leaves the System Agreement, it is assumed to operate as a stand alone balancing authority under the Entergy OATT/ICT, with its own unit commitment and dispatch and ancillary services. In the RTO cases, all OpCos are assumed to be part of the centralized Day 2 market. The System Agreement accounting would allocate costs from the RTO market among the remaining System Agreement members; some technical modifications to the System Agreement would likely be required in order to effectuate this. 27. If the Operating Companies join MISO, is a System Agreement still needed? The System Agreement is an agreement to share generation and transmission facilities and an agreement for how to allocate the resulting costs among the Operating Companies. If the

9 Operating Companies are all in a Day 2 market under an RTO transmission tariff, the day to day sharing of generation and transmission facilities takes place automatically under the provisions of the RTO tariff; an Operating Company no longer needs to be in the System Agreement in order to be part of a larger pool of generation. However, those Operating Companies that have not given notice of termination would continue to participate in the System Agreement under a Day 2 market. This means they would, through the System Agreement accounting, continue to share the output of their owned generation units among themselves at cost. They would also continue reserve sharing and joint planning of generation resources within the MISO market. If they do elect to terminate membership pursuant to the applicable provisions of the agreement, such termination would be subject to FERC approval. 28. How does the recommendation to join MISO affect the effort to develop a successor arrangement to the current System Agreement? A proposed successor arrangement was developed as a way to keep EAI generation in a dispatch and cost sharing pool with the remainder of the Operating Companies after EAI terminates its participation in the System Agreement. The proposal was called the CODA Commitment, Operations, and Dispatch Agreement and it was discussed extensively with retail regulators. However, by joining MISO, all of the Operating Companies will be in a much larger generation dispatch pool, the MISO Day 2 market, regardless of whether they continue to participate in the System Agreement. The rationale for the CODA is no longer present, and therefore the CODA proposal has been withdrawn. 29. If the EOCs go to MISO, will the WPP be continued? No. The functions provided by the WPP in particular the simultaneous granting of transmission service and evaluation of generator offers are already performed within the MISO Day 2 market. The Operating Companies may elect to procure bilaterally on a weekly basis, as they did before the WPP was initiated, but the procurement would not involve the simultaneous granting of transmission service. 30. How will the new MISO proposal on capacity markets affect the potential benefits to the EOCs of joining MISO? MISO is considering instituting a forward capacity market. Under this proposal, any entity could continue to self supply its capacity requirements. This means that the EOCs would be able to continue to supply their capacity needs through building or bilateral procurement, and they would have an additional option of procuring through the MISO s forward capacity market (assuming it is approved by FERC), which may provide an opportunity to further reduce costs for customers. Retail regulator jurisdiction over generation resource planning would not be altered by this proposal. 31. Will the EOCs join MISO as one member? Holding companies in MISO typically sign a single Transmission Owner Agreement, and the EOCs would expect to do the same. However, the question of the EOCs membership should not be confused with the issue of zones, such as transmission zones and load settlement zones. The decisions on transmission and load zones will be made after further review and study of the

10 alternatives under the MISO tariff. It is anticipated that a preliminary determination will be completed prior to any Change in Control filings later this year. The question of membership is also different from the issue of load serving entities. The current expectation is that Entergy Arkansas will operate as a separate load serving entity within the MISO market and the other five Operating Companies will continue to operate as a single, combined load serving entity, at least initially. 32. Once the EOCs become members of an RTO, can they exit? Yes, although MISO generally requires at least five years of membership before withdrawal can take place. Both RTOs have exit provisions that obligate departing members to assume responsibility for non-avoidable costs that were incurred on their behalf. Both RTOs require that transmission service agreements between the departing member and other members of the RTO that were in effect at the time of exit must continue for the life of those agreements under the rates, terms, and conditions as if the withdrawal had not occurred. In both cases withdrawal may take place only with FERC review and approval of the terms and conditions of the withdrawal. SPP is in the process of revisiting its withdrawal provisions and any forthcoming changes are unknown at this time. 33. If Cleco elected not to join MISO, would the recommendation change? No. While trade benefits might diminish somewhat if Cleco were not in MISO, they would not be eliminated. For instance, the incentives for QFs to bid or schedule day ahead in a Day 2 market are independent of Cleco s participation in that market. The calculation of the other production cost benefits for the Operating Companies did not assume Cleco s participation. In sum, without Cleco there would still be meaningful benefits to joining MISO relative to the other alternatives.