Highlights of the 2012 Annual Report on the ISO New England Markets

1. Highlights of the 2012 Annual Report on the ISO New England Markets David B. Patton, Ph.D. Potomac Economics External Market Monitor June 12, 2013

2. Introduction • Potomac Economics serves as the External Market Monitor (“EMM”) for the ISO New England. In this role, we: • Evaluate and report on the competitive performance and operation of the wholesale markets operated by ISO New England; • Identify and recommend necessary changes to existing and proposed market rules, tariff provisions and market design elements; and • Evaluate the quality and appropriateness of mitigation by the Internal Market Monitor. • This presentation summarizes our assessment of New England’s wholesale power markets in 2012. We address two primary areas: • The prices and the operational efficiency of the markets; and • The competitive performance of the markets. • In addition to our findings in these two areas, we also present recommendations for potential improvements in the ISO’s markets. - 2 -

3. Introduction The current wholesale electricity markets began operation in March 2003. ISO New England has made enhancements to the markets and introduced new markets for other products that have improved market performance. ISO New England’s markets currently include: Day-ahead and real-time energy: coordinates commitment and production from the region’s generation and demand resources, and facilitates wholesale energy trading; Financial Transmission Rights (“FTRs”): allows participants to hedge the congestion costs associated with delivering power over the network; Forward and real-time operating reserves: ensures that sufficient resources are available when a contingency occurs; Regulation: allows the ISO to instruct specific units to adjust output moment-by-moment to balance system supply and demand; and Forward Capacity Market (“FCM”): intended to provide efficient long-term market signals to govern decisions to invest in new generation and demand resources and to maintain existing resources.

4. Benefits of the ISO New England Markets The ISO New England markets produce substantial benefits in the following areas: • Efficient commitment of generation: Coordinated commitment of generation through the day-ahead market produces savings relative to decentralized systems by: • Reducing the quantity of generation that is committed; and • Ensuring that the most economic generation is committed. • Efficient dispatch and congestion management: Total dispatch costs are reduced by: • Producing energy from the most economic supply and demand resources; • Employing the lowest cost re-dispatch options to manage congestion; and • Fuller utilizing of the transmission capability in the region. • Enhanced reliability: Reliability is improved because the real-time dispatch provides much more responsive and accurate control of power flows on the transmission system than the previous Transmission Line Loading Relief procedures (“TLR”). • Efficient price signals: The prices produced by the energy and capacity markets provide a transparent economic signal to guide short-term and long-term decisions by participants and regulators. - 4 -

5. Highlights of Market Performance in 2012 Based on our evaluation of the markets in New England (in both constrained areas and the broader market), we find that the markets performed competitively in 2012. Energy prices fell 22 percent from 2011 to 2012, due primarily to the reduction in natural gas prices (the dominant fuel in New England), which fell 21 percent on average from 2011. The correspondence of fuel prices and offer prices in New England is an indication of the competitiveness of ISO-NE’s markets. Other variations in supply and demand contributed to the reduction in energy prices: On the demand side, average load fell in 2012 by 1 percent across all hours and by 6 percent in the first quarter because of milder winter weather. The summer peak load fell 7 percent from 2011 to 2012. On the supply side, a new 620 MW gas-fired combined cycle unit in Connecticut entered the market in mid-2011. In addition, nuclear generation and imports from neighboring areas rose by an average of 570 MW combined in 2012. Real-time automated mitigation was successfully implemented in April 2012. This enables the ISO to identify and prevent the abuse of market power in a more timely and accurate fashion than the previous manual process.

6. Prices and Market Operations

7. Energy Prices The first figure shows the load-weighted average day-ahead price at the New England Hub and the average natural gas price for each month in 2011 and 2012. Overall, energy prices fell 22 percent from 2011 to 2012, primarily due to the 21 percent decrease in natural gas prices. Lower fuel costs should translate to lower offer prices and, thus, lower market clearing prices in a competitive, well-functioning market. Implied Marginal Heat Rates (energy price ÷ gas price) in the second figure isolate changes in energy prices that are not related to the changes in natural gas prices. This metric typically rises when natural gas prices fall because a small share of generation costs is not related to fuel prices. However, the implied marginal heat rates fell 1 percent from 2011 to 2012, due to: 1 percent decrease in average load levels; 300 MW increase in average net imports from neighboring areas; and 260 MW increase in nuclear generation due to fewer outages.

8. Day-Ahead Energy and Natural Gas Prices2011 & 2012 Note: The energy prices are load-weighted averages.

9. Average Implied Marginal Heat Rate2011 & 2012

10. Operating Reserve Constraints and Clearing Prices The next figure summarizes average reserve clearing prices in each quarter of 2011 and 2012 for: (a) all three service types outside the local reserve zones (on the left); and (b) for 30-min reserves only in the three local reserve zones (on the right). Each price is broken into components associated with each class of reserve. For example, the system-level 10-min spinning price is based on the costs of meeting three requirements: the 10-min spinning, 10-min total, and 30-min requirements. The figure shows that reserve constraints bound infrequently in 2011 and 2012. The system-level 10-min spinning reserve requirement bound most frequently (in roughly 3.4 percent of the intervals), down slightly from 2011. 30-min reserve prices in local areas were almost identical to those in other areas because the local reserve requirements were rarely binding. The clearing prices for all reserve types rose from 2011 to 2012, primarily in the second half of 2012, due primarily to two significant market rule changes. The RCPF for the system-level 30-min reserve rose from $100 to $500/MWh on June 1, 2012 (which sets prices during reserve shortages). The system-level 30-min reserve requirement rose in July 2012, consistent with the 25 percent increase in the system-level 10-min requirement.

11. Operating Reserve Constraints and Clearing Prices By Quarter 2011-2012

12. Virtual Trading and Uplift Allocation The overall volume of virtual scheduling have decreased substantially since 2010. Most of the decline was due to a sharp decrease at the nodal level in May 2010. The ISO deployed a software solution in May 2010 to correct an inconsistency in loss modeling at certain locations that had motivated a large share of the nodal trading. Virtual trading at hubs and zones decreased in 2012 in response to smaller differences between DA and RT prices. Recent FERC enforcement actions against virtual traders in a number of markets have likely increased the perceived regulatory risks associated with virtual trading. NCPC charges to virtual trades remained high in 2012 largely because the reduction in virtual trading reduced the base of deviations to which costs are allocated. The high NCPC rate may have contributed to the decrease of virtual trading, which likely hindered the natural market response to RT price premiums since 2010. The current NCPC allocation scheme over-allocates costs to deviations relative to the portion of the NCPC they likely cause. We are working with the ISO and IMM to develop changes to the NCPC allocation that would improve its efficiency. Virtual traders netted a profit of $5 million (not including NCPC charges) in 2012. This indicates that virtual trades generally improved price convergence. However, when NCPC charges are considered, overall virtual trading was unprofitable with an overall net loss of $4 million.

13. Virtual Trading and Uplift Allocation 2010-2012

14. Transmission Congestion and FTRs The following figure shows day-ahead and real-time congestion prices and FTR prices for each of the eight ISO-NE load zones in 2011 and 2012. Congestion increased modestly in 2012 --- day-ahead congestion revenues totaled $30 million in 2012, up from $18 million in 2011. The increased congestion level was attributable to several factors: Peak load conditions occurred more frequently in 2012, leading to more frequent congestion into import-constrained areas in the summer months; Congestion increased in areas where planned transmission outages substantially affected the network capability (e.g., Western Central Massachusetts) ; and Natural gas prices rose sharply in November and December 2012, increasing redispatch costs and associated congestion-related price differences. Nonetheless, the levels of congestion revenues are still far below: (a) the historic levels that prevailed before transmission upgrades completed in 2009; and (b) the levels seen in other LMP markets. The FTR markets performed reasonably well in 2012. The consistency of FTR prices and congestion patterns improved substantially overall in 2011 and 2012 from prior years. As expected, monthly FTR prices were more consistent with congestion patterns than annual FTR prices because more information is available.

15. Transmission Congestion and FTR Auction Prices

16. External Interface Scheduling Power is usually imported from Quebec and New Brunswick, rising in peak hours (1,640 MW in 2012) and falling in off-peak hours (1,480 MW in 2012), consistent with hydro operations. New England and New York are connected by three interfaces. Exports are consistently scheduled across two small interfaces from Connecticut to Long Island (averaging 360 MW in 2012). Power flows in either direction on an hourly basis over the large primary interface between areas (averaging roughly 235 MW from New York in 2012). The spread in natural gas prices between New England and New York has been an important driver of the variations in interchange between the two markets. The following table evaluates the relationship between real-time schedules and clearing prices for NE and NY across the three interfaces in 2012. Power was scheduled in the inefficient direction (from the high-priced market to the low-priced market) in 48 percent of the hours across the primary interface and in 42 percent of the hours over the two smaller interfaces. This inefficiently raises costs in both areas and lowers reliability. NE and NY are pursuing CTS to improve coordination between markets. We recommend that the ISO-NE continue to place a high priority on this initiative.

17. Efficiency of Real-Time Schedules Between NE and NY2012

18. Real-Time Pricing and Market Performance Efficient real-time prices (particularly during shortages) are important because they encourage competitive scheduling by suppliers, participation by demand response resources, and investment in new resources when and where needed. The next two analyses evaluate the efficiency of real-time pricing during periods when fast-start units were deployed in merit order in 2012. The first figure evaluates the extent to which the costs of fast-start units started by UDS are reflected in energy prices by comparing their average offer costs with the average real-time LMP over the commitment period (usually one hour). Starts are shown according to the size of the difference between the average total offer and the average real-time LMP over the initial commitment period. This comparison is shown separately for hydro and thermal peaking units. The second figure evaluates how real-time prices would be affected if the average total offers were fully reflected in real-time LMPs. The lower portion shows how frequently thermal and hydro fast-start units were started by UDS in merit order when their average total offers were greater than the real-time LMP during the initial commitment period. The upper portion shows the difference between the average total offer and the real-time LMP from these periods averaged over the year by hour of day.

19. Real-Time Pricing of Fast-Start Resources The full deployment costs of peaking units (particularly thermal units) were frequently higher than real-time LMPs. In 2012: Less than 30 percent of thermal peaking starts and hydro starts were ‘economic’ (i.e., the average total offer < the average real-time LMP). 29 percent of offers from thermal peaking units and 5 percent of offers from hydro units exceeded the average real-time LMP by at least 50 percent. NCPC results when fast-starts are started and their costs are not reflected in LMPs. Fast-start units were started by UDS when their average total offer exceeded the real-time LMP over the initial commitment period in 9 percent of all hours in 2012. If the average total offers were fully reflected in the energy price, the average real-time LMP would increase by more than $2/MWh and the uplift would reduce by more than $6 million in 2012. The impact can be much higher on individual days or during individual hours (e.g., the average price impact during hour 19 would be over $7/MWh.) These estimates likely overstate the impact from more efficient RT pricing because they do not consider the market responses to the higher RT prices. Although hydro generation accounted for the majority (over 80 percent) of fast-start generation that was started by UDS in merit order, the operation of thermal peaking resources occurred during tighter operating conditions.

20. Real-Time LMPs vs. Offers of Fast-Start Generators First Hour Following Start-up by UDS, 2012

21. Difference Between RT LMPs and Offers of Fast-Start UnitsFirst Hour Following Start-up by UDS - 2012

22. Real-Time Pricing and Market Performance We also evaluated three other important aspects regarding the RT pricing and dispatch and made a total of three recommendations to improve real-time market performance. Real-Time Pricing during Operating Reserve Shortages: When the marginal cost of meeting system-level 30-min reserve requirements exceeds the RCPF, this can result in inefficient real-time prices. The ISO replaced the $100 RCPF for system-level 30-minute reserves with the $500 RCPF on June 1, 2012. This has reduced the need for manual actions to maintain reserves and provide more efficient price signals during reserve shortages. Real-Time Pricing During Demand Response Activation: Demand response has surged from 530 MW in January 2006 to nearly 2,800 MW in January 2013. Although these resources provide substantial benefits, they also pose significant challenges for efficient real-time pricing (i.e., real-time price levels did not always fully reflect the cost of deploying these resources to maintain reliability). However, in 2012, there were no capacity deficiencies that required activation of emergency DR resources, so the markets were not affected by the pricing issues. Ex Ante and Ex Post Pricing: the ISO re-calculates prices after each interval (“ex post pricing”) rather than using the prices produced by the real-time dispatch model. Our evaluation of ex post prices in New England indicates that it: Biases prices upward slightly in uncongested areas, and Sometimes distorts the value of congestion into constrained areas.

23. Commitments for Local and System Reliability The ISO commits additional resources after the day-ahead market to maintain reliability. These commitments increase uplift costs and affect real-time prices. Following the completion of transmission upgrades in Boston, CT, and SEMA in 2009, the need to commit generation to satisfy local reliability fell significantly. Local reliability commitments also help satisfy system-wide requirements. Hence, supplemental commitment for system-wide reserves has increased since 2009. The following figure shows that supplemental commitments rose modestly in 2012. Local reliability commitment rose in Maine and Western Central Massachusetts where planned transmission outages led to increased local needs. System-wide supplemental commitments also rose in 2012, although the amount was still significantly lower than in the years prior to 2010. The sharp rise in supplemental commitment following the arrival of Superstorm Sandy accounted for a substantial share of the increase. Variations in supplemental commitments led to similar changes in uplift charges. Uplift payments for local reliability rose by $12 million in 2012. “Economic” NCPC uplift associated with non fast-start resources (which are primarily committed for system-level reserves) rose by more than $6 million in 2012.

24. Commitment for Reliability by ZoneDaily Peak Hour, 2011 – 2012 Note: The category RAA/RT – First Contingency & System Reserves shows capacity committed for local first contingency protection and for system-level reserve requirements together since the ISO does not maintain data that distinguishes between these two reasons for commitment.

25. Improvements in Market Operations We are supportive of several ISO initiatives that will improve the recognition of the capacity required to maintain reliability: Replacement Reserves Procurement – The ISO proposes a Replacement Reserve requirement before the 2013/14 Winter period, which will result in the procurement of additional 30-minute reserves using an RCPF reflecting their value ($250/MWh). Off-line Reserve Auditing – The ISO is improving its methods for determining the off-line reserve capability of fast-start resources to help ensure consistency between the offered performance and the actual performance. On-line Reserve Auditing – The ISO is also improving its methods for determining the capability of on-line resources to provide reserves. These initiatives are expected to lead to more accurate calculation of the amount of available resources, which should: Lead to higher real-time clearing prices for energy and reserves during tight operating conditions when reliable generator performance is most important; Reduce NCPC uplift charges, improve the incentives for generator commitment in the day-ahead market, and provide signals for investments to improve performance by both new and existing resources..

26. Forward Capacity Market Each FCA held so far has procured a significant amount of excess capacity, largely due to the effects of the price floor that prevents capacity prices from falling sufficiently to clear only the minimum requirement. When the floor is eliminated beginning in FCA 8, the clearing price will likely fall significantly due to the level of existing capacity and the vertical demand curve implicit in the FCM design. Despite improvements made in recent years, the current FCM design is not likely facilitate the efficient entry and exit of resources in New England. Most of the new investment in generation under FCM has been motivated by out-of-market payments related to RFPs of the Connecticut DPUC. A large share of capacity that has attempted to go out-of-service by de-listing has been unable to do so for reliability reasons. We believe it is critical to introduce market reforms to address these issues before the current surplus of capacity declines and recommend that the ISO: Adopt a sloped demand curve that recognizes the benefits of installed capacity beyond what is necessary to satisfy planning reserve requirements; and Determine whether the Rationing Election and the Capacity Commitment Period Election will promote efficient investment and FCM outcomes over the long-term.

27. Competitive Assessment

28. Structural Indicators of Market Power The competitive assessment includes structural assessments of market power in New England and evaluations of participant conduct. The structural assessment relies on a pivotal supplier analysis, which helps identify conditions when a supplier may have market power. A supplier is “pivotal” when energy and operating reserve needs cannot be satisfied without the supplier in the real-time market. The following figure summarizes the pivotal supplier analyses, showing: The largest suppliers in Connecticut and Boston were pivotal in almost 60 percent of hours and in 34 percent of hours in all of New England. When we exclude nuclear capacity, results in Boston are unchanged while a supplier was pivotal in 25 percent of hours in All of New England and in only 1 percent of hours in Connecticut. The pivotal frequency in All of NE fell notably in 2012 because: The size of some large suppliers decreased during 2012 (e.g., the portfolio of the largest supplier fell 750 MW and the third largest supplier lost about 600 MW); and A significant portion in the largest supplier’s portfolio is coal-fired capacity, which was economically committed less frequently in 2012 than in prior years because of lower natural gas prices.

29. Frequency of Pivotal Suppliers by Region 2011 – 2012

30. Competitive Assessment: Evaluation of Potential Withholding The competitive assessment examines market participant behavior to identify potential exercises of market power through: Economic withholding (i.e., raising offer prices to reduce output and raise prices); or Physical withholding (i.e., reducing the claimed capability of a resource or falsely taking a resource out of service to reduce output and raise prices). The next two figures summarize our analyses, showing the results by load level for the largest suppliers in New England and all other suppliers. Indicators of potential withholding are relatively low; and The quantity of potential withholding for the largest suppliers was comparable to the levels for other suppliers (that are not likely to have market power). Our report shows similar results for load pockets where the pivotal supplier analysis indicated there was significant potential for local market power. Based on these results and the ongoing monitoring we performed over the year, we find very little evidence that suppliers withheld capacity to raise clearing prices. Suppliers can also exercise market power by raising their offer prices to inflate the NCPC payments they receive when committed for local reliability. This was not significant in 2012 due to: (a) the relatively low level of local reliability commitments; and (b) the mitigation rules made to address such conduct.

31. Average Output Gap by Load Level and SupplierAll of New England, 2012

32. Forced Outages and Deratings by Load Level and SupplierAll of New England, 2012

33. Real-Time Automated Mitigation Procedure (“AMP”) ISO-NE implemented real-time AMP in Apr. 18, 2012, which includes: System wide mitigation – All units are subject to a market-wide Pivotal Supplier Test and conduct thresholds of: i) a $100/MWh or 300% increase in the energy offers; or ii) a 200% increase in the commitment offers (i.e., start-up and no-load). Constrained area mitigation – Units in these areas are subject to more stringent thresholds of: (a) a $25/MWh or 50% increase in the energy offers; or (b) a 25% increase in the commitment offers. Local reliability mitigation – Units committed for local reliability are subject to the threshold of a $80 or 10% increase in the low load commitment cost. The next figure shows the frequency of each type of AMP mitigation by resource type and the total number of hours that were affected in each month of 2012. As expected, mitigation rose considerably under the AMP, which occurred more than 250 times in 2012. AMP enables the ISO to identify and prevent the abuse of market power in a more timely and accurate fashion than the previous manual process. Commitment mitigation accounted for 63% of all mitigation, while energy mitigation accounted for the remaining 37%. We have reviewed the mitigation and found that most were appropriate. However, some of mitigation can be attributed to inaccurate reference levels (MPs and the IMM have been working on improving the reference levels).

34. Real-Time Automated Market Power MitigationApril – December 2012

35. Recommendations

36. List of Recommendations Notes: 1. Feasible in Short Term: Complexity and required software modifications are likely limited. 2. High Benefit: Will likely produce considerable efficiency benefits.

37. List of Recommendations (cont.)