DWG Progress Report to TAS
February 1-2, 2016
Salt Lake City, UT
Jamie Austin, PacifiCorp
TEPPC\Data Work Group - Chair
2
Overview
• The Round Trip Process & the TEPPC 2026CC
• Update on DWG work building the TEPPC 2026
Common Case
–
–
–
–
–
–
–
–
–
Loads And Hydro Data
Approval Item: EE Assumptions
Approval Item: Distributed Generation
Approval Item: Station Service
Approval Item: Heat Rate Curves
Approval Item: Plant Outage Rates
Approval Item: Plant Retirement Assumptions
Approval Item: Fuel Prices
Approval Item: Transmission Wheeling Rates
3
The Round Trip Process & The TEPPC 2026CC
4
The NTTG Round Trip
5
Power Flow
Export 2025 HS
Power Flow
LRS
hort-Term Round Trip Process (STRTP)
Loads:
Monthly Peak and
Energy
December 8, 2015 6
Version 1.0
DRAFT
WECC staff to build
Gen Dynamic
Models for atypical
– new resources
iterate
2026 HS Power Flow
Iterate
Regional Planning
Groups
WECC Staff
Resources
Iterate using
NTTG s Round Trip Process
Existing Resources:
Start with the
TEPPC 2024CC,
reconciled with
WECC 2025 hsa1
power flow
Iterate
Incremental (Future)
Resources to be
determined by GAP
Analysis Task Force .
Stall to feed into
2026 HS Power Flow
Hourly Shapes (Year 2009) –
FERC 217
LBNL – EE, DSM, DR
Hourly Wind, Solar & Hydro
DWG – Validates 2026
Hourly Loads & Energy
Shapes
Create 2026, v0.1
Common Case v0.1,
0.2. 0.3...
Iterate
Other Inputs thermal
Unit Commitment Data
for incremental
resources, new Heat
Rate Curves, etc.
NTTG - PCM
TEPPC 2026 CC
Plus
WECC 2025 HS Power
flow i
(resource mapping by 4
regions)
NTTG
Round Trip
NTTG Solved 2026 Power
Flow with Mapped
Resources, (resource
mapping by 4
regions)
Create CCTA
Create 2026
Common Case v1.0
Export Select
Hours for TEPPC
Studies
TEPPC 2026 CC
&
Corresponding
one hour
solved power
flow case
Use to Run
Reliability Studies
Select needed hours;
Run Power Flow
Analysis
7
In Summary
Updates Using Power Flow
• Add new generators in the power flow as the correct generator location is
necessary when accounting for appropriate integrating elements (e.g., underlying
transmission area reactive definition). Also, this will lead to consistent accounting
of generators and their mapping between PF and PCM.
• Transmission line changes and other system adjustments should be applied in the
PF model to achieve a PF solution (i.e., convergence) in successive PF iterations
because certain critical PF data (e.g., new reactive requirements) will be stored in
the PF base case that is exported to the PCM and from PCM back to PF model.
PCM direct updates include the following:
• The PCM program in general requires more extensive generator data than the PF
program: Heat Rate Curves, Ramp Rates, Startup costs, Fuel Costs, EFOR,
Maintenance Data, Reserves, etc.
• Loads (Monthly peak and energy and hourly energy shapes)
• Wind, Solar, EE, DR, DG and other hourly shapes both on the load and supply side
8
Loads & Hydro Data
9
TEPPC 2026CC Loads
• Use LRS submittals collected in March of 2015--BAA
load forecasts 10 years forward, through 2025.
– For the 2024 CC, we used sixth polynomial, linear fit
extrapolation; However,
– For the 2026 CC, DWG recommends using simple compound
and recent data from the last three to four years as that will
lead to more accurate results. Using sixth polynomial
assumes a high level of accuracy that is beyond our
forecasting capabilities.
• Exception: For California use the “new” CED forecast
approved by the CEC January 27, 2016. The CEC
forecast covers through year 2026.
10
TEPPC 2026CC Loads
Next Steps
• Apply EE adjustments
– Adjustments already determined by LBNL
• Remove Pumping Loads from forecast
– Already determined by Irina Green
• Create load shapes using 2009 historic data
• Work with DWG to validate shapes and load
factors
• Gridview import
11
Hydro Data
• Hydro Data – Status Report
– Irina Green just finished processing California’s
hourly hydro shapes for both 2008 & 2009,
covering SMUD, MID and TID but not IID.
– PacifiCorp hydro hourly shapes for years 2008 and
2009 will be made available by February 8.
– Kevin is working with BPA on getting Northwest
hydro
– Pending: Canada and Colorado River
12
EE and DR Data
W
E
S
T
E
R
N
E
L
E
C
T
R
I
C
I
T
Y
C
O
O
R
D
I
N
A
T
I
N
G
C
O
U
N
C
I
L
13
Energy Efficiency and Demand Response
• The Common Case is intended to reflect current policies
and utility plans (RPS, IRP, EES, etc.)
• BA load forecasts vary in the manner/extent to which
they account for planned energy efficiency and demand
response policies and program plans
• Some may not include any EE impacts, while others may
only include a portion of the planned EE
• In prior study cycles, LBNL assisted DWG consistent with
past years with making adjustments to the firm and nonfirm load forecasts in order to:
– Support the overarching intention of the Common Case (i.e., to
reflect current policies)
– Improve consistency across BAs in terms of EE & DR accounting
14
Energy Efficiency Adjustments
• Objective: Adjust firm load forecasts, as
necessary, to fully capture energy efficiency
impacts under current policy and program plans:
– Based on current Energy Efficiency Resource Standards or
IRPs
• Last study cycle (2024 Common Case):
– Focused only on utility ratepayer-funded programs; did not
make adjustments for federal or state appliance standards,
building codes, or other program/policy types
– Focused only on those specific BAs (CISO, IPC, PNM, TEP)
that, through prior study cycles, were known to
systematically “under-count” energy efficiency impacts in
the load forecasts submitted to WECC
15
Energy Efficiency Adjustments
(continued)
For this year’s study cycle:
• LBNL reached out to the load forecasting staff with IPC, TEP,
SRP, and PNM. These were the four BAs that, in previous
iterations of the Common Case, were found to not fully
account for planned EE within their LRS forecasts.
• Based on responses received, only IPC did not fully include
planned EE in the LRS load forecast in addition:
– Galen confirmed that non-ISO CA BAs have already made necessary EE
adjustments with more recent study cycles.
• The only EE adjustments will be applied to the IPC loads.
• Use the CEC “preliminary issue of the 2016 load forecast for
California that includes latest assumptions for EE and AAEE.
16
Motion
“It is moved that TAS approves:
• Accepting the LBNL adjustment to IPC loads to
account for Energy Efficiencies (EE)
assumptions in the TEPPC 2026 Common
Case.
• Use the CEC “newly approved 2016 load
forecast for California that includes latest
assumptions for EE and AAEE, and DR.”
17
Distributed Generation
W
E
S
T
E
R
N
E
L
E
C
T
R
I
C
I
T
Y
C
O
O
R
D
I
N
A
T
I
N
G
C
O
U
N
C
I
L
18
Distributed Generation
• In the context of developing the load forecast for the
TEPPC 2026 Common Case, DWG held several
discussions to determine how best to account for
Distributed Generation (DG) in the TEPPC 2026
Common Case
• DG is also referenced as behind the meter PV (BTM PV)
– large scale photovoltaic generation that is connected
to the distribution system.
• The discussions addressed:
– Should DG be netted from loads or modeled on the supply
side?
– How to best coordinate modeling needs in terms of
implementing the “round trip”?
19
The Challenge
• Relative to models, the ideal would be to have
consistent data, assumptions and representation in
both power flow and in the production cost model
to facilitate implementation of the round trip.
• Relative to data, the challenge is twofold:
– What estimates to use for distributed generation?
– Where to place them?
• Relative to TEPPC, DG cannot be netted from loads;
DG has to be tracked and accounted for concisely.
20
DG Modeling Limitations
• The WECC data preparation manual stipulates that single generating units 10
MVA or higher, or multiple units with aggregated capacity of 20 MVA be connected
to the transmission system (69kV and above) through a step-up transformers(s)
modeled as distinct generation in the WECC base case.
– Hence in PF, smaller DG is modeled as a negative load and is tracked and
accounted for in the “Composite Load Model” with associated dynamic model
for running stability analysis.
• In GridView negative loads are tracked separately, however negative loads
can’t have hourly shapes.
• Other concerns relate to the PCM run time when adding DG generators to
the model:
– “Spillage” impacts the run time of generators using hourly shaped resource
like wind or solar and DG
– If no “Spillage”, the impact on run-time for a hourly shaped resource is
minimal
21
DG Data Limitation
• There are three major reasons why we cannot map DG to the
customer bus in the TEPPC 2026CC:
– It is reported that upcoming ISO planning studies will include DG
mapping to customer level; we do not have access to mapping info.
– The CEC nets DG from the local load in Plexos when determining
demand and supply assumptions that feeds into NAMgas--the model
that produces the gas price forecast.
– The States keep track of DG customers by state and by zip code.
However, TEPPC cannot possibly use the states’ data to map DG due to
the restricted schedule.
• Mapping resources to the bus in the new 2026 CC will invlolve major
players (e.g., CASIO, CEC, Regions and others) and require more time than
is available.
22
Motion
“It is moved that TAS approves the following rules for DG when
building the TEPPC 2026 CC:
• Model DG as explicit generators, one per BA, using the generator
distribution factor to map DG to busses representing a minimum of
50% of loads. DG distribution will be prorated, based on the largest
load busses in the BA such that DG load does not exceed 50% of bus
loads.
• To quantifying how much DG (BTM-PV) to model:
– For California, use assumptions developed by the CEC in their new
2016 Load forecast.
– For other states model programs that reflect current policies and
utility plans (RPS, IRP, EES, etc.):
• Use results from the LBNL survey , asking BAAs for:
– How much DG is embedded in the load forecast?
– How do they model DG?
– What is their forecast for year 2026?
• Use the E3 proposed estimate for market driven DG in scenario
analysis, however, vetted and approved by DWG\TAS.”
23
Station Service
W
E
S
T
E
R
N
E
L
E
C
T
R
I
C
I
T
Y
C
O
O
R
D
I
N
A
T
I
N
G
C
O
U
N
C
I
L
24
Accounting for Station Service Loads
• SS values in the TEPPC 2024CC are all equal to zero,
consistent with how they are treated in the LRS load
forecast; SS values were netted from generators.
• The WECC 2016 Data Preparation Manual for WECC power
flow cases calls on SS loads to be modeled explicitly and in
general placed at the generator bus:
– Station service at modeled generation facilities with loads
greater than or equal to 1 MW shall be modeled explicitly and
load modeling generator station service shall have Load ID set
to ‘SS.’
– A Long ID shall be provided for each load in accordance with
the WECC MVWG Load Long ID Instructions , either within the
case or in a separate spreadsheet file. See Dynamic section
Load Characteristics.
25
Data Limitation
• Consistent with the NTTG “round trip” automation, ABB added load bus ID to
GridView that allows for tracking non-conforming loads (e.g., SS loads can be
tracked separate from native loads). This leads to the conclusion that
modeling SS explicitly is more limited by data and process.
• In an ideal world we want to have equivalent treatment of all modeled
elements to allow for bidirectional transfer of date between the two databases
for power flow and production cost modelling. Hence, consideration needs to
be given to the followings:
– Since there is no consistent SS load amongst generators, it is impossible to write an
equation that would direct GridView to adjust for SS load when the generator is derated or is off line.
– Heat Rate Curves are being calculated based on generator gross capacity. If SS is
modeled explicitly, we need to adjust the Pmax to correct for net.
– The SS dynamic model for stability analysis is based on plant gross Pmax; the
governor Pmax is based on plant gross rating.
– If we elect to model SS explicitly, the staff would have to restore full generator
capacity in the TEPPC 2026CC (Pmax was de-rated in the TEPPC 2024CC to
represent capacity net station service.)
26
Motion
• “It is moved that TAS approves: modeling
Station Service (SS) load as netted from
generator capacity for the 2026 Common
Case. In addition, WECC will correct the
“BusLoadDist” table to reflect SS in the 2026
HS power flow case for export power flow
hours. TAS further requests that WECC
develop seasonal load distributions for other
seasons.”
27
Heat Rate Curves
28
Heat Rate Curves
• Given the importance of the heat rate curves to the commitment decision, it is
prudent to have common assumptions for the whole set. Further, it is also
important to refresh with new CEMS data every several years as operations change
and hence, the heat rate curves.
• Problem – the TEPPC 2024 common case has a set of non-matching heat rate
curves developed by different sources:
– The SSGWI database was handed to WECC in 2006. At that time typical manufacturer data was
used based on vintage, size and technology that were also vetted by plant owners.
– In 2011 an attempt was made to update all heat rate curves using CEMS data. Replacement curves
were applied to large units only as we ran out of time and resources for full implementation.
– The staff time is scarce and this task requires time and involving experts in the field to produce
credible data.
• Solution – use a credible stakeholder process where all parties can benefit by
collaborating. The CEC has started their effort to update Heat Rate Curves for the
IPER, using consistent methodology. TEPPC has stakeholder experts who are willing
to work with the CEC staff on behalf of TEPPC on this synergistic project.
29
DWG Agreed to Methodology
• Approximate the IO curve data with a polynomial function
– Calculate Average Heat Rate Curve (AHR) from the following
equations:
– Calculate Incremental Heat Rate Curve (IHR) as follows:
• Use CEMS data to approximate the IO Curve as follows:
– For each hour of the year, the CEMS data gives the unit’s
• heat input (input power in MMBTU/h)
• gross generation (output power in MW)
– Approximate the IO curve from the CEMS data as follows:
• scrub the CEMS data
• graph the scrubbed dataset as a scatter plot
• represent the scatter plot with a polynomial regression curve
30
Scrubbing CEMS Data
• A few levels of scrubbing have been completed:
– Use only Whole hours
– Delete outliers
– Use only data above Min generating level
Before
After
31
Results
Gross Values
Capacity
IO Curve (Fuel Burn)
Average Heat Rate
1.00
225.29
225.29
All - Capacity
101.67
202.33
1,198.38 2,254.56
11.79
11.14
Units
303.00 MW
3,393.84 MMBtu
11.20 MMBtu/MWh
Net (Modeled Values)
Capacity
Average Heat Rate
Incr Heat Rate
0.89
251.89
Gross Values
Capacity
IO Curve (Fuel Burn)
Average Heat Rate
Whole Hour - Capacity
Units
1.00
101.67
202.33
303.00 MW
225.29 1,198.38 2,254.56 3,393.84 MMBtu
225.29
11.79
11.14
11.20 MMBtu/MWh
Net (Modeled Values)
Capacity
Average Heat Rate
Incr Heat Rate
0.89
251.89
90.93
13.18
10.81
90.93
13.18
10.81
180.96
12.46
11.73
180.96
12.46
11.73
271.00 MW
12.52 MMBtu/MWh
12.65 MMBtu/MWh
271.00 MW
12.52 MMBtu/MWh
12.65 MMBtu/MWh
32
Results Cont.
Gross Values
Capacity
IO Curve (Fuel Burn)
Average Heat Rate
Net (Modeled Values)
Capacity
Average Heat Rate
Incr Heat Rate
Gross Values
Capacity
IO Curve (Fuel Burn)
Average Heat Rate
Net (Modeled Values)
Capacity
Average Heat Rate
Incr Heat Rate
EIA Min and Outliers - Capacity
Units
75.00
151.00
227.00
303.00 MW
932.52
1705.59
2526.04
3393.84 MMBtu
12.43
11.30
11.13
11.20 MMBtu/MWh
67.08
13.90
135.05
12.63
11.37
203.03
12.44
12.07
271.00 MW
12.52 MMBtu/MWh
12.77 MMBtu/MWh
Min Level from Scatterplot - Capacity
Units
160.00
207.67
255.33
303.00 MW
1,800.28 2,312.84 2,844.02 3,393.84 MMBtu
11.25
11.14
11.14
11.20 MMBtu/MWh
143.10
12.58
185.73
12.45
12.02
228.37
12.45
12.46
271.00 MW
12.52 MMBtu/MWh
12.90 MMBtu/MWh
33
Status
• Paul is well underway toward producing the heat rate curves for the
TEPPC case under the advisement and guidance of the DWG Task
Force, composed of industry exports including:
–
–
–
–
–
–
–
–
Paul Deaver – CEC
Kevin Harris - Columbia Grid
Mike Baily – WECC Staff
Steven Wallace – CPS
Greg Brinkman – National Renewable Energy Labs (NREL)
Ben Brownlee – Energy strategies
Massoud Jourabch i– NPCC
Jamie Austin – PacifiCorp
• The last step involves final review by DWG and validation by plant
owner as appropriate.
34
Motion
• “It is moved that: TAS approves the use of
heat rate curves that are currently under
development by the California Energy
Commission and that are expected to be
complete during March, 2016, for use in the
2026 Common Case”.
35
Plant Outage Rates
36
Method Used for Developing Plant
Maintenance Data
• GridView has an integrated tool for developing plant maintenance
schedules that allows for customization at the plant level, down to
the hour, per user’s discretion (e.g. nuclear units, baseload units,
units with consistent outage periods such as northwest thermal).
– Scheduling plant maintenance is both Art & Science. Hence, GridView is set
up to allow maintenance tuning outside the program.
• Commonly used rules when scheduling maintenance include:
– Generally, plants are scheduled for maintenance during off-peak load periods.
– It is assumed plant owners schedule at least one maintenance outage each
year.
– Make certain one unit is out at a time at multi-unit plants.
• Stan shared that what is done differently this year is that we’re
doing a resource adequacy check as well, especially in the spring.
37
Other Considerations
• In GridView:
– LOLP is calculated weekly based on inputted hourly loads
– Maintenance is performed by regions which may not line
up with actual operations
• Kevin promotes using dependable capacity instead of
using physical capacity when calculating LOLP.
– For traditional thermal units this is the winter/summer
rating
– For Hydro, dependable capacity is limited to the plants
ability to serve load on a daily bases
– For Wind/Solar the expected capacity during the peak
hour with a 90+% probability of exceedance
38
Plant Outage Data (Forced Outage and
Maintenance)
APTECH Grouping
Group
1
2
3
4
5
6
7
Description
Small coal-fired subcritical steam (35 - 299
MW)
Large coal-fired subcritical steam (300 - 900
MW)
Large coal-fired
supercritical steam (500
- 1300 MW)
Gas-fired combined
cycle
Gas-fired simple cycle
large frame
Gas-fired simple cycle
Aero-Derivative
Gas-fired steam
EFOR GADS Data 2013 (average 2009-2013)
GADS Data 2016 (average 2010-2014)
APTEC
Forced +
Forced +
H
Forced
Scheduled Scheduled
Forced
Scheduled Scheduled
Value Outages
Outages
Outages
Outages
Outages
Outages
#
#
#
#
#
#
% Hour % Hour % Hour % Hour % Hour % Hour %
Time s Time s Time s Time s Time s Time s Time
5.2%
372 4.3%
597 6.9%
969 11.2%
302 3.5%
592 6.9%
894 10.4%
428 4.9%
831 9.6% 1259 14.5%
367 4.2%
794 9.2% 1161 13.4%
426 5.0%
540 6.3%
966 11.3%
440 5.0%
608 6.9% 1048 12.0%
277 3.2%
827 9.5% 1104 12.7%
286 3.3%
861 9.9% 1147 13.2%
477 5.5%
488 5.6%
465 5.3%
491 5.6%
6.5%
7.5%
3.7%
4.8%
7.2%
965 11.1%
956 11.0%
Proposed, use GADS 2016
data in the 2026 CC
39
Motion
“It is moved that TAS approves the following
process for incorporating plant outage rates into
the 2026 Common Case:
• WECC will use the GridView integrated tool for
creating the plant maintenance schedule.
– Use plant-level outage information where available as
substitute to model generated data.
• WECC will use current NERC Generating
Availability Data System (GADS) data for plant
Equivalent Forced Outage Rates (EFOR) and
Maintenance Schedules.
40
Plant Retirement Assumptions
41
Plant Retirement Assumptions
• The last update to plant retirement was when building
the TEPPC 2024 case, in October, 2013.
• Given the new developments in accelerating coal plant
reduction to meet restrictions associated with the EPA
rule 111d and other carbon reduction initiatives, it
becomes evident that we need to have the latest
information we can assemble for the new 2026 CC.
• DWG held several sessions focused on discussing plant
retirement assumptions for the TEPPC 2026 Common
Case. These were in addition to an earlier effort that
resulted in securing approval for SONGS\OTC proxy
assumptions on plant retirement\replacements by TAS.
42
Plant Retirement – Data Sources
• Following are additional sources of data used to update
Table 1a & 1b below, a comparison of multi sources
that publishes plant retirements including data
collected by WECC – LRS:
– In August, 2015 DWG hosted a session that featured the
Laurence Berkley National Laboratories (LBNL) who
provided an update on their Resource Planning Portal
(RPP) tool. The RPP data is a summary of western
Integrated Resource Plans surveyed contacting 36
departments responsible for 90% of delivered load across
WECC.
– DWG – OTC final assumptions, approved by TAS in Q4,
2015
– Edits to reflect the latest from the PacifiCorp 2015 .
– Edit to the Diablo Canyon by PG&E
43
Table 1a – Plant Retirement Schedule
Retirements
relevant to 2024 CC
Page 1 of 2
Proposed Retirement Dates for the
2026 Common Case
LBNL
LRS
OTC -( Table 4TEPPC
Nameplate Commission Retirement Retirement Retiremen 4 ISO 2015-16
PAC Plant/Unit (Short)
Area
GV SubType
(MW)
Date
Date
Date
t Date
Study Plan) 2015 IRP
Battle River
AESO
ST-NatGas
149
2018
Alamosa, 1
PSC
CT-NatGas-Industrial
26.6
2026
Alamosa, 2
PSC
CT-NatGas-Industrial
26.6
2026
Boardman
PGE
642.2
2020
Burrard
BEP
Coal
337
2016
Carbon 1, 2
PAC
SCCT
172
2014
Centralia, ST1
BPAT
ST-Coal
729.9
2020
Centralia, ST2
BPAT
ST-Coal
729.9
2024
Cerro Prioto
CEF
30
2020
Cholla 4
PAC
387
2025
Clark_04
Clark-4
NEVP
ST-NatGas
72.4
2020
Contra Costa
GenOn
674
2017
Cooper
EPE
GT
80.55
2025
Diablo Canyon
PG&E
2240
2029
Encina
NRG
946
2017
Fort Churchill
1 SPPC
ST
115
2018
Fort Churchill
2 SPPC
ST
115
2021
Fort Lupton
1 SPPC
GT
39.2
2020
Fort Lupton
2 SPPC
GT
39.2
2020
Fruuita
1 PSC
GT
26.6
2026
Harry Allen
1 NEVP
GT
101.5
2025
HR Millner
1 AESO
ST
144
2018
Hueco Mtn. Wind
2
WT-Onshore
1.3
2021
HuntingtonBeach3
AES Huntington Beach
CISC LLC-3ST-NatGas
225
7/31/2002 10/15/2012
2020
HuntingtonBeach4
AES Huntington Beach
CISC LLC-4ST-NatGas
225
8/7/2003 10/31/2012
2020
HuntingtonBeach5
AES Huntington Beach LLC-5CT-NatGas-Industrial
133
4/1/1969 9/30/2002
2020
Mandalay
GenOn
560
2020
Moss Landing Power Block 1
ST-NatGas
960
2017
Moss Landing Power Block 2
Dynegy
2530
2017
Naughton
3 PAC
Coal
280
2018
Plant/Unit
(Long)
44
Retirements
relevant to 2024 CC
Page 2 of 2
Plant/Unit (Short)
Newman 1
Newman 2
Newman 3
Newman 4
Newman 4
Newman 4
North Valmy
North Valmy
Ormond Beach
Pdte.Juarez
Pdte.Juarez
Pdte.Juarez
Pdte.Juarez
Pdte.Juarez
Pittsburg
Pittsburg
Redondo Beach
Reid Gardner
Rio Grande 7
San Juan
San Juan
Sun Peak
Sun Peak
Sun Peak
Tracy
Valmont
Valmont
Valmy 1
Valmy 2
Plant/Unit
(Long)
TEPPC
Area
1
2
3
G1
G2
S1
1 NVE
2 NVE
GenOn
5 CEF
6 CEF
7 CEF
1 CEF
2 CEF
5 GenOn
6 GenOn
AES
4 NEVP
7 EPE
2 PNM
3 PNM
3 NEVP
4 NEVP
5 NEVP
NEVP
PSC
PSC
NEVP
NEVP
GV SubType
ST
ST
ST
CT
CT
CA
ST
ST
ST
ST
GT
GT
GT
ST
ST
ST
ST
GT
GT
GT
ST
ST
GT
Coal
Coal
Proposed Retirement Dates for the
2026 Common Case
LBNL
LRS
OTC -( Table 4Nameplate Commission Retirement Retirement Retiremen 4 ISO 2015-16 PAC (MW)
Date
Date
Date
t Date
Study Plan) 2015 IRP
81.6
2022
81.6
2023
121.8
2024
85
2022
85
2023
120
2021
277.2
2021
289.8
2025
1516
2020
160
2020
160
2020
150
2026
30
2018
30
2018
2017
2017
1343
2020
294.8
2017
50
2020
369
2017
555
2017
74
2026
74
2026
74
2026
119.8
2024
191.7
59.3
23.1
2021
17.7
2025
45
Motion
“It is moved TAS approves the plant retirement
assumptions shown in Table 1 for use in the
2026 Common Case”.
46
Fuel Prices
47
Methodology for developing
Natural Gas Price
• TAS – TEPPC approved a hybrid approach during the last round that includes
using the California Energy Commission major and minor Hub Prices and the
Northwest Power and Conservation Council monthly shapes.
• The two models differ in that the council’s model is a regression model that
reflects historic usage and accounts for forward-looking factors exogenously
(e.g., LNG development, Pipe expansions, etc.). In contrast, the CEC model,
North American Market Gas-trade “NAMGas” starts with the World Gas Trade
Model (WGTM) and applies changes including but not limited to:
– Reconfigures California portion of the model
– Removes all non-North American structure
– Add functional nodes to account for approved LNG
– imports and exports
– Add nodes needed to represent natural gas demand in the transportation
sector
W
E
S
T
E
R
N
E
L
E
C
T
R
I
C
I
T
Y
C
O
O
R
D
I
N
A
T
I
N
G
C
O
U
N
C
I
L
NG: Pipeline System & Hubs
Henry Hub
Major Hubs
AECO
Sumas
Rockies
San Juan
Permian
Minor Hubs
Stanfield
Malin
Topock
SoCalGas
PG&E CG
Burner-Tip:= Henry Hub + Basis to Hub + Local Transport Fee
49
TEPPC Modeled Load Areas
W
E
S
T
E
R
N
E
L
E
C
T
R
I
C
I
T
Y
C
O
O
R
D
I
N
A
T
I
N
G
C
O
U
N
C
I
L
NAMGas
• NAMGas produces Supply Side Cost Curve. “Elasticity is
included in the model” in that the CEC uses Plexos
interchangeably to produce the supply cost curve which, in
turn, is used as an input parameter to NAMGas
• NAMGas 2016 Prices are from the October 2015 final
NAMGas Model results used for the 2015 Natural Gas
Outlook Draft Staff Report at:
http://docketpublic.energy.ca.gov/PublicDocuments/15IEPR
• Transportation rates are from the natural gas pipeline
operators' filed tariffs. Deflators are from Moody's
Analytics.
CEC 2013 IEPR vs. 2015 IEPR Hub Prices
Units: $/MMBtu, in 2014 Dollars
Major Hub Prices
Minor Hub Prices
Area
2024
Common
Case
2026
Proposed
Price
Seattle
4.21
4.44
Malin
4.24
4.39
Ehrenberg
4.63
4.62
SoCal
5.01
5.25
PG&E
4.69
4.70
Phoenix
4.30
4.29
Forecast Year:
2024
2024
Common
Case
2026
Proposed
Price
Henry Hub
4.61
4.49
AECO
3.95
4.07
Sumas
3.96
4.12
San Juan
4.06
4.01
Permian
4.11
4.09
52
NWPCC – Seventh Northwest Power Plan
Historic Gas Prices
$/mmBtu, 2012 dollars
12
10
Price $
8
Med
6
Low
High
4
2
0
YEAR 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
W
E
S
T
E
R
N
E
L
E
C
T
R
I
C
I
T
Y
C
O
O
R
D
I
N
A
T
I
N
G
C
O
U
N
C
I
L
53
NWPCC – Seventh Northwest Power Plan
Monthly Gas Price Shaping
1.40
PNW_E
1.20
PNW_W
1.00
Monthly Shape(N. CA) (San Juan)
Monthly Shape (S. CA & S. NV) (San Juan)
0.80
Monthly Shape (S. NM & W. TX) (Permian)
0.60
Monthly Shape (ID & OR & Montana) (AECO)
0.40
Monthly Shape (AZ & S. NM) (San Juan)
0.20
Monthly Shape (CO & N. NV & Utah & WY)
(Rockies)
Monthly Shape (WA) (Kingsgate) (Sumas)
0.00
1
W
E
S
T
2
E
R
3
N
4
E
5
L
E
6
C
T
7
R
I
C
8
I
T
9
Y
10
C
O
11
O
12
R
D
I
N
A
T
I
N
G
C
O
U
N
C
I
L
54
Other Fuel Prices
W
E
S
T
E
R
N
E
L
E
C
T
R
I
C
I
T
Y
C
O
O
R
D
I
N
A
T
I
N
G
C
O
U
N
C
I
L
55
Other Fuel
Fuel
Definition
2026
Price Source
(2014$)
Oil_DFO2
22.40
Oil_DFO_H 29.87
Oil_DFO_M 13.21
Petr_Coke
1.40
Uranium
0.87
Waste_Heat 0.00
Bio_Misc
2.89
Agri_Res
0.53
NPCC
NPCC
NPCC
NPCC
NPCC
2026
Fuel
Source
Definition Price
(2014$)
Blk_Liquor
Landfill_gas
Refuse
Solid_waste
Wood
Geothermal
0.01
2.24 NPCC
0.00 NPCC
0.00
2.86 NPCC
0.00
Validated by NPCC for medium price_1/29/16. Escalated remaining prices from 2024 to 2026 $
56
Coal Prices
W
E
S
T
E
R
N
E
L
E
C
T
R
I
C
I
T
Y
C
O
O
R
D
I
N
A
T
I
N
G
C
O
U
N
C
I
L
57
The CEC Coal Prices
For coal Burner-Tip Prices, the CEC started with the 2015 Annual
Energy Outlook:
• EIA evaluates U.S. energy markets and uses trends to forecast
coal prices
• For the Western US, The EIA develops estimated price
projections that are aggregated over seven coal mine regions:
– These regions are Western Montana, Powder River Basin, Western
Wyoming, Rocky Mountain, Southwest (Arizona/New Mexico),
Northwest (Washington/Alaska), and Dakota (Northeast Montana/
North and South Dakota).
• The mine-mouth price projections also provide cost details for
the different types and grades of coal mined.
W
E
S
T
E
R
N
E
L
E
C
T
R
I
C
I
T
Y
C
O
O
R
D
I
N
A
T
I
N
G
C
O
U
N
C
I
L
58
Coal Prices for Burner Tip
• Unfortunately, the EIA does not have stand-alone projected delivery costs.
• However, the EIA does forecast delivered coal price projections for coal
plants located in four large regions in the WECC, Northwest, California,
Southwest, and Rockies.
• EIA does not provide the level of detail needed to adequately model all of
the coal power plants in the WECC .
– In general, the regional averages gloss over key characteristics that will
influence the dispatch of coal facilities, particularly in Oregon, Wyoming, and
the South West.
– In many of these cases, the type or grade of coal greatly impacts the price.
– In the Southwest and Wyoming, there are coal plants located at the minemouth giving them transportation cost advantages.
• CEC Staff used these projections as a starting point to estimate the
delivered coal prices by coupling the analysis with historic plant-level
details regarding the type/grade, quantity, and mine location of coal.
59
Regional Delivered and Commodity Prices
EIA Reference Case
(Nominal $/MMBtu)
W
E
S
T
E
R
N
E
L
E
C
T
R
I
C
I
T
Y
C
O
O
R
D
I
N
A
T
I
N
G
C
O
U
N
C
I
L
Region
Powder River Basin
Powder River Basin
Western Wyoming
Western Wyoming
Rocky Mountain
Rocky Mountain
Southwest
Southwest
Southwest
Northwest
Western Montana
Western Montana
Western Montana
Dakota
US- Average
Coal Grade
Low Sulfur Sub-Bituminous
Medium Sulfur Sub-Bituminous
Low Sulfur Sub-Bituminous
Medium Sulfur Sub-Bituminous
Low Sulfur Bituminous
Low Sulfur Sub-Bituminous
Low Sulfur Bituminous
Medium Sulfur Bituminous
Medium Sulfur Sub-Bituminous
Low Sulfur Sub-Bituminous
Low Sulfur Bituminous
Low Sulfur Sub-Bituminous
Medium Sulfur Sub-Bituminous
Lignite
Waste Coal
CEC
Garry O’Neill
YEAR
SUB_LS_AWA
BIT_LS_ANM
BIT_MS_ANM
SUB_MS_ANM
BIT_LS_RMO
SUB_LS_RMO
SUB_LS_WMO
BIT_LS_WMO
SUB_MS_WMO
SUB_LS_PRB
SUB_MS_PRB
SUB_LS_WWY
SUB_MS_WWY
WC_LS_USA
Fuel Definition
Coal_Alberta
2026
Nominal
2014 Dollars
3.73
2.78
2.81
2.62
2.35
2.62
1.37
1.69
1.92
1.35
1.53
3.94
2.61
2.11
3.03
2.26
2.28
2.13
1.91
2.12
1.11
1.37
1.56
1.10
1.24
3.20
2.12
1.72
Coal_AZ
Coal_CA_South
Coal_CO_East
Coal_CO_West
Coal_ID
Coal_MT
Coal_NM
Coal_NV
Coal_PNW
Coal_UT
Coal_WY_E
Coal_WY_PRB
Coal_WY_SW
60
EIA – Outlook 2015
2024 Price
Plants
(2014$)
1.53
Alberta plants
Apache, Cholla, Coronado, Navajo,
2.44
Springerville
1.79
Ace cogen
Arapahoe, Cherokee, Comanche,
2.20
Drake, Noxon, Pawnee, Valmont
2.19
Bonanza, Cameo, Craig, Hayden
1.19
Idaho small coal
1.36
Colstrip, Corrette
2.25
Escalante, Four Corners, San Juan
3.18
North Valmy, Reid Gardner
2.67
Boardman, Centralia
1.96
Carbon, Hunter, Huntington
1.52
Dave Johnston, Laramie River
0.97
Wygen, Wyodak, Simpson
2.11
Jim Bridger, Naughton
Ventyx 2024
Nominal
2.94
2.65
2.64
1.64
2.72
3.84
3.22
2.36
1.84
1.17
2.55
61
Motion
• “It is moved that: TAS approves the use of
natural gas prices, coal prices and other fuel
prices as presented in the 2026 Common
Case”.
62
Transmission Wheeling Rates
W
E
S
T
E
R
N
E
L
E
C
T
R
I
C
I
T
Y
C
O
O
R
D
I
N
A
T
I
N
G
C
O
U
N
C
I
L
63
Wheeling Rates
Wheeling versus Hurdle Rates - The terms “hurdle rates” and
“wheeling rates” are often used synonymously, however in
reality the two differ greatly.
• “Wheeling Rates” cover utility tariffs, the cost of transporting power over
transmission lines. Whereas,
• “Hurdle Rates” are used to align the imperfection of real dispatch with the
perfect foresight of model generated dispatch. For example, TEPPC used
“Hurdle Rates” in the TEPPC 2010 back-cast as a Band-Aid to cover
inexplicable results and align with historic results.
• When modeling full rates, wheeling rates should be used to cover nonfirm transactions, whereas, in the TEPPC database they are applied as flat
rates on all transfers. Firm transactions are associated with rights that
have sunk costs and should not be charged wheeling rates.
– Most WECC paths are fully committed; the non-firm piece constitutes a small
percentage of total flows on the transmission, about 10%.
– Jin from ABB, recommends using a graduated schedule when the flows reach
an agreed to percentage of the total, then apply the wheel rate (e.g., apply a
wheel rate when the flow exceed at 90% of line\path capacity.
64
Wheeling Rates of Other BAs
65
Motion
“It is moved that TAS approves applying export wheeling
charges based on utility tariffs to every BA with the
following exceptions:
• Trading hubs are free of export wheeling charges
• Firm transmission rights are free of pancaked charges
along the way. If there is a firm transmission right,
wheeling charges are .
• No wheeling charge for remote generators; all remote
generators have firm transmission rights or associated
transmission.
• Contract paths
• Path-based free-wheeling”
66