TODAY’S STUDY, 9-27 – 20% NEW ENERGY WILL RIDE THE WIRES
Integration of Renewable Resources; Operational Requirements and Generation Fleet Capability at 20% RPS
August 31, 2010 (California ISO and GE Energy)
This is the latest in a series of studies from grid experts and showing the current transmission system can handle far more New Energy than has yet been built. The conclusion is simple: Those who say energy storage or new wires must come before further investment is made in the sun, the wind, the earth's deep heat, flowing waters and combustible waste don't know what they are talking about. (see OVER A THIRD OF POWER FROM NEW ENERGY and STUDY SAYS NEW ENERGY FITS FINE)
Under California’s existing Renewables Portfolio Standard (RPS), utilities must supply 20 percent of all electricity retail sales from eligible renewable resources by 2010, with compliance expected in the 2011-2012 timeframe.1 Much of the additional renewable generation to meet the RPS goal will be wind and solar technologies with variable operating characteristics that complicate electric system operations. As the entity responsible for the reliable operation of the bulk electric power system for most of the state, the California Independent System Operator Corporation (ISO) is focused on ensuring that the electric system is able to operate reliably with these additional renewable resources. This report represents an essential step in that effort. It describes the technical effects on system operations and wholesale markets of increases in wind and solar generation to achieve the 20 percent RPS target and evaluates the capability of the current generation fleet to maintain reliability under these changed conditions.
The chart below (Figure ES-1) shows the expected technology mix of renewable resource capacity assuming the 20 percent RPS is achieved in 2012 and compares it to the renewable resources in 2006, which is the year used to benchmark a number of study results.2 Much of the expansion in renewable energy will come from variable energy resources, namely wind and solar technologies. The integration of variable energy resources will require increased operational flexibility—notably capability to provide load-following and regulation in wider operating ranges and at ramp rates that are faster and of longer sustained duration than are currently experienced. Forecast uncertainty associated with wind and solar production will increase the need for reservation of resource capacity to ensure that these requirements are met in real-time operations.
There is also the likelihood of increased occurrence and magnitude of overgeneration, a condition where there is more supply from non-dispatchable resources, than there is demand. In providing these capabilities, the existing and planned generation fleet will likely need to operate longer at lower minimum operating levels and provide more frequent starts, stops and cycling over the operating day. Against this backdrop, certain conventional generators will also be operating at lower capacity factors due to the increased output from renewable energy generation.
To understand the extent of these impacts at 20 percent RPS, the ISO has conducted several analyses, both collaboratively and independently, over the past several years,including a study released in 2007 that focused on the operational and transmission requirements of wind integration (“2007 Report”).3 This study builds on those prior efforts. The purpose of this study is to assess the operational impacts of an updated renewable resource portfolio that includes 2,246 MW of solar and to evaluate in more detail the operational capabilities of the existing generation fleet, as well as changes to their energy market revenues. The study utilizes several analytical methods, including a statistical model to evaluate operational requirements, empirical analysis of historical market results and operational capabilities, and production simulation of the full ISO generation fleet.
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The results presented in this report have significant operational and market implications.
From an operational perspective, the ISO is concerned with the extremes of potential
impacts—in particular large, fast ramps that are difficult to forecast. A key purpose of the simulations in this study is to estimate the operational capabilities and clarify possible changes to market and operational practices to ensure that the system can perform as needed under these conditions, even if they rarely occur. Hence, the study identifies the maximum values of simulated operating requirements, such as load-following and regulation, by operating hour and by season. In addition, to clarify how more typical daily operations may change, distribution statistics are provided for most of the simulated requirements and capabilities to facilitate both operational and market preparedness.
Key Findings and Results
The modeling of 2,246 MW of solar resources under the 20 percent RPS changes the operational requirements, compared to the incremental wind-only results presented in the ISO’s 2007 Report.
The changes to the operational requirements due to additional solar resources take place in the mid-morning and early evening hours. The ramp up in solar generation in the mid-morning can increase the load-following down and regulation down requirements compared to the case with wind generation alone that was studied in 2007. Similarly, the solar ramp down in early evening can increase the load-following up and regulation up requirements compared to the case with wind alone.
In other hours, the combination of solar and wind resources can lessen operational requirements, because solar resources are ramping up when wind resources are ramping down, and vice-versa.
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The combination of increased production of wind and solar energy will lead to displacement of energy from thermal (gas-fired) generation in both the daily offpeak and on-peak hours. Due to this displacement and to simultaneous reduction in market clearing prices, there may be significant reductions in energy market revenues to thermal generation across the operating day in all seasons.
A core operational and market function of the ISO is to forecast system load and renewable production day-ahead and in real-time, and then to ensure that sufficient generation and non-generation resources are committed such that intra-hourly deviations from hourly schedules can be accommodated by those resources under ISO dispatch control. These deviations can take place in the upward or downward direction.
Currently, the intra-hourly deviations are largely caused by changes in load, hence the term “load-following.” With additional variable energy resource production, the net load-following requirement—i.e., the requirement due to load schedule deviations plus wind and solar schedule deviations—could increase substantially in certain hours due both to the variability of wind and solar production and forecast uncertainty. Unless otherwise indicated, all results on load-following requirements in this report are of net load following.
The simulated maximum load-following up and load-following down ramp rates for 2012, by season in which they occur, are 194 MW/min (summer) and -198 MW/min (winter), respectively.4 These represent possible increases at times in the range of ± 30-40 MW/min over the ramp rates simulated for the year 2006.
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While the system must be capable of delivering these capabilities, such ramp rates will not be experienced in every operational hour, nor sustained over the entire hour.
One measure of the upper bound on the duration of the increased ramp rates is the hourly load-following capacity requirement.5 The maximum hourly load following up and load-following down capacity requirements for 2012 are 3737 MW and -3962 MW (both summer season requirements), respectively. For the summer months, the maximum increase in the hourly capacity requirement when 2012 is compared to 2006 is 845 MW for load-following up and -930 MW for load-following down. As shown in Figures ES-2 and ES-3, in the summer, the highest requirements are typically in the morning and evening wind and solar ramp periods.
When the simulated maximum requirements for all hours in the season are taken into account, the percentage increase in total load-following capacity requirements in the summer season between 2012 and 2006 is estimated at 12 percent for load-following up and 14 percent for load-following down; the results for all seasons are shown in Table ES-1.
The historical 5-minute load-following capability7 of the generation fleet, was measured for the period between April 1, 2009, and June 30, 2010. Figures ES-4 and ES-5 show the 5-minute load-following up and load-following down capability for units on 5-minute dispatch in the summer months during that period. The results show that the ISO dispatch in recent months appears, for the majority of intervals analyzed, to be able to meet the load-following up requirements simulated for 20 percent RPS within 20 minutes or less.9 This is simply due to the ramp capacity remaining on units not dispatched to their maximum operating levels, and not to any preparations made by the ISO to address renewable integration.
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The simulated maximum load-following down ramp rate for summer in 2012 was -169 MW/min, which is -845 MW/5 min. These high load-following down requirements are often for the mid-morning hours. Under the current practice of self-scheduling generation rather than allowing them to be operated through economic dispatch, the 5-minute downward ramp capability as shown in Figure ES-5 could be well below the requirement of -845 MW during some of the midmorning hours.
Figures ES-5 and ES-6 compare the 5-minute load-following down capability, limited and not limited by self-schedules, respectively. Figure ES-6 suggests that current load following down capability could be more than doubled in many hours if all thermal generation were fully dispatchable. The implication is that to accommodate the increased variability at 20 percent renewable energy, the level of self-schedules will have to decrease.
To further evaluate the load-following up and down capabilities of the ISO generation resources, the ISO also conducted production simulations for selected days that included simulation of 5-minute dispatch. The production simulation assumed that all thermal generation were fully dispatchable (i.e., maximum operational flexibility), but that all other classes of generation were following fixed schedules.
Figure ES-7 shows the load-following capability over one such simulated day, May 28, 2012. This figure shows the capability of the dispatchable generators to move from one 5-minute dispatch to the next, subject to ramp and other operational constraints. The 5-minute load-following down capability is at or close to zero during the morning hours from 4 a.m. to 10 a.m.11 as shown. If current scheduling practices continue, this simulated capability would be further diminished due to self-scheduling. Production simulation results for additional days can be found in Section 5 and Appendix C.
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Figure ES-8 then shows the simulated overgeneration on May 28, 2012 due to the shortage of load-following down capability. Insufficient capability to ramp down manifests itself as overgeneration in the production simulations.12 This figure also shows the regulation down procurement (green line) and the CPS213 violation threshold (yellow line) for the same period. While there is significant, sustained overgeneration for a few hours from 5 a.m. to 8 a.m., for the other hours in the day, the overgeneration can be covered by the procured regulation down or allowed to result in an Area Control Error (ACE) violation, if it is not sustained. Only significant overgeneration sustained over 10 minutes is likely to result in the curtailment of generation.
For the year, production simulations show that load-following down shortages will result in less than 0.02 percent of renewable generation (approx. 10 GWh) potentially needing to be curtailed under assumed conditions. The production simulations did not identify any load-following up shortages.
In real-time, the ISO operators issue dispatch instructions to generators every 5 minutes based on forecasts of demand and supply that are available in the prior minutes. The second-by-second variability of load, net of wind and solar production, within those 5-minute intervals is balanced by units on automatic generation control (AGC) that can provide regulation as needed in the upwards or downwards direction.
The maximum hourly regulation up and regulation down capacity requirements in 2012, which take place in different seasons, are 502 MW (spring) and -763 MW (summer), respectively. The largest increases in these requirements between the 2012 and 2006 simulations are 270 MW (spring) and -457 MW (summer). These results are found in Appendix A-1, tables A-1 to A-8.
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As shown in Figures ES-9 and ES-10 for the summer 2012 season, the highest regulation up requirements are typically in the morning and evening wind and solar ramp periods, while regulation down requirements are concentrated in the mid-afternoon hours. Hour 18 consistently results in very high regulation down requirements in the summer simulations, due largely to the consistently fast wind ramp up experienced in that hour.
The maximum hourly simulated regulation up and regulation down ramp rates in 2012 are 122 MW/min (spring) and -97 MW/min (summer), respectively, compared to 75 MW/min and -79 MW/min, respectively, for simulated 2006 levels.
The simulated percentage change in total regulation capacity requirements in the summer season between the 2012 and 2006 simulations is estimated at 37 percent for regulation up and 11 percent for regulation down (as shown in Figure ES-10, most of the regulation down increased requirement is concentrated in three afternoon hours); the results for other seasons are shown in Table ES-1.14
The regulation results require several important clarifications. First, the ISO currently procures 100 percent of its regulation requirement in the day-ahead market, with a minimum requirement in the range of 300 MW in the upwards and downwards direction. First, the simulation does not consider the effect of day ahead wind and solar production forecast errors on determining the forecast next day regulation need. Second, there are other uncertainties factored into regulation procurement, such as actual uninstructed deviations from dispatch instructions that are not considered in the simulation. Hence, the simulated results shown here may understate the ISO’s actual regulation needs, but are indicative of future increases in regulation procurement.
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The additional regulation requirements appear to be well within the capabilities of the existing generation fleet. The ISO regulation markets have procured levels ofregulation up and regulation down since April 1, 2009, in the range of 600-700 MW in each hour of the operating day, with these high procurements largely taking place during the first month of market implementation to ensure reliability.
These procurement levels provide one test of the ISO’s ability to meet the higher regulation requirements that could be experienced under 20 percent RPS. Moreover, as another indicator of current regulation capability, the 5-minute regulation ramp capability of the generation resources committed and dispatched in each hour of the day since April 1, 2009, has been measured and determined to be above the calculated regulation requirements under 20 percent RPS for most hours.15 Hence, the empirical analysis suggests that deficiency of regulation capability should not be a problem except in the hours of overgeneration, when regulation down may be in shortage.
The production simulations analyzed both a high hydro year (based on 2006 hydro production) and a low hydro year (based on 2007 hydro production), as well as sensitivities to assumptions about load growth and firm imports, to evaluate their effect on overgeneration. The maximum overgeneration occurred in a scenario that assumed no load growth between 2006 and 2012. The overgeneration in this case was approximately 0.3% (150 GWh) of annual renewable generation.
Most of the overgeneration occurs in late spring (April-May), due to combination of high generation from hydro and variable energy resources, and low loads. In general, overgeneration was found to be directly correlated to the amount of nondispatchable generation in the system. There appears to be sufficient dispatchable generation available to operate if the ISO is not prevented from doing so due to an excess of non-dispatchable generation, including imports.
Fleet Operations and Economic Impacts
The increased supply variability associated with the 20 percent RPS results in the dispatched gas-fired generators starting and stopping more frequently. In an hourly simulation of 2012, combined cycle generator starts increase by 35 percent compared to a reference 2012 case16 that assumes no new renewable capacity additions beyond 2006 levels. Also, the energy from the combined cycle units reduces by roughly 9 percent on an average, with more reduction occurring during off-peak hours when there wind production is highest, indicating more cycling in the dispatchable fleet.
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The lower capacity factors combined with the reduced energy prices under 20 percent RPS may result in a significant drop in energy market revenues for the gas fleet in all hours of the day and in all seasons. Tables ES-2 to ES-4 show the change in simulated annual energy revenues for three types of gas resources: combined cycle units, simple cycle gas turbines, and gas-fired steam turbines.
These simulated revenue results, based on marginal production costs, are provided to illustrate potential changes in energy market revenues rather than as a forecast; actual market prices will reflect factors not considered, or only partially considered, in the model, such as congestion and the effect on prices of market bids. Also, revenues from ancillary services are not included in the annual
Based on the study results, the following recommendations are made. Evaluate market and operational mechanisms to improve utilization of existing generation fleet operational flexibility. The study confirmed that the generation fleet possesses sufficient overall operational flexibility to reliably integrate 20 percent RPS in over 99 percent of the hours studied. However, the current markets do not reveal that full capability due to selfscheduling.
In particular, the empirical analysis demonstrated the shortage of the 5-minute load-following capability in the downward direction when resources are self-scheduled, as compared to offering their actual physical capabilities for economic dispatch. These results were further substantiated using production simulation. Hence, the study makes clear that the ISO should pursue incentives or mechanisms to reduce the level of self-scheduled resources and/or increase the operating flexibility of otherwise dispatchable resources.
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Evaluate means to obtain additional operational flexibility from wind and solar resources. The simulations demonstrated the need for additional dispatchable capacity in the morning hours under certain conditions. The ISO should explore market rules and incentives intended to encourage greater participation by wind and solar resources in the economic dispatch. Greater economic dispatch control, including curtailment and ramp rate limitations, can be used in targeted circumstances to mitigate overgeneration or shortfalls in regulation and load-following capability generally.
Improve day-ahead and real-time forecasting of operational needs: (a) Develop a regulation prediction tool. The analysis demonstrated that regulation needs will vary substantially from hour to hour depending on the expected production from wind and solar resources. The development of a tool to forecast the next day’s hourly regulation needs based on probabilities of expected renewable resource output would enhance market efficiency.
Improve day-ahead and real-time forecasting of operational needs: (b) Develop a ramp/load-following requirement prediction tool. TheISO should accelerate the development of improved forecasting of operational ramps generally and load-following requirements on different intra-hourly time frames. This capability could be complemented by evaluation of whether to modify unit commitment algorithms and procedures to reflect those forecast ramp requirements.
Further analysis to quantify operational and economic impacts on fleet at higher levels of RPS. Although this study was not focused on the impact of renewable integration on the revenues of existing generation, it has provided some indications of possible changes in such revenues, primarily through changes in energy market prices. Further analysis is needed to clarify the net revenue impact from changes in procurement and prices for wholesale energy and ancillary services as well as the implications for payments through resource adequacy contracts.