The Renewable Energy Integration Challenge: Mitigation Options Lori Bird, NREL NCSL Webinar April 28, 2013 NREL is a national laboratory of the U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.
Overview What challenges do higher penetrations of wind and solar pose for grids? How much wind/solar can be integrated? What solutions are available to address variable nature of wind, solar? What are the costs of integration? What can policymakers do? Source: First Wind Source: Dennis Schroeder 2
Renewable Energy Integration Challenges 3 Variability and Uncertainty Load varies each minute Wind, solar add to variability o output not always available o daily or seasonal patterns Wind and solar are uncertain due to weather changes o Solar has predictable daily pattern, but cloud cover changes rapidly o Winds can be stronger at night PV Output 1 Plant versus Large Number of Plants and in winter Source: WWSIS-2 (2013)
Output Normalized to Mean 4 Variability Smoothed Over Wide Area 15 Turbines Stdev = 1.21, Stdev/Mean =.184 200 Turbines Stdev = 14.89, Stdev/Mean =.126 215 Turbines Stdev = 15.63, Stdev/Mean =.125 1.6 1.4 1.2 1.0 0.8 0.6 1.6 1.4 1.2 1.0 0.8 0.6 1.6 1.4 1.2 1.0 0.8 0.6 0 5 10 15 Seconds 20 25 30x10 3 Source: NREL Wind Plant Data (Approximately 8 hours) Variability is reduced with more wind or solar plants and spread over a wider area
How much wind/solar can be accommodated? 5 No physical limit found in studies it depends on system, operations and economics Regional integration studies show up to 35% RE can be integrated if adequate transmission operational changes can provide additional flexibility Sources: Eastern Wind Integration and Transmission Study, Jan 2010; Western Wind and Solar Integration Study, Mar 2010
What Does More Variability Mean for Power Systems? More flexible reserves are needed to balance load & generation each day o each wind plant does not need to be backed up by a conventional plant o reserves are managed for the whole system; existing units can be used o sometime wind increases (or decreases) with load, which helps the system Conventional power plants may need to be ramped up and down or cycled on and off more Source: NREL 6
Fossil Plant Cycling and Emissions Impacts Average NO X emissions rate (lbs/mwh) Wind and solar can affect dispatch of fossil plants (starts, ramps or plants run at part load) Wind- and Solar-Induced Cycling Can Have a Positive or Negative Impact on Emissions System-wide impacts of cycling in West: o Negligible impact (<0.2%) on CO 2 benefit o Improves NO X benefit by 1% 2% o Lessens SO 2 benefit by 2% 5% Source: WWSIS-2 (2013 Coal CC CT GasSteam 3.00 2.50 2.00 1.50 1.00 0.50 0.00 0.4 0.9 Fraction of maximum generation 7
How Can Systems Handle More Variability? 8 Improved institutional flexibility Faster energy markets Shorter intervals for transmission scheduling Balancing over a large geographic area to net out variability Advanced forecasting techniques Better utilize existing transmission capacity A more flexible generating fleet Modify existing plants to improve start-up time, ramp rate, and lower minimum operating load New flexible generating plants Demand response Some loads can respond rapidly (up and down) with automation Adequate transmission Energy storage ex., pumped hydro, batteries, compressed air, electric vehicles Source: U.S. DOE
9 Flexibility Options: Costs Vary Each power system is different: solutions vary Source: NREL
What are the Costs of Integrating RE? Integration costs are difficult to calculate Some entities have estimated costs Costs can be reduced with forecasting and operational changes Most generation sources have costs with integrating them on the grid (e.g., nuclear ramping limitations) Year Study Wind Capacity Penetration Regulation Integration Cost ($/MWh) Load Following Unit Commit. Gas Supply TOTAL 2003 Xcel-UWIG 3.5% 0 0.41 1.44-1.85 2003 We Energies 29% 1.02 0.15 1.75-2.92 2004 Xcel-MNDOC 15% 0.23-4.37-4.60 2005 PacifiCorp-2004 11% 0 1.48 3.16-4.64 2006 Calif. (multi-year)* 4% 0.45 trace trace - 0.45 2006 Xcel-PSCo 15% 0.20-3.32 1.45 4.97 2006 MN-MISO** 31% - - - - 4.41 2007 Puget Sound Energy 12% - - - - 6.94 2007 Arizona Pub. Service 15% 0.37 2.65 1.06-4.08 2007 Avista Utilities 30% 1.43 4.40 3.00-8.84 2007 Idaho Power 20% - - - - 7.92 2007 PacifiCorp-2007 18% - 1.10 4.00-5.10 2008 Xcel-PSCo*** 20% - - - - 8.56 2009 Bonneville (BPA) + 36% 0.22 1.14 - - 5.70 2010 EWITS ++ 48% - - 1.61-4.54 2010 Nebraska +++ 63% - - - - 1.75 * Regulation costs represent 3-year average. Source: ** Highest LBNL over 3-year Wind evaluation Market period. Report *** This integration cost reflects a $10/MMBtu natural gas price scenario. This cost is much higher than the integration cost calculated for Xcel-PSCo in 2006, in large measure due to the higher natural gas price: had the gas price from the 2006 study been used in the 2008 study, the integration cost would drop to $5.13/MWh. + Costs in $/MWh assume 31% capacity factor. Aside from regulation and following reserves, the costs of BPA s imbalance reserves are $4.33/MWh. ++ The unit commitment costs listed in EWITS are the cost of day-ahead wind forecast error; the remaining integration costs included in the total are for shorter term variable reserves that account for regulation and short-term forecast errors (energy imbalance). +++ These integration costs only capture regulating reserves and day-ahead forecast error. A sensitivity case in this study shows that integration costs increase if the differences between the actual hourly deliveries of wind energy are compared to daily flat block of power. The increased costs are shown in Figure 39. Sources: Brooks et al. (2003) [Xcel-UWIG]; Electrotek Concepts, Inc. (2003) [We Energies]; EnerNex Corp. and Wind Logics, Inc. (2004) [Xcel-MNDOC]; PacifiCorp (2005) [Pacificorp-2004]; Shiu et al. (2006) [Calif. (multiyear)]; EnerNex Corp. (2006) [Xcel-PSCo]; EnerNex Corp. and Windlogics Inc. (2006) [MN-MISO]; Puget Sound Energy (2007) [Puget Sound Energy]; Acker (2007) [Arizona Pub. Service]; EnerNex Corp. (2007) [Avista 10
11 Options for Cost-Effectively Integrating Wind/Solar Operational and market tools, flexible demand and supply side resources 1. Improve wind and solar forecasting 2. Encourage geographic diversity of resources 3. Retool demand response to complement variable generation 4. Access greater flexibility in the dispatch of existing generating plants 5. Focus on flexibility for new generating plants 6. Expand subhourly dispatch & scheduling 7. Implement an energy imbalance market WGA Report: Meeting Renewable Energy Targets at Least Cost: The Integration Challenge http://www.westgov.org/
Improve and Expand Forecasting Improve wind and solar forecasting o Forecasting helps utilities and grid operators anticipate the amount of renewable energy generations reduces uncertainty o Advanced forecasting improves scheduling of other resources to reduce reserves, fuel consumption, and operating, maintenance costs o Substantial cost savings and reduction in integration costs: Xcel Energy found that 1% improvement in forecast error saved $800k (PSCO) Policy and regulatory options: Encourage expanded use of wind, solar forecasting by utilities and balancing areas Encourage regional forecasts or exchange of forecasts among balancing areas Encourage forecasting improvements Source : Alstom 2010. 12 12
Increase Flexibility of Generation Access greater flexibility in the dispatch of existing generating plants o Some plants can be retrofitted to increase flexibility by lowering minimum loads, reducing cycling costs and increasing ramp rates. Focus on flexibility for new generating plants o Requires rethinking resource adequacy analysis to reflect the economic benefit of flexibility service o Changes to resource planning and procurement frameworks Policy and Regulatory Options Conduct a flexibility inventory for existing resources Analyze the potential for retrofitting less flexible generating plants Review incentives/disincentives for plant owners to invest in increased flexibility Examine and amend guidance for evaluating flexibility needs in utility resource planning Use competitive procurement processes to evaluate alternative flexible capacity solutions 13 13
Encourage Geographic Diversity Geographic diversity reduces variability o o Variations in output from wind and solar plants are reduced over a large area Diversity lowers aggregate variability and forecast errors, reducing reserves needed Policy and Regulatory Options o In transmission plans and utility resource plans/rfps, consider siting wind and solar to minimize variability of aggregate output and better coincide with load profiles o Support right-sizing of interstate lines (increasing project size, voltage, or both to account for credible future resource needs) that access renewable resources Source: Dennis Schroeder 14 14
Encourage Demand Response Shift customer load up and down to complement wind and solar through direct load control and real-time pricing with automation Demand response (DR) may be less expensive than supplyside resources and energy storage technologies Policy and Regulatory Options Allow DR to compete on a par with supply-side alternatives in utility resource planning and acquisition Consider potential value of enabling DR when evaluating advanced metering Examine ratemaking practices for features that discourage costeffective DR e.g., demand charges that penalize large customers for higher peaks when they shift loads away from periods of limited energy supplies 15 15
16 Concluding Remarks Higher penetrations of wind, solar can be managed through operational changes All power systems differ depending on generation mix, operations, markets, etc. --- solutions differ Policymakers can play a role in helping to manage higher penetrations of RE by encouraging: o new generation sources to be flexible o flexible loads i.e., demand response o use of forecasting o transmission investments o installed RE technologies can support the grid o geographic diversity of RE, if appropriate Source: Steve Wilcox
Contact: lori.bird@nrel.gov