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Meeting Renewable Energy Targets in the West at Least Cost:
The Integration Challenge
Presented by:
Lisa Schwartz, Regulatory Assistance Project
June 10, 2012
Western Governors’ Association Meeting
Integration Challenges for Renewable Energy
• Variability – The range of expected load and generation
– Renewable and conventional plants may be unavailable or capacity-limited (partial outages)
– Load also varies by seconds, minutes, hours, day type and weather
– Variability is reduced with more resources spread over a wider area (diversity of weather patterns)
• Uncertainty – When/how much load, generation will change
– Operators plan based on forecasts of needs and generation sources. Some error is inherent.
– Uncertainty of wind and solar output is due to unknown changes in weather (e.g., no wind, cloud cover)
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SunEdison facility, Aurora, Colo.
NR
EL
Integration Is Not a Unique Issue to Renewable Resources
• Many types of generation impose integration costs – New, inexpensive base-load • Causes other units to incur cycling
costs, lower capacity factor
– Large units that increase contingency reserve • Increases cost of contingency
compliance for others in the pool
– Conventional plants that impose regulation cost
– Wind and solar
• Integration costs are not always assigned based on cost-causation (but should be)
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Milligan, M.; Ela, E.; Hodge, B. M.; Kirby, B.; Lew, D.; Clark, C.; DeCesaro, J.; Lynn, K. (2011). Cost-Causation and Integration Cost Analysis for Variable Generation. NREL Report No. TP-5500-51860
PGE’s Boardman coal plant
How Can Grid Flexibility Be Increased? • Improved institutional flexibility
– Faster energy markets and shorter intervals for transmission scheduling
– Balancing wind and solar resources over a large geographic area to address variability (net out changes in load and generation)
– Application of advanced solar and wind forecasting techniques – Make better use of existing transmission capacity
• A more flexible generating fleet – C0st-effective modifications of existing plants may be possible to
improve load-following capability (ramp rate up and down, lower minimum load and faster startup capability)
– For new generating plants, focus on flexibility
• Demand response – Some loads can respond rapidly (up and down) with automation
• Adequate transmission • Energy storage – e.g., pumped hydro, batteries,
compressed air, plug-in electric vehicles
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Flexibility Supply Curve
NREL/Utility Variable Generation Integration Group
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Penetration Level
High Wind
Penetration Level
Meeting Renewable Energy Targets in the West at Least Cost: The Integration Challenge
– New Western Governors’ paper explores ways to reduce costs to consumers for integrating wind and solar, barriers to adopting cost- saving measures and possible state actions (http://www.westgov.org/index.php)
• Project team
– Regulatory Assistance Project
– Exeter Associates
– National Renewable Energy Laboratory
• Funded in part by The Energy Foundation. USDOE funded NREL’s participation.
• Draws from existing studies, experience to date
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WGA paper identifies 9 ways to save: operational and market tools, flexible
demand- and supply-side resources
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6. Improve reserves management
7. Retool demand response to complement variable generation
8. Access greater flexibility in the dispatch of existing generating plants
9. Focus on flexibility for new generating plants
1. Expand subhourly dispatch & scheduling
2. Facilitate dynamic transfers between balancing authorities
3. Implement an energy imbalance market
4. Improve weather, wind and solar forecasting
5. Take advantage of geographic diversity of resources
Technical Committee Laura Beane, Iberdrola
Ty Bettis, Portland General Electric
Steve Beuning, Public Service of Colorado
Daniel Brooks, Electric Power Research Institute
Ken Dragoon, Northwest Power and Conservation Council
Jack Ellis, consultant
Udi Helman, Brightsource
Gene Hinkle, GE Energy
David Hurlbut, National Renewable Energy Laboratory
Elliot Mainzer, Bonneville Power Administration
Michael Milligan, National Renewable Energy Laboratory
Andrew Mills, Lawrence Berkeley National Laboratory
Dave Olsen, Western Grid Group
Carol Opatrny, Opatrny Consulting
Jim Price, California ISO
Jim Shetler, Sacramento Municipal Utility District*
Charlie Smith, Utility Variable-Generation Integration Group
Ryan Wiser, Lawrence Berkeley National Laboratory
Robert Zavadil, EnerNeX
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* Serving in his role as an advisor to SMUD, not as a WECC Board member.
Improved Institutional Flexibility
• Expand subhourly dispatch and scheduling
– Faster scheduling of energy and transmission
– Key recommendations
• Encourage expansion of Joint Initiative’s efforts
• Foster standardization among Western balancing authorities (BAs), allowing updating of schedules within the hour
• Evaluate costs, benefits and impacts of extended pilots on the need for reserves, particularly for regulation
• Commission an independent analysis of equipment and labor costs of transitioning to subhourly dispatch and scheduling
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Footprint Regional BAU
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Average Total Regulation for 6 Dispatch/Lead Schedules by Aggegation (Dispatch interval -
Forecast lead time)
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Faster Faster Faster
Large Medium Small
• Facilitate dynamic transfers between balancing authorities – Moving generation from the BA area where it physically resides
to another area in real-time, for control by receiving BA
– Access to flexibility from a broader geographic area
– Joint Initiative implementation relatively inexpensive
– Key recommendations
• Encourage BAs to use dynamic transfers
• Identify most receptive and most restrictive transmission lines
• Determine priority for improvements to ease restrictions
• Automate reliability procedures such as voltage control and RAS arming* to enable expanded use of dynamic transfers
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*Remedial action schemes trip generation to maintain system reliability in the event of loss of transmission
• Implement an energy imbalance market – Centralized market to: 1) re-dispatch generation every 5 minutes
to address generator schedule deviations and load forecast errors and 2) manage grid congestion
– Enables dispatch of generation and transmission across BA areas to resolve energy imbalances using the full geographic diversity of load and generation in the EIM footprint
– Key recommendations
• Explore financing options
• Investigate in PUC proceedings costs and benefits to ratepayers
• Support continuing efforts to explore EIM governance
• Address concerns that an EIM could lead to an RTO
• Explore mechanisms to prevent market manipulation
• Define rates/terms for transmission service agreements for each entity
• Support new NWPP Committee’s evaluation of an EIM
• Support West-wide efforts to design an EIM for broadest footprint
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• Improve weather, wind and solar forecasting – Use weather observations, meteorological data, Numerical Weather
Prediction models, and statistical analysis to generate short, medium, and long-term wind and solar forecasts
– Improves scheduling of other resources to reduce reserves, fuel consumption, O&M costs and emissions
– Key recommendations
• Encourage expanded use of variable generation forecasting by BAs and forecasting improvements
• Study feasibility of using forecasts for day-ahead unit commitments/ schedules and schedule updates
• Encourage regional forecasts or exchange of forecasts among BAs
• Review whether existing forecasting systems adequately predict ramps
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Alstom 2010. Photo courtesy of DOE/NREL
• Take advantage of geographic diversity – Variations in output from wind and solar
plants are reduced over a large area
– Lowers aggregate variability and forecast errors, reducing reserves needed
– Key recommendations
• 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
• Investigate pros/cons of siting optimization software
• Support right-sizing of interstate lines (increasing project size, voltage, or both to account for credible future resource needs) that access renewable resources from zones designated through a stakeholder-driven process – when project benefits exceed costs
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NR
EL
• Improve reserves management – Amount of reserves for wind/
solar should vary by conditions
– Options include reserve sharing, dynamic calculations, using contingency reserves for wind events, and controlling variable generation
– Key recommendations
• Expand reserve-sharing activities (e.g., ADI), expand limits
• Ask BAs to explore dynamic reserve requirements
• Perform statistical analysis to determine benefits if reserves for wind and contingency reserves can be shared
• Equip more conventional generation with automatic generation control (AGC); evaluate benefits of AGC for wind vs. revenue lost during curtailment
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Demand Response That Complements Variable Generation
• Shift customer load up and down to complement wind and solar through direct load control and real-time pricing with automation
• May be cheaper than supply-side resources and energy storage technologies
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Key recommendations
• Consider DR to complement variable energy resources
• Test value propositions to assess customer interest in strategies for frequent control of loads both up and down
• Consider potential value of enabling DR for integrating variable generation when evaluating advanced metering
• Cultivate strategies that earn consumer confidence in DR
• Encourage participation of third-party DR aggregators
• Allow DR to compete on a par with supply-side alternatives in utility resource planning and acquisition
• Examine ratemaking practices for features that discourage cost-effective DR – e.g., demand charges that penalize large customers for higher peaks when they shift loads away from periods of limited energy supplies and revenue models that tie utility profits primarily to energy sales
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A More Flexible Generating Fleet
• Access greater flexibility in the dispatch of existing generating plants
– 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
– Requires rethinking resource adequacy analysis to reflect the economic benefit of flexibility service
– Changes to resource planning and procurement frameworks
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Key recommendations
• 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
• Identify strategies to minimize or avoid cycling
• Explore development of a flexible ramping ancillary service to take advantage of fast-response capabilities
• Examine and amend guidance for evaluating flexibility needs in utility resource planning
• Use competitive procurement processes to evaluate alternative flexible capacity solutions
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Blue - high confidence in estimate
Yellow - medium confidence
Orange - low confidence
Assessment of Integration Actions – Western Interconnection
1 Low - <$10 million region-wide; medium - $10-$100 million; high - >$100 million 2 Ranges in costs and integration benefits reflect different scheduling intervals (5-30 min.) 3 Forthcoming NREL report will provide more information on EIM integration benefits
About RAP
The Regulatory Assistance Project (RAP) is a global, non-profit team of experts that focuses on the long-term economic and environmental sustainability of the power and natural gas sectors. RAP has deep expertise in regulatory and market policies that:
Promote economic efficiency Protect the environment Ensure system reliability Allocate system benefits fairly among all consumers
Learn more about RAP at www.raponline.org
Lisa Schwartz
802-498-0723 (office); 541-990-9526 (cell)
