Keith Beall; Edith L. Bandy;

Transcription

1 From: Kim McCloud To: MPSCEDOCKETS; CC: Keith Beall; Edith L. Bandy; Subject: Date: Attachments: U Midwest ISO 2010 Summer Assess Comments Thursday, April 29, :16:08 PM Midwest ISO 2010 Summer Assessment Comments (U-16160) complete FINAL pdf To the MPSC: Attached, please find the comments of the Midwest Independent Transmission System Operator, Inc. ( Midwest ISO ) regarding the 2010 Summer Assessment under Docket No. U Thank you. Kim McCloud Paralegal Midwest ISO P.O. Box 4202 Carmel, IN (direct) (fax) kmccloud@midwestiso.org For Overnight Deliveries: 720 City Center Drive Carmel, IN 46032

2 S T A T E O F M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the investigation, on the ) Commission s own motion, into the electric ) supply reliability plans of Michigan s ) Case No. U electric utilities for the year ) COMMENTS AND BACKGROUND INFORMATION OF THE MIDWEST ISO The Commission opened this docket to explore and investigate the adequacy and reliability of the electric generation capacity for meeting customer requirements. The scope of the inquiry includes, among other things, the availability of transmission capability, the effects of the companies retail open access programs, affiliate dealings, the Customer Choice and Electricity Reliability Act, MCL et seq., expected changes in the wholesale market for electricity in the Midwest, and the interconnection of merchant generating plants. The Commission requested certain entities to submit comments discussing the ability of the respective entities to meet their customers expected electric requirements in In addition, the Commission specifically invited regional transmission organizations, namely the Midwest Independent Transmission System Operator, Inc. ( Midwest ISO ), and PJM Interconnection ( PJM ) to file comments regarding issues that affect the role of transmission in ensuring reliability. The Commission specifically noted topics such as: (i) peak demand coverage; (ii) expected reserves; (iii) reserve margins; and (iv) in-state and out-of-state generation resources, including deliverability of generation output and purchased power under peak operating conditions and transmission capabilities and constraints or other factors affecting deliverability. The Midwest ISO appreciates the opportunity to submit comments in response to the Commission's inquiry. These comments focus on just some of the Midwest ISO activities that

3 Midwest ISO Comments in MI PSC U April 29, 2010 assist member entities ability to provide necessary and valuable services to help them meet their annual peak demand needs. The Midwest ISO recognizes that these Comments are being filed somewhat tardy, but respectfully requests that the Commission accept these Comments for its consideration. The Midwest ISO was diligently working on its footprint wide summer assessment analysis which was not complete and publicly made available until April 27, As such, The Midwest ISO was unavoidably delayed in finalizing these Comments and being able to submit them. The following is a summary of the pertinent information from the Midwest ISO s 2010 Summer Resource Assessment 1. I. The Midwest ISO Regional Footprint Summer 2010 Assessment The Midwest ISO projects the coincident net internal demand to peak at 104,288 MW during the 2010 summer season. Driven by the Iowa integration on September 1 st, 2009 and Dairyland Power Cooperative, set to integrate on June 1 st, 2010, the Midwest ISO demand forecast has increased from The Iowa integration added 5.0 percent and Dairyland contributed 0.9 percent for a combined 5.9 percent increase in the 2010 demand compared to the 2009 summer. However, without the new membership, the net internal demand would have decreased by 1.7 percent primarily due to the economic down turn. The overall result is a 4.2 percent increase in the Midwest ISO s net internal demand compared to the prior summer season. 1 A copy of the full public presentation is attached hereto and also available for review at: 2

4 Midwest ISO Comments in MI PSC U April 29, 2010 Since the 2009 summer season, 10,370 MW of nameplate capacity has been added to the Midwest ISO market. The Iowa and Dairyland integrations contributed significantly to this addition with 7,822 MW of nameplate capacity. The integrations also contributed 72 percent to the overall 2,008 MW of additional wind nameplate capacity added to the footprint. This overall addition reflects a 36 percent growth in the Midwest ISO s wind nameplate capacity since the 2009 summer season. Compared to the added capacity, retirements in the Midwest ISO were nominal with only 756 MW of nameplate capacity. The 2010 projected reserve margin is 25.9 percent which exceeds both the 15.4 percent Midwest ISO system Planning Reserve Margin requirement for 2010 and the 18 percent reserve margin forecasted in In light of a strong reserve margin forecasted, firm load curtailment due to a system wide capacity shortage is a very low probability event for the 2010 summer period. The Midwest ISO confers many benefits to Michigan as an essential link in the costeffective delivery of electric power across the expanding footprint. The Midwest ISO is committed to sustaining reliability and working closely with Michigan stakeholders to maintain innovative solutions within our ever-changing industry. II. Other Issues of Note Relevant to Regional Transmission and Peak Demand The Midwest ISO performs a number of critical reliability functions that it provides to its participating members. These functions include: monitoring energy transfers on the high voltage transmission system; scheduling transmission service and performing tariff administration; managing transmission congestion in and around the members systems through security-constrained economic dispatch; operating the Day-Ahead and Real-Time energy markets; balancing load and generation in real time; and performing regional transmission planning. In order to provide these services the Midwest ISO is registered with NERC as a 3

5 Midwest ISO Comments in MI PSC U April 29, 2010 Reliability Coordinator ( RC ), Planning Authority ( PA ), Transmission Service Provider ( TSP ), Balancing Authority ( BA ), and Interchange Authority ( IA ). On January 6, 2009, the Midwest ISO began to administer an operating reserves market, often referred to as our Ancillary Services Market ( ASM ) and to perform Balancing Authority functions. When it began operating as a NERC-certified Balancing Authority, the obligation to carry reserves shifted from the multiple BAs in the Midwest ISO footprint to the new Midwest ISO Balancing Authority. The Midwest ISO now performs the majority of BA responsibilities including Automatic Generation Control ( AGC ), Control Performance Standard ( CPS ), and Disturbance Control Standard ( DCS ), while Local Balancing Authorities ( LBAs ) perform an important subset of these requirements such as tie line metering, load shedding, and the development and implementation of restoration plans. During October 2009 the Midwest ISO underwent a comprehensive NERC audit of these functions, with no violations or recommendations for corrective measures. 1. Reliability Benefits. There are several significant benefits provided daily by the Midwest ISO. First, member entities experience improved local and regional reliability. Second, LSEs gain full access to the benefits of the Midwest ISO s efficient, market-based congestion management mechanisms. Third, membership enables reduced energy costs by gaining access to a larger, and more diverse, generation mix with no additional transmission charges. Finally, participation allows entities the ability to minimize its respective administrative costs and uplifts by exploiting the economies of scale in a centralized organization. 4

6 Midwest ISO Comments in MI PSC U April 29, Seams Coordination. Seam issues have been thoroughly addressed by the RTOs serving Michigan. In accordance with the FERC's orders, 2 a Joint Operating Agreement ("JOA") was executed by Midwest ISO and PJM, and filed with the FERC. The provisions of the JOA and the Congestion Management Process ("CMP") incorporated into the JOA, have been implemented, greatly reducing the cost of managing transmission congestion cost at the seams through dispatch of generation in both RTOs, based on least cost dispatch, to manage congestion. By reducing redispatch, congestion cost is reduced providing direct saving to customers in Ohio through lower overall supply cost. The JOA obligates the two RTOs to exchange real-time and day ahead operating information, and planning information, to increase reliability coordination. The JOA spells out how outage coordination, voltage control, and emergency operations will be handled between the two entities, and adopted the highly detailed CMP to govern congestion management during the period when PJM operated energy markets, but Midwest ISO did not. After Midwest ISO started its own energy markets, Midwest ISO and PJM implemented a "market-to-market" congestion management process called the "Interregional Coordination Process" (ICP). The ICP builds on the CMP and moves to a financial system allowing one RTO to compensate the other when the second RTO redispatches internal generation to solve a congestion problem occurring in the first RTO's system. This occurs when the economics of the congestion are more reasonably addressed by redispatch than by having the first RTO attempt to reduce its own flows to relieve congestion. 2 See Docket No. ER04-375, 106 FERC 61,251 (March 18, 2004) and 108 FERC 61,143 at PP 58, 59 (August 5, 2004), and Docket No. EL , et al., 100 FERC 61,137 (July 31, 2002 Order). 5

7 Midwest ISO Comments in MI PSC U April 29, 2010 In response to the order of the FERC, PJM and the Midwest ISO eliminated pancaked rates for transmission service between the RTOs. The RTOs also engaged in a protracted "Joint and Common Market" stakeholder process between 2005 and 2009 that identified additional commercial and operating issues that were later improved, when economically feasible, to reduce as much as possible remaining impacts on transactions across the seam. Accordingly, the economic and coordination seams issues that existed during the early phase of RTOs have been largely resolved. Moreover, to the extent that there are seam issues remaining to be resolved, a framework is in place to address such issues. 3. Midwest ISO s Module E: Resource Adequacy. The Midwest ISO s long-term resource adequacy plan went into effect on June 1, This long-term resource adequacy plan is set forth in the Midwest ISO Tariff under Module E. Module E requires LSEs to have adequate resources to meet their forecasted load, plus a planning reserve margin, which is their Planning Reserve Margin Requirement. The Midwest ISO s Resource Adequacy construct is premised on LSEs historically meeting their planning reserve requirements primarily using their own supply or bilateral contracts and is consistent with a market (spanning multiple state and local jurisdictions) predominantly managed by traditional, vertically-integrated utilities. In this role, the Midwest ISO, through its stakeholder planning meetings, determines a number of critical components of the resource adequacy requirements, including the calculation of a loss of load expectation to determine the Planning Reserve Margin Requirement mentioned above. The Midwest ISO does not require load serving entities ( LSEs ) to procure capacity from a centralized capacity auction like that used in PJM or ISO New England. Instead, the 6

8 Midwest ISO Comments in MI PSC U April 29, 2010 Midwest ISO s long term resource adequacy construct allows the LSE to use its own resources or procure capacity bilaterally in order to meet its Planning Reserve Margin Requirement. The approach of allowing LSEs to procure their own capacity has been used with success for decades by the NERC regions and planned reserve sharing groups prior to the Midwest ISO s adoption of it. The Midwest ISO annually performs a Loss of Load Expectation ( LOLE ), to set the Planning Reserve Margin Requirement for the LSEs in the upcoming planning year. The Midwest ISO Resource Adequacy Review ( RAR ) construct was developed through close collaboration with the Organization of MISO States (OMS) and our other stakeholders. In addition to the long term LOLE study, the Midwest ISO also performs a longterm reliability assessment. This assessment shows the projected demand and resources for the next ten years. The most recent Long Term Resource Assessment shows the Midwest ISO having a reserve margin of 25.5% in Accordingly, this shows sufficient generation supply for Michigan and the entire Midwest ISO footprint for at least the next 10 years. In addition, the Midwest ISO provides market mechanisms that allow Demand Resources, BTMG and External Resources to participate on a level playing field with generators in the various products and services it offers, consistent with the laws of the jurisdiction where those resources are located. Altogether, the Midwest ISO estimates that over 9,000 MW of Demand Resources and BTMG are registered for capacity credit as Load Modifying Resources with the Midwest ISO. 4. Footprint Diversity Advantages. The Midwest ISO submits that there are improved opportunities for utilization and development of generation and transmission infrastructure that participating entities enjoy by participating in the Midwest ISO. Because of its unique role and access to certain information, the Midwest ISO can independently navigate 7

9 Midwest ISO Comments in MI PSC U April 29, 2010 the many complex and competing financial, economic, and regulatory issues that arise when transmission improvements and expansions become necessary. One such concrete advantage comes in the form of what we call Footprint Diversity. Footprint Diversity means the benefits that arise because each Load Serving Entity s peak does not coincide with the Midwest ISO s system peak. To account for this diversity of the peaks and ability to shift power as individual peaks occur at different times within the entire system, the regional planning reserve margin established by a Midwest ISO Loss of Load Expectations study showed a decrease from a typical 15.4% down to 12.69%. This significantly lowered planning reserve margin is enabled by the Midwest ISO s larger coordinated footprint and creates considerable benefits for the region by allowing participating entities to defer investments in new generation. 5. Loop Flows. The desire of participants in ISO and RTO energy markets and in non-market areas is for a buyer and a seller to agree on a price and a quantity of electricity commodity and to deliver that quantity over the network from the place where it is produced to the place where it will be resold or consumed. The electric industry for years has grappled with the problem that electric power does not flow as requested on the grid, but rather, as described in Ohm s law, flows along the path of least resistance. The configuration of any and every element of the electric grid determines this resistance or impedance that governs the flow of electricity. The disconnect between the contract path between source and sink becomes a reliability concern when the attempt to dispatch scheduled flows negatively impacts the system by creating actual flow patterns that are significantly different from scheduled flows due to the physical reality of the transmission system. The unscheduled flow patterns can load transmission facilities beyond their rated capacity even though these facilities could accommodate the nominal quantity scheduled for transfer had the actual flows matched those scheduled. 8

10 Midwest ISO Comments in MI PSC U April 29, 2010 Unscheduled energy, also known as loop flow and circulation flow, results from the difference between the energy that is scheduled to flow across an interface connecting two balancing areas versus the amount of energy that actually flows across the interface between those two balancing areas. In addition, loop flows are caused by a balancing area s generation to load dispatch when a portion of the resulting flows travel over neighboring systems. a. Regulatory Status of Current Loop Flow Issues. MISO staff is meeting on a regular basis with NYISO, PJM and the IESO to continue discussions on the development of solutions to Lake Erie loop flows. Weekly conference calls have taken place since August 27, Four on site meetings have been held at the NYISO, PJM and IESO offices, (most recent at PJM on March 5, 2010). Two Joint Stakeholder Technical Conferences have been held (Albany, NY and Carmel, Ind.). MISO is leading a team consisting of PJM, NYISO and IESO staff to begin a regional coordinated device study. It is anticipated that the study team will hold the initial kick off meeting in the April-May 2010 timeframe. Additionally, Regional interface price methodologies are being evaluated using different operating scenarios considering the impact of Michigan- Ontario Phase Angle Regulators. NYISO is working with their stakeholder community to evaluate their interface price methodologies. This includes evaluating the continued applicability of the existing circuitous path prohibitions. An area of particular concern relative to loop flow issues is what is commonly called the Lake Erie Situation. On January 12, 2020, NYISO filed their report to FERC on Broader Regional Markets to address this issue. The initial comments period ended February 2, MISO, PJM and IESO filed comments in support of the overall solution. The group is currently 9

11 Midwest ISO Comments in MI PSC U April 29, 2010 awaiting FERC response to the NYISO filing and comments. The FERC has docketed the matters as: ER Minimum Generation Alerts. The Midwest ISO Minimum Generation Task Force ( Min Gen TF ) recently concluded its duties and brought to the Midwest ISO Market Subcommittee its recommendations of market solutions and also an administrative pricing solution. The Min Gen TF found there was no one issue that drove the system to supply surplus situations, but a number of conditions that could impact the situation. Whereas wind would seem to be an impact, the Midwest ISO s centralized forecasting capability does give us a good idea of what the output of wind will be over the next 48 hours. This forecast is used in Operations to plan for the next day and the current day operations. One issue noted by the Min Gen TF dealing with variable wind resources relates to how wind is treated in the financially binding Day Ahead Market and in the Real Time Market. Wind is not required to offer its output into the Day Ahead Market. Depending on the wind farm some do participate in the DA, others do not. The DA market clears enough generation to meet the load that is bid into the DA Market. If wind does not participate or only participates to a lesser degree than what is available and shows up in realtime, then there may be excess generation to that which was already cleared to meet the load. In the current Supply Surplus Procedure, wind that is above its Day Ahead schedule can be curtailed as one of the steps, but before that is done, non-firm import schedules and emergency ranges of conventional generation are used. If Michigan s Renewable Portfolio Standard requires local wind to be developed in Michigan, this wind and the conventional generation within Michigan would be part of the overall Midwest ISO Balancing Area and the benefits of a large geographically diverse footprint will help spread out the potential impacts of the local wind and tend to mitigate the effects of 10

12 Midwest ISO Comments in MI PSC U April 29, 2010 Min Gen Alerts. The Michigan wind would be trained in the Midwest ISO s wind forecasting program and be used to help forecast potential supply surplus procedures and also alleviating them through proactive measures and through our Supply Surplus procedure if needed. Further, it is worth noting that the Midwest ISO is currently working on a new market product called Dispatchable Intermittent which will allow intermittent resources (wind included) to offer their generation into the Market and be sent dispatch signals to follow. This product can help minimize manual curtailments and allow intermittent resources which register as Dispatchable Intermittents to set a price in the market. Further, the coordinated planning done by the Midwest ISO will also incorporate and accommodate these types of wind integration needs identified by the Wind Resource Zone Board (MIPSC Case No. U-15899). 7. Transition of Load Serving Entities in to and Out of RTOs. As noted above, the Midwest ISO is both integrating new members and in one instance assisting in the transition of one entity, namely First Energy, in its requested move to PJM Interconnect, LLC. The voluntary nature of RTOs allows such changes but has caused some state regulatory bodies to pause because of perceived impacts such changes may create for their jurisdictional utilities. Based on the initial assessment of the Midwest ISO, the First Energy Transition to PJM should have no impact on system reliability, market efficiency, or Michigan utilities. The Midwest ISO - First Energy transition to PJM project is currently in the planning stages. The Midwest ISO leadership participated in a project kick-off meeting with the leadership of First Energy and PJM in October During this meeting, project leads were identified for each organization, expectations for coordination were communicated and next steps were determined. The project planning and coordination efforts increased beginning in 2010 after First Energy received its FERC orders allowing for the change. To date, the Midwest ISO has 11

13 Midwest ISO Comments in MI PSC U April 29, 2010 completed a comprehensive project plan which includes all of the model, procedural, systematic, and infrastructure changes required for the First Energy transition. Additionally, the Midwest ISO has completed a draft cut-over plan that will be used to ensure that the June 1, 2011 transition is seamless and has no operational impacts other than the Midwest ISO or its member entities. The Midwest ISO project and management teams meet weekly to review issues and receive project updates as necessary. Any issues that might arise are discussed first during the project team meeting and then escalated, as required, to the management team to be addressed. In addition, the core project leads for each organization participate in weekly coordination meetings. Additional meetings are coordinated by the project leads where topics arise that specifically require discussion with the applicable subject matter experts. In order to ensure focus on a smooth transition, weekly internal and coordination meetings are expected to continue through transition. All of these efforts are designed to ensure a smooth transition for the Midwest ISO and its existing member entities and participants as well as First Energy. III. Conclusion. Michigan, through its State Regulatory Commission as well as the member organizations and market participants have all been very active in the development, implementation, operation, and on-going improvements of the Midwest ISO. The Midwest ISO encourages and requests that all of these groups continue their active participation in the vitally important Midwest ISO stakeholder processes to ensure this continued level of reliability and to make sure peak demands continue to be met. The Midwest ISO stakeholder processes provide a great and unique forum to raise and discuss problem areas and enhance opportunities to craft solutions that most times result in far better results because of the interplay and collective thinking and discussion the 12

14 Midwest ISO Comments in MI PSC U April 29, 2010 stakeholder process encourages. The Midwest ISO likewise encourages Michigan s continued participation in and through the Organization of Midwest ISO States (OMS) and appreciates the leadership role that MI PSC Commissioner Monica Martinez has taken on within that critically unique stakeholder group. Michigan has been and continues to be a shining example of how reviewing its own mandates and needs within the context of a regional process can result in solutions that work for both the State and the region as a whole. The Midwest ISO submits that the collective efforts of the OMS, the stakeholder groups, and its management team help to ensure that the demand within Michigan, as well as the Midwest ISO region generally, continues to be reliably met all-the-while creating significant value for the participating members, loadserving entities, and the ultimate consumers they serve in Michigan and elsewhere. Respectfully Submitted, MIDWEST INDEPENDENT TRANSMISSION April 29, 2010 SYSTEM OPERATOR, INC. Keith L. Beall Keith L. Beall Senior Corp. Counsel - State Regulatory Midwest ISO - Legal Dept. P.O. Box 4202 Carmel, IN (317) (Direct Dial) kbeall@midwestiso.org 13

15 ATTACHMENT

16 Midwest Independent Transmission System Operator 2010 Summer Resource Assessment Midwest ISO Market Footprint Regulatory and Economic Studies (RES) Department

17 Table of Contents 1. Executive Summary Demand Demand Forecast Demand Resources Behind-the-Meter Generation (BTMG) Net Internal Demand Load Forecast Uncertainty Calculations Capacity Resources Midwest ISO Internal Generation Wind Availability External Resources System Conditions Fuel Coal Gas Hydro Transmission Operations Risk Assessment Variables Capacity Demand Wind availability External Support Risk Analysis Findings Case Summaries System As-Is Analysis Variable Sensitivity Analysis Case Comparison Conclusion

18 1. Executive Summary The Midwest ISO projects the coincident net internal demand to peak at 104,288 MW during the 2010 summer season. Driven by the Iowa integration on September 1 st, 2009 and Dairyland Power Cooperative, set to integrate on June 1 st, 2010, the Midwest ISO demand forecast has increased from The Iowa integration added 5.0 percent and Dairyland contributed 0.9 percent for a combined 5.9 percent increase in the 2010 demand compared to the 2009 summer. However, without the new membership, the net internal demand would have decreased by 1.7 percent primarily due to the economic down turn. The overall result is a 4.2 percent increase in the Midwest ISO s net internal demand compared to the prior summer season. Since the 2009 summer season, 10,370 MW of nameplate capacity has been added to the Midwest ISO market. The Iowa and Dairyland integrations contributed significantly to this addition with 7,822 MW of nameplate capacity. The integrations also contributed 72 percent to the overall 2,008 MW of additional wind nameplate capacity added to the footprint. This overall addition reflects a 36 percent growth in the Midwest ISO s wind nameplate capacity since the 2009 summer season. Compared to the added capacity, retirements in the Midwest ISO were nominal with only 756 MW of nameplate capacity. The 2010 projected reserve margin is 25.9 percent which exceeds both the 15.4 percent Midwest ISO system Planning Reserve Margin requirement for 2010 and the 18 percent reserve margin forecasted in In light of a strong reserve margin forecasted, firm load curtailment due to a system wide capacity shortage is a very low probability event for the 2010 summer period. The Midwest ISO is a Regional Transmission Organization (RTO) that coordinates operation of transmission facilities in 13 states and one Canadian province. Under the North American Electric Reliability Corporation (NERC), Midwest ISO functions as the Reliability Coordinator (RC), the Planning Coordinator (PC) and the Balancing Authority (BA) for utility companies in the Midwest region. Midwest ISO runs a price-driven electricity market in which Locational Marginal Pricing (LMP) provides price transparency for users of the wholesale Bulk Electric System (BES). As such, Midwest ISO has a filed Transmission, Energy and Ancillary Services Market Tariff at the Federal Electric Regulatory Commission (FERC). Approximately 87 percent of the load in the Midwest ISO s RC footprint is in the Energy Market. Resources used to meet this load include internal generators, external purchases, Behind-The-Meter Generation (BTMG), Interruptible Load, and Direct Controlled Load Management (DCLM). This document assesses the sufficiency levels across the Midwest ISO Market during the peak month in the 2010 summer season, which is forecasted to be July As required in Module E (Resource Adequacy Requirements) of the Midwest ISO tariff, Loss of Load Expectation (LOLE) analysis was conducted by Midwest ISO this year to establish a minimum Planning Reserve Margin. In order to maintain a reliability level of one loss of 2

19 load event in ten years the Midwest ISO has established a system planning reserve margin requirement of 15.4 percent. The Iowa new member integration on September 1 st, 2009 ( Iowa Integration ) added MidAmerican Energy Company, Muscatine Power and Water, and the Municipal Electric utility of the City of Cedar Falls, Iowa (News Release). In addition, Dairyland Power Cooperative is planned to integrate on June 1, 2010 ( Dairyland Integration ) (News Release). Together, the Iowa and the Dairyland integrations significantly contributed to the increased Net Internal Demand of 104,288 MW for the upcoming summer season. To be consistent with the qualification requirements of Module E, this value assumes BTMG as a capacity addition as opposed to a load reduction. The projected metered load (Net Internal Demand less BTMG) will be closer to 100,246 MW due to the netting effect that BTMG has on the Midwest ISO system in real time. There are 131,284 MW of Total Designated Capacity Resources which are committed to serve Midwest ISO load this summer; 5,549 MW and 4,042 MW of these resources are comprised of External Designated Capacity Resources to the Midwest ISO Market and for BTMG, respectively. There were 49 MW of Demand Response Resources designated at the time of this report for the upcoming summer period. The projected reserve margin for the 2010 summer is 26,996 MW or 25.9 percent of the estimated peak demand. Due to the implementation of Module E provisions in the Midwest ISO Tariff and the advent of the Module E Capacity Tracking (MECT) tool, Demand Resources, External Designated Capacity Resources, and BTMG were not finalized when this report was drafted. Typical values from the 2009 Post Summer assessment were utilized to forecast in place of the pending designations. 3

20 Midwest ISO Summer Load and Capability Demand (MW) vs. 09 Unrestricted Non-Coincident Peak 112, , % Estimated Diversity 5,072 4, % Total Internal 107, , % Direct Control Load Management * % Interruptible Load *2,874 1, % Net Internal Demand 104, , % Capacity (MW) Internal Designated Capacity Resources 121, , % External Designated Capacity Resources *5,549 4, % Behind-the-Meter Generation *4,042 4, % Demand Response Resources % Total Designated Capacity 131, , % Reserve Margin Reserve Margin (MW) 26,996 17, % Reserve Margin (%) 25.9% 18.0% 44.5% *2009 values used to estimate for 2010 forecasts Other 2010 values reflect data as of 3/8/2010 Table 1-1: Midwest ISO Summer 2010 and 2009 Load and Capability Probabilistic methods were used to analyze the effect of various conditions on the loss of load expectations (LOLE). The conditions under analysis include load levels, external support and intermittent capacity availability. The study was performed on 13 combinations of load and capacity using the model developed for the Module E Planning Reserve Margin Study. Historically, there has been a non-linear relationship between LOLE and reserve margin; as reserve margins decrease LOLE is expected to increase exponentially. However, utilizing the same model as used in 2009, the 2010 analysis incurred negligible risk due to high reserve margins projected for the upcoming summer. To illustrate some level of system risk, the assessment examined a hypothetical reduction in reserve levels. More specifically, the level of risk was measured for a 20 percent reserve margin case by lowering capacity and introducing load variability. This reduction in the reserve margin accompanied with a system-as-is sensitivity resulted in a 1.2 percent chance (LOLE of 0.012) of having insufficient capacity to serve demand. This level of reliability is roughly eight times more reliable than the current level standards dictate. It is always possible that a combination of high loads due to adverse weather coupled with a high rate of outages and lack of external support could result in curtailment of firm demand. By understanding and managing the associated risk factors, the possibility of 4

21 load shed can be drastically decreased. Such curtailment is considered to be a very low probability event for this summer because the increase in capacity has been greater than the increase in demand, and fuel scarcity is not projected to be an issue. 5

22 2. Demand The unrestricted non-coincident peak demand of 112,701 MW is the sum of individual coincident forecasts from the Load Serving Entities (LSEs) in the Midwest ISO. Taking a four-year average of the estimated diversities from the summer seasons in and applying the value to the unrestricted non-coincident peak demand establishes the total internal demand of 107,629 MW. The total internal demand is the forecasted coincident number after applying the estimated diversity. The difference between unrestricted non-coincident demand and total internal demand reflects the four-year average of estimated diversities and amounts to 5,072 MW. Reducing the total internal demand by demand resources, namely direct controlled load management and interruptible load, results in the net internal demand of 104,288. Demand (MW) vs. 09 Unrestricted Non-Coincident Peak 112, , % Estimated Diversity 5,072 4, % Total Internal 107, , % Direct Control Load Management * % Interruptible Load *2,874 1, % Net Internal Demand 104, , % *2009 values used to estimate for 2010 forecasts Note: Other 2010 values reflect data as of 3/8/2010 Table 2-1: Midwest ISO 2010 Summer Load Due to the implementation of Module E provisions in the Midwest ISO Tariff and the advent of the Module E Capacity Tracking (MECT) tool, Demand Resources, External Designated Capacity Resources, and BTMG were not finalized when this report was drafted. Typical values from the 2009 Post Summer assessment were utilized to forecast in place of the pending designations. The Midwest ISO does not create the load forecast for the Summer Resource Assessment. Instead, load projections are reported by Network Customers under the Resource Adequacy Requirements section (Module E) of the Midwest ISO Tariff. Historically, reported load forecasts have been accurate as each member has expert knowledge of their individual loads. A closer look at the comparisons between 2009 forecasts and 2010 forecasts can be found in the following sections Demand Forecast The demands as reported by Network Customers are weather normalized, or 50/50, forecasts. A 50/50 forecast is the mean value in a normal probability distribution, meaning there is a 50 percent chance the actual load will be higher and a 50 percent 6

23 chance the actual load will be lower than the forecast. An unrestricted non-coincident peak demand is created on a regional basis by summing the coincident monthly forecasts for the individual Load Serving Entities (LSE) in the larger regional area of interest. The aggregate of the unrestricted noncoincident peak demand for summer 2010 are reported in the table below. June July August September 104, , ,414 98,570 Table 2-2: Unrestricted Non-Coincident Demand by Month Historically, the Midwest ISO has experienced an annual load growth between a 1.5 and 2.0 percent. Then in 2008 and 2009, the slowing economy had a significant effect by decreasing load forecasts and extinguishing load growth. The forecasts for the 2010 summer season have been considerably affected by the Iowa and Dairyland Integrations and an overall 5.2 percent increase in the unrestricted non-coincident peak demand is expected compared to The table below shows the differences in summer peak total internal demand Forecasts by Planning Region. Region 2010 (MW) 2009 (MW) Change From 2009 West 38,099 31, % East 36,987 38, % Central 37,615 37, % Midwest ISO 112, , % Table 2-3: Unrestricted Non-coincident Peak Demand by Region Using four years of historic market data, a load diversity factor was calculated by observing the individual peaks of each Local Balancing Authority and comparing them against the system peak. This resulted in a.955 diversity factor. By taking the product of the diversity factor and the unrestricted non-coincident peak demand, the Midwest ISO is able to estimate a Total Internal Demand. As shown in Table 2-3, the Total Internal Demand for the 2010 summer is 107,629 MW, which is 5.0 percent higher than last year s demand. Region 2010 (MW) 2009 (MW) Change From 2009 West 36,385 30, % East 35,322 36, % Central 35,922 35, % Midwest ISO 107, , % Table 2-4: Total Internal Demand 7

24 2.2. Demand Resources Demand Resources reduce the total internal demand to arrive at the net internal demand. Demand Resources were pending final designations at the time of this report due to the timing of the Demand Resources registration process. The Midwest ISO currently separates Demand Resources into two separate categories, Direct Controlled Load Management and Interruptible Load. Direct Controlled Load Management is the magnitude of customer service (usually residential) that can be interrupted at the time of peak by direct control of the applicable system operator. Direct Controlled Load Management is typically used for peak shaving. In the Midwest ISO, air conditioner interruption programs account for the vast majority of Direct Controlled Load Management during the summer months. The Midwest ISO forecasts 467 MW of Direct Controlled Load Management for the upcoming summer season. Interruptible Load is the magnitude of customer demand (usually industrial) that, in accordance with contractual arrangements, can be interrupted at the time of peak by direct control of the system operator (remote tripping) or by action of the customer at the direct request of the system operator. The Midwest ISO forecasts 2,874 MW of Interruptible Load for this summer season Behind-the-Meter Generation (BTMG) A FERC Order issued on February 19, 2009 required that Behind-the-Meter Generation (BTMG) be treated as a capacity resource as opposed to a demand reducing resource as has been done previously. While this change does not affect reported BTMG levels it does affect the net load forecasts and reserve level calculations. In the Midwest ISO Market there are approximately 4 GW of generation capacity that Market Participants designate as a capacity resource which does not participate in the Market. This capacity is referred to as BTMG generation. The Midwest ISO forecasts 4,042 MW of BTMG for the upcoming summer season Net Internal Demand Net Internal Demand is the Total Internal Demand less Demand Resources. At the peak hour, it is this value that is expected to be metered in real-time. Another way to look at Net Internal Demand is that it represents the MW of firm demand during the summer peak. When calculating Net Internal Demand for this assessment, it is assumed that all Demand Resources are reducing demand at the reported levels during the system peak. For a reliability assessment, it is fair to make this assumption because all registered Demand Resources have an obligation to perform when called upon by the Midwest ISO. Note that the actual amounts of Demand Resources that may be called upon could be different from the maximum available because of the actual system conditions at the time of peak. 8

25 The projected Net Internal Demand for the Midwest ISO Market is 104,288 MW for the summer of A higher gross forecast offset by an increase in forecasted Demand Resources establishes the 2010 net internal demand to be 4.18 percent higher than the 2009 demand as detailed in the table below. Region 2010 (MW) 2009 (MW) Change From 2009 West 35,089 29, % East 33,824 35, % Central 35,376 35, % Midwest ISO 104, , % Table 2-5: Net Internal Demand (BTMG as Capacity) In order to better reflect the change in Net Internal Demand, BTMG is treated as a Demand Resource for both 2010 and 2009 in the table below. Treating BTMG in this way would more closely match the metered load at time of peak. Region 2010 (MW) 2009 (MW) Change From 2009 West 34,177 28, % East 31,903 33, % Central 34,165 33, % Midwest ISO 100,246 95, % Table 2-6: Net Internal Demand (BTMG as Load Modifier) 9

26 2.5. Load Forecast Uncertainty Calculations The Load Forecast Uncertainty (LFU) value is derived from variance analysis to determine how likely actual load will deviate from forecasts. In order to establish a Load Forecast Uncertainty (LFU) value for the summer period, four years of real time load data was compared to forecasts for those same periods. Load forecasts for the months of June, July and August were adjusted for the reported demand side management programs to arrive at coincident net internal demand forecast values. Those monthly forecasts were compared to the actual monthly peak loads of the same period and the differences compiled into a sample space to derive a standard deviation. A load forecast uncertainty of approximately 4 percent was calculated using this methodology, which accounts for roughly 4,050 MW of load variability applied to the summer projections. This uncertainty can then be used to form the normal distribution seen in the Figure below. In order to obtain a value which would most closely match an actual metered load value, this analysis treats BTMG generation as a load modifier. This curve represents all possible load levels with their associated probability of occurrence. At any point along the curve it is possible to derive the percent chance that load will be above or below a load value by finding the area under the curve to the right or left of that point. The 2009 actual market peak was 96,790 MW, the area to the left of this value represents a 20 percent chance that this year s peak will be less than 2009 s and the area to the right represents a 80 percent chance this year s peak will exceed that of Figure 2-1: Net Coincident Demand Probability Distribution 10

27 3. Capacity Resources Since the last summer season, 10,370 MW of nameplate capacity has been added to the Midwest ISO market. The Iowa and Dairyland integrations contributed significantly to this addition with 7,822 MW of nameplate capacity. The integrations also contributed 72 percent to the overall 2,008 MW of additional wind nameplate capacity added to the footprint. This overall addition reflects a 36 percent growth in the Midwest ISO s wind nameplate capacity since the prior summer season. Compared to the added capacity, retirements in the Midwest ISO were nominal with only 756 MW of nameplate capacity. The Midwest ISO Summer Assessment utilizes capacity values derived from various sources in order to produce a detailed analysis of the resource adequacy for the upcoming summer. Member reported data, nameplate capacities and historical analysis provide for a varied look at the capacity levels attainable throughout the summer period Midwest ISO Internal Generation The nameplate capacity represented in the figures below refers to the manufacturer s projected output of a given unit. The Midwest ISO projects 141,993 MW of nameplate capacity for the upcoming summer season. Coal units represented the largest class with approximately 52 percent of the capacity resources within the Midwest ISO Market. Gas fueled units accounted for 22 percent and wind units represented 5 percent of the fleet. A breakdown of the 2010 nameplate capacity by fuel type is represented in the figure below. Figure 3-1: Nameplate Capacity by Fuel Type 11

28 Without considering the new nameplate capacity added by the Iowa and Dairyland integrations, the Midwest ISO added 3,534 MW of new nameplate capacity in 2010 compared to the 2009 summer on an aggregate basis. Coal units were the most prevalent with approximately 51 percent of the new nameplate capacity. Wind added 16 percent to the new nameplate additions reflecting the growth in renewable energy resources in the Midwest ISO. Lastly, oil/gas added a comparable 22 percent to the new additions. The Midwest ISO experienced a 177 MW drop in nameplate capacity for gas since the prior summer. Since new nameplate for 2010 is calculated on an aggregate basis compared to 2009, gas is not represented in the chart below. The figure below reflects the new nameplate described above. Figure 3-2: New Nameplate since the 2009 Summer without New Members by Fuel Type The Iowa and Dairyland integrations contributed significantly adding 7,822 MW or 75 percent to the total nameplate capacity of 10,370 MW added to the Midwest ISO since the prior summer. Coal units were the most prominent fuel type added comprising approximately 58 percent of the added capacity. However, the integrations also contributed 1,444 MW or 72 percent to the 2,008 MW of total additional wind nameplate capacity added to the Midwest ISO since the prior summer. Lastly, oil/gas and gas units together accounted for approximately 21 percent of the additions for 8 percent and 13 percent of the additions, respectively. The figure below illustrates the new member nameplate capacity added to the Midwest ISO. 12

29 Figure 3-3: New Member Nameplate by Fuel Type Compared to the new nameplate capacity, retirements in the Midwest ISO were nominal with only 756 MW. Coal units were the most prominent amongst the others accounting for 66 percent and gas units accounted for 30 percent of the overall retirements. Oil, oil/gas, and wind combined were nominal representing less than 5 percent of the total retirements. The figure below illustrates the retirements since the 2009 summer by fuel type. Figure 3-4: Retirements Since the 2009 Summer by Fuel Type 13

30 Since the 2009 summer season, 10,370 MW of nameplate capacity has been brought into the Market. The Midwest ISO experienced a 2,008 MW or 36 percent growth in the amount of wind nameplate capacity from since the prior summer. Again, the Midwest ISO experienced a 177 MW drop in nameplate capacity for gas since the prior summer. Given that new nameplate for 2010 is calculated on an aggregate basis compared to 2009, gas is not represented in the chart below. Units that are known to be committed outside the Midwest ISO Market, including jointly-owned-units owned by non-market parties, were excluded from all capacity totals in this year s assessment. The fuel breakdown for this new nameplate capacity is detailed the Figure below. Figure 3-5: Nameplate Capacity Brought into the Market since the 2009 Summer by Fuel Type Under Module E and through the Module E Tracking Tool (MECT), Load Serving Entities (LSEs) are required to designate planning resources capacity to the Midwest ISO. LSEs can designate resources as internal, behind the meter generation (BTMG), demand response resources (DRR), or External Resources for each month of the planning year to meet their planning reserve margin requirements. The Nameplate Dispatch Capacity represented in the Figure below refers to the manufacturer s projected output of a given unit, minus the nameplate capacity of wind and Run of River hydro (ROR) units. The Summer Rated Dispatch Capacity obtains data from either Generator Availability Database Systems (GADS) or utilizes the nameplate capacity based on availability of data. If both values are available for a given unit, the Summer Rated Dispatch Capacity acquires the lower value between the two. The difference between the Summer Rated Dispatch Capacity and Committed Dispatch Capacity is represented as Not Designated in Module E. The Committed Dispatch Capacity adds both the Designated Wind Capacity of 197 MW 14

31 and the Designated ROR to arrive at the Internal Designated Capacity Resources. As mentioned above, LSEs are required to register BTMG, DRR, and External Resources in the MECT. The addition of these capacity values to the Internal Designated Capacity Resources establishes the 131,284 MW capacity represented as Total Designated Capacity. The Net Internal Demand is shown below to illustrate the reserve margin calculation. Not Designated in Module E, 6,983 Designated Wind Capacity, 197 Designated ROR Capacity, 374 BTMG, 4,042 DRR, 49 External Resources, 5,549 Reserve Margin, 26,996 (or 25.9%) *Nameplate *Summer Dispatch Rated Capacity, Dispatch 133,654 Capacity, 128,056 Committed Dispatch Capacity, 121,073 Internal Designated Capacity Resources, 121,644 Total Net Designated Internal Capacity, Demand, 131, ,288 *Nameplate Dispatch Capacity and Summer Rated Dispatch Capacity do not include wind or Run of River hydro (ROR) units Figure 3-6: Capacity/Resource Overview Data as of 3/8/2010, all values in MW Although there are 141,993 MW of nameplate capacity projected for the upcoming summer, not all are committed to serve load within the Midwest ISO. As shown in the Figure 3-6, the Internal Designated Capacity adds the committed BTMG, DRRs, and External Resources to arrive at the Total Designated Capacity. The Total Designated Capacity value represents the MW of capacity from the various resource types that are designated by LSE s towards meeting their Resource Adequacy Requirements in Module E. The figure below illustrates the fuel breakdown of the Total Designated Capacity which represents the projected capacity on the peak day of the 2010 summer season. 15

32 Figure 3-7: Total Designated Capacity by Fuel Type 3.2. Wind Availability Due to the intermittent nature of wind, there is no way to guarantee the wind capacity available on peak. As wind begins to comprise a greater portion of the Midwest ISO footprint capacity, this variability poses several potential issues. The Designated Wind Capacity referred to in the prior section represents the MW of wind capacity that has met all the requirements of Module E to be a Capacity Resource and has also been designated by an LSE towards meeting their Resource Adequacy Requirements. Currently, for Planning Year , the maximum wind capacity credit is determined by using a technique that calculates the Equivalent Load Carrying Capacity (ELCC) for wind generation. The ELCC method is linked to a Loss of Load Expectation (LOLE). Based on the estimated 9 GW of registered maximum wind capacity for the upcoming summer and the newly determined 8 percent capacity credit, a potential market capacity credit of approximately 700 MW is established for This 700 MW approximation represents an Unforced Capacity (UCAP) value for the wind capacity. For information on the wind capacity credit please refer to the 2010 LOLE Study, Section (2010 LOLE Report). The Table below details the wind performance metrics on peak for the previous five years. 16

33 Summer Metered Wind MW at Peak Load Registered Max MW % of RMax *Potential Market Capacity Credit MW % , % , % , % , % 1,127 Table 3-1: Wind Production at Peak (A 20 percent maximum wind capacity credit was applied through 2009 whereas an 8 percent maximum wind capacity credit was applied in 2010) 3.3. External Resources The Midwest ISO forecasts 5,549 MW of capacity from outside of the Midwest ISO footprint to be designated for use during the 2010 summer. This capacity is designated to serve load within the Midwest ISO and cannot be recalled by the source Transmission Provider. After examining historical data, it has been determined that this external designated capacity does not account for the entirety of external support that the Midwest ISO is capable of receiving. 17

34 4. System Conditions There are no foreseeable fuel delivery issues throughout the 2010 summer period. With no droughts or low water levels projected, hydro conditions are expected to allow for normal operations. Finally, there are no unusual operating conditions anticipated that could adversely impact reliability for the upcoming summer period. Various conditions are monitored through the summer period to ascertain their impact on the system. The following sections outline factors that could have an impact on available capacity Fuel A study of historical performance and reported projections provides an indication of the available capacity throughout the summer period, but considerations for fuel availability must be made. In previous years, fuel supply and delivery problems have had a significant impact on the available generating capacity. Droughts can affect the delivery of fuel by waterways as well as the availability of cooling water; rail bottlenecks and outages can affect coal stockpiles; and issues with natural gas pipelines can force plants to shut down Coal Coal generation represents approximately 54 percent of total designated capacity within the Market and is dependent on a resource in plentiful supply throughout the region. The main concern with coal fired generation is the delivery of coal to plants throughout the summer months. Coal delivery issues have been experienced in the past, but are not projected for this summer. However, it is possible that unexpected rail outages could impact generating capacity Gas Generation fueled solely by gas represents approximately 20 percent of total designated capacity within the Market. Peak storage conditions and demand for natural gas occur during the winter period; currently, there is no concern that the present storage levels will be insufficient for summer demand. 18

35 Hydro Hydro generation represents approximately 2 percent of the total designated capacity within the Midwest ISO Market and a significant amount of the external capacity. The region is not currently experiencing drought conditions. There is a low probability that water levels will create problems during summer peak conditions Transmission The Morgan-Werner West transmission project, spanning 47 miles of 345 kv lines, was placed in-service in the 2009 fall season and has alleviated common constraints in the northern Wisconsin area. The Paddock-Rockdale transmission project, also in Wisconsin, added 7.6 miles of new 345 kv transmission lines and 22.7 miles of upgrades to existing 345 kv lines placed in-service in January New 345 kv transmission lines are expected to be in service within the Midwest ISO before the 2010 summer season. Transmission lines spanning 54.6 miles will be added to the American Transmission Co. (ATC LLC) area. Four new bulk power transformers are also expected to be in service before the 2010 summer season. These will be in areas of American Transmission Co., Northern States Power Co., Great River Energy and Duke Energy Midwest. There are no significant transmission additions expected to be placed in-service during the 2010 summer season and there have been no transmission reliability concerns identified in the coordinated seasonal assessment currently in progress. For details on the transmission system please see the Coordinated Seasonal Transmission Assessment at: Coordinated Seasonal Assessments 4.3. Operations There are no anticipated problems due to generation or transmission outages for the upcoming summer period. No unusual operating conditions, which could impact system reliability, are expected. More information can be found here: 2010 Summer Workshop 19

36 5. Risk Assessment A Loss of Load Expectation analysis was performed on 13 different sensitivities to study various system conditions and evaluate potential risk levels for the upcoming summer. Due to high reserve margins forecasted, the model showed little to no risk for the 2010 summer season. The purpose of this analysis is not to determine whether enough resources will be available for the 2010 summer season, but instead, the objective is to point out the effects of changes in the operating conditions so that risk can be managed. Using the various levels of capacity, a Loss of Load Expectation (LOLE) study was performed over the summer season. This study concluded that little to no risk resulted with the various predicted states during the summer period Variables The risk analyses illustrate the affects of various conditions on the system. The LOLE Model, utilized for the Midwest ISO 2010 Planning Reserve Margin Study, was modified to reflect certain conditions which could be experienced this summer. Since load levels impact LOLE, both high and low load scenarios were studied without a standard variance on load. This approach ascertains the system risk with respect to varying levels of peak load. To account for the intermittency of wind generation, scenarios with no wind generation outputs were studied to get an understanding of the impact that lack of wind generation would have on the Midwest ISO footprint. Lastly, the availability of external support has a significant impact on system reliability during peak conditions. Therefore, in order to establish risk levels associated with the lack of external support, the Midwest ISO Market was also studied as an isolated system. 20

37 Capacity MISO has calculated 1,824 MW of Planned Outages after applying an outage rate to account for the number of hours each unit is out within the summer season. Generally, planned unit outages tend to be minimal during the summer peak. The majority of planned outages have been out for an extended period but have not been formally retired. The figure below incorporates the Planned Outages and the Average Forced Outage to the prior Capacity/Resource Overview figure. Not Designated in Module E, 6,983 Designated Wind Capacity, 197 Designated ROR Capacity, 374 BTMG, 4,042 DRR, 49 External Resources, 5,549 Planned Outages, 1,824 Average Forced Outage, 9,233 Reserve Margin, (or 15.3%) *Nameplate Dispatch Capacity, 133,654 *Summer Rated Dispatch Capacity, 128,056 Committed Dispatch Capacity, 121,073 Internal Designated Capacity Resources, 121,644 Total Designated Capacity, 131,284 Adjusted Resources, 120,227 Net Internal Demand, 104,288 *Nameplate Dispatch Capacity and Summer Rated Dispatch Capacity do not include wind or Run of River hydro (ROR) units Figure 5-1: Capacity/Resource Overview Data as of 3/8/2010, all values in MW The key statistic used for the Averaged Forced Outage is a unit s XEFORD, equivalent forced outage rate on demand. The X indicates the exclusion of events which are outside of management control. Examples of these events are natural disasters such as tornados, earthquakes, hurricanes, etc. By definition, the equivalent forced outage rate represents the percent of scheduled operating time that a unit is out of service and consequently, cannot reach full capability due to a forced component or equipment failures. Both derates and total forced events are captured using the equivalent forced outage rate. It is calculated in PowerGADS to acquire a three year weighted summer average XEFORD of 7.04 percent. Since PowerGADS does not calculate a wind XEFORD, the average rate was applied to the Total Designated Capacity less Designated Wind Capacity yielding 9,233 MW of forced outage. This is represented as the Average Forced Outage in the Figure above. 21

38 As illustrated in the Figure above, the Total Designated Capacity is reduced by the Planned Outages and the Average Forced Outages to establish the Adjusted Resources. Comparing with the Net Internal Demand, the resulting reserve margin is 15.3 percent. This reserve margin far exceeds the unforced capacity reserve margin of 4.5 percent Demand The Load Forecast Uncertainty (LFU) analysis described in Section 2.5 results in the formation of a normal distribution of load levels as seen in Figure 5-2. When analyzing variables along a normal distribution, it is industry standard practice to use 10/90 and 90/10 levels as outlying cases that represent the extreme values of load. These load values represent the load at which there is a 90 percent chance the peak will exceed this level in the case of the 10/90 forecast and a 90 percent chance that the peak will be lesser than the level represented by the 90/10 forecast. For reference, the highest peak experienced by the Midwest ISO was at an 85/15 load level. These values are represented in Figure 6-1 as the Low and High Cases with the Mid Case representing the reported coincident net internal demand around which the normal distribution is constructed. This year s Loss of Load Analysis utilized the model created for the 2010 LOLE Report in order to more accurately reflect the varying sensitivity s affect on the system. In order to utilize this model the percent load change between cases was utilized to modify the LOLE model with the Mid Case being assumed as the default load levels. In the high load case the load within the model was multiplied by approximately in order to achieve a high load model with a multiplier applied for the low load case. 22

39 Figure 5-2: Case Summary of Net Demand Wind availability Based on Module E, 197 MW has been designated wind capacity for the 2010 summer season. To simulate a peak period when wind is unavailable, this capacity was removed from the model External Support A tie capacity of 6,320 MW to the external world was modeled when the Midwest ISO reserve margin was established. Altering the tie limit to 0 MW simulated a peak day when all neighboring footprints were unable to supply support Risk Analysis Risk analysis was performed on 13 case studies, ranging from the base case to no wind and no external generation scenarios. This range represented a diverse combination of variables. A risk level was determined for each case. In the event that system conditions should exceed the levels modeled within this analysis, these results would no longer be applicable. Cases were run through an existing model developed for use in establishing reserve margins under Module E. This model closely resembles the systems available capacity and transmission limitations. Beyond the sensitivities explored within this analysis, further information regarding the model and original Loss of Load Expectation study used to establish reserve margins can be found at the following link: 23

40 2010 LOLE Report 5.3. Findings Each case provided a LOLE value which estimates the percent probability that there will be insufficient resources for that case. Every case estimated little to no risk of insufficient resources Case Summaries The three states of load input to the model were: Base: The load input to the model was left as established for the original LOLE study. Low Load: The load was adjusted by High Load: The load variability was adjusted by For each of these load inputs four different capacity levels were modeled: Base: The capacity modeled was left as established for the original LOLE study. No Wind: A wind capacity of 0 MW was modeled. No External: External tie capacity of 0 MW was modeled. No Wind and No External: Both wind and external tie capacities were set to 0 MW. High Load Base Low Load Base 0.0% 0.0% 0.0% No Wind 0.0% 0.0% 0.0% No Externals 0.0% 0.0% 0.0% No Wind and No Externals 0.0% 0.0% 0.0% Table 5-1: Risk Analysis Case Summary A LOLE of one day in ten years is an industry standard benchmark for minimum system reliability. In this analysis, no cases exceed this benchmark System As-Is Analysis In order to establish the risk level most likely experienced by the system during the upcoming peak; the adjustments made to the Loss of Load Expectation model in order to drive the system to a one day in ten condition were removed. This entailed removal of all capacity decrements leaving all generation within the system available to serve load. In such an ideal condition the system experienced a Loss of Load Expectation of 0.0 percent. 24

41 Variable Sensitivity Analysis Using cases with load adjusted to high levels, it was possible to examine each sensitivity and it s impact on LOLE. The Figure below demonstrates no risk for the ideal case and for each sensitivity added. Figure 5-3: LOLE Sensitivity to Variable Adjustment Case Comparison As the reserve level of the system declines, it is expected that associated risk levels rise exponentially. However, the figure below reflects no risk for the 2010 summer without reserve margin adjustments. 25