1. IMM Report on MISO South Integration Presented by: David B. Patton, Ph.D. Independent Market Monitor Presented to: Entergy Regional State Committee April 25, 2014

2. MISO integration of the South region was successfully executed on December 19, 2013. This presentation provides an update on the market’s performance in the MISO South region, showing: Prices in MISO South; Issues affecting of the Operations Reliability Coordination Agreement (“ORCA”) constraint limiting flows into or out of MISO South; Trends in Reserve Sufficiency Guarantee (“RSG”) payments made to units committed to satisfy reliability needs in MISO South. We also identify areas where additional evaluation and improvements are warranted. Introduction and Summary - 2 -

3. Prices in MISO South and Transfer Constraints Winter 2013–2014 - 3 - The following figure summarizes the price trends in MISO South. The line graphs shows average weekly day-ahead and real-time prices at three MISO South region hubs. Day-ahead prices ranged between $30 and $60/MWh. Texas had the highest average day-ahead prices because of congestion into the area. Real-time prices were higher and more volatile than day-ahead prices, partly because of the higher congestion on the transfer constraints between MISO Midwest and MISO South. The poor convergence in day-ahead and real-time market should improve as experience with the market improves. We show additional figures in the Appendix.

4. Prices in MISO South and Transfer Constraints Winter 2013–2014 - 4 - The bars at the bottom of the figure shows the average price impact from transfer constraints, which include: Operations Reliability Coordination Agreement (ORCA) constraints that have limited transfers between the two areas to 2000 MW; and TLR constraints affected by the transfer constraints. In the day-ahead market, the transfer constraints lowered prices in MISO South by 5 to 6 percent. Most of the day-ahead congestion occurred on January 28 when constraints in TVA were overloaded most of the day. In the real-time market, the reverse ORCA bound most frequently, raising prices in MISO South by 5 to 6 percent. These results highlight the difficulty participants have had accurately predicting the congestion on the transfer constraints.

5. Prices in MISO South and ORCA Transfer Constraints Winter 2013–2014 - 5 -

6. The 2000 MW ORCA limit is a very conservative starting value intended to ensure that MISO does not cause substantial congestion on the systems that are party to the agreement. The agreement contemplates the limit being raised if the MISO dispatch is not causing congestion elsewhere. MISO’s integrated dispatch has not caused significant external congestion. The ORCA constraints are having substantial effects on MISO’s dispatch and prices – it is critical that the collaborative process to raise the limits be effective. In addition, initial ORCA modeling had the unintended consequence of creating intra-regional price spreads where none should exist. This issue has been resolved starting in April. ORCA Concerns - 6 -

7. SPP complained at FERC that MISO should pay for transfers in excess of 1000 MW. FERC’s initial order establishing a settlement conference creates the potential that MISO may be liable for transmission charges when transfers increase over 1000 MW. We will be participating in the settlement conference. MISO filed for re-hearing, which we support. However, MISO’s has proposed to limit transfers to 1000 MW, although this was not required by FERC. This is inefficient because MISO will incur costs that are multiples of the potential SPP transmission charges ($10-$20 per MWh). Ultimately, this will raise the costs borne by MISO’s customers. Hence, we are filing a protest to the MISO filing. SPP Transmission Charges - 7 -

8. The next two figures show total RSG payments by region and by conduct. The first figure shows that a significant portion of all RSG payments over the period accrued to units in the South region. The large majority of these payments were payments made to satisfy local reliability requirements in WOTAB and Amite South (“VLR”). As it gains experience operating the system, MISO should evaluate the need for the operating guides that are causing the local commitments and associated RSG in MISO South. If these needs persist, local reserve products may be a more efficient alternative. Roughly half of the RSG costs are allocated locally under the VLR allocation. However, a large share of the remaining RSG in the MISO South is incurred to satisfy the VLR requirements in the day-ahead market, but not tagged as VLR and thus not currently allocated properly. Daily DA and RT RSG Payments - 8 -

9. Daily DA and RT RSG Payments by Region, December 19, 2013 – February 28, 2014 - 9 -

10. The second figure examines more closely the RSG payments to units in the South. The figure shows total payments that would have been made: If the units offered at their reference levels, as well as payments associated with the offer price increases. Two-thirds of total RSG payments to units in the South were associated with costs above reference The majority of which was in the form of high commitment costs. The transparent bars indicate payments that were reduced under market power mitigation measures. Mitigation in MISO South totaled over $6 million or 20 percent of all of the RSG in the region. Daily DA and RT RSG Payments - 10 -

11. Daily DA and RT RSG Payments by Conduct, South Region, December 19, 2013 – February 28, 2014 - 11 -

12. MISO’s integration of MISO South region has been relatively smooth. The initial results in MISO South indicate some areas of potential improvement that we will continue to evaluate and work with MISO to address, including: Evaluation of the need for local commitment requirements in MISO South; Improvements in the market design to reflect these commitment requirements; The modeling and limits applied for the ORCA constraints; The modeling of other external constraints; and Improvement in rules affecting incentives to follow dispatch signals. Conclusion - 12 -

13. Appendix

14. Natural gas prices were unusually volatile in January and February and significantly affected MISO’s market results. The following figure shows daily natural gas prices. In addition to showing the average price at 4 locations, it shows the intraday price range at the Chicago City Gate price, the most representative price for many participants. The bottom panel shows day-ahead and incremental real-time congestion (visible when RT cong. value > DA cong.) for four constraints between the Midwest and South regions. There were several significant periods of high natural gas prices in the two months shown. The spikes were due to a combination of sustained high demand and pipeline bottlenecks. During the price spikes, prices at Chicago and at Ventura (Iowa) diverged substantially from prices at the Henry Hub in Texas, leading to inter-regional congestion. Daily Natural Gas Prices - 14 -

15. Daily Natural Gas Prices and Congestion Costs January – February 2014 - 15 -

16. Daily Day-Ahead Margin Assurance Payments By Region, January 2014 - 16 -