the mit future of the electric grid study · 2017. 12. 8. · john g. kassakian. professor of...
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The MIT Future of the Electric Grid Study
Richard Schmalensee
September 23, 2011
A Crisis?? Really?? What to do??“Our nation’s electric power infrastructure that has served us so well for so long… is rapidly running up against its limitations. Our lights may be on, but systemically, the risks associated with relying on an often overtaxed grid grow in size, scale, and complexity every day.”
U.S. Department of Energy, 2009
The MIT Future of the Grid study aims • to provide an objective portrait of the U.S. grid and the new challenges and opportunities it will likely face before 2030, and
• to recommend policy changes to assist its appropriate evolution
• Follows & is modeled on a set of recent multidisciplinary MIT studies of energy topics addressed to decision‐makers
• Study began in Fall, 2009; expect to unveil (online) in November or December.
• Will be too long to cover completely; topical coverage reflects only my priorities.
• And we are still debating findings & recommendations; opinions today are mine alone
The Study Context
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Research TeamStudy Co‐Chairs
John G. KassakianProfessor of Electrical Engineering and Computer Science (EECS) , MITRichard SchmalenseeHoward W. Johnson Professor of Economics and Management, MIT
Study Management
Gary DesGroseilliersExecutive Director
Timothy D. HeidelResearch Director
Study Group
Khuram AfridiAssociate Professor Lahore University of Management Sciences, Pakistan; Visiting Associate Professor, EECS, MIT
Amro M. FaridAssistant Professor of Engineering Systems and Management, Masdar Institute, UAE; Research Affiliate, MIT
Jerrold M. GrochowFormer Vice President for Information Services and Technology, MIT
William HoganRaymond Plank Professor of Global Energy Policy, John F. Kennedy School of Government, Harvard University
Henry D. JacobyWilliam F. Pounds Professor of Management Emeritus, MIT
James L. KirtleyProfessor of Electrical Engineering, MIT
Harvey G. MichaelsResearch Scientist, Urban Studies and Planning, MIT
Ignacio Pérez‐ArriagaProfessor of Electrical Engineering, Comillas University, SpainVisiting Professor, Engineering Systems Division, MIT
David J. PerreaultProfessor of Electrical Engineering and Computer Science, MIT
Nancy L. RoseCharles P. Kindleberger Professor of Applied Economics, MIT
Gerald L. WilsonVannevar Bush Professor of Electrical Engineering Emeritus, MITFormer Dean, MIT School of Engineering
Student Research Assistants
Nabi Abudaldah, Wageningen University, The Netherlands and Visiting Student, MIT
Minjie Chen, EECS, MIT
Pearl E. Donohoo, Engineering Systems Division, MIT
Samantha J. Gunter, EECS, MIT
P. Jordan Kwok, Engineering Systems Division, MIT
Vivek A. Sakhrani, Engineering Systems Division, MIT
Jiankang Wang, EECS, MIT
Andrew Whitaker, Engineering Systems Division, MIT
Xiang Ling Yap, Harvard University and Engineering Systems Division, MIT
Richard Y. Zhang, EECS, MIT
Advisory CommitteeJ. Bennett Johnston, ChairUnited States Senate (Retired)
George ArnoldNational Institute of Standards and Technology
Lisa M. BartonAmerican Electric Power
Troy Batterberry and Elizabeth GrossmanMicrosoft Corporation
William W. BerryDominion Resources (Retired)
Clark GellingsElectric Power Research Institute
Robert Gilligan and Larry SollecitoGeneral Electric
Laura Ipsen and Paul De MartiniCisco Systems
Paul JoskowAlfred P. Sloan Foundation
Elizabeth Anne MolerFormer Chair, Federal Energy Regulatory Commission (FERC)
Steven NaumannExelon Corporation
Pedro Pizarro and David MeadSouthern California Edison
Claes RytoftABB Group
Miguel Ángel Sánchez ForniéIberdrola S.A.
Basem SarandahNexant, Inc.
J. Charles SmithUtility Wind Integration Group
Susan TierneyAnalysis Group
Gordon van WelieISO New England
Stephen G. WhitleyNew York ISO
The Diverse & Complex US System
• No comprehensive US national policy, limited FERC authority
• 3 “interconnections”; 107 balancing authorities (6 in AR, 1 in NY)
• Generation: investor‐owned (84% of generation), plus cooperatives and systems owned by city, state, and federal governments
• Distribution: 3,200 government owned, cooperative, and investor‐owned entities (242 investor‐owned firms have 66% of sales)
• Organized (ISO/RTO) wholesale markets serve about 2/3 of load, about 42% of generation by firms without retail customers:– Regulated integrated companies dominate in the southeast;– Federal hydro generation and transmission are important in the west.
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Key Emerging Challenges & Opportunities
• Remote sensing and automated operating technologies in transmission and distribution
• More grid‐scale, remote non‐dispatchablerenewables
• More distributed generation and plug‐in electric vehicles
• Technologies that enable making load responsive to system conditions
• More data communications, raising cyber‐security and information privacy concerns
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Talk (& Report) Outline
•Transmission and bulk power (3 chapters)• New technologies• Transmission Expansion
• Operation with VERs
•Distribution and demand (4 chapters)• Demand response
• Regulatory policies & incentives
•Communications, cybersecurity, and privacy (1 chapter)
Transmission & Bulk Power:
New Technologies
Control Center
Energy Management System Functions:• State Estimation• Economic Dispatch• Unit Commitment• Contingency Analysis• Automatic Generator
Control• Phase
Monitoring/Alarms• Improved System
Models• Oscillation Detection
Generators andSubstations:• Protective Relays• Circuit Breakers• Transformers• SCADA Remote Terminal
Units• Surge Arresters• Phase Shifters• Flexible ac Transmission
Systems• Phasor Measurement Units• SensorsLines and Cables:• Extra High Voltage ac Lines• High Voltage dc Lines• Superconducting Lines• Fault Current Limiters• Dynamic Line Rating
Systems
New Technologies for System Operation
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PMU Data Could Warn of Blackouts• PMUs give frequent, GPS-synchronized measures of current, voltage,
and phase angle at their locations.
• Ex-post analysis of 2003 blackout:
Greater Capacity & Reliability, if…
• PMU data & data from other sensors can also be used with FACTS technologies to increase capacity
• Some PMUs deployed, but lack software to use the massive data flow from PMUs and other sensors
• And that software needs to employ more accurate system models based on those rich data
• Need to develop suitable applications software, system models; requires sharing PMU data
Transmission & Bulk Power
Transmission Expansion
The VER Challenge
• 29 states & the District of Columbia have “renewable portfolio standards,” generally requiring increasingamounts of non‐hydro renewable (NHR) generation.– A national standard and more state standards are possible
• Expect more NHR generation, mainly wind & solar VERs.
• Key Challenges:
– New transmission will be required (due to location constrained nature of resources).
– Changes to system operation will be required (due to variability and imperfect predictability).
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Will Need More Boundary-Crossing (B-C) Lines
• Required by increasing system integration as well as VERs.
• Little wide‐area planning; cost allocation negotiated for each B‐C line; states and federal agencies (30% of US land) control siting.
• FERC’s new Order 1000 requires regional planning, general bilateral cost allocation rules for B‐C lines, consistency with “beneficiary pays.” BUT• Does not require interconnection‐wide planning or development of
tools to support it.
• Does not require single interconnect‐wide cost allocation rules; could get inconsistent bilateral rules.
• Does not address the major problem of multiple vetoes in siting B‐C lines; FERC should have either initial siting authority (as in natural gas pipelines) or effective backup authority if states/agencies don’t approve.
Transmission & Bulk Power
Operation with VERs
System Operation with lots of VERs• Stochastic nature of wind complicates unit commitment and economic
dispatch decisions. Some conventional generation resources will be required to cycle more often.
• Wind ramp events (large slow changes in output over several hours) are particularly worrisome.
System Dispatch with Wind Generation Wind Generation Ramp Event
• Operators are very aware of the technical problems; lots of work ongoing; no obvious major policy prescriptions.
• Improvements in wind forecasting needed, under development: better sharing of turbine‐height wind data would help
• Sources of flexibility in operations need to be more explicitly recognized & rewarded; may need markets in ramping(?)
• Virtual or full consolidation of balancing areas can reduce integration costs (ie. shared reserves, frequency regulation, etc.)
• VERs built now need to work in high‐VER futures, but today’s grid codes may not be adequate for such futures.
Operation with lots of VERs, continued
Distribution & Demand
Demand Response
Demand Response & AMI• Air conditioning, loss of industrial load (50% in 1950s, 28% in
2000s) have made load “peakier”; how to offset this?
“Peakier” Load Duration Curves Raise Cost
Normalized Load Duration Curves: 1980–1984 versus 2005–2009
Demand Response & AMI• Air conditioning, loss of industrial load (50% in 1950s, 28% in
2000s) have made load “peakier”; how to offset this?– In organized markets, large commercial & industrial customers
sometimes face real‐time prices; smaller customers rarely do.
– Most current demand response programs – e.g., interruptible power –focus on emergencies, not load‐leveling.
• Without effective incentives to charge off‐peak, PHEVs/EVs could add significantly to peak loads in some areas– Don’t expect big national impact by 2030, though.
• With huge variations in marginal cost, more real‐time pricing + responsive demand could flatten load & lower cost, but metering has been too expensive for small customers.
Marginal Cost Variation: PJM, 2010
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2010 Average Daily v. Selected Day Hourly (inset) Average Real-Time LocationalMarginal Price (RT LMP) in the PJM Region. Source: http://pjm.com/markets-and-operations/energy/real-time/monthlylmp.aspx
Demand Response & AMI• Air conditioning, loss of industrial load (50% in 50s, 28% in
00s) have made load “peakier”; how to offset this?– In organized markets, large commercial & industrial customers
sometimes face real‐time prices; smaller customers rarely do.
– Most current demand response programs – e.g., interruptible power –focus on emergencies, not load‐leveling.
• If no change in incentives, electric vehicles could add peakiness, but not likely to be big nationally by 2030.
• With huge variations in marginal cost, more real‐time pricing + responsive demand could flatten load & lower cost, but metering has been too expensive for small customers.
• AMI now makes real‐time pricing much cheaper.– Feds have subsidized some AMI; some states have required it.
AMI & Demand Response
• While there is a lot of investment in AMI in the U.S., there is essentially no movement to real‐time pricing.
• Consumers like bill certainty; technologies to automate price response are immature; very little retail competition in the U.S. (and no movement toward it).
• If a utility is not committed to AMI, & operational benefits don’t justify it (they often don’t), no reason to rush.
• If a utility has AMI, though, it should work toward real‐time pricing with education & information, and share what is learned – esp. if feds subsidized investment.– We worry about data‐sharing from current DOE projects.
Distribution & Demand
Regulatory Policies & Incentives
Distributed Generation (DG)
• The technical problems associated with high DG penetration are real but do not seem serious.
• However, as long as fixed network costs are recovered via volumetric (per‐kWh) charges, – Utilities have incentives to retard penetration of DG, perhaps citing technical problems.
– Compensating DG at retail rates (net metering) tilts in favor of (clean & dirty) DG, against central station generation.
• Obvious fix: Fixed network costs should be recovered through fixed charges, not volumetric charges.– If this is not possible, decoupling distribution revenues from short‐run sales changes would be useful.
Learning About New Distribution Technologies
• A variety of promising new distribution technologies have been developed and demonstrated, some with DOE support, including– Automatic fault detection & restoration (self‐healing)
– SCADA/EMS/DMS/OMS integration
– Volt/VAR optimization
– AMI Integration for outage notification & restoration verification
• Investments in these new technologies often add capability, not just capacity; returns may be high but are less certain than traditional investments that just add capacity
• It is important that results – good and bad – from early “smart grid” projects, esp. DOE‐supported demos, be widely shared
New Technologies & Old Regulation
• Because regulators and utilities are often punished politically for bad ex post outcomes, they have historically been highly risk‐averse.
• Excessive risk‐aversion will become more expensive as DG and EVs penetrate and new technologies advance, but it is not clear how to solve this important problem.
• Risk‐aversion may also be why useful, comparable performance metrics are rare: there is a high downside risk if performance don’t look good over time or space.– Easy to say that regulators should develop and use performance
metrics; not clear how to make them less averse to doing so.
Communications, Cybersecurity& Information Privacy
These domains are linked: as data communications becomes more important, so do issues of privacy & problems of cybersecurity.
33Source: NIST
Communications & Privacy Issues
• Communication and Interoperability Standards• Different types and generations of components must be
interoperable over different networks (AMI v. grid ops).• NIST-overseen standard-setting is (inevitably) messy, but seems to
be going well.
• Ownership of Data Communications Networks and Spectrum• Utilities will continue to use a variety of different networks for
different purposes; public/private boundary in dispute.
• Policies Regarding Consumer Electric Usage Data (CUED)
• Privacy concerns similar to those involving other consumer data; being adequately addressed by ongoing state-level debates? Not really a problem to be solved…
Cybersecurity Risks & Issues
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• Many sorts of risks are present now and will become even more serious; not clear how well the diverse industry participants and regulators appreciate this; not their expertise.
• Lots going on at the bulk power level, much of it “in the black.”
• Participants focus on protection, but can’t protect perfectly; emphasis should shift toward response and recovery
• NERC leads at the bulk power level; nobody leads at the distribution level – esp. with munis, coops, other mostly small, unregulated entities – and trans/dist line is blurring.
• Need a single federal agency (DHS?), with system‐wide cybersecurity responsibility, requirement to collaborate.
Some Concluding Thoughts
• The electric grid in the US (and elsewhere!) will face significant new challenges and undergo major changes in the next two decades.
• There is no crisis; the U.S. system is not broken and is adaptable – but we do not advise complacency.– Regulatory policies need to be reformed;
– incentives need to be better aligned;
– research & demonstration need to be done;
– and valuable data need to be compiled and shared.
• The journey to the grid of 2030 has just begun, and much can and should be done now to smooth the road ahead.
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