Meeting Notes
Committee
Leader:
Jamie Austin
Committee:
Data Work Group
From Date
10:30 – 10:35
10:35 – 10:45
September 15, 2015
To Date
September 29, 2015

Welcome and Introductions

WECC Anti – Trust Policy Summary

Review of “Thermal Plant” Data and Assumptions

Generator Cost Parameters

Guidance from Intertek-APTECH
o Startup and Cycling Cost
o Variable O&M
o Ramping Penalty
o Final assumptions for forced outage rates

How to apply Ramp Rate Penalty in GridView?

Better alignment with historic Operation

Adjourn
10:45 – 11:00
11:00 – 11:30
11:30 – 11:45
11:45 – 12:00
Meeting Objectives
Develop thermal plant data and assumptions for the TEPPC 2026 Common
Case, starting with baseline values from the TEPPC 2024 Common Case.
Welcome and Introductions
Dan covered the WECC anti-trust policy. Jamie welcomed participants,
reviewed the agenda and explained that WECC and NREL contracted with
Intertek-APTECH Engineering in response to stakeholders concerns about
thermal plant cycling caused by greater penetration of renewable resources in
in their respective studies. At the request of NREL and WECC, Intertek
APTECH conducted a comprehensive analysis to aggregate power plant
cycling costs inputs with high and low bounds for the eight distinct groups of
generator types:
 Hot, Warm, and Cold Start Costs
o Load follow/ramping cost impacts
o Base-load Variable operation and maintenance (VOM)
o Base Load and Cycling Costs
Then APTECH agreed that TEPPC uses the low-end cost data in public
domain with some exception given “typical” values for large coal plants. The
reason for just low-end data is a hedge for APTECH to protect their business.
1
Microsoft PowerPoint
Presentation
Jamie learned from a recent conversation with Greg Brinkman that NREL is
planning on using low-end cost data in upcoming work as it is in public domain
and is refraining from repeated use of both high and low values as was done
previously.
Guidance from Intertek-APTECH
Stan explained that his presentation was a resurrection of old slides from 2011
used to provide high level summary of work by Intertek-APTECH.
Microsoft PowerPoint
Presentation
Stan added Intertek-APTECH is a company that tracks generator maintenance
costs. The need stemmed from higher wind at night resulting in base units
ramping down. The APTECH work instructed on how to model associated
costs.
The non-fuel costs (capital & maintenance) used were representative of median
– cold start costs (see slide 5, enclosed). The ramping costs from APTECH
were omitted from both the TEPPC 2022 and 2024 databases due to timing
issues as it relates to model capability.
How to apply Ramp Rate Penalty in GridView?
Jin Zhu from ABB explained, thermal unit modeling defines the operating
ranges (Pmain, Pmax and associated costs). The ramping rate, Up\Down
defines the unit capability to move within the hour; ramping penalty, however,
controls the unit ability to respond to changes. It is modeled in Gridview as
piece-wise linear function with up to 7 sections.
GridView on
Generation Ramping Penalty.pdf
Jan asked if the penalty in terms of dollars is reported as part of O&M costs.
Jin responded that it is not part of O&M; it is separate.
2
Steven asked, does ramping penalty impact the operating price?
Jin responded it will affect the LMP. It is priced at the next MW (e.g., $20 LMP
plus $3 ramping penalty). Steven countered; LMP is a bid price and agreed,
this is the way to do it.
Basically there is a layer for consideration for why to move up or down, leading
to the Ramping Penalty Curve. The charge is a relatively small amount and it
increases as it moves up to the higher range (as block size increases). The
reverse also applies based on the same concept. Gridview allow defining seven
blocks. The ramp penalty has to cover the full spectrum of dispatch range.
Jin used the TEPPC 2024CC, version 1.5 case to run tests applying the “V”
curve – ramping penalty costs, see diagrams showing impacts on power plants
(e.g., the higher penalty the penalty is the greater swing is). Jin tried applying a
$35 penalty on all large coal plants; this resulted in the cycling from Pmin to
Pmax moving monthly.
Steven asked if the test included look ahead to control monthly. Jin responded
no, has not yet tested with look-ahead logic.
Jin noted that the ramping penalty depends on first block settings--giving the
program a range to slow down. We need to collect operating data and
document how much the plant owner is willing to move up and down. We can
develop a cost/block that can be used in the simulation.
Xiaobo asked if the one block application is limiting. Jin responded that it
allows for small movement.
Kevin asked if multiple shapes for any time of the day are possible. He
suggested that there are two types to mimic:
Base loaded
Base to ramp up morning and ramp down as needed
Jin responded that hourly changes are temporary and can change over
time…the data can be temporal as well.
Ben added the following comment and question:
In the APTECH report lower bound $/MW is a multiplying factor that would help
to develop the “V” curve. What does the “*” under the multiply factor stand for?
Jamie responded if not noted, we may need to go back to APTECH for an
answer.
3
Better Alignment with Historic Operation
Kevin began his presentation by explaining what the production cost model is:
It economically commits and dispatches supply to serve load. There are no
hard constraints. Everything is evaluated as a cost. The objective is to mimic
utility operation.
The rules of Production Cost Modeling:
Single owner dispatch
Everything is evaluated as a cost ($)
WECC is composed of 38 BAAs, and each optimizes their supply to
economically serve their load and contractual obligations.
A modeler can only layer in constraints to mimic a desired behavior.
Back-casting provides a known behavior; what inaccuracies are you willing to
accept?
Jamie commented that the past cannot be totally predictive of future operation.
System operation is dependent on developing markets, and as such many
developments (e.g., EIM, CA-SB 350 calling for 50% RPS) plus other factors
will definitely impact future dispatching.
Ben added that we need to be sensitive to this at this time. I appreciate your
knowledge and experience but we need to use data in the public domain. What
would you give the staff to work with?
Kevin responded everything is evaluated based on Heat Rate and Start-up
costs. The modeled start cost can be fine-tuned by running a near term year
and iterating on the start cost to mimic general historic behavior.
Steven noted the decision to commit a unit to meet area reserve requirement is
made at the BA level. We need to have data to populate the model, to model
the future dispatch.
Kevin responded that BA supply commitment to serve the reserves requirement
only meets that requirement while the remaining BA supply economically
commits/dispatches to serve the modeled footprint (WECC).
Ben added that he was not sure what data to recommend that would substitute
for knowledge and experience.
Jamie commented we’ve always validated consistent with number of starts
typical to buckets, based on data collected from plant owners.
4
Kevin noted – the APTECH data does not make sense. Most often the contract
covers for a number of starts (e.g., min per week, month, and year). The
TEPPC case penalizes for every start. Kevin offered the following idea in a
subsequent conversation:
“If you had to select an APTECH value, moving from the cold median to
the cold start/25th percentile would lower the start cost more in line with
judgment, assuming the start on many of the CC will go up therefore a
warm start/25th percentile would be better, if we expect daily cycling we
could move to a hot start/25th percentile.”
Ben concluded this can be treated as a process:
1. Start with APTECH data
2. Review the number of starts
3. Adjust going forward to individual plant; this can be done by using CEMS
data
Using startup cost is like using “hurdle rate”, analogues with using switches to
tune the answer to a predictable outcome. Perhaps we need to run sensitivities
to control some of the uncertainties as in the Kevin’s recommendation to also
use costs for warm starts.
APTECH started from actual physical costs, assumed to reflect known
operation, leaving us with the question, what did that cover?
The best approach is the hedge by adding sensitivities, rather than just using
one value to predict future operation.
The main question becomes how to bridge the gap between the future and
today’s operation?
Brathwaite, Leon
In attendance at the 092915 Meeting:
Company
Name
PAC
x
Lau, Elaine
Larsen, Peter
Le, David
CEC
Lee, Peter
CEC
Lehr, Ron
VoteSolar
Lindsay, Jimmy
WECC
Linvill, Carl
LBNL
Mao, Megan
CEC
Brownlee, Ben
Beckstead, Dan
Belval, Ron
Energy
Strategies
WECC
TEP
Name
Austin, Jamie
Amjadi, Amir
Alvarado, Al
Anderson, Grace
Baack, Jim
Bailey, Michael
Barbose, Galen
Maracas, Kate
x
x
Marrs, Richard
McLean, Christopher
Company
CPUC
LBNL
CAISO
BPA
AWEA
RAP
SCE
WWND
CEC
5
McCann, Richard
Broad, Diane
Brathwaite, Leon
Brinkman, Gregory
Brooks, Donald
Brown, Elise
Brush, Ray
Burner, Bob
Carr, Tom
Carvallo, Juan Pablo
Charles, Gillian
Chhajed, Pushkar
Chisholm, Tom
Colburn, Mitch
Coe, Scott
Cole, Brian
Corum, Ken
Davis, Enoch
Deaver, Paul
Decker, Megan
Denker, Brendan
Depenbrock, Fred
Delleney, Mike
Donnohoo, Pearl
Didsayabutra, Paul
Drennan, Ted
Eaton, Pam
Evans, Mike
Ezequiel
Filippi, Jim
Fisher, Emily
Freeman, Bryce
Gazewood, Jim
Green, Irina
Griffin, Karen
CEC
NREL
CPUC
SPSG
Western
Duke Energy
WIEB
IID
x
NPCC
LCG
Consulting
BPA
IPC
x
NWPCC
WECC
CEC
SRP
Nevada Hydro
CAISO
NREL
COGRID
PAC
SPSG
Shell Energy
IID
First Solar
NREL
WYOC
BLM
CAISO
x
x
x
CEC
Grau, Judy
Gutierrez, Noe
Hamilton, Roger
Haenichen, Jack
Hands, Betsey
Harris, Gerald
Harris, Kevin
Harwood, Patrick
Hein, Jeff
Heutte, Fred
Hodge, Bri-Mathias
Holland, Stan
Hosie, Bill
IID
WECC
Duke Energy
x
x
x
SDG&E
SCE
CAISO
PG&E
NREL
E3
SDG&E
WECC
Newman, Raymond
Nail, George
PN&M
Nothstein, Greg
O’Neill, Ean
Pacheco, Ezquiel
Pacini, Heidi
Papic, Milorad
Pascoe, Bill
Perez, Army
Piper, David
CEC
IID
ICF
IPC
TREL
WECC
SCE
Prochnik, Julia
Pryor, Mark
Puglia, Peter
Quick, Kirha
Raub, Jenika
NRDC
CEC
CEC
WECC
SRP
Richard, J
Rowe, Sarah
Rucker, Magdalena
Sapp, Shawn
Satchwell, Andy
Schlag, Nick
Schanahan, Patrick
Schellberg, Ron
Schilmoeller, Michael
CEC
OPUC
IPC
NWPCC
Xcel Energy
Simmons, Steve
NWPCC
Spears, Michael
Satyal, Vijay
Starck, Jan
Stefan
Stokes, Mark
Tanghetti, Angela
Trinh, Lan
Tilghman, Henry
Voisin, Nathalie
Von Reis Baron, Kate
x
Ventyx
LBNL
E3
Schmidt, Jason
Singh, Harliv
WWND
MT
Reos
COGRID
WAPA
Xcel
NWEC
NREL
McIntosh, Henry
Mejia, Roni
Misca, Catalin
Miller, Tom
Milligan, Michael
Moore, Jack
Moussa, Effat
Moyer, Keegan
Xcel Energy
WECC
SDG&E
OPUC
x
x
CEC
ABB
Tilghman
Associates
NWNL
PGE
x
x
6
Huang, Wenxiong
Ibanez, Eduardo
Jenka, Raub
Jensen, Richard
Johnson, Anders
Johnson, Colby
Jourabchi, Massoud
Kates, David
Kelly, Nancy
Kennedy, Robert
Ketabi, Noushin
Kim, Songtae
Klapka, Paul
Klein, Joel
Knudsen, Steve
Kujala, Ben
Kravchuk, Luba
PLEX
NREL
SRP
CEC
BPA
WECC
NWPCC
Nevada Hydro
CEC
Energy
Division
PAC
SCE
CEC
BPA
NWPCC
CAISO
x
x
Wang, Xiaobo
Wallace, Steve
Wheeler, Dan
Williams, Stan
White, Keith
White, Stephen
Weiss, Steve
Woertz, Byron
Wong, Lana
Xiong, Lei
CAISO
CPS
Gaelectric
BPA
CPUC
BPA
BPA
WECC
CEC
Alberta Electric
System Operator
(AESO)
x
x
CAISO
ABB
x
x
x
Young, Patrick
Zewe, Janice
Zhang, Yi
Zhu, Jin
Zhang, Hui
Zichella, Carl
NRDC
7