University of Southern California
DANIEL J. EPSTEIN DEPARTMENT OF
INDUSTRIAL AND SYSTEMS ENGINEERING
EPSTEIN INSTITUTE SEMINAR
ISE 651 SEMINAR
Treating Uncertainty in Electricity Markets by
Defining Ramp Capability Products
Paul Gribik
Pacific Gas and Electric, Market Design and Analysis
ABSTRACT
Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) use
Security Constrained Unit Commitment (SCUC) and Security Constrained Economic Dispatch
(SCED) models to operate their electricity markets and power systems. In the Real-Time
market, the ISO typically forecasts the system requirements (e.g. five minute loads, operating
reserve requirements) and system capability (e.g. a generator’s maximum output available and
ramp rate, transmission constraints) for upcoming dispatch intervals over a dispatch horizon. It
uses SCUC and SCED to find a least-cost commitment and dispatch that satisfies the power
balance, transmission flow limits, and resource limits in each dispatch interval over the planning
horizon.
SCUC and SCED do not account for uncertainties in forecasts of load or resource capability.
They will dispatch the system to achieve least cost over the dispatch horizon for a single
forecast. As a result, the dispatch may not maintain any flexibility for the RTO to adjust the
dispatch to respond to changes in forecasts as time progresses over the dispatch horizon. This
can result in transmission violations or shortages of energy or reserves when forecasts change
along with price spikes. To avoid this, the RTO will need controllable resources for which the
RTO can alter power output to meet varying needs. With increases in the proportion of
generation from intermittent renewable resources and increases in the flexibility of interchange
scheduling (e.g., 15 minute scheduling intervals), it is likely that the variability the RTO will face
will increase in the future, taxing the ramp response of controllable resources and increasing
the frequency of short-term scarcity events due to shortages of rampable capacity.
TUESDAY, OCTOBER 21, 2014
GRACE FORD SALVATORI HALL (GFS) ROOM 101
3:30 - 4:50 PM
SPEAKER BIO
Paul Gribik joined PG&E in 2012 where he works on market design and analysis issues.
Prior to that, he was at Midwest Independent Transmission System Operator where he
was a Senior Director. He joined MISO in 2003 as Director of Financial Transmission
Rights. He developed the processes that were used to allocate FTRs to market
participants and organized the group that runs the MISO’s FTR markets. He later
started the Market Development and Analysis Group at MISO and led the group in
developing a variety of market processes and in analyzing market outcomes. Most
recently, he led their efforts to develop the Extended LMP methodology that allows
commitment related costs to be included in LMPs, ramping flexibility products, and a
zonal reserve procurement methodology that incorporates transmission constraints.
Prior to joining MISO, Paul was a consultant from 1989 to 2003. He worked on
developing electricity markets and on evaluating market processes and software. He
also assisted electric utilities and independent power producers with their planning and
operations problems both in areas with RTOs and without RTOs.
Paul received a BS in Electrical Engineering, a MS in Industrial Administration and a
PhD in Operations Research from Carnegie-Mellon University.