Phase Two Wind Integration

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1 Phase Two Wind Integration RECOMMENDATION PAPER Kelly Gunsch, Vice-President, Market Services Date: December 20, 2012 Prepared by: Mariya Goloshchapova, Wind Integration Intern cc: Jacques Duchesne, Wind Integration Program Manager Miranda Keating Erickson, Director Market Design Department: Market Services

2 Table of Contents 1. Executive Summary Purpose Background Short-Term Wind Integration Recommendation Paper Phase Two Wind Integration Discussion Paper Wind Work Group Sessions Summary Policy Coherence Guiding Principles Options Analysis Considered Options Reliance on the EMMO Refine Short-Term Recommendations Wind Firming Service Recommended Options Recommendations Investigate Options to Make Wind Dispatchable Explore the Need for a System Ramping Service Wind Ramping Events Impact of Over-dispatching the EMMO Possible Ramping Service Design Alter Regulating Reserve Technical Requirements Investigate Pay For Performance Element in the Regulating Reserve Market Next Steps Appendix I Stakeholders Feedback to the Phase Two Discussion Paper... 16

3 1. Executive Summary Wind power in Alberta has seen substantial growth in the last few years. As of November 2012, 1087 MW of generating capacity from 16 wind facilities is connected to the transmission system, representing 7.5 per cent of total installed generation capacity. There continues to be strong interest in building more wind generation in the province; there are currently more than 3200 MW of wind generation projects in the AESO connection project queue. The AESO June 2012 Long-term Transmission Plan 1 estimates a total of 2500 MW of wind generation by 2020 in the baseline scenario. However, there are implications of connecting more wind into the Alberta interconnected electric system (AIES), particularly with regard to wind variability. In September 2010, the AESO released the Short-Term Wind Integration Recommendation Paper 2 that identified measures to address up to 1100 MW of wind capacity, with sensitivities tested for up to 1500 MW of capacity. These measures are currently in implementation as Phase One of the program. This recommendation paper describes the proposed measures to integrate increasing wind capacity beyond 1500 MW. In December 2010, the AESO released the Phase Two Wind Integration Discussion Paper 3 that identified and analyzed options to integrate variable generation on the system in the long term. The six options identified were: 1. Reliance on the energy market merit order; 2. Increase of regulating reserve volumes; 3. Refinement of short-term wind integration recommendations; 4. Development of a ramping service; 5. Development of a wind firming service; and 6. Development of must offer must comply (MOMC) rules for wind. The options identified were not necessarily meant to be mutually exclusive or utilized as standalone methods to deal with wind integration. In order to obtain external feedback, the AESO formed an industry Wind Work Group and held twelve sessions to discuss the options with stakeholders, eventually having them rank the options according to several criteria. These options were also evaluated and analyzed in the context of the AESO mandate to promote a fair, efficient and openly competitive (FEOC) market, as well as operational needs and implications. This recommendation paper follows on from the discussion paper and advises on the options in greater detail. Wind being dispatched through the merit order, together with possible changes to regulating reserves to incorporate a new ramping service are the recommended solutions to be explored by the AESO in Phase Two (beyond 1500 MW) of its Wind Integration Program. Specifically, the AESO recommends the following: 1. Investigate options for allowing wind to participate in the energy market merit order; 2. Explore the need for and development of a new system ramping service, including the possibilities of: a. changes to the regulating reserve technical standards; and b. options for altering the payment structure of the regulating reserve. The AESO will consult with stakeholders on the recommendations in this paper and will post responses to stakeholders comments prior to proceeding with implementation. The timing of implementation of the various recommendations may be spread over a significant period of time Page 1

4 2. Purpose This paper aims to inform stakeholders about the AESO recommendations to facilitate further integration of wind generation in Alberta. The AESO is committed to developing market-based solutions that will enable the integration of more than 1500 MW of wind to the AIES. These solutions will facilitate sustainable market development, send clear market signals in the context of Alberta s electricity framework and increase system flexibility while maintaining reliability of the AIES. They will also support the development of new technologies and increase opportunities for demand-side participation in the Alberta market. 3. Background 3.1 Short-Term Wind Integration Recommendation Paper The Short-Term Wind Integration Recommendation Paper, released in September 2010, outlined the first phase work required to integrate wind into the Alberta market. These Phase One recommendations were intended to enable the reliable operation of the system with approximately 1100 MW to 1500 MW of wind connected, and were implemented in 2011 and Phase Two Wind Integration Discussion Paper The Phase Two Wind Integration Discussion Paper, released in December 2010, explored a range of potential options to integrate larger volumes of wind on the AIES. Each identified option has different potential impacts on the investment signal in Alberta. The paper highlights advantages and disadvantages of each option identified. Costs associated with integrating variable generation are also borne by different groups under each option. These high level options indicate the range of market design choices that could possibly be used to successfully integrate variable generation in the long term. The options were not meant to be mutually exclusive; elements of one approach could ultimately be combined with elements of other approaches in order to find the overall plan that best supports the FEOC operation of Alberta s market. The six options identified were: 1. Reliance on the Energy Market Merit Order - This option would rely strictly on dispatching units in the energy market to absorb the variability associated with wind generation. No new services or market rules would be developed to integrate wind generation. 2. Increase regulating reserve volumes - This option would involve procuring larger volumes of regulating reserves within the existing ancillary services product design to absorb wind variability. 3. Refinement of Short-Term Wind Integration Recommendations - These recommendations, also identified as the phase one plan, could potentially evolve to see the development of a market service for wind power management (WPM) and a new ancillary service to act as replacement energy when wind ramps down. 4. Development of a ramping service - A ramping service could be used to keep the system in balance when the EMMO cannot maintain the energy demand balance without over dispatching. Separate ramp up and ramp down services could be developed to allow assets such as wind generators to participate in the ramp down service and load to participate in the ramp up service. 5. Development of a wind firming service - A market service could be developed to firm overall wind production. This service would be tied directly to firming total wind output and would not be used to manage other system events. 6. Development of must offer must comply (MOMC) rules for wind - MOMC rules would obligate wind to offer their energy and follow a dispatch on a similar basis as other generators. Page 2

5 The continued development and improvement of the wind power forecast is an important element of all the above proposed options. Reducing the uncertainty associated with individual wind generation facilities allows all the available options to function more efficiently. A summary of and the AESO responses to the Phase Two Discussion Paper comments by stakeholders are provided in Appendix I of this paper. 3.3 Wind Work Group Sessions Summary After the release of the Phase Two Discussion Paper, a Wind Work Group comprised of industry stakeholders was formed to discuss those options and to help the AESO better understand the perspective of market participants. The AESO conducted a total of twelve Work Group sessions and released a paper summarizing the output of the sessions 4. The feedback received from stakeholders was organized through a ranking by the participants utilizing the Kepner-Tregoe (KT) approach. The results indicated a ramping service was the option most preferred by stakeholders, whereas the MOMC option received the least support. Stakeholder opposition to the MOMC option centered on FEOC concerns as well as potential compliance issues for wind generators. The new ramping service garnered positive support based on a number of reasons, including that it is a market based solution that provides clear market signals. Stakeholders indicated possible drawbacks of the ramping service are the time to implement, high cost and complexity of the solution. 4. Policy Coherence As stated in the Electric Utilities Act (EUA), it is the mandate of the AESO to exercise its powers and carry out its duties, responsibilities and functions in a timely manner that is fair and responsible to provide for the safe, reliable and economic operation of the interconnected electric system and to promote a fair, efficient and openly competitive market for electricity 5. The ISO duties outlined in Section 17 of the Electric Utilities Act provide direction for wind integration. In particular, 17(a) through 17(c) and 17(i) are relevant for the purposes of developing a framework to integrate wind power: The Independent System Operator has the following duties: (a) to operate the power pool in a manner that promotes the fair, efficient and openly competitive exchange of electric energy; (b) to facilitate the operation of markets for electric energy in a manner that is fair and open and that gives all market participants wishing to participate in those markets and to exchange electric energy a reasonable opportunity to do so; (c) to determine, according to relative economic merit, the order of dispatch of electric energy and ancillary services in Alberta and from scheduled exchanges of electric energy and ancillary services between the interconnected electric system in Alberta and electric systems outside Alberta, to satisfy the requirements for electricity in Alberta; (i) to assess the current and future needs of market participants and plan the capability of the transmission system to meet those needs Division 2, section 16, p. 24 Page 3

6 Wind power integration raises a number of challenges for the electricity industry, and while a range of technical solutions generally exist, there are high level questions surrounding what the FEOC operation of the market means with respect to wind integration. The legislative and policy background provides general guidance for market design along with specific guidance for the integration of wind energy. The 2005 Market Framework states: 6 The Department does not support one type of generation over another but rather allows competitive market forces to determine the appropriate generation mix (e.g. no fuel use policy). As a result, the Department does not support market refinements that will create an uneven playing field or be detrimental to the development of renewable resources. Environmentally friendly power generation benefits all customers with a cleaner environment and reduction in environmentrelated health problems. It also assists Alberta in meeting environmental emission targets under Clean Air Strategic Alliance (CASA). The 2005 Market Framework also makes clear that all fuel sources should be free to compete in the market on an equivalent basis: Suppliers using diverse fuel sources will compete for the opportunity to sell their products, based on a straightforward and transparent market framework, minimal barriers to entry, and a level playing field. In December of 2008, the government of Alberta released the Provincial Energy Strategy 7 (PES) which included a long-term action plan for Alberta. The goals of the plan include clean energy production, wise energy use and sustained economic prosperity: Generation sources are becoming more diverse as renewable energy grows, testing the grid in new ways and creating pressures not experienced before. Our system also remains one of the least interconnected in the country with limited capacity to either import or export electricity when necessary to maintain the integrity of the grid. This creates challenges for safety, reliability and affordability. Our electricity system will play a large role in delivering more and cleaner energy to Albertans in years to come. (p. 11) Therefore, the support for renewable energy development (p. 24) is one of the strategic targets of the government that guides the AESO in its wind integration efforts. 5. Guiding Principles The AESO s wind integration program is guided by five major principles that were outlined in the Phase Two Discussion Paper 8. These principles reflect the AESO s duty to provide for the reliable operation of the system and promote a FEOC market. The AESO is committed to utilizing a holistic approach and not viewing the implementation of one option without considering its potential impact on the entire energy market. Therefore, in evaluating recommendations for long-term wind integration, the AESO has considered, among others, the following two criteria: 6 Alberta Department of Energy, Alberta s Electricity Policy Framework: Competitive, Reliable, Sustainable. June 2005, Pages 47-48, page p.7 Page 4

7 1. Efficient market mechanism: The market should be operated in a way that stimulates competition among the participants and turns to administrative solutions as a last resort. The policies and structure should create price signals that inform both short and long-term decisions. They should allow the market to respond to system needs in an economic manner. Lastly, the market should provide incentives to increase system flexibility, and provide at least some incentive to wind to manage what can be controlled (i.e. wind ramp up events). 2. Fair and Open Competition: As a generation source, wind should be treated similarly to other generators, with neither privileges nor barriers to competition. This principle also supports the taking into account of each generator s unique characteristics. Wind should be considered the same as any other fuel source in terms of how ancillary services are used to backstop generation on the system in the event of contingencies. All generators are required to support system reliability. Moreover, as an additional consideration, the AESO looked at stakeholders comments and preferences based on the Work Group output. After the presentations and discussions of the options at the Work Group meetings, stakeholders were invited to voice their opinion through ranking of the options they saw as the most and the least desirable. The AESO documented the comments of the stakeholders and took into consideration their perspective in the further development of wind integration recommendations. 6. Options Analysis 6.1. Considered Options Reliance on the EMMO Dispatch via the EMMO is a central tenet in the Alberta energy market design. The underlying idea of this option is always dispatching the full capability of the EMMO to balance supply and demand in real-time. The EMMO thus delivers a ramping service to the market, as it is expected that multiple offers could be dispatched for a short time to achieve the required ramp rate. This is how ramping events have been handled to date. In an energy-only market, the EMMO should always be the first tool used to balance supply and demand in real time and provides a critical price signal for future generation investment, including both timing and technology choices. However as the magnitude of ramping events increases with the continued addition of wind resources, the operational inefficiencies of very short term dispatches simply to achieve the desired ramp rate may become a significant challenge for other generation technologies 9, and the resulting very short term price volatility may not be desirable. This option is one that requires the least effort in terms of implementation, but was not strongly supported by the stakeholders as a stand-alone solution; they felt it should be supplemented by other tools. The AESO generally agrees that the need for other tools to supplement the EMMO should be further explored, but is not entirely convinced given development and evolution in the industry Refine Short-Term Recommendations This option emphasizes the use of wind power management (WPM) when the EMMO cannot handle the intensity of the ramping events. WPM is an administrative way to limit wind generation when it is ramping up very quickly. Whenever wind ramping events are expected to exceed the system wind power limit, 9 More information on the impact of cycling baseload facilities is available in a report produced by Intertek APTECH for the National Renewable Energy Laboratory (NREL) and Western Electricity Coordinating Council (WECC) to support their renewable integration studies: Page 5

8 each wind power facility receives a pro rata share of the overall limit. This method is being currently utilized by the AESO. The AESO does not recommend this option for Phase Two wind integration other than as a last resort, as the frequency of use would be expected to increase significantly. With a higher amount of wind being integrated in the AIES, more wind would be spilled through the curtailment directives, reducing the efficiency of the solution Wind Firming Service A Wind Firming Service was suggested in order to address the issues of uncertainty and variability that are associated with a higher amount of variable energy on the grid. Ensuring firm wind supply would ease system control procedures and create conditions facilitating the treatment of wind like other generators. The key suggestion from the AESO was to implement this service centrally rather than at each facility, however, other options such as contracts with other generators and/or use of energy storage technologies were not disregarded. Although the AESO does not completely discount this option at some point in the future, it is not recommended in Phase Two. There are advantages and disadvantages to wind firming. One of the challenges with this option is the debate raised by stakeholders regarding the definition of firm energy supply. There is no other generator that is obliged to supply energy 100 per cent of the time; therefore it is not fair for wind to face this requirement. In the Wind Work Group ranking, this option was among the two least preferred. The Alberta Innovates Report on Energy Storage 10 (ES) considered the possibility of the use of energy storage by wind power facilities in Alberta. A major proposition of the report was that wind facilities could benefit from ES through profit shifting in the form of creating energy arbitrage and firming. The study also suggested the possibility of ES enabling wind participation in the AS market. Although more research is yet to be done in order to confirm their results, the study concluded that time shifting would be more profitable than firming. In order to recover the investment costs for the cheaper of the two suggested ES technologies (compressed air energy storage over sodium sulphur batteries), the wind facility would have to operate at least 20 years, making the use of ES for wind firming currently uneconomic. This option could be considered again in the future, if energy storage technology becomes less expensive and more efficient. Energy storage may support wind industry development in other ways, through enabling its participation in the AS market, facilitating higher revenues through arbitrage opportunities and the storage of the energy that would otherwise be curtailed because of high wind ramps. The AESO suggests this option may be explored again at some point in the future Recommended Options The AESO recommends further exploring a blend of the other three options outlined in the Phase Two Discussion Paper primarily wind dispatch via the merit order, with further exploration around the development of a new ramping service combined with changes to regulating reserves. The key recommendations are: 1. Test options for allowing wind to participate in the energy market merit order. 2. Explore the need for the development of an ancillary service for mitigation of system ramping events, separated into three components: regulating service, ramp up and ramp down. Regulating service would respond instantaneously to energy supply and demand imbalance on a second-to-second and minute-to-minute basis. Ramp down and up services would work in 10 Page 6

9 conjunction with the EMMO to balance supply and demand during significant system ramps. This would include: a. Possible changes to the regulating reserve technical standards to support the long-term plan to split regulating reserve into ramping and regulating components. These changes are intended to also allow technologies such as storage devices and demand resources to participate. b. Exploring options for altering the payment structure of the regulating reserve market to tie compensation to performance. Each of the subsections in chapter 7 provides further detail on the above recommendations. The options are presented with varying degrees of detail as some of the recommendations require significant further stakeholder consultation prior to any implementation. The overall intent of the Phase Two recommendations is to ensure high fidelity market signals that deliver operational flexibility as well as incent investment decisions that facilitate the safe, reliable and economic operation of the market. 7. Recommendations 7.1 Investigate Options to Make Wind Dispatchable Wind does not currently enter an offer into the EMMO, and as such, is only directed by the AESO for reliability reasons such as transmission limitations. Wind is, in effect, a passive participant in the energy market; it is not dispatched under normal conditions, and does not have the ability to indicate price responsiveness through an offer. Since wind generation does not currently offer into the merit order, higher amounts of wind energy in the market will result in growing amounts of generation that acts as a price taker. Participation in the market through dispatch is a trend for wind generation throughout the world as the amount of wind generation increases. Independent system operators such as NYISO, MISO, ERCOT, and PJM are already dispatching wind. The specific terms and conditions for enabling wind to be dispatchable vary from jurisdiction to jurisdiction due to differing market designs; however, at a minimum the majority of markets have developed an option for wind to participate in the market. The AESO recommends wind generators should, at a minimum, have the option to participate in the EMMO. In order to accommodate this, the AESO will work to develop the rules, guidelines and practices that will be used for wind dispatch. Initially, the AESO recommends that having wind actively participate in the market should be voluntary, while mandatory participation continue to be explored. In addition, the AESO will examine the potential for wind generators to sell services such as DDS, and potentially some ancillary services. The key benefits of allowing wind to be dispatchable are: Creates greater visibility of expected wind generation for the system controller and allows wind to be dispatched up in a controlled fashion. Treats wind more consistently as compared to other generators. Creates an incentive for more accurate wind forecasting. Allows wind to actively participate in the market through energy offers. Potentially results in less frequent occurrences of supply surplus conditions. Page 7

10 Allowing wind to be dispatchable will not require wind to procure backup generation or other infrastructure. The intent is that wind be allowed to re-state its capability based on the short-term wind forecast. If the capability falls in real-time, the lack of wind will be considered an acceptable operating reason (AOR) for the lack of supply, assuming accurate forecasting data (per ID R) was supplied by the market participant. When capability increases due to wind conditions, wind generators will be allowed to restate their capability but will be dispatched up by the system controller based on their position in the merit order. As a first step towards implementation of this recommendation, the AESO initiated a wind dispatch pilot project with one market participant on May 8 th, It involved two wind assets using the terms described above. The pilot project term was 6 months and it aimed to test the ability of wind facilities to be equivalent to other generators in terms of energy dispatch requirements and participation in the energy market merit order, given existing ISO rules. The preliminary results of the pilot will be published in early On November 6 th 2012, the AESO extended the option to participate in the wind dispatch pilot to all existing wind generating facilities, and intends to extend the pilot with broader participation. This recommendation will be the AESO s first priority within the Wind Integration Program in Explore the Need for a System Ramping Service The analysis outlined in the Phase Two Discussion Paper suggests that as the amount of wind on the system increases, there is the potential for an increase in frequency and magnitude of area control error (ACE) events 12. Table 1 presents summary causes for all large ACE events modeled under different simulation scenarios. Table 1 Count of ACE Events 13 Name Wind Capacity Count of ACE events Categorization: W = Wind, L = Load, T = Tie Year Forecast Type W WL WT WLT Other w/ Wind Other (Tie & Load) 2011 Baseline Persistent MW Baseline Persistent MW Perfect Forecast Perfect Baseline Persistent MW Perfect Forecast Perfect Baseline Persistent MW Perfect Forecast Perfect Green Persistent MW Green Perfect Forecast Perfect Total The unscheduled flows average 200 MW and wind variability contributes to the majority of the events, either alone or together with the tie lines and load 14. The number and magnitude of events also increases as the amount of wind capacity on the system grows. In order to mitigate these events, the AESO has to either use standby contingency reserves or over-dispatch the EMMO to reach the required ramp rate level. In effect, the incremental contingency reserves are being used as a proxy for a ramping service in the upward direction. This approach is not ideal in the longer term because it requires standby reserves to be activated prior to a wind ramp down event, and it uses contingency reserves for a purpose that is not part of their original intent, which is as back-up in the event active providers are unable to provide. Therefore, the AESO is interested in exploring the development of a ramping service that would be a new Area Control Error (ACE) is unscheduled flow over the BC interconnection. For example, if Alberta was scheduled to have a zero schedule for a given hour (no imports or exports), ACE would be measured by actual flows of imports or exports, ignoring frequency deviations and payback of inadvertent energy flows. A number of NERC reliability standards determine acceptable ACE performance, and the results of the analysis are measured against these standards. 13 The baselines of the wind generation levels mentioned in the table were modeled in the discussion paper. These assumptions are consistent with the overall supply and demand assumptions in the AESO s Long Term Plan for the detailed ACE effect analysis, please refer to p.7 Page 8

11 product allowing system ramp requirements to be met without over dispatching the EMMO or the purchase of incremental regulating reserves Wind Ramping Events One can observe the number of ramping events caused by wind through the following analysis. In 2011 there were on average 18 wind ramping events per month that exceeded the rate of 7 MW per minute for a 10 minute period. Extreme ramping events of 100 MW or more were observed on average 5 times per month or once every week. The maximum variance averaged 121 MW for wind ramp up events and 119 MW for ramp down. Out of the total count of 212 ramping events, ramping down was registered 108 times and ramping up was registered 104 times. Therefore ramping events were somewhat evenly distributed in both directions. Table 2 Minute by Minute Wind Ramping Events for 2011 Month 10 Minute Ramp Events MW max variance 7 MW/ Minute 10 MW/ Minute Up Down January February March April May June July August September October November December Total Average Figure 1 Historical (2011) Maximum Ramp Up and Down Events Figure 1 shows the fastest ramp up and down events of The most rapid ramp up event was registered on August 30th with 777 MW of total wind installed capacity. There was a ramp of 148 MW within 10 minutes (reaching 390 MW in 52 minutes). The projected values for a similar ramp event given 2000 MW on the grid (Figure 2) show the potential for over 1000 MW of wind ramp up within 50 minutes. Page 9

12 For ramping down events the fastest event of 2011 was on January 27 th, dropping 174 MW within 10 minutes (reaching a max of 229 MW in 22 Minutes). The projections for the same ramp down event given 2000 MW are 590 MW within 22 minutes (Figure 2). Figure 2 Projected Maximum Ramp Up and Down Events for 2000 MW of Wind As one can see from Figure 2, a ramping service could potentially be a valuable tool for reliable electricity supply in the future with higher volumes of variable energy in the AIES. The system may, with increasing wind volume, not have capacity to keep relying on standby contingency reserves to cover abrupt wind movements, and instances of issuing Wind Power Management limits and/or over-dispatching the EMMO may increase Impact of Over-dispatching the EMMO There are two outcomes of over-dispatching the EMMO to deal with system ramp events: operational wear and tear on other suppliers in the merit order and the resultant short-term price volatility. From an operational perspective, some forms of electricity supply are very flexible and are able to ramp very quickly, such as hydro facilities, some natural gas-fired generators and intertie flows. Others, particularly thermal and other typically baseload facilities, have much slower ramp rates and little flexibility to enable them to change direction quickly. Thus, depending on the current position in the merit order, the ramping capability of the EMMO to offset large system ramps may vary greatly. When an extreme ramping event occurs, if the next suppliers in the merit order are all slower ramping, many of them many need to be dispatched for a very short period of time to achieve the required ramping speed to offset the system ramp, then asked to change direction very quickly once the EMMO has caught up. For inflexible generation, this can create operational challenges and in the long term may increase wear and tear. An example of price impact can be illustrated through an event on May 28 th of From hour ending (HE) 11 to HE 12, 445 MW of imports on the BC intertie came offline in the 20 minutes that are used to ramp the intertie. During this time there was a clear over-dispatching of the merit order in order to maintain the supply/demand balance, and SMP briefly reached $996/MWh in response to the ramp requirement. Figure 3 illustrates a case where the system needed to achieve a ramp rate up of 22.5 MW/minute for a 20 minute period. In response to this, SMP increased from $46/MWh at 10:30 to $996/MWh at 10:49. After the ramping had occurred, SMP returned to $78/MWh by 11:20. This resulted in HE 11 and HE 12 having increased pool prices as a result of the higher SMPs during this period. For HE 11 without ramping, it is estimated that pool price would have settled at $41.80/MWh instead of $304.39/MWh. Similarly, for HE 12, price settled at $230.43/MWh due to the dispatch of higher price units to meet the Page 10

13 ramp during the first 20 minutes, whereas if the dispatch level that was achieved after the ramping had set price, pool price would have been $76.98/MWh. Figure 3 Over-Dispatching to Get a Faster Ramp Rate Up 15 Figure 4 Over-Dispatching to Get a Faster Ramp Rate Down The ramp down case is illustrated in Figure 4, where the system needed to achieve a ramp rate of MW/minute for the 20 minute period. In response to this, more generation was dispatched down than what was required to meet the energy change only. This resulted in lower SMPs than would have been 15 The over-dispatched generation is the generation that was dispatched only for ramp rate. The total generation level is adjusted to reflect the replacement generation required. Page 11

14 realized if the dispatches were for energy only. In this situation pool price in HE 14 settled at $60.81/MWh, but if there was no ramping, the pool price would have been $65.25/MWh. In HE 15, pool price was $28.14/MWh, but without the over-dispatch the price would have been $34.00/MWh. As illustrated in this set of examples, using the merit order to over-dispatch for ramp rate can impact price substantially in the very short term, particularly when over-dispatching to ramp up units, when high ramp rate units may be located substantially higher in the merit order. The development of a ramping service specifically for those extreme system ramps that exceed the capability of the EMMO could reduce this very short-term volatility and the associated operational concerns from short-term dispatches. There remain, however, significant questions about the requirement for this ramping product. As the industry evolves in Alberta to include newer, faster-moving and more flexible forms of generation, as it integrates more demand response and new technologies such as large-scale energy storage, and as wind generation itself evolves technically and becomes dispatchable via the merit order, the need for any ramping product may be temporary, if at all. In fact, the short term dispatches and resulting price changes may signal the need for these other changes to evolve more quickly. For these reasons, the AESO intends to update its models with new information, and strike an industry work group to further explore both the need for, and the design of, a ramping service Possible Ramping Service Design The ramping service would be dispatched only when the system ramp requirement is greater than the EMMO can provide. In determining whether to dispatch the ramping service, the AESO would calculate the available ramp rate from the EMMO based on current conditions, as well as expected changes in load and the net intertie schedule. Qualified market participants who offer the service would get paid a premium for ramp rate dispatches in addition to the payment for energy production at pool price. This ramping service would provide a direct price signal for both upward and downward ramping capability. It would be designed to be used for short periods whenever the net change in the supply demand balance is greater than can be accommodated by energy market dispatches. This can occur due to changes in load, intertie schedule changes, wind generation, or other changes that significantly alter the supply demand balance. The key challenge in developing the service is to create a transparent mechanism to distinguish between energy market dispatches and ramp rate dispatches. This service is not unique to Alberta. Other energy markets that are characterized by high volumes of variable energy are also challenged by system reliability concerns and abrupt, short-term dispatches and price volatility. Such ISOs as CAISO, MISO, and ERCOT, for example, are utilizing similar approaches. The structure and procurement of the services vary due to the differences in the market structures of the jurisdictions. These ISOs similarly enhance reliability of the system through ramping capability offers from market participants aimed to offset extreme system ramping events. The key aspects of the fully integrated service contemplated would be: The ramping service allows providers with qualifying capacity and ramp rates to be compensated for an ancillary service specifically for the provision of ramp rate. The ramping service would only be dispatched for short periods to supplement the ramp rate inherent in the EMMO. The energy from ramping service providers would not have to be held in reserve; it would continue to be offered through the EMMO and dispatched in economic order, but also be able to be dispatched specifically for ramp rate when required. Page 12

15 The ramp up and ramp down services will be separate. This will maximize potential suppliers and thus competition, i.e. wind could sell ramp down service, load could sell ramp up service and other generators and potentially some storage technologies could sell both directions. Some advantages of a fully integrated ramping service are: The service sends a direct signal for flexibility, allowing market participants to indicate their willingness and ability to accept short term dispatches in one or both directions, and at what price. The ramping service provides benefits to the system beyond wind integration (managing load ramps without incremental regulating reserve, managing intertie ramps). The service opens up the possibility for regulating reserve to be redesigned to reduce or eliminate the energy component. The service is scalable as system requirements change. Increasing or decreasing ramping requirements will be reflected through price for the service and the volume of service utilized. As illustrated in Figure 5, the ramping service would supplement the regulating component that addresses second-to-second and minute-to-minute variations in the supply and demand energy balance. Ramping service would be activated during the course of normal operations to fill in the energy gaps triggered by extreme system ramping events. Providers would be compensated for the energy at the system marginal price until the EMMO dispatches catch up and the service is no longer required. The ramping service would work according to the same principle in both directions. Addressing extreme system ramping events in this manner could help avoid over-dispatching of the EMMO, reducing operational concerns and short term price spikes and volatility in the market caused by large ramping events. Figure 5 Possible Ramping Service Design MW a. Net Demand MW b. Regulating component that removes second to-second variations Time Time MW Ramp Up Service c. the EMMO; ramping service corrects the system supply and demand imbalance beyond the regulating service Ramp Down Service Page 13 Time

16 7.2.4 Alter Regulating Reserve Technical Requirements The AESO s reliability products have been designed primarily from the perspective of generation assets. However, given the AESO s mandate to facilitate a fair, efficient and openly competitive market, technical standards should be technology neutral to make AESO procured services accessible to new technologies wherever possible, and to increase competition. In conjunction with the design of a ramping service, standards should be revised to allow regulating reserve to be supplied by all assets that can meet the physical responsiveness required by the system. If two types of providers can create the same benefits for the system, the standards should allow both to compete. This is consistent with the AESO s desired approach to all products and services. Opening the regulating reserve market to storage devices and demand-side resources should result in more competitive reserve prices, and may also provide an incentive for innovation. As noted in the Alberta Innovates 16 study, ancillary services, and regulating reserve in particular, are considered the most valuable markets for storage devices Investigate Pay For Performance Element in the Regulating Reserve Market Also in conjunction with the design work on a possible ramping service, the AESO recommends exploring the addition of a pay for performance element to the pricing mechanism for regulating reserves. This should improve the quality of the regulating reserves and incentivize greater participation. Regulating reserve is currently paid a capacity payment and an energy payment for net energy production. In addition to capacity, the ability to follow frequent dispatches is the key technical requirement of the regulating reserve service. However, Alberta s regulating reserve market does not differentiate the pricing based on capability. Pricing the quality of regulating reserve capability is a growing issue throughout North America, partly due to the increased variable generation capacity in most markets. In response to this driver, the Federal Energy Regulatory Commission (FERC) has proposed to review regulations regarding the procurement of frequency regulation service due to the emergence of new technologies that are capable of faster and more accurate response than those generators that are currently providing the services 17. Alberta is not a FERC jurisdiction, but the lack of an incentive for performance in the regulating reserve market may create similar issues in Alberta. The AESO recommends exploring the addition of a performance element to the regulating reserve market that will serve to potentially improve the overall performance of existing regulating reserve capacity and create an improved price signal for flexibility. It also serves as a means of leveling the playing field between technologies with different characteristics. Different types of suppliers could provide different services i.e. some may only provide ramping services while higher performing assets could provide the regulating service. The proposed regulating reserve payment structure to be explored is: The market for regulating reserve will continue to trade based on a capacity price traded dayahead Performance would be evaluated based on the measured real-time ability to follow the AGC control signal The AESO will initiate consultation in 2013 on the specific mechanisms within this framework to integrate a pay for performance element into the regulating reserve price. At a high level, the mechanism would FERC Notice of Proposed Rule Making 134: Frequency Regulation Compensation in the Organized Wholesale Power Markets Page 14

17 adjust the capacity payment from the day ahead clearing price based on the ability of the provider to follow the AGC signal, but any specific details of this adjustment will be developed through consultation. 8. Next Steps The AESO invites stakeholders to comment on the recommendations in this paper using the comment matrix provided and submit them to Jacques Duchesne at the AESO by February 1, The AESO appreciates the contribution of time and effort by all members of the Wind Work Group participating in the sessions that were used as input to this Recommendation Paper. Their input was extremely valuable and enabled the AESO to gather a great deal of information that was used in the development of these recommendations. The next steps in the wind integration program include: Receive and respond to stakeholder feedback on the recommendations. Publish the preliminary results of the wind dispatch pilot and extend participation. Explore the next steps in having wind facilities participate in the merit order. Update market analysis to assist in the evaluation of the need for a system ramping service. Initiate consultation on ramping service design with industry stakeholders, including a review of technical standards that allow multiple resource types to supply regulating reserve, and consultation on a pay for performance element in the regulating reserve market. Page 15

18 9. Appendix I Stakeholders Feedback to the Phase Two Discussion Paper 9.1 Policy Coherence Section Stakeholders have suggested lack of wind and an inaccurate forecast should be considered loss of fuel, and therefore should be declared an acceptable operating reason (AOR). Market participants also suggest AESO look for more flexible policies and regulations in developing a market-based, competitively procured firming product. Stakeholders want AESO to maintain a holistic view of the market and conduct in-depth analysis of the options. The suggestion of making wind firm and being equalized to other generators was received differently by stakeholders, with some supporting and the others being strictly against it. One stakeholder questioned why the AESO is not concerned with environmental issues. The AESO acknowledges the unique characteristics of wind and would agree in certain circumstances lack of wind could be treated as an AOR. The AESO is currently exploring dispatching wind based on more accurate short-term forecasts as well as the possibility of creating the ramping service. If the initiative proves to be successful, in the long term there should be a reduction in any administrative pro rata wind curtailments. The detailed design and implementation plans for the Phase Two integration recommendations are still in the consultation and analysis stage of development. The recommendations for wind integration were developed with the intention of recognizing the unique characteristics of wind energy within the construct of a FEOC market. The AESO strives to create policies and recommendations that will facilitate fair market conditions for all types of generators, accounting for uncontrollable factors such as the variable nature of the wind energy fuel source. It is not in the AESO s mandate to consider any revision of environmental policies. 9.2 Analysis Section Some stakeholders questioned the credibility of the analysis section of the discussion paper, stating that it was potentially misleading as load creates ACE, not just wind. The other stakeholder comment received was that any type of energy added would increase ACE and suggests the AESO come up with a strategy to identify events caused by wind or a specific type of generation. There are three major factors that contribute to ACE events: wind ramping, load, and intertie ramps. Wind plays a role as either a direct or an indirect contributor. Table two of section 5 of the Phase Two Discussion Paper shows that 88 per cent of ACE events are contributed to by wind and conclusions can be drawn based on this analysis. Due to its variable nature, increasing wind capacity is an incremental change to the system. Load on its own does not bring about significant changes on a year over year basis. Generator contingencies were not simulated in the study. The use of contingency reserves already mitigates ACE events caused by generator contingencies within 10 minutes. Moreover, their inclusion would complicate the analysis and make it more difficult to isolate wind, interties, and load changes. 9.3 Reliance on the EMMO Option All but one stakeholder objected to over dispatch of the EMMO to provide ramping service and the use of the EMMO in the long term as a standalone approach. Some insisted that the cost of integration should be transparent. Ramp rates and response times for other generators should be revised to compensate for the uncontrollable nature of variable generation. Stakeholders suggested ramping should be paid for by load and suggested more analysis should be conducted on the price effect. The AESO recognizes that significant over-dispatching of the EMMO to deal with wind variability may not be an appropriate stand-alone long term tool due to the operational inefficiencies and very short term price volatility. Page 16

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