MTEP13 Economic Model Assumptions
MTEP13 Economic Study
Models Assumptions for MISO
Midwest
February 10, 2014
MISO Policy & Economic Studies Department
i
MTEP13 Economic Model Assumptions
Contents
1
Introduction ......................................................................................................................... 6
2 Database Development ........................................................................................................... 9
2.1 PROMOD IV 10.1 Database ............................................................................................. 9
2.1.1 Scenario/Case Structure ............................................................................................ 9
2.1.2 Area Structure ............................................................................................................ 9
2.1.3 Hourly Profiles ...........................................................................................................11
Hourly load profile ..........................................................................................................11
Hourly wind profile ..........................................................................................................11
Hourly solar profile .........................................................................................................12
2.1.4 Generator Category Structure ...................................................................................12
2.1.5 Emissions Data .........................................................................................................14
2.1.6 MISO Queue .............................................................................................................14
2.1.7 External Queue .........................................................................................................15
2.1.8 Industrial Loads .........................................................................................................15
2.1.9 Interruptible Loads ....................................................................................................16
2.1.11 Behind-the-Meter Generator Mapping .....................................................................16
2.1.12 Wind Curtailment Price............................................................................................16
2.1.13 EPA and Age-Related Unit Retirements ..................................................................16
2.1.14 Ramp Rates ............................................................................................................18
2.1.15 Must-Run Status .....................................................................................................18
2.1.16 Nuclear Unit Maintenance .......................................................................................18
2.1.17 Fuel Heat Content ...................................................................................................19
2.1.18 Fuel Forecasts ........................................................................................................19
2.2 Futures Matrix & Uncertainty Variables ............................................................................20
2.3 Regional Assumptions .....................................................................................................23
2.3.1 Resource Mix ............................................................................................................24
2.3.2 Regional Generation Forecasts .................................................................................30
2.3.3 Regional Demand & Energy Forecasts .....................................................................30
2.3.4 External Transactions, Interruptible Load and Industrial Loads .................................31
2.4 Local Resource Zone Data ..............................................................................................32
3
Regional Resource Forecasting .........................................................................................33
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MTEP13 Economic Model Assumptions
4
5
3.1
Study Period ...............................................................................................................33
3.2
Study Areas ................................................................................................................33
3.3
Capacity Types ...........................................................................................................34
3.4
Firm Interchange .........................................................................................................34
3.5
Planning Reserve Margin Target.................................................................................34
3.6
Wind Hourly Profile and Capacity Credits ...................................................................35
3.7
Reserve Contribution ..................................................................................................35
3.8
Financial Variables......................................................................................................35
3.9
Load Shapes...............................................................................................................36
3.10
Generic Generator Categories ....................................................................................36
3.11
Generic Generator Data ..............................................................................................37
3.12
Economic Rates ..........................................................................................................37
Unit Siting ..........................................................................................................................39
4.1
General Siting Methodology ........................................................................................39
4.2
Unit Capacity Type and Status Definitions ..................................................................39
4.3
Site Selection Priority Order ........................................................................................40
4.4
Greenfield Siting Rules ...............................................................................................41
4.5
Renewable Unit Siting .................................................................................................41
Production Cost Modeling ..................................................................................................42
5.1
Study Footprint ...........................................................................................................42
5.2
Study Years & Powerflow Data Sources .....................................................................42
5.3
Pool Definition.............................................................................................................42
5.4
Hurdle Rates ...............................................................................................................48
5.5
Losses ........................................................................................................................49
5.6
Generator Outage and Maintenance ...........................................................................49
5.7
Scheduled Transmission Outages ..............................................................................50
5.8
Operating Reserve Requirement.................................................................................50
5.9
Event File ....................................................................................................................51
Appendix A: Local Resource Zone Data and Additional Regional Data .....................................53
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MTEP13 Economic Model Assumptions
List of Tables
Table 1. PJM Region Changes .................................................................................................10
Table 2. Areas Changing Pool ..................................................................................................11
Table 3. Monthly Energy Limits for all Solar PV.........................................................................12
Table 4. MTEP13 Emissions Structure ......................................................................................14
Table 5. Emission Rates Assumed for New Generation ............................................................15
Table 6. Total MW of Assumed Retirements .............................................................................17
Table 7. Ramp Rates ................................................................................................................18
Table 8. Average Heat Contents ...............................................................................................19
Table 9. Fuel Prices Per Year and Future in $/MMBtu ..............................................................20
Table 10. MTEP13 Futures Matrix.............................................................................................21
Table 11. MTEP13 Uncertainty Variables Categorization. .........................................................22
Table 12. MTEP13 Uncertainty Variables Categorization (Continued). .....................................23
Table 13. Existing, Under Construction and Planned Units .......................................................24
Table 14. Baseline Demand and Energy Growth Rates by Region............................................31
Table 15. Effective Demand and Energy Growth Rates by Region............................................31
Table 16. Total External Transactions, Interruptible Loads and Industrial Loads by Region ......32
Table 17. PRM Margins and Targets .........................................................................................34
Table 18. Financial Variables ....................................................................................................35
Table 19. Load Shape Descriptions and Sources......................................................................36
Table 20. Generic Generator Categories - Supply Side Options ...............................................36
Table 21. Generic Generator Categories - Demand Side Options .............................................37
Table 22. Generic Generator Data ............................................................................................37
Table 23. Economic Rates and Descriptions .............................................................................38
Table 24. Greenfield Siting Rules ..............................................................................................41
Table 25. Dispatch Hurdle Rates ..............................................................................................48
Table 26. Commitment Hurdle Rates ........................................................................................49
Table 27. Reserve Requirement by Region (2028) ...................................................................51
Table 28. Zonal Demand and Energy Growth Rates .................................................................54
Table 29. Forecasted BAU Zonal Annual Peak Load (MW) for 2013-2020 ................................64
Table 30. Forecasted BAU Zonal Annual Peak Load (MW) for 2021-2028 ................................64
Table 31. Forecasted RE Zonal Annual Peak Load (MW) for 2013-2020 ..................................64
Table 32. Forecasted RE Zonal Annual Peak Load (MW) for 2021-2028 ..................................65
Table 33. Forecasted LG Zonal Annual Peak Load (MW) for 2013-2020 ..................................65
Table 34. Forecasted LG Zonal Annual Peak Load (MW) for 2021-2028 ..................................65
Table 35. Forecasted GS Zonal Annual Peak Load (MW) for 2013-2020 ..................................66
Table 36. Forecasted GS Zonal Annual Peak Load (MW) for 2021-2028 ..................................66
Table 37. Forecasted ENV Zonal Annual Peak Load (MW) for 2013-2020 ................................66
Table 38. Forecasted ENV Zonal Annual Peak Load (MW) for 2021-2028 ................................67
Table 39. Forecasted BAU Regional Annual Peak Load (MW) for 2013-2020 ...........................67
Table 40. Forecasted BAU Regional Annual Peak Load (MW) for 2021-2028 ...........................67
Table 41. Forecasted RE Regional Annual Peak Load (MW) for 2013-2020 .............................68
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MTEP13 Economic Model Assumptions
Table 42. Forecasted RE Regional Annual Peak Load (MW) for 2021-2028 .............................68
Table 43. Forecasted LG Regional Annual Peak Load (MW) for 2013-2020 .............................68
Table 44. Forecasted LG Regional Annual Peak Load (MW) for 2021-2028 .............................69
Table 45. Forecasted GS Regional Annual Peak Load (MW) for 2013-2020 .............................69
Table 46. Forecasted GS Regional Annual Peak Load (MW) for 2021-2028 .............................69
Table 47. Forecasted ENV Regional Annual Peak Load (MW) for 2013-2020 ...........................70
Table 48. Forecasted ENV Regional Annual Peak Load (MW) for 2021-2028 ...........................70
Table 49. Forecasted Zonal Annual Energy (GWh) for BAU 2013-2020 ....................................70
Table 50. Forecasted Zonal Annual Energy (GWh) for BAU 2021-2028 ....................................71
Table 51. Forecasted Zonal Annual Energy (GWh) for RE 2013-2020 ......................................71
Table 52. Forecasted Zonal Annual Energy (GWh) for RE 2021-2028 ......................................71
Table 53. Forecasted Zonal Annual Energy (GWh) for LG 2013-2020 ......................................72
Table 54. Forecasted Zonal Annual Energy (GWh) for LG 2021-2028 ......................................72
Table 55. Forecasted Zonal Annual Energy (GWh) for GS 2013-2020 ......................................72
Table 56. Forecasted Zonal Annual Energy (GWh) for GS 2021-2028 ......................................73
Table 57. Forecasted Zonal Annual Energy (GWh) for ENV 2013-2020 ....................................73
Table 58. Forecasted Zonal Annual Energy (GWh) for ENV 2021-2028 ....................................73
Table 59. Forecasted Regional Annual Energy (GWh) for BAU 2013-2020...............................74
Table 60. Forecasted Regional Annual Energy (GWh) for BAU 2021-2028...............................74
Table 61. Forecasted Regional Annual Energy (GWh) for RE 2013-2020 .................................74
Table 62. Forecasted Regional Annual Energy (GWh) for RE 2021-2028 .................................75
Table 63. Forecasted Regional Annual Energy (GWh) for LG 2013-2020 .................................75
Table 64. Forecasted Regional Annual Energy (GWh) for LG 2021-2028 .................................76
Table 65. Forecasted Regional Annual Energy (GWh) for GS 2013-2020 .................................76
Table 66. Forecasted Regional Annual Energy (GWh) for GS 2021-2028 .................................76
Table 67. Forecasted Regional Annual Energy (GWh) for ENV 2013-2020...............................77
Table 68. Forecasted Regional Annual Energy (GWh) for ENV 2021-2028...............................77
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MTEP13 Economic Model Assumptions
List of Figures
Figure 1. MISO Value-Based 7-Step Planning Process.............................................................. 6
Figure 2. Overall Pool Structure ................................................................................................. 9
Figure 3. MISO and MISO South Company Structure ...............................................................10
Figure 4. MTEP13 Generator Category Structure .....................................................................13
Figure 5. MHEB Resource Mix ..................................................................................................25
Figure 6. MISO Resource Mix ...................................................................................................26
Figure 7. MISO South Resource Mix .........................................................................................26
Figure 8. MRO Resource Mix ....................................................................................................27
Figure 9. NYISO Resource Mix .................................................................................................27
Figure 10. PJM Resource Mix ...................................................................................................28
Figure 11. SERC Resource Mix ................................................................................................28
Figure 12. SPP Resource Mix ...................................................................................................29
Figure 13. TVA Resource Mix ...................................................................................................29
Figure 14. TVA-Other Resource Mix .........................................................................................30
Figure 15. Local Resource Zones .............................................................................................53
Figure 16. Nameplate Capacity Additions for MISO Midwest ....................................................55
Figure 17. Energy Production by Fuel Type for MISO Midwest .................................................56
Figure 18. Nameplate Capacity Additions for MISO South ........................................................57
Figure 19. Nameplate Capacity Additions for MRO ...................................................................58
Figure 20. Nameplate Capacity Additions for New York ............................................................59
Figure 21. Nameplate Capacity Additions for PJM ....................................................................60
Figure 22. Nameplate Capacity Additions for SERC..................................................................61
Figure 23. Nameplate Capacity Additions for SPP ....................................................................62
Figure 24. Nameplate Capacity Additions for TVA ....................................................................63
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MTEP13 Economic Model Assumptions
1 Introduction
This document details the assumptions underlying the economic study models used in the 2013
MISO Transmission Expansion Plan (MTEP13). Two different sets of modeling assumptions are
used in MTEP13 for MISO Midwest and MISO South planning studies. The assumptions
detailed in this document describe that of the MISO Midwest studies.
MISO’s MTEP study methodology for developing a top-down, value-based transmission plan to
support economic and reliable energy delivery under a wide range of potential energy policy
outcomes is summarized below in Figure 1.
Figure 1. MISO Value-Based 7-Step Planning Process.
The data foundation for the first few steps of the seven-step process is centralized in a database
(Ventyx PROMOD IV 10.1). Each year this database is refreshed and updated to model the
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MTEP13 Economic Model Assumptions
MTEP defined Futures, which are fully vetted through the Planning Advisory Committee (PAC) 1.
As voted on by the PAC, the MTEP13 Futures include:
-
Business as Usual (BAU)
Robust Economy (RE)
Limited Growth (LG)
Generation Shift (GS)
Environmental (ENV)
The economic study models used in the MTEP13 study are forward-looking, and assumptions
must be made in building and applying the models. This document addresses these
assumptions and the uncertainty underlying each model.
Future-based analysis provides the basis for developing economically feasible transmission
plans for the future. A future scenario is a stakeholder-driven postulate of what could be. This
determines the non-default model parameters (such as assumed values) driven by policy
decisions and industry knowledge. With the increasingly interconnected nature of organizations
and federal interests, forecasting the future greatly enhances the planning process for electric
infrastructure. The futures development process provides information on the cost-effectiveness
of environmental legislation, wind development, demand-side management programs,
legislative actions or inactions and many other potential scenarios.
Future scenarios and their associated assumptions are developed with high levels of
stakeholder involvement. As a part of compliance with the FERC Order 890 planning protocols,
MISO-member stakeholders are encouraged to participate in PAC meetings to discuss
transmission planning methodologies and results. Scenarios have been developed and
refreshed annually to reflect items such as shifts in energy policy, changing demand and energy
growth projections, and/or changes in long-term projections of fuel prices.
The following narratives describe the 2013 future scenarios and their key drivers:

The Business as Usual (BAU) future is considered the status quo future and continues
current economic trends. This future models the power system as it exists today with
reference values and trends. Renewable portfolio standards vary by state and 12.6 GW
of coal unit retirements are modeled.

The Environmental (Env) future considers a future where policy decisions have a heavy
impact on the future generation mix. Mid-level demand and energy growth rates are
modeled. Potential new EPA regulations are accounted for using a carbon tax and statelevel renewable portfolio standard mandates and goals are assumed to be met. A total of
23 GW of coal unit retirements are modeled.

The Limited Growth (LG) future models a future with low demand and energy growth
rates due to a very slow economic recovery and impacts of EPA regulations. This can be
1
The MISO PAC provides a forum for stakeholder input on the direction and execution of the MTEP
process.
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MTEP13 Economic Model Assumptions
considered a low side variation of the BAU future. Renewable portfolio standards vary by
state and 12.6 GW of coal unit retirements are modeled.

The Generation Shift (GS) future considers a future with low demand and energy
growth rates due to a very slow economic recovery. This future models a changing base
load power system due to many power plants nearing the end of their useful life. In
addition to the 12.6 GW of coal unit retirements modeled as a minimum in all futures,
this future also models the retirement of each thermal generator (except coal or nuclear)
in the year that it reaches 50 years of age or each hydroelectric facility in the year that it
reaches 100 years of age during the study period. Renewable portfolio standards vary
by state.

The Robust Economy (RE) future is considered a future with a quick rebound in the
economy. This future models the power system as it exists today with historical values
and trends for demand and energy growth. Demand and energy growth is spurred by a
sharp rebound in manufacturing and industrial production. Renewable portfolio
standards vary by state and 12.6 GW of coal unit retirements are modeled.
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MTEP13 Economic Model Assumptions
2 Database Development
This section outlines the organization and development of the PROMOD IV 10.1 database,
which serves as the foundation for both Electric Generation Expansion Analysis System
(EGEAS)2 and PROMOD IV (PROMOD)3 simulations. Though there is a significant amount of
crossover between the databases for EGEAS and PROMOD, these two software packages
serve different purposes and require different inputs. Information specific to each will be detailed
in later sections of this document.
2.1 PROMOD IV 10.1 Database
2.1.1 Scenario/Case Structure
The PROMOD IV 10.1 database is organized into a scenario/case structure. Each of the
Futures for MTEP13 is modeled by a single scenario, and each scenario is a collection of cases.
Those cases common to all scenarios compose a Master Scenario; the others are scenariospecific cases. The final PowerBase database posted for stakeholders includes a merge of a
number of cases for each scenario. Specifics on individual cases included in the merge will not
be given in this document.
2.1.2 Area Structure
The overall pool structure is largely unchanged from the MTEP12 pool structure and is shown in
Figure 2. For MTEP13, the Independent Electricity System Operator (Ontario), IESO, will no
longer be included in the study footprint and will be replaced by external transactions.
Figure 2. Overall Pool Structure
2
EGEAS is a capacity expansion software tool from the Electric Power Research Institute (EPRI) used for
long-term regional resource forecasting (RRF).
3
PROMOD IV (PROMOD) is a production cost simulation software tool from Ventyx used to examine the
economics of transmission expansion planning.
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MTEP13 Economic Model Assumptions
Another major difference is that MISO includes companies in the South Region, which was
officially integrated into MISO in December 2013, as reflected in the model by the “MISO South”
region, shown below in Figure 3. For the purposes of this document, MISO South will be
referred to separately from MISO Midwest, which is comprised of MISO Central, MISO East,
and MISO West. All four areas: MISO Central, MISO East, MISO South, and MISO West will be
referred to as MISO.
Figure 3. MISO and MISO South Company Structure
Based on membership changes to the different Regional Transmission Organizations (RTOs)
some companies and regions have changed within the pools. The following regions were
deleted from the PowerBase:




PJM West
Southern Mid-Atlantic
Western Mid-Atlantic
PJM Northern Illinois Control Area
In this case the pools/regions were adjusted to reflect current regional planning entity
membership. Several changes were made to the regions within PJM Interconnection. Table 1
shows the changes to the regions within the PJM Interconnection pool. Any areas within the old
region are moved to the new region.
Table 1. PJM Region Changes
Old Region
Current Region
PJM West
PJM Western
PJM Northern Illinois Control Area
PJM Western
Southern Mid-Atlantic
Rest of Mid-Atlantic
Western Mid-Atlantic
Rest of Mid-Atlantic
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MTEP13 Economic Model Assumptions
Additionally, some companies have recently joined a RTO, which are listed in Error! Reference
ource not found..
Table 2. Areas Changing Pool
Area
Old Pool
East Kentucky Power Coop.
TVA - Other
Current Pool
PJM Interconnection
South Mississippi Electric Power Association
MISO South
SERC
The Area tab in PowerBase contains the area structure, or the assignment of companies
modeled to aggregate companies, sub-regions, and regions. The final area structure can be
found in Section 5.3.
2.1.3 Hourly Profiles
In order to synchronize load profiles with hourly wind and solar profiles, the default Ventyx data
was overwritten with a 2005 historical hourly shape.
Hourly load profile
Historical hourly load for 2005 and 2006 was obtained from Ventyx. These hourly profiles are
historical values obtained by the National Renewable Energy Lab (NREL) during the Eastern
Wind Integration and Transmission Study (EWITS).
The 2006 historical hourly load shape was used to better represent load patterns in MISO South
following Hurricane Katrina. The following areas use a 2006 historical hourly load shape:











Central Louisiana Electric Co. Inc.
Entergy Arkansas
Entergy Gulf States
Entergy Louisiana
Entergy Mississippi
Entergy New Orleans
Entergy Texas
Lafayette (City of)
Louisiana Energy and Power Authority
Louisiana Generating/Cajun Electric
South Mississippi Electric Power Association
All other areas still use the 2005 historical hourly load shape.
Hourly wind profile
Wind units in PowerBase are mapped to their nearest NREL wind site. The NREL dataset
contains historical wind speed readings for 2004, 2005, and 2006. The 2005 data set was
selected as the hourly profile most representative of an average year.
The NREL dataset only includes domestic wind sites. Wind units in Saskatchewan and
Manitoba were accordingly assigned the hourly profile of the closest US NREL site.
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MTEP13 Economic Model Assumptions
Hourly solar profile
A custom wind profile was developed by MISO staff to represent the monthly variation of solar
intensity (due to the tilt of the earth). A single hourly profile is used for all solar PV generators.
The annual energy limit for each solar PV generator was calculated based on the following
formula:
The monthly energy limits are in per-unit and the same for all generators. They were set to
values in Table 3.
Jan
Energy 0.04
Table 3. Monthly Energy Limits for all Solar PV
Feb
Mar
Apr
May Jun
Jul
Aug Sep
0.06 0.07 0.09 0.11 0.12 0.13 0.11 0.10
Oct
0.08
Nov
0.06
Dec
0.03
2.1.4 Generator Category Structure
The default Ventyx generator category structure matches the MTEP12 database structure.
Therefore, the generator category structure is unchanged from what was used in MTEP12 and
is shown in Figure 4.
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MTEP13 Economic Model Assumptions
Figure 4. MTEP13 Generator Category Structure
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MTEP13 Economic Model Assumptions
2.1.5 Emissions Data
In MTEP12, in order to capture power plant emissions rule changes from the Environmental
Protection Agency (EPA), including the Cross State Air Pollution Rule (CSAPR) and Mercury
and Air Toxics Standards (MATS), emission (effluent) categories were updated in PowerBase.
Several default SO2 and NOx categories were renamed and others removed or combined, as
shown in Table 4. Default individual plant emissions rates were updated based on previous
studies. In MTEP13, the generator emission structure and names are unchanged.
Table 4. MTEP13 Emissions Structure
Name
CSAPR 1.SO2
CSAPR 2.SO2
CSAPR Annual .NOx
CSAPR Seasonal .NOx
Mercury (Hg)
National .CO2
NOx
RGGI .CO2
SO2
Additionally, in the Environmental future only, a tax of $50/ton for CO2 is assumed.
2.1.6 MISO Queue
A snapshot of the MISO queue was taken on December 31, 2012 to determine projects with
signed generator interconnection agreements (GIAs). Over 1,400 MW of mostly new wind
generation was added.
For all new thermal units default emissions rates were assumed which comply with current
emission standards. The rates assumed for the different types of generation are shown in Table
5.
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MTEP13 Economic Model Assumptions
Table 5. Emission Rates Assumed for New Generation
Column1
SO2
NOx
Hg
CO2
(#/MMBTU) (#/MMBTU) (#/MMBTU) (#/MMBTU)
Coal
0.05
0.08
1.22 x 10-6
201
-7
IGCC
0.03
0.06
8.05 x 10
195
Nuclear
0
0
0
0
CC
0
0.03
0
120
CT
0
0.03
0
120
Wind
0
0
0
0
CC
0
0
0
18
w/Sequestration
IGCC
0.03
0.06
0
30
w/Sequestration
Storage
0
0
0
0
Photovoltaic
0
0
0
0
Biomass
0
0
0
0
Hydro
0
0
0
0
Wind Offshore
0
0
0
0
Distributed
0
0.03
0
120
Generation Peak
Additionally, 450 MW of wind generation was deactivated due status changes in the queue.
2.1.7 External Queue
A survey of all neighboring queues was conducted on December 31, 2012. Any new generation
with a signed GIA (or equivalent) was added. The Western Area Power Administration (WAPA)
and Associated Electric Cooperative Inc. (AECI) queues didn’t show any new generation which
should be added or removed.
Generation was added from the NYISO, PJM and SPP generation interconnection queues. Over
7,000 MW was added in those three pools.
Additionally, several generators were deactivated based on the information gathered from the
external queue survey.
2.1.8 Industrial Loads
As the Ventyx default data does not provide industrial load information, large industrial loads
(this only includes aluminum smelters) in the modeling footprint must be added to the database,
and are modeled as fixed transactions. MTEP12 was used as the information source for
industrial load information, with confirmation from Module E data, publicly available information,
and cross-checking with the powerflow.
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MTEP13 Economic Model Assumptions
2.1.9 Interruptible Loads
Interruptible Load and Direct Control Load Management (DCLM) programs currently registered
with MISO were added to the database. A company-level aggregated generator is used instead
of modeling each individual program reported in MISO’s Module E Capacity Tracking (MECT)
tool.
The capacity values for each area are based on the maximum capacity reported through the
MECT tool (using 2012 submissions). Seasonal dependency of the interruptible and DCLM
loads was captured by using a monthly maximum capacity profile for each of the generators.
2.1.11 Behind-the-Meter Generator Mapping
All generators in MISO were cross-referenced to a list of behind-the-meter (BTM) generation
currently registered in the MECT tool. Any generators which had not been mapped to the
Commercial Model or Interconnection Queue were given special attention and a determination
of if they were BTM generation was made.
Once all BTM generators within MISO were identified, a company aggregated BTM generation
total was calculated based on the amount registered in the MECT tool. The BTM was further
categorized by the amount in each state. Based on the amount already existing in PowerBase
and the amount registered in the MECT tool, a company level aggregate BTM generator was
added to make up any difference.
A total of 3,229 MW of BTM generation is registered in the 2012 MECT tool, which is less than
what was in 2011 (MTEP12) and as a result many of the company aggregated BTM generators
were turned off or reduced in size.
2.1.12 Wind Curtailment Price
All wind generators’ Curtailment Price was set to $0/MWh (changed from the Ventyx default of
-$20/MWh), given the uncertainty of the production tax credit for wind along with the vast
majority of wind generators electing to choose the lump-sum cash payment instead of the
production tax credit in recent years.
2.1.13 EPA and Age-Related Unit Retirements
Cost estimates were developed for every coal unit in the Eastern Interconnect to comply with
proposed EPA regulations, using publicly available information.
Specifically for MISO Midwest, 12 GW of coal is required to be retired as a part of the
assumptions for the BAU, LG, GS, and RE futures; whereas, approximately 23 GW of coal is
required to be retired in the ENV future. The compliance cost of each coal unit meeting the
emission standards was calculated based on data obtained through Ventyx and MISO research.
The units were then sorted according to cost, capacity, and age, where the units with the
highest compliance cost, smallest capacity, and greater age are generally selected to retire first.
For an external region, a similar coal retirement assumption was made.
The Generation Shift (GS) future includes retirements in addition to the 12 GW of coal unit
retirements modeled as a minimum in all futures. It also models the retirement of each thermal
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MTEP13 Economic Model Assumptions
generator (except coal or nuclear) in the year that it reaches 50 years of age or each
hydroelectric facility in the year that it reaches 100 years of age during the study period.
The consolidated unit retirement listing was then used as a manual input into the EGEAS
program file creation to perform out-year regional resource forecasting.
Table 6 is a regional breakdown of the forced coal and age-related retirements by future.
Table 6. Total MW of Assumed Retirements
MISO
Region
Assumed retirements (GW) by Future
MISO Midwest
MISO South
MRO
BAU
12.2
0.1
0.5
ENV
22.4
0.1
0.5
LG
12.2
0.1
0.5
GS
19.7
3.4
0.6
RE
12.2
0.1
0.5
NYISO
1.7
1.7
1.7
4.3
1.7
PJM
SERC
SPP
TVA
20.2
12.0
4.7
5.0
20.2
12.0
4.7
5.0
20.2
12.0
4.7
5.0
27.9
17.4
9.1
8.6
20.2
12.0
4.7
5.0
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MTEP13 Economic Model Assumptions
2.1.14 Ramp Rates
All synchronous machines require a ramp rate. Several generators in the Ventyx data set did
not include a ramp rate. For generators without a ramp rate, one was created based on a
percentage of their Maximum Capacity. The percentage is different for the different types of
generators and was calculated based on the average ramp rates of the existing fleet. The
percentage used for the different categories of generators is shown in Table 7. This change was
made in the original MTEP12 PowerBase and is shown here for reference.
Category
Table 7. Ramp Rates
Ramp Down
(% of max
capacity)
Ramp Up
(% of max
capacity)
CC
28
55
Conventional Hydro
70
75
CT Gas
80
81
CT Oil
84
86
CT Other
85
90
IC Gas
39
42
IC Oil
68
72
IGCC
82
86
Nuclear
Pumped Storage
Hydro
ST Coal
23
23
95
95
29
45
ST Gas
30
47
ST Oil
29
45
ST Other
33
60
2.1.15 Must-Run Status
All coal units in PowerBase with a nameplate capacity greater than 300 MW are set to must-run
status. Additionally, all nuclear units are set to must-run status.
2.1.16 Nuclear Unit Maintenance
All nuclear generators take a scheduled outage to refuel and perform maintenance on a regular
cycle. Ventyx populates the scheduled outages based on the historical outages taken by an
existing nuclear plant (data that can be obtained from the Nuclear Regulatory Commission).
For new nuclear generators this cycle is unknown but a common assumption is that it will follow
a 16 to 18 month cycle. Additionally, nuclear plants with multiple generators at the same
location schedule their outages such that only one generator is out-of-service at a time. Using
this information, a maintenance schedule was established for all new nuclear generators.
MISO
18
MTEP13 Economic Model Assumptions
2.1.17 Fuel Heat Content
The default average heat contents, which are the fuel heat conversion factors in MBTUs per unit
of fuel, are shown in Table 8.
Table 8. Average Heat Contents
Fuel
Average Heat Content
(MBTUs per unit of fuel)
Jet Fuel-ERCOT
7.00
Jet Fuel-MW
7.00
Jet Fuel-NPCC
7.00
Jet Fuel-SE
7.00
Jet Fuel-WECC
7.00
Kerosene/Jet Fuel
5.67
Kerosene-ERCOT
5.67
Kerosene-MW
5.67
Kerosene-NPCC
5.67
Kerosene-SE
5.67
Kerosene-WECC
5.67
Biomass
17.00
Landfill Gas
0.50
Other
4.00
Refuse (MSW)
11.00
Wood
16.00
Waste Coal
22.00
2.1.18 Fuel Forecasts
Fuel forecasts for out years in the economic study models for natural gas, oil and coal are
determined using fuel indices and MISO Planning Advisory Committee-defined escalation rates.
Layered indices are used to capture both regional and local price adjustments for natural gas,
all of which are pinned to the PAC’s 2013 Henry Hub price. Due to a desire to see a greater outyear natural gas price range, more variability was introduced into the Henry Hub gas price by
adding or subtracting from the Henry Hub 2013 gas price depending on the future. The discrete
prices at the Henry Hub are given for each year of simulation and each Future in Table 9 below.
The values for the out years, for all fuels, are calculated by escalating the 2013 value. The
escalation rates for each Future and each fuel are given in Table 12. The coal price in Table 9 is
the average across the MISO footprint. The 2013 uranium price is also PAC-defined and
escalated for out years. All fuel prices are given in $/MMBtu.
MISO
19
MTEP13 Economic Model Assumptions
Table 9. Fuel Prices Per Year and Future in $/MMBtu
Scenario Natural Gas
Oil#2
Coal
URANIUM
(Henry Hub)
(Distillate)
2013 BAU
3.22
19.97
1.71
1.14
RE
3.87
19.97
2.14
1.14
LG
2.58
19.97
1.71
1.14
GS
3.22
15.97
1.71
1.14
ENV
3.87
15.97
1.71
1.37
Year
2018 BAU
6.03
22.03
1.93
1.29
RE
LG
GS
ENV
7.78
4.59
5.74
23.69
20.97
16.78
2.60
1.84
1.84
1.39
1.23
1.23
7.23
17.62
1.93
1.55
2023 BAU
8.04
24.92
2.19
1.46
RE
LG
GS
ENV
11.16
5.83
7.29
28.82
22.59
18.08
3.16
1.98
1.98
1.69
1.32
1.32
9.65
19.94
2.19
1.75
2028 BAU
10.19
28.20
2.48
1.65
RE
LG
GS
ENV
15.21
7.04
8.80
12.23
16.88
16.88
16.88
16.88
3.85
2.13
2.13
2.48
2.05
1.43
1.43
1.98
2.2 Futures Matrix & Uncertainty Variables
The Matrix in Table 10 provides an overview of the uncertainty variables (i.e. those variables
that change from one Future to another). Three categories--low (“L”), medium (“M”), and high
(“H”)--are used to indicate the relative value of the variable in question. For example, the low,
medium and high values for the Demand Growth Rate assumption are .71%, 1.41% and 2.12%,
respectively. The “L” Growth Rate represents the demand growth assumption in the Limited
Growth Future; “M” in the Business As Usual and Combined Policy Futures; and “H” in Historical
Growth. The L and H values were built around the BAU mid-values, which were based on
historical information. The L, M, and H assumptions in Table 10, per uncertainty variable, are
expressed numerically in Table 11 and Table 12. Together, the tables below allow a quick
comparison of the assumptions and their resultant values used in modeling each of the Futures.
MISO
20
MTEP13 Economic Model Assumptions
Table 10. MTEP13 Futures Matrix
Uncertainties
Demand and
Energy
Future
Business as Usual
Robust Economy
Limited Growth
Generation Shift
Environmental
MISO
Fuel Cost
Fuel
Emission
(Starting Escalations
Costs
Other
Variables
Coal
CC
CT
Nuclear
Wind Onshore
IGCC
IGCC w/ CCS
CC w/ CCS
Pumped Storage Hydro
Compressed Air Energy
Photovoltaic
Biomass
Conventional Hydro
Wind Offshore
Demand Response Level
Energy Efficiency Level
Demand Growth Rate
Energy Growth Rate
Natural Gas Forecast
Oil
Coal
Uranium
Oil
Coal
Uranium
SO2
NOx
CO2
Inflation
Retirements
Renewable Portfolio Standards
Capital Costs
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
H
L
L
M
M
H
L
L
M
M
H
L
M
H
M
M
M
L
L
M
M
L
L
L
21
M
M
M
M
H
M
H
L
L
M
M
H
L
L
M
M
H
L
L
M
L
L
L
L
L
L L
L L
L L
L L
L M
M
H
L
L
M
L
L
L
M
H
M
M
M
M
H
MTEP13 Economic Model Assumptions
Table 11. MTEP13 Uncertainty Variables Categorization.
Uncertainty
Unit
Low (L)
Mid (M)
New Generation Capital Costs
High (H)
1
Coal
($/KW)
2,641
2,934
3,668
CC
($/KW)
921
1,023
1,279
CT
($/KW)
608
676
845
Nuclear
($/KW)
4,973
5,525
6,906
Wind-Onshore
($/KW)
1,993
2,214
2,768
IGCC
($/KW)
3,406
3,784
4,730
IGCC w/ CCS
($/KW)
5,939
6,599
8,249
CC w/ CCS
Pumped Storage
Hydro
Compressed Air
Energy Storage
($/KW)
1,886
2,095
2,619
($/KW)
4,759
5,288
6,610
($/KW)
1,164
1,294
1,617
Photovoltaic
($/KW)
3,486
3,873
4,841
Biomass
($/KW)
3,703
4,114
5,143
Conventional Hydro
($/KW)
2,642
2,936
3,670
Wind-Offshore
($/KW)
5,607
6,230
7,788
Demand and Energy
Demand Growth
Rate2
Energy Growth Rate3
Demand Response
Level
Energy Efficiency
Level
Natural Gas5
%
0.53%
1.06%
1.59%
%
0.53%
1.06%
1.59%
MECT
4
Estimates
MECT
4
Estimates
%
%
Natural Gas
See "Natural Gas" Tab for Low / Mid / High
($/MMBtu)
forecasts
Fuel Prices (Starting Values)
($/MMBtu)
Powerbase
default -20%
Powerbase
default -20%
Powerbase
6
default
Powerbase
7
default
Powerbase default
+ 20%
Powerbase default
+ 20%
($/MMBtu)
0.91
1.14
1.37
Oil
($/MMBtu)
Coal
Uranium
1
All costs are EIA overnight construction costs in 2013 dollars
2
Mid value for demand growth rate is the Module-E 50/50 load forecast growth rate
MISO
22
MTEP13 Economic Model Assumptions
3
Mid value for energy growth rate is the Module-E energy forecast growth rate
4
Starting in Dec. 2012, LSE's voluntarily report DR and EE data for MTEP planning purposes in MECT
5
Prices reflect the Henry Hub natural gas price
6
Powerbase default for oil is $19.39/MMBtu
7
Powerbase range for coal is $1 to $4, with an average value of $1.69/MMBtu
Table 12. MTEP13 Uncertainty Variables Categorization (Continued).
Uncertainty
Unit
Low (L)
Mid (M)
High (H)
Fuel Prices (Escalation Rates)
Gas
%
1.5
2.5
4.0
Oil
%
1.5
2.5
4.0
Coal
%
1.5
2.5
4.0
Uranium
%
1.5
2.5
4.0
Emissions Costs
SO2
($/ton)
0
0
500
NOx
($/ton)
0
0
NOx: 500
Seasonal NOx:
1000
CO2
($/ton)
0
50
N/A
1.5
2.5
4.0
MW
12,600 MW
12,600 MW +
7,500 MW agerelated
retirements =
8
20,100 MW
23,000 MW
%
Reduced state
mandates
State mandates
only
State mandates
and goals
Other Variables
Inflation
Retirements
Renewable Portfolio
Standards
8
%
7,500 MW value is based on MTEP12 database
2.3 Regional Assumptions
This section details the regional breakdown of the PowerBase database. Eight regions are
modeled, including:



Manitoba Hydro (MHEB)
Midwest Reliability Organization (MRO)
Midwest Independent Transmission System Operator (MISO)
MISO
23
MTEP13 Economic Model Assumptions





New York Independent System Operator (NYISO)
PJM Interconnection (PJM)
South Eastern Reliability Corporation (SERC)
Southwest Power Pool (SPP)
Tennessee Valley Authority (TVA)
MISO Midwest and MISO South are both modeled under the same MISO region. For reference,
the following types of information will display MISO Midwest and MISO South separately.
2.3.1 Resource Mix
Each region within the overall footprint considered for MTEP13 has a different resource mix.
Table 13 gives the total nameplate capacity by region and resource type for 2013, rounded to
the nearest MW. The nameplate capacity includes all existing, under-construction and planned
units, as assigned in the MTEP13 PowerBase database. Existing capacity is defined as those
units in operation. Operating license extensions are assumed on all nuclear units. Planned units
include all planned capacity resources with a signed Generator Interconnection Agreement
(GIA). The “Other” column in Table 13 includes the following PowerBase generator categories:
ST (steam turbine) Other, ST Renewable, CT (combustion turbine) Other, CT Renewable, IC
(internal combustion) Other, and IC Renewable. The “Coal” category includes IGCC units in
addition to traditional coal units, and the “Gas” category includes CC units in addition to
traditional gas units.
Region
Table 13. Existing, Under Construction and Planned Units
Coal
Nuclear
Gas
Wind
Solar
Hydro Pumped
Storage
97
400
551
5,404
4,604
2,249
1,293
3,408
-
Oil
Other
MHEB
MRO
199
70
MISO
63,667
8,309
37,534 13,585
1
1,412
2,490
3,905
1,120
Midwest
MISO
8,622
5,461
30,082
563
28
73
124
South
NYISO
2,068
5,297
21,355
1,773
4,631
1,405
5,073
915
PJM*
78,287 33,954 58,248
6,865
225
2,758
5,561
12,667
2,493
SERC
41,822 17,419 46,296
35
6,708
4,453
3,540
540
SPP
24,397
2,455
30,430
7,630
52
2,534
474
1,239
104
TVA8,961
5,787
308
31
143
45
Other
TVA
14,449
6,878
13,656
1,378
13
5,193
1,825
14
3
*PJM capacity numbers include queue projects with commission dates set to 2013 or before in the PB case supplied
by PJM. Many of these dates do not agree with in-service dates as listed in PJM’s generation interconnection queue.
As such, the numbers in the table may be overstating the actual capacity in-service in PJM in 2013, specifically with
respect to wind generation.
** Other utility members of the Tennessee Valley Authority (TVA) were uniquely noted in the pool structure as “TVAOther” in order to better model power sale limitations
MISO
24
MTEP13 Economic Model Assumptions
Figures 5 through 14 on the following pages show the resource mix breakdowns as a
percentage of total generation for each region.
MHEB Region: 2013 Resource Mix
Coal
1%
Gas
6% Wind
9%
Coal
Nuclear
Gas
Wind
Solar
Hydro
Pumped Storage
Oil
Hydro
84%
Other
Figure 5. MHEB Resource Mix
MISO
25
MTEP13 Economic Model Assumptions
MISO Midwest Region: 2013 Resource
Pumped Storage Other Mix
Hydro
1%
2%
1%
Coal
Nuclear
Oil
3%
Gas
Wind
10%
Wind
Solar
Coal
48%
Gas
29%
Hydro
Pumped Storage
Oil
Other
Nuclear
6%
Nuclear
6%
Figure 6. MISO Resource Mix
MISO South Region: 2013 Resource Mix
Hydro
1%
Coal
Nuclear
Coal
19%
Gas
Wind
Solar
Nuclear
12%
Gas
67%
Hydro
Pumped Storage
Oil
Other
Figure 7. MISO South Resource Mix
MISO
26
MTEP13 Economic Model Assumptions
MRO Region: 2013 Resource Mix
Oil
2%
Coal
Nuclear
Gas
Hydro
29%
Coal
39%
Wind
Solar
Hydro
Pumped Storage
Wind
11%
Oil
Other
Gas
19%
Figure 8. MRO Resource Mix
NYISO Region: 2013 Resource Mix
Other
2%
Pumped Storage
3%
Oil
12%
Coal
5%
Coal
Nuclear
Nuclear
13%
Gas
Wind
Solar
Hydro
11%
Hydro
Pumped Storage
Wind
4%
Oil
Gas
50%
Other
Figure 9. NYISO Resource Mix
MISO
27
MTEP13 Economic Model Assumptions
PJM Region: 2013 Resource Mix
Other
1%
Pumped Storage
3%
Hydro
Wind 1%
Coal
Nuclear
Oil
6%
4%
Gas
Wind
Coal
39%
Solar
Hydro
Pumped Storage
Gas
29%
Oil
Other
Nuclear
17%
Figure 10. PJM Resource Mix
SERC Region: 2013 Resource Mix
Pumped Storage
4%
Hydro
6%
Coal
Oil
3%
Nuclear
Gas
Coal
35%
Wind
Solar
Hydro
Pumped Storage
Gas
38%
Oil
Other
Nuclear
14%
Figure 11. SERC Resource Mix
MISO
28
MTEP13 Economic Model Assumptions
SPP Region: 2013 Resource Mix
Oil
Pumped Storage 2%
1%
Coal
Hydro
4%
Nuclear
Wind
11%
Gas
Coal
35%
Wind
Solar
Hydro
Pumped Storage
Oil
Gas
44%
Other
Nuclear
3%
Figure 12. SPP Resource Mix
TVA Region: 2013 Resource Mix
Pumped Storage
4%
Coal
Nuclear
Wind
3%
Hydro
12%
Gas
Coal
33%
Wind
Solar
Hydro
Pumped Storage
Gas
32%
Oil
Nuclear
16%
Other
Figure 13. TVA Resource Mix
MISO
29
MTEP13 Economic Model Assumptions
TVA - Other Region: 2013 Resource Mix
Wind
2%
Hydro
1%
Coal
Nuclear
Gas
Wind
Solar
Gas
38%
Hydro
Coal
59%
Pumped Storage
Oil
Other
Figure 14. TVA-Other Resource Mix
2.3.2 Regional Generation Forecasts
In order to maintain the load/resource balance and Planning Reserve Margin (PRM) target for
out years in the models, future generation must be forecasted. The Generation Interconnection
Queue (Queue) is the first source for out-year capacity forecasts; however, foresight gained
from the Queue is generally limited to five years into the future. Electric Generation Expansion
Analysis (EGEAS), a capacity forecast software tool, is used to supplement available data on
future generation. The output of EGEAS runs are Regional Resource Forecasted (RRF) Units.
Details on assumptions behind siting and application of RRFs units can be found in Sections 3
and 4, Regional Resource Forecasting.
2.3.3 Regional Demand & Energy Forecasts
In PowerBase, projected future demand and energy growth rates are input at the company
level. In Table 14, rates have been aggregated for each region, per Future. Demand and energy
growth rates used in EGEAS simulations for the MISO footprint are based on data from loadserving entities (LSEs) as reported in MISO’s Module E Capacity Tracking (MECT) tool. The
mid-value (M) for the demand growth rate is the Module E 50/50 load forecast growth rate
(1.06%). Low (L) and high (H) values are based off of this rate. For external regions, Ventyx
default growth rates are scaled to arrive at the baseline demand and energy growth rates which
are inputted into EGEAS.
MISO
30
MTEP13 Economic Model Assumptions
Table 14. Baseline Demand and Energy Growth Rates by Region
MTEP13 Growth Rates
LG, GS
BAU, ENV
RE
Low
Mid
High
Study Region
Demand
Energy
Demand
Energy
Demand
MH
0.73%
0.77%
1.45%
1.54%
2.18%
MISO Midwest
0.53%
0.53%
1.06%
1.06%
1.59%
MISO South
0.45%
0.47%
0.90%
0.93%
1.36%
MRO
0.40%
0.52%
0.81%
1.05%
1.21%
NYISO
0.41%
0.31%
0.81%
0.62%
1.22%
PJM
0.67%
0.73%
1.35%
1.46%
2.02%
SERC
0.70%
0.74%
1.40%
1.48%
2.10%
SPP
0.34%
0.35%
0.69%
0.71%
1.03%
TVA
0.68%
0.51%
1.36%
1.03%
2.05%
Energy
2.31%
1.59%
1.40%
1.57%
0.92%
2.19%
2.22%
1.06%
1.54%
The effective demand and energy growth rates for each region are calculated after the EGEAS
capacity expansion analysis, taking only state-level DSM mandate and goal projections into
consideration. In the past two MTEPs, MISO allowed EGEAS to pick additional DSM based on
program economics. Without having updated projections of DSM potential (the Global Energy
Partners study was completed in 2010), stakeholders expressed concern over the accuracy of
continuing to model GEP-developed DSM estimates. The effective growth rates are ultimately
used in the PROMOD production cost modeling simulations. These rates are given in Table 15.
Table 15. Effective Demand and Energy Growth Rates by Region
MTEP13 Growth Rates
LG, GS
BAU, ENV
RE
Low
Mid
High
Study Region
Demand
Energy
Demand
Energy
Demand
MH
0.73%
0.77%
1.45%
1.54%
2.18%
MISO Midwest
0.23%
0.29%
0.75%
0.81%
1.28%
MISO South
0.44%
0.46%
0.89%
0.92%
1.34%
MRO
0.34%
0.48%
0.74%
1.00%
1.14%
NYISO
-0.70%
-0.66%
-0.24%
-0.32%
0.16%
PJM
0.07%
0.24%
0.75%
0.98%
1.42%
SERC
0.69%
0.73%
1.40%
1.47%
2.10%
SPP
0.14%
0.17%
0.48%
0.53%
0.82%
TVA
0.68%
0.51%
1.36%
1.03%
2.05%
Energy
2.31%
1.34%
1.39%
1.52%
0.02%
1.71%
2.21%
0.88%
1.54%
2.3.4 External Transactions, Interruptible Load and Industrial Loads
External transactions, interruptible loads and industrial loads (aluminum smelters) are all
modeled in PowerBase.Table 16 shows the max capacity of each type of resource per region.
MISO
31
MTEP13 Economic Model Assumptions
Table 16. Total External Transactions, Interruptible Loads and Industrial Loads by Region
External
Interruptible
Industrial
Region
Transactions
Loads
Loads
(MW)
(MW)
(MW)
MHEB
0
167
0
MRO
0
156
0
MISO
3,006
5,781
1,821
NYISO
5,095
2,219
0
0
5,523
522
2,300
3,002
400
SPP
0
1,238
0
TVA
0
2,057
0
PJM
SERC
2.4 Local Resource Zone Data
9 Local Resource Zones (LRZs) have been established for the MISO footprint, as shown in
Figure 15, in Appendix A . Zones 1 through 7 were developed by MISO with input from
stakeholders as part of a new Resource Adequacy construct filed at FERC under Module E of
the MISO Tariff. The new construct addresses the MISO-wide Planning Reserve Margin (PRM)
and captures any additional requirements internal to each LRZ that may be due to congestion
effects inside and outside of the LRZs. Aggregation of economic study model data at the LRZ
level provides a sub-regional view of the MISO footprint. Demand and energy growth rates per
zone along with annual energy and load forecasts can be found in Appendix A.
With the addition of the South Region to MISO’s footprint, MISO evaluated how to incorporate
the incoming set of Local Resource Zones (LRZ), into the Resource Adequacy (RA) construct.
After collaboration from the stakeholder committee and analysis of a completed Proof-OfConcept (POC) study, MISO’s final recommendation for the new South Region zones consisted
of a two-zone configuration with Arkansas being LRZ-8 and remaining Southern Region making
up LRZ-9.
MISO
32
MTEP13 Economic Model Assumptions
3 Regional Resource Forecasting
The Electric Generation Expansion Analysis System (EGEAS) is a capacity forecasting software
tool from the Electric Power Research Institute (EPRI) used for long-term regional resource
forecasting (RRF). EGEAS performs capacity expansions based on long-term, least-cost
optimizations with multiple input variables and alternatives. Optimizations can be performed on
a variety of constraints such as reliability (loss-of-load hours), reserve margins, or emissions
constraints. The objective function of the MTEP13 study optimization aims to minimize the net
present value of twenty-year capital and production costs, with a reserve margin requirement
indicating when and what type of resources will be added to the system. This section focuses on
those data assumptions and methodologies specific to EGEAS applications.
3.1 Study Period
The standard future outlook for MTEP EGEAS simulations is 20 years. The base year for
MTEP13 modeling is 2013, extending out to 2032. In order to eliminate any “end effects” an
extension period of 40 years is simulated, with no new units forecasted during this time. This
additional study period ensures that the selection of generation in the last few years of the
forecasting period (e.g. years 18, 19, 20) is based on the costs of generation spread out over
the total tax / book life of the new resources (i.e. beyond year 20).
3.2 Study Areas
The MTEP13 database is comprised of all areas in the Eastern Interconnect, with the exception
of Florida, ISO New England and Eastern Canada. The ten areas referenced in this document
are:










Manitoba Hydro (MHEB)
Midwest Reliability Organization (MRO)
Midcontinent Independent System Operator – Midwest (MISO Midwest)
Midcontinent Independent System Operator – South (MISO South)
New York Independent System Operator (NYISO)
PJM Interconnection (PJM)
SERC Reliability Corporation (SERC)
Southwest Power Pool (SPP)
Tennessee Valley Authority (TVA)
TVA – Other
MTEP13 regional resource forecasting was performed before the integration of various
companies in the South into MISO. Therefore, resource forecasting for the companies
composing MISO South was performed separately from that of MISO Midwest.
The TVA region has been modeled as two pools in an effort to more accurately model market
behavior, which is constrained by the Tennessee Valley Authority’s ability to sell power only to
certain companies. The three companies that compose the “TVA-Other” pool do not have such
a restriction. This phenomenon has been termed the “TVA Fence” and it is captured through
PROMOD pool definitions and their associated settings.
MISO
33
MTEP13 Economic Model Assumptions
3.3 Capacity Types
Capacity is categorized into existing, under construction, planned, or retired. Assumptions
related to each of these categories include the following:
–
–
–
–
Existing: Operating license extensions are assumed on all nuclear units.
Under Construction: Units with steel in the ground, but not yet under commercial
operation.
Planned: All capacity resources with a signed Generator Interconnection Agreement
(GIA) are modeled as planned units.
(Retirements) See Section 2.1.13 EPA and Age-Related Unit Retirements
3.4 Firm Interchange
Firm interchange contributes to resource adequacy by reducing a region’s overall internal
capacity needs over time. It is assumed that each modeled region will build generation capacity
to meet its own resource adequacy needs.
MISO and MHEB have a firm interchange of 1,500 MW (into MISO), growing to 3,000 MW over
the course of the study period. This is owed to projected added capacity in the Manitoba
footprint, and it is scheduled as followed:
–
–
–
2013: 1,500 MW total
2018: 2,000 MW total
2023: 3,000 MW total
MISO and IESO also have a firm interchange of 1,799 MW (into MISO), falling by 257 MW per
year to 0 MW by 2020. The MISO – IESO interchange is modeled in EGEAS as:
–
–
–
–
–
–
–
–
2013: 1,799 MW
2014: 1,542 MW
2015: 1,285 MW
2016: 1,028 MW
2017: 771 MW
2018: 514 MW
2019: 257 MW
2020: 0 MW
3.5 Planning Reserve Margin Target
The Planning Reserve Margin (PRM) is entered into EGEAS for the first year of the simulation,
and this PRM is carried throughout the rest of the study period. PRM targets are based on
respective system co-incident peaks (MW), with the exception of SPP’s, which is based on its
non-coincident peak (MW). Table 17 below presents the 2013 reserve margin, as well as the
PRM target, on a regional basis.
Region
MISO
Table 17. PRM Margins and Targets
2013 Reserve
PRM
Margin (%)
Target (%)
34
MTEP13 Economic Model Assumptions
61.8
32.5
60.0
31.8
29.3
30.6
37.4
34.6
MISO South
MISO Midwest
MRO
NYISO
PJM
SERC
SPP
TVA
16.85
14.20
15.00
16.50
15.40
15.00
13.60
15.00
3.6 Wind Hourly Profile and Capacity Credits
EGEAS models all wind as a non-dispatchable technology. One hourly wind profile is created
for the MISO footprint by averaging all MISO Regional Generator Outlet Study (RGOS) zone
profiles. A single profile for each of the regions external to MISO is made by averaging all NREL
wind sites in each region.
The wind Capacity Credit is the max Capacity Credit that a wind resource may receive if it
meets all other obligations of Module E to be a Capacity Resource. This value, which is a % of
the maximum capacity of the unit, reflects the risk associated with reliance upon an intermittent
resource, such as wind. The capacity factor is the anticipated annual energy output of the unit
as a % of the total potential energy output. The wind capacity credit is updated annually during
the MISO Loss of Load Expectation (LOLE) analysis and, for the 2013 planning year, was
calculated to be 13.3 percent.
3.7 Reserve Contribution
Two specific assumptions were made with regard to reserve contribution:


8% of nameplate solar capacity was counted toward its reserve capacity contribution
The summer de-rated capacity for conventional generation is counted toward its reserve
capacity contributio
3.8 Financial Variables
Financial variables used in MTEP13 EGEAS simulations are listed in Table 18.
Table 18. Financial Variables
Variable
Rate (%)
Composite Tax Rate
39.00
Insurance Rate
0.50
Property Tax Rate
1.00
AFUDC* Rate
7.00
*Adjusted for Funds Used During Construction
MISO
35
MTEP13 Economic Model Assumptions
3.9 Load Shapes
The load shapes used in EGEAS simulations and their sources are presented in Table 19.
Table 19. Load Shape Descriptions and Sources
Load Shape
Description and Source
System
2005 hourly profiles from Ventyx
2005 hourly profiles developed by AWS TrueWind for
EWITS
Basic representation of production during the day,
adjusted for seasonal variations
Wind
Solar
Energy Efficiency
Provided by Global Energy Partners, LLC.
3.10 Generic Generator Categories
Tables 20 and 21 on the following pages list the generic categories of generators used when
forecasting future units to meet the Planning Reserve Margin requirements.
Table 20. Generic Generator Categories - Supply Side Options
Supply Side Options
Biomass
Coal
Combined Cycle (with and without sequestration)
Combustion Turbine
Compressed Air Energy Storage
Distributed Generation
Hydro
Integrated Gasification Combined Cycle (IGCC) - with and without sequestration
Nuclear
Pumped Hydro Storage
Solar
Wind (on-shore and off-shore)
MISO
36
MTEP13 Economic Model Assumptions
Table 21. Generic Generator Categories - Demand Side Options
Demand Side Options
Commercial & Industrial (C&I) Low Cost Energy Efficiency (EE) program
C&I Interruptible
3.11 Generic Generator Data
Table 22 shows the fixed operation and maintenance (Fixed O&M) cost, variable O&M cost,
heat rate, lead time (inclusive timeframe for unit construction), maintenance hours, and forced
outage rate (FOR) for the generic supply-side generator categories used in MTEP13 regional
resource forecasting. Additional generic generator data includes overnight construction costs,
must-run status and capacity. The overnight construction costs per generic generator type vary
depending on the Future and can be found in the Futures Matrix, in Section 2.2 Futures Matrix &
Uncertainty Variables labeled as Alternative Capital Costs. The capacity of each forecasted
generic unit from each category is 600 MW, with the exception of wind at 300 MW. Monetary
values given in the table are in 2013 dollars.
The following table is from the Technology Performance Specifications in the Energy
Information Administration’s Annual Energy Outlook Report (released April 2013).
Table 22. Generic Generator Data
Fixed
O&M
($/kW-Yr)
Variable
O&M
($/MWh)
Heat Rate
(MMBTU/
MWh)
Lead
Time
(Years)
Biomass
105.63
5.26
13.50
4
0
3.25
Coal
31.18
4.47
8.80
6
672
4.48
CC
15.37
3.27
6.43
3
336
5.11
CCS*
31.79
6.78
7.53
3
504
5.11
CT
7.04
10.37
9.75
2
168
5.93
Hydro
14.13
2.66
0.00
4
0
3.25
IGCC
51.39
7.22
8.70
6
672
5.11
IGCCS**
72.83
8.45
10.70
6
672
5.11
Nuclear
93.28
2.14
10.40
11
672
2.95
PV
21.75
5.00
0
2
0
0
Type
Maintenance
Schedule
FOR
(Hours)
(%)
39.55
5.00
0
2
0
0
CCS* = Combined-Cycle with Sequestration
IGCCS** = Integrated Gasification Combined-Cycle with Sequestration
Wind
3.12 Economic Rates
The economic rates used in EGEAS simulations are given in Table 23.
MISO
37
MTEP13 Economic Model Assumptions
Table 23. Economic Rates and Descriptions
Rate Type
Inflation Rate
Discount Rate
Escalation Rate
Description
Applies to the growth of all costs within the
model over time.
Can vary between scenarios.
Must be applied at the same rate for all
regions.
Does not change between scenarios.
Future fuel prices are escalated based on
current prices.
Can vary between scenarios.
The specific values for the economic rates vary depending on the Future and can be found in
the Futures Matrix, in Section 2.2 Futures Matrix & Uncertainty Variables.
MISO
38
MTEP13 Economic Model Assumptions
4 Unit Siting
Once the Regional Resource Forecasts have been developed, the generation must be sited in
the study footprint. To ensure consistent siting, a siting methodology has been established,
lending to a set of conditions that is applied in siting for all Futures. To see a complete list of
RRF units and their siting, please refer to Item 2 (PAC MTEP13 EGEAS Results Siting) from the May
15, 2013, Planning Advisory Committee meeting, found at
https://www.misoenergy.org/Events/Pages/PAC20130515.aspx.
4.1 General Siting Methodology
This methodology applies to all Futures.

Transmission is not an initial siting factor, but may be used as a weighting factor, all things
being equal.

Siting is done by region with the exception of wind units.

Generation is distributed throughout the states in the study footprint; no one state will have
all units sited within its borders; no one state will have zero units sited.

Brownfield sites are preferable to Greenfield sites for gas units (CTs & CCs).

Baseload units are sited in 600 MW increments and nuclear units, at 1,200 MW each.

The total amount of expansion to an existing site is limited to no more than an additional
2,400 MW.

Greenfield sites are restricted to a total of 2,400 MW.

Use of Queue generation in multiple Futures should be limited.
4.2 Unit Capacity Type and Status Definitions
Unit siting is dependent upon capacity type and unit status. The following are definitions of unit
developmental status:
–
Active: Existing online generation including committed and uncommitted units.
Does not include generation which has been mothballed or decommissioned.
–
Planned: Existing offline generation, with a future in-service date, that is not
suspended or postponed and has proceeded to a point where construction is
almost certain, such as when an interconnection agreement has been signed, all
permits have been approved, all study work has been completed, state or
administrative law judge has approved, etc.
o
MISO
These units are used in the model to meet future demand requirements
prior to the economic expansions.
39
MTEP13 Economic Model Assumptions
–
Future: Generators with a future online date that do not meet the criteria of the
“planned” status. Generators with a future status are typically proposed, in
feasibility studies, have permits pending, etc.
o
–
These generators are not used in the models but are considered in the
siting of future generation.
Canceled: Generators which have been suspended, canceled, retired or
mothballed.
4.3 Site Selection Priority Order
The following bullets describe the priority order for site selection.
Priority 1: Sites of generators with a “Future” Status
o
Queue generators without a Signed IA
o
Ventyx’s “New Entrants” Generators (Will be referred to as “EV” Gens)
o
Both Queue and EV Gens are under the following statuses:

Permitted

Feasibility

Proposed
Priority 2: Brownfield sites (Coal, CT, CC, Nuclear Methodology)
Priority 3: Retired/Mothballed sites which have not been re-used
Priority 4: Greenfield Sites
o
For Queue & EV Gens in Canceled or Postponed Status
Priority 5: Greenfield Sites
o
MISO
Using Greenfield Siting Methodology
40
MTEP13 Economic Model Assumptions
4.4 Greenfield Siting Rules
The site criteria in Table 24 are used as inputs to MapInfo to produce potential Greenfield sites
for coal generation. The legend below the table describes the codes used.
Table 24. Greenfield Siting Rules
Fuel
Type/
Criteria
Railroad/
Navigable
Waterway
Class
lands
Nonattainment
region
Urban
Area
Major
River/
Lake
Gas
Pipeline
Coal Mine/
Dock
Coal
<1
LM
>20
O
>25
<0.5
PA
<20
Biomass
<1
LM
>20
O
>25s
<0.5
PA
-
CC
<1
>20
-
<25
<2
<10
-
CT
<20
>20
-
-
<1-2
L
<5
-
L = “likes” : This feature is strongly preferred for siting a unit of this type.
LM = “likes multiples” : Multiple instances of this feature are strongly preferred for siting a unit
of this type.
<x = “within x miles”: The unit should be sited within x miles of this feature.
>x = “outside of x miles” : The unit should be sited outside of x miles of this feature.
O = “outside” : The unit should be sited outside of the range of this feature.
PA = “prefer access” : Access to this feature is preferred, though not required.
4.5 Renewable Unit Siting
Wind in MISO is sited in the Regional Generator Outlet Study (RGOS) zones identified by the
RGOS study. These sites were also used in the Multi-Value Project (MVP) business case
justification. All incremental MISO wind expansion to meet state and/or federal mandates was
sited to the RGOS zones in the same proportion to their capacity distributions in the MTEP11
MVP study.
MISO
41
MTEP13 Economic Model Assumptions
5 Production Cost Modeling
PROMOD IV (PROMOD) is a production cost simulation software tool from Ventyx used to
examine the economics of transmission expansion planning. This section focuses on those data
assumptions and methodologies specific to PROMOD applications.
5.1 Study Footprint
The powerflow cases used in PROMOD include the whole Eastern Interconnection footprint.
However, if the transmission, generation and load details of each region within the
Interconnection are included in simulations, the bus limitation of PROMOD is exceeded. As
such, these details for the Florida, ISONE, IESO, and Eastern Canada regions are excluded.
Instead, fixed transactions are used to model the exchanges between these regions and the
detailed regions, including:








MHONSALE (MHEB Sale to IESO)
MIONPURC (MISO Purchase from IESO)
MIONSALE (MISO Sale to IESO)
NYHQPURC (New York Purchase from Hydro Quebec)
NYNEPURC (New York Purchase from New England)
NYHQSALE (New York Sale to Hydro Quebec)
NYNESALE (New York Sale to New England)
FLASALE (Southern Sale to Florida).
5.2 Study Years & Powerflow Data Sources
The study years simulated by PROMOD are 2018, 2023 and 2028. Data for the remaining years
of the system outlook are either interpolated or extrapolated from these three one-year
simulations. Separate powerflows were used for 2018 and 2023/2028. These powerflows are
based on the NERC 2013 Multiregional Modeling Working Group (MMWG) powerflow series
with MISO and PJM updates, and the MISO Model on Demand (MOD). Additionally, MISO
coordinates with PJM, SPP and TVA to incorporate each entity’s best available model.
5.3 Pool Definition
A pool is a grouping of companies into an area in which all the generators are dispatched
together to meet the area’s combined load. The pool represents an energy market, like MISO or
PJM. For MTEP13 PROMOD simulations, nine pools are defined in the study footprint, which
align closely with the regional definitions given in Section 2.
–
–
–
–
–
–
MISO
MHEB
MISO
MRO
New York
PJM Interconnection
SERC
42
MTEP13 Economic Model Assumptions
–
–
–
Southwest Power Pool
TVA
TVA-Other
The TVA region has been modeled as two pools in an effort to more accurately model market
behavior, which is constrained by the Tennessee Valley Authority’s ability to sell power only to
certain companies. The three companies that compose the “TVA-Other” pool do not have such
a restriction. This phenomenon has been termed the “TVA Fence” and it is captured through
PROMOD pool definitions and their associated settings. Below are lists of all companies in each
of the ten pools.
–
MHEB
 Manitoba Hydro
–
MISO
 MISO Central
o Ameren Illinois
o Ameren Missouri
o Big Rivers Electric Corp
o Columbia Missouri Water and Light Department
o Duke Energy Indiana
o Hoosier Energy Rural Elec.
o Indianapolis Power & Light
o Southern Illinois Power Co-operative
o Southern Indiana Gas & Electric
o Springfield Illinois – City Water Light & Power
 MISO East
o Consumers Energy – METC
o Detroit Edison Company
o Northern Indiana Public Service
o Wolverine Power Supply Cooperative
 MISO South
o Central Louisiana Electric Co. Inc.
o Entergy Arkansas
o Entergy Gulf States
o Entergy Louisiana
o Entergy New Orleans
o Entergy Texas
o Lafayette (City of)
o Louisiana Energy and Power Authority
o Louisiana Generation/Cajun Electric
o South Mississippi Electric Power Association
 MISO West
o Aliant West – Interstate Power & Light
MISO
43
MTEP13 Economic Model Assumptions
o American Transmission Co (ATC)
– Aliant East – Wisconsin Power and Light Company
– Madison Gas and Electric Company
– Upper Peninsula Power Company
– Wisconsin Electric Power Company
– Wisconsin Public Power Inc
– Wisconsin Public Service Corporation
o Dairyland Power Cooperative (GSE)
o Great River Energy
o MidAmerican Energy Co
o Minnesota Power and Light Company
o Missouri River Energy Services
o Montana-Dakota Utilities Co.
o Muscatine Power & Water
o Northern States Power Company
o Otter Tail Power Company
o Southern MN Municipal Power Agency
–
MRO






–
MISO
Basin Electric Power Coop
Corn Belt Power Cooperative
Minnkota Power Coop
NorthWestern Public Service
Saskatchewan
o SaskPower
WAPA – Upper Great Plains East
New York
 NY Rest of State
o NY East
– NY-F (Capital)
 New York Zone F – Capital
– NY-GHI (Southeast)
 New York Zone G – Hudson Valley
 New York Zone H – Millwood
 New York Zone I – Dunwoodie
o NY West
– NY-AB (West)
 New York Zone A – West
 New York Zone B – Genessee
– NY-CDE (Cent North)
 New York Zone C – Central
 New York Zone D – North
44
MTEP13 Economic Model Assumptions

New York Zone E – Mohawk Valley
o NY South
– NY-J (NY City)
 New York Zone J – NY City
– NY-K (Long Island)
 New York Zone K – L Island
–
PJM Interconnection
 RFC Reserve Zone
o PJM MidAtlantic
– Eastern Mid-Atlantic
 Atlantic Electric
 Delmarva Power & Light Company
 Jersey Central Power & Light Company
 PECO Energy Company
 Public Service Electric & Gas Company
 Rockland Electric Company
– Rest of Mid-Atlantic
 Baltimore Gas & Electric Company
 Metropolitan Edison Company
 Pennsylvania Electric Company
 PPL Electric Utilities
 Potomac Electric Power Company
o PJM Western
– Allegheny Power
– American Electric Power
– Commonwealth Edison Co.
– Dayton Power & Light Co.
– Duke Energy Ohio/Kentucky
– Duquesne Light Company
– East Kentucky Power Coop.
– First Energy ATSI
 Southern PJM Reserve Zone
o PJM – South
– Virginia Power Company
–
SERC
 Southern Company
o Alabama Power Company
o Georgia Power Company
o Gulf Power Company
o Mississippi Power Company
o Santee Cooper
MISO
45
MTEP13 Economic Model Assumptions

–
–
–
o Yadkin Inc.
VACAR
o Duke Energy Carolinas
o PowerSouth Energy Coop
o Progress Energy Carolinas East
o Progress Energy Carolinas West
o South Carolina Electric & Gas Company
Southwest Power Pool
 SPP – Central
o AEP West
o Grand River Dam Authority
o Oklahoma Gas & Electric Company
o Southwestern Power Administration
o Southwestern Public Service Company
o Western Farmers Electric Cooperative
 SPP – KSMO
o Board of Public Utilities Kansas City Kansas
o City Power & Light Independence
o Empire District Electric Co.
o Kansas City Power & Light Co.
o KCPL-Greater Missouri (MPS)
o Sunflower Electric Power Corp.
o Westar Energy/Western Resources
 SPP – Nebraska
o Lincoln Electric System
o Nebraska Public Power District
o Omaha Public Power District
TVA – Other
 Associated Electric Cooperative Inc.
 E.ON US
TVA

Tennessee Valley Authority
Additionally, an “Other Areas” category is included in the Areas definition, which contains the
following areas and companies:
–
MISO
Eastern Canada
 Maritimes
o Maritime Electric Company Limited
o New Brunswick Power Corp.
o Northern Maine
o Nova Scotia Power Inc.
46
MTEP13 Economic Model Assumptions

Quebec
o Hydro-Quebec
–
Florida
 Florida Municipal Power Pool
 Florida Power & Light
 Gainesville Regional Utilities
 JEA
 Progress Energy Florida
 Seminole Electric Cooperative Inc.
 Tallahassee Electric Dept. (City of)
 Tampa Electric Company
–
IESO (Ontario)
 Ontario-Bruce
 Ontario-East
 Ontario-ESSA
 Ontario-Niagara
 Ontario-Northeast
 Ontario-Northwest
 Ontario-Ottawa
 Ontario-Southwest
 Ontario-Toronto
 Ontario-West
–
New England
 NE – Maine
o ISNE – Maine – Bangor Hydro Electric
o ISNE – Maine – Central
o ISNE – Maine – Southwest
 NE – Rest of Pool
o NE – East
– ISNE – Boston
– ISNE – Massachusetts – Central-Northeast
– ISNE – Massachusetts – Southeast
– ISNE – New Hampshire
– ISNE – Rhode Island
o NE – SWCT
– ISNE – Connecticut – Norwalk
– ISNE – Connecticut – Southwest
o NE – West
– ISNE – Connecticut – Central-Northeast
– ISNE – Massachusetts-Western
MISO
47
MTEP13 Economic Model Assumptions
–
ISNE – Vermont
5.4 Hurdle Rates
Hurdle rates influence the capability of a pool to obtain, support or sell energy to other pools. In
order for a sale to occur, the difference in dispatch costs between the buying pool and the
selling pool must be greater than the hurdle rate between them.
PROMOD performs security constrained unit commitment and economic dispatch, with userdefined hurdle rates. The hurdle rate for the unit commitment step is called the commitment
hurdle rate; likewise, the hurdle rate defined for the economic dispatch step is the dispatch
hurdle rate.
Normally, users set the commitment hurdle rate to be greater than the dispatch hurdle rate. This
causes a pool’s units to be dispatched against its own pool load first, then allows pool
interchange during the final dispatch via the dispatch hurdle rate.
Though there is no standard for defining hurdle rates, they are commonly based on the filed
transmission through-and-out rates, plus a market inefficiency adder. This is the method used to
determine hurdle rates for MTEP13, which are set in the TMSV (Multi-party definition) PROMOD
Custom Table.
The dispatch and commitment hurdle rates between pools are shown in Tables 25 and 26
respectively, below. In each cell, the weekday hurdle rate is listed first followed by a ‘/’ and then
a value that is both the weeknight and weekend hurdle rate.
Table 25. Dispatch Hurdle Rates
To -->
PJM
MISO
TVA
MRO
SPP
SERC
MHEB
NYISO
TVAO*
PJM
*
1/1
4.8 / 4.8
N/A
N/A
4.8 / 4.8
N/A
10 / 10
4.8 / 4.8
MISO
8/8
*
7.5 / 5.4
5.5 / 3.4
7.5 / 5.4
8/8
0/0
N/A
7.4 / 5.4
TVA
30 / 30
30 / 30
*
N/A
-/-
30 / 30
N/A
N/A
30 / 30
MRO
N/A
6.3 / 5.7
N/A
*
6.9 / 6.9
N/A
6.5 / 4.5
N/A
SPP
N/A
5.1 / 5.1
5.1 / 5.1
5.1 / 5.1
*
N/A
N/A
N/A
5.1 / 5.1
SERC
6.5 / 4.5
10 / 10
6.8 / 5.0
N/A
N/A
*
N/A
N/A
6.8 / 5.0
MHEB
N/A
0/0
N/A
11.6 /
7.3
N/A
N/A
*
N/A
N/A
NYISO
3/3
N/A
N/A
N/A
N/A
N/A
N/A
*
N/A
TVAO*
6.5 / 4.5
8.3 / 8.3
8/8
N/A
8.3 / 8.3
8.4 / 5.7
N/A
N/A
*
From
*TVAO = TVA Other
MISO
48
MTEP13 Economic Model Assumptions
Table 26. Commitment Hurdle Rates
To -->
PJM
MISO
TVA
MRO
SPP
SERC
MHEB
NYISO
TVAO*
PJM
*
3/3
10 / 10
N/A
N/A
10 / 10
N/A
10 / 10
10 / 10
MISO
10 / 10
*
10 / 10
10 / 10
10 / 10
10 / 10
0/0
N/A
10 / 10
TVA
30 / 30
30 / 30
*
N/A
-/-
30 / 30
N/A
N/A
30 / 30
MRO
N/A
10 / 10
N/A
*
10 / 10
N/A
10 / 10
N/A
N/A
SPP
N/A
10 / 10
10 / 10
10 / 10
*
N/A
N/A
N/A
10 / 10
SERC
10 / 10
10/10
10/10
N/A
N/A
*
N/A
N/A
10 / 10
MHEB
N/A
0/0
N/A
12 / 10
N/A
N/A
*
N/A
N/A
NYISO
10 / 10
N/A
N/A
N/A
N/A
N/A
N/A
*
N/A
TVAO*
10 / 10
10 / 10
10 / 10
N/A
10 / 10
10 / 10
N/A
N/A
*
From
*TVA-Other
5.5 Losses
There are three ways to treat losses in PROMOD:
Option 1: Load in PROMOD equals actual load plus the loss. Losses and LMP loss
component are not calculated by PROMOD.
Option 2: Load in PROMOD equals actual load plus the loss. Losses are not calculated
by PROMOD. LMP loss component is calculated by PROMOD in an
approximation method.
Option 3: Load in PROMOD equals actual load. PROMOD calculates losses and the
LMP loss component through dynamic iteration. This is sometimes called
“marginal loss” calculation method. This option will triple the run time and will
only be used in some special studies in which very accurate loss calculations
are required.
Option 2 is used in MTEP13 to provide enough detail without significantly increasing run times.
5.6 Generator Outage and Maintenance
As part of the security constrained unit commitment and economic dispatch process, PROMOD
creates an outage library of all units, typically for a period of one year. This process has two
steps:
1)
MISO
A random number generator determines whether or not a forced outage will occur for
each unit, based on that unit’s mean-time-to-failure (MTTF) function.
49
MTEP13 Economic Model Assumptions
2)
If the unit is selected for an outage, the length of the outage is calculated, using the
unit's mean-time-to-repair (MTTR) function.
Additionally, PROMOD automatically schedules maintenance to conform to the maintenance
cycle requirements of each unit, and to provide for the best overall system reliability. The
criterion for determining the best time to schedule maintenance is the minimization of risk in
terms of loss-of-load for any given week.
Generation outage and maintenance schedules have a significant influence on economic
analyses. Since the focus of the economics piece of the MTEP is to analyze the economic
benefits of new transmission, noise in benefit values due to variations in generation outage and
maintenance is undesirable. As such, the same generation outage library and maintenance
schedule is used for all study runs that are the same year and same future scenario.
5.7 Scheduled Transmission Outages
In the MTEP13 PROMOD cases, scheduled transmission outages were not considered. The
status of the transmission lines and transformers are the same as in the corresponding
powerflow case.
5.8 Operating Reserve Requirement
MISO’s operating reserve requirements include contingency reserves and regulating reserves.
Contingency reserves are comprised of spinning reserves and supplemental reserves. It is
assumed that supplemental reserves can be met by fast-response combustion turbine
generators, so only spinning reserve and regulating reserve requirements are considered for
each pool.
Table 27 shows the reserve requirements of each pool for 2028. In PROMOD, each pool is
modeled as a Balancing Authority and the reserve requirement is met at the pool level, not at
the company level. As shown in the table below, spinning reserve is typically 50% of operational
reserve and operational reserve is typically 3% of peak load.
MISO
50
MTEP13 Economic Model Assumptions
Table 27. Reserve Requirement by Region (2028)
Operational Reserve
Spinning Reserve
(% of Operational Reserve)
0MW
50
Region
MHEB
MISO
MRO
NYISO
PJM
1985MW (account for only spinning
reserve)
3% of peak load
1200MW
100
2789MW
3% of peak load
50
50
949.2MW(account for only spinning
reserve)
3% of peak load
100
3% of peak load
50
SERC
SPP
TVA
TVA-Other
50
50
50
5.9 Event File
Production cost models use an “event file” to capture a set of transmission constraints, to
ensure the system reliability is maintained by performing security constrained unit commitment
and economic dispatch. The file consists of monitored lines and contingencies, and is built from
the following sources:
-
MISO Book of Flowgates
NERC Book of Flowgates
MISO historical top congested flowgates data
MISO stakeholder updates
Flowgates recommended by other entities, such as other RTOs and ISOs
In support of planning coordination, MISO works with PJM to ensure that the appropriate
monitored lines and contingencies across the seams and in the PJM footprint are captured in
simulations.
A separate event file is developed for each powerflow used in simulations. Thus, for MTEP13,
there is a 2013 file, a 2018 file, and a 2023/2028 file. Certain flowgates may have operating
guides associated with them in real time operations which cannot be reflected in PROMOD.
Hence the “event file” is scrubbed to remove any flowgates that might have an operating guide
associated with them.
Monitored line ratings are based on those in the powerflow, unless stakeholders provide
different values and associated justification for these substitutions. For summer normal and
emergency ratings, the summer peak powerflow ratings of the corresponding years are used
(rate A for normal and rate B for emergency). Specifically, MISO event ratings come from MOD,
for which ratings are supplied and verified by transmission owners (TOs). PJM events use PJM
Regional Transmission Expansion Planning (RTEP) ratings. Events for regions outside of PJM
and MISO use ratings from the Eastern Interconnection Reliability Assessment Group (ERAG)
MISO
51
MTEP13 Economic Model Assumptions
powerflow cases. For winter normal and emergency ratings, MTEP13 2018 winter peak
powerflow values are used.
MISO
52
MTEP13 Economic Model Assumptions
Appendix A: Local Resource Zone
Data and Additional Regional Data
Figure 15. Local Resource Zones
MISO
53
MTEP13 Economic Model Assumptions
Table 28 shows the baseline annual demand and energy growth rates by Local Resource Zone
for each of the five Futures.
Zone
Zone 1
Table 28. Zonal Baseline Demand and Energy Growth Rates
BAU
RE
LG
GS
ENV
Demand Energy Demand Energy Demand Energy Demand Energy Demand Energy
1.32%
1.31%
1.83%
1.82%
0.73%
0.72%
0.73%
0.72%
1.32%
1.31%
Zone 2
0.86%
0.84%
1.41%
1.40%
0.28%
0.26%
0.28%
0.26%
0.86%
0.84%
Zone 3
1.21%
1.20%
1.73%
1.72%
0.61%
0.59%
0.61%
0.59%
1.21%
1.20%
Zone 4
2.37%
2.37%
2.79%
2.79%
1.88%
1.88%
1.88%
1.88%
2.37%
2.37%
Zone 5
0.82%
0.80%
1.37%
1.35%
0.16%
0.14%
0.16%
0.14%
0.82%
0.80%
Zone 6
0.75%
0.76%
1.31%
1.32%
0.26%
0.26%
0.26%
0.26%
0.75%
0.76%
Zone 7
0.44%
0.41%
1.03%
1.01%
0.05%
0.04%
0.05%
0.04%
0.44%
0.41%
Zone 8
0.83%
0.88%
1.29%
1.35%
0.37%
0.41%
0.37%
0.41%
0.83%
0.88%
Zone 9
0.90%
0.93%
1.36%
1.40%
0.45%
0.47%
0.45%
0.47%
0.90%
0.93%
Table 29 shows the effective annual demand and energy growth rates by Local Resource Zone
for each of the five Futures.
Zone
Zone 1
Table 29. Zonal Effective Demand and Energy Growth Rates
BAU
RE
LG
GS
ENV
Demand Energy Demand Energy Demand Energy Demand Energy Demand Energy
1.05%
1.08%
1.55%
1.59%
0.45%
0.48%
0.45%
0.49%
1.05%
1.08%
Zone 2
0.56%
0.60%
1.11%
1.15%
-0.02%
0.01%
-0.02%
0.01%
0.56%
0.60%
Zone 3
0.93%
0.97%
1.45%
1.49%
0.32%
0.36%
0.32%
0.36%
0.93%
0.97%
Zone 4
2.13%
2.17%
2.55%
2.59%
1.65%
1.68%
1.65%
1.69%
2.13%
2.17%
Zone 5
0.52%
0.55%
1.07%
1.11%
-0.15%
-0.12%
-0.15%
-0.12%
0.52%
0.55%
Zone 6
0.45%
0.51%
1.02%
1.07%
-0.04%
0.01%
-0.04%
0.01%
0.45%
0.50%
Zone 7
0.12%
0.15%
0.72%
0.75%
-0.26%
-0.22%
-0.26%
-0.22%
0.12%
0.15%
Zone 8
0.81%
0.87%
1.27%
1.34%
0.35%
0.40%
0.35%
0.40%
0.81%
0.87%
Zone 9
0.89%
0.92%
1.34%
1.39%
0.44%
0.46%
0.44%
0.46%
0.89%
0.92%
MISO
54
MTEP13 Economic Model Assumptions
Figures 16 gives the nameplate capacity additions to the economic study models resulting from
MTEP13 regional resource forecasting, for MISO Midwest from 2013 through 2028.
Figure 16. Nameplate Capacity Additions for MISO Midwest
MISO
55
MTEP13 Economic Model Assumptions
Figures 17 gives the approximate energy production by fuel type forecasted by future for MISO
Midwest in 2013 and 2028.
Figure 17. Energy Production by Fuel Type for MISO Midwest
MISO
56
MTEP13 Economic Model Assumptions
Figures 18 through 24 gives the nameplate capacity additions to the economic study models
resulting from MTEP13 regional resource forecasting, per region and Future, for the years of
2013 through 2028.
-100
100
100
-100
100
-100
100
100
100
100
-100
Retirements
100
100
Additions
100
Business As
Usual
Robust
Economy
Retirements
Additions
Retirements
Additions
Retirements
Additions
-3,400
Retirements
500
0
-500
-1,000
-1,500
-2,000
-2,500
-3,000
-3,500
-4,000
Additions
Nameplate Capacity Additions (MW)
MISO South: Nameplate Capacity Additions
(2013 through 2028)
Limited Growth Generation Shift Environmental
Renewable
Coal
Combined Cycle
Combustion Turbine
Nuclear
Demand Response
Energy Efficiency
Retirements
Figure 18. Nameplate Capacity Additions for MISO South
MISO
57
MTEP13 Economic Model Assumptions
Business As
Usual
0
-500
Additions
Retirements
Additions
-600
Retirements
0
-500
Additions
-500
Additions
-500
0
Retirements
0
Retirements
0
Retirements
0
-100
-200
-300
-400
-500
-600
-700
Additions
Nameplate Capacity Additions (MW)
MRO: Nameplate Capacity Additions (2013
through 2028)
Robust Economy Limited Growth Generation Shift Environmental
Renewable
Coal
Combined Cycle
Combustion Turbine
Nuclear
Demand Response
Energy Efficiency
Retirements
Figure 19. Nameplate Capacity Additions for MRO
MISO
58
MTEP13 Economic Model Assumptions
13,900
15,000 11,500
10,000
5,000
0
6,100
1,200
6,600
5,800
5,700
-1,700
11,100
10,800
11,800
6,000
5,700
6,100
5,100
5,100
5,700
-1,700
-1,700
-1,700
-4,300
-5,000
Business As
Usual
Robust
Economy
Limited Growth
Generation
Shift
Renewable
Coal
Combined Cycle
Combustion Turbine
Nuclear
Demand Response
Energy Efficiency
Retirements
Retirements
Additions
Retirements
Additions
Retirements
Additions
Retirements
Additions
Retirements
-10,000
Additions
Nameplate Capacity Additions (MW)
NYISO: Nameplate Capacity Additions (2013
through 2028)
Environmental
Figure 20. Nameplate Capacity Additions for New York
MISO
59
MTEP13 Economic Model Assumptions
Figure 21. Nameplate Capacity Additions for PJM
MISO
60
MTEP13 Economic Model Assumptions
Figure 22. Nameplate Capacity Additions for SERC
MISO
61
MTEP13 Economic Model Assumptions
Figure 23. Nameplate Capacity Additions for SPP
MISO
62
MTEP13 Economic Model Assumptions
13,200
15,000
10,000
5,000
0
6,000
6,000
3,600
2,400
7,200
6,000
3,600
-5,000
-5,000
0
-5,000
2,400
2,400
1,200
3,600
-5,000
-5,000
-8,600
Business As
Usual
Robust
Economy
Limited Growth
Generation
Shift
Renewable
Coal
Combined Cycle
Combustion Turbine
Nuclear
Demand Response
Energy Efficiency
Retirements
Retirements
Additions
Retirements
Additions
Retirements
Additions
Retirements
Additions
Retirements
-10,000
Additions
Nameplate Capacity Additions (MW)
TVA: Nameplate Capacity Additions (2013
through 2028)
Environmental
Figure 24. Nameplate Capacity Additions for TVA
Tables 30 through 69 below give the peak demand and annual energy levels for years 20132028 on a local resource zonal and regional level.
MISO
63
MTEP13 Economic Model Assumptions
Region
Table 30. Forecasted BAU Zonal Annual Peak Load (MW) for 2013-2020
2013
2014
2015
2016
2018
2018
2019
2020
Zone 1
17,230
17,408
17,573
17,730
17,881
18,032
18,189
18,361
Zone 2
12,914
12,989
13,051
13,106
13,156
13,204
13,254
13,315
Zone 3
8,920
9,003
9,079
9,150
9,218
9,286
9,355
9,433
Zone 4
11,148
11,367
11,583
11,797
12,012
12,232
12,459
12,700
Zone 5
8,869
8,916
8,955
8,989
9,018
9,047
9,078
9,115
Zone 6
17,831
17,914
17,981
18,036
18,084
18,130
18,179
18,241
Zone 7
21,443
21,479
21,496
21,498
21,491
21,480
21,472
21,479
Zone 8
6,261
6,312
6,363
6,415
6,466
6,518
6,571
6,624
Zone 9
23,650
23,865
24,082
24,299
24,518
24,739
24,962
25,188
Region
Table 31. Forecasted BAU Zonal Annual Peak Load (MW) for 2021-2028
2021
2022
2023
2024
2025
2026
2027
2028
Zone 1
18,546
18,744
18,954
19,175
19,407
19,649
19,899
20,157
Zone 2
13,383
13,459
13,543
13,633
13,730
13,832
13,938
14,049
Zone 3
9,517
9,607
9,702
9,804
9,910
10,020
10,135
10,253
Zone 4
12,954
13,221
13,500
13,791
14,094
14,409
14,734
15,070
Zone 5
9,157
9,205
9,258
9,316
9,377
9,443
9,511
9,582
Zone 6
18,315
18,399
18,493
18,597
18,709
18,829
18,954
19,085
Zone 7
21,499
21,530
21,573
21,626
21,688
21,758
21,834
21,916
Zone 8
6,678
6,732
6,787
6,843
6,899
6,955
7,013
7,070
Zone 9
25,417
25,649
25,883
26,121
26,361
26,604
26,850
27,098
Region
Table 32. Forecasted RE Zonal Annual Peak Load (MW) for 2013-2020
2013
2014
2015
2016
2018
2018
2019
2020
Zone 1
17,228
17,492
17,744
17,990
18,232
18,476
18,728
18,999
Zone 2
12,913
13,057
13,190
13,316
13,438
13,560
13,684
13,821
Zone 3
8,919
9,047
9,169
9,286
9,402
9,518
9,638
9,767
Zone 4
11,147
11,410
11,670
11,930
12,194
12,464
12,744
13,042
Zone 5
8,868
8,963
9,051
9,134
9,214
9,293
9,375
9,465
Zone 6
17,830
18,011
18,177
18,332
18,481
18,630
18,783
18,952
Zone 7
21,441
21,602
21,744
21,872
21,991
22,107
22,227
22,366
Zone 8
6,261
6,341
6,421
6,503
6,585
6,668
6,753
6,838
Zone 9
23,650
23,972
24,298
24,627
24,961
25,298
25,641
25,988
MISO
64
MTEP13 Economic Model Assumptions
Region
Table 33. Forecasted RE Zonal Annual Peak Load (MW) for 2021-2028
2021
2022
2023
2024
2025
2026
2027
2028
Zone 1
19,287
19,591
19,910
20,245
20,595
20,958
21,334
21,721
Zone 2
13,969
14,126
14,292
14,468
14,653
14,844
15,043
15,248
Zone 3
9,905
10,050
10,202
10,362
10,529
10,703
10,882
11,066
Zone 4
13,355
13,683
14,028
14,388
14,764
15,155
15,560
15,980
Zone 5
9,562
9,665
9,775
9,891
10,013
10,140
10,272
10,407
Zone 6
19,135
19,331
19,540
19,762
19,995
20,238
20,489
20,749
Zone 7
22,520
22,687
22,868
23,063
23,270
23,486
23,712
23,946
Zone 8
6,925
7,013
7,102
7,193
7,285
7,378
7,473
7,569
Zone 9
26,341
26,700
27,064
27,435
27,811
28,192
28,580
28,973
Region
Table 34. Forecasted LG Zonal Annual Peak Load (MW) for 2013-2020
2013
2014
2015
2016
2018
2018
2019
2020
Zone 1
17,235
17,316
17,384
17,442
17,493
17,542
17,593
17,655
Zone 2
12,918
12,922
12,915
12,899
12,877
12,853
12,829
12,813
Zone 3
8,922
8,954
8,979
8,999
9,014
9,028
9,042
9,063
Zone 4
11,151
11,323
11,490
11,653
11,816
11,981
12,150
12,329
Zone 5
9,330
9,322
9,305
9,282
9,255
9,226
9,197
9,173
Zone 6
17,837
17,838
17,824
17,799
17,765
17,728
17,692
17,666
Zone 7
21,449
21,409
21,350
21,277
21,194
21,106
21,019
20,944
Zone 8
6,261
6,283
6,305
6,328
6,350
6,372
6,394
6,416
Zone 9
23,650
23,759
23,867
23,976
24,084
24,193
24,302
24,412
Region
Table 35. Forecasted LG Zonal Annual Peak Load (MW) for 2021-2028
2021
2022
2023
2024
2025
2026
2027
2028
Zone 1
17,726
17,807
17,896
17,994
18,100
18,212
18,330
18,453
Zone 2
12,803
12,799
12,801
12,808
12,820
12,836
12,856
12,878
Zone 3
9,087
9,116
9,149
9,186
9,227
9,271
9,317
9,366
Zone 4
12,518
12,716
12,923
13,139
13,364
13,596
13,836
14,084
Zone 5
9,155
9,140
9,129
9,123
9,120
9,120
9,122
9,126
Zone 6
17,649
17,639
17,638
17,645
17,658
17,676
17,700
17,727
Zone 7
20,880
20,825
20,779
20,743
20,714
20,692
20,674
20,662
Zone 8
6,439
6,461
6,484
6,508
6,531
6,555
6,578
6,602
Zone 9
24,524
24,637
24,751
24,866
24,982
25,100
25,218
25,338
MISO
65
MTEP13 Economic Model Assumptions
Region
Table 36. Forecasted GS Zonal Annual Peak Load (MW) for 2013-2020
2013
2014
2015
2016
2018
2018
2019
2020
Zone 1
17,232
17,311
17,376
17,431
17,480
17,527
17,576
17,638
Zone 2
12,916
12,918
12,909
12,891
12,867
12,842
12,817
12,801
Zone 3
8,921
8,952
8,975
8,993
9,007
9,020
9,034
9,054
Zone 4
11,150
11,320
11,485
11,647
11,808
11,971
12,140
12,319
Zone 5
9,329
9,319
9,300
9,276
9,247
9,217
9,188
9,165
Zone 6
17,834
17,833
17,816
17,788
17,751
17,712
17,675
17,649
Zone 7
21,446
21,402
21,340
21,263
21,177
21,087
20,999
20,924
Zone 8
6,261
6,283
6,305
6,327
6,349
6,371
6,394
6,416
Zone 9
23,650
23,759
23,867
23,975
24,083
24,192
24,301
24,411
Region
Table 37. Forecasted GS Zonal Annual Peak Load (MW) for 2021-2028
2021
2022
2023
2024
2025
2026
2027
2028
Zone 1
17,711
17,792
17,883
17,983
18,090
18,205
18,324
18,449
Zone 2
12,792
12,789
12,791
12,800
12,813
12,831
12,852
12,875
Zone 3
9,079
9,109
9,143
9,181
9,222
9,267
9,314
9,364
Zone 4
12,509
12,707
12,915
13,132
13,358
13,592
13,833
14,081
Zone 5
9,146
9,132
9,123
9,117
9,115
9,116
9,119
9,124
Zone 6
17,633
17,625
17,625
17,633
17,648
17,669
17,694
17,723
Zone 7
20,861
20,807
20,764
20,729
20,703
20,682
20,667
20,656
Zone 8
6,438
6,461
6,484
6,507
6,531
6,554
6,578
6,602
Zone 9
24,523
24,636
24,750
24,865
24,982
25,099
25,218
25,337
Region
Table 38. Forecasted ENV Zonal Annual Peak Load (MW) for 2013-2020
2013
2014
2015
2016
2018
2018
2019
2020
Zone 1
17,234
17,418
17,589
17,751
17,907
18,061
18,219
18,391
Zone 2
12,918
12,996
13,063
13,122
13,175
13,226
13,277
13,337
Zone 3
8,922
9,008
9,087
9,161
9,231
9,301
9,371
9,449
Zone 4
11,151
11,373
11,592
11,810
12,028
12,249
12,477
12,719
Zone 5
8,871
8,921
8,963
8,999
9,032
9,062
9,093
9,130
Zone 6
17,836
17,924
17,997
18,058
18,111
18,160
18,210
18,273
Zone 7
21,448
21,491
21,515
21,525
21,523
21,516
21,510
21,517
Zone 8
6,261
6,312
6,363
6,415
6,467
6,519
6,571
6,625
Zone 9
23,650
23,866
24,082
24,300
24,520
24,741
24,964
25,190
MISO
66
MTEP13 Economic Model Assumptions
Region
Table 39. Forecasted ENV Zonal Annual Peak Load (MW) for 2021-2028
2021
2022
2023
2024
2025
2026
2027
2028
Zone 1
18,575
18,770
18,976
19,194
19,423
19,661
19,908
20,163
Zone 2
13,405
13,479
13,560
13,648
13,742
13,841
13,945
14,053
Zone 3
9,532
9,620
9,714
9,813
9,918
10,027
10,139
10,256
Zone 4
12,972
13,237
13,514
13,803
14,104
14,416
14,739
15,073
Zone 5
9,172
9,219
9,270
9,326
9,386
9,449
9,516
9,585
Zone 6
18,345
18,426
18,517
18,617
18,725
18,841
18,963
19,090
Zone 7
21,535
21,563
21,601
21,650
21,708
21,773
21,845
21,923
Zone 8
6,678
6,733
6,787
6,843
6,899
6,956
7,013
7,071
Zone 9
25,419
25,651
25,885
26,122
26,362
26,605
26,850
27,098
Table 40. Forecasted BAU Regional Annual Peak Load (MW) for 2013-2020
Region
2013
2014
2015
2016
2018
2018
2019
2020
MHEB
MISO
Midwest
MISO South
4,646
4,713
4,782
4,851
4,922
4,993
5,066
5,139
98,354
99,076
99,718
100,306
100,861
101,411
101,986
102,643
29,910
30,177
30,445
30,714
30,985
31,258
31,533
31,812
MRO
7,844
7,942
8,041
8,140
8,241
8,343
8,446
8,551
NYISO
34,084
33,970
33,810
33,619
33,408
33,185
32,966
32,806
PJM
164,829
166,165
167,167
167,870
168,373
168,845
169,443
170,309
SERC
92,720
93,995
95,286
96,596
97,926
99,275
100,646
102,040
SPP
48,825
49,078
49,297
49,489
49,663
49,832
50,006
50,205
TVA
42,936
43,520
44,112
44,713
45,321
45,939
46,565
47,200
Table 41. Forecasted BAU Regional Annual Peak Load (MW) for 2021-2028
Region
2021
2022
2023
2024
2025
2026
2027
2028
MHEB
MISO
Midwest
MISO South
5,214
5,290
5,367
5,445
5,524
5,604
5,685
5,768
103,372
104,165
105,022
105,942
106,917
107,940
109,006
110,111
32,095
32,381
32,670
32,963
33,260
33,559
33,862
34,168
MRO
8,659
8,768
8,880
8,995
9,111
9,230
9,350
9,473
NYISO
32,694
32,624
32,602
32,630
32,701
32,806
32,942
33,104
PJM
171,404
172,706
174,215
175,931
177,823
179,868
182,046
184,340
SERC
103,457
104,899
106,365
107,855
109,370
110,910
112,475
114,066
SPP
50,425
50,665
50,924
51,204
51,501
51,812
52,136
52,471
TVA
47,844
48,497
49,159
49,831
50,512
51,202
51,903
52,613
MISO
67
MTEP13 Economic Model Assumptions
Table 42. Forecasted RE Regional Annual Peak Load (MW) for 2013-2020
Region
2013
2014
2015
2016
2018
2018
2019
2020
MHEB
MISO
Midwest
MISO South
4,646
4,747
4,851
4,956
5,064
5,175
5,287
5,403
98,346
99,582
100,745
101,861
102,952
104,048
105,180
106,412
29,911
30,313
30,719
31,130
31,546
31,967
32,393
32,826
MRO
7,844
7,994
8,146
8,300
8,457
8,616
8,779
8,946
NYISO
34,095
34,126
34,103
34,041
33,951
33,843
33,738
33,701
PJM
164,856
167,333
169,494
171,360
173,020
174,643
176,399
178,449
SERC
92,720
94,651
96,621
98,632
100,685
102,782
104,925
107,117
SPP
48,829
49,256
49,651
50,020
50,371
50,716
51,066
51,441
TVA
42,936
43,812
44,707
45,621
46,553
47,506
48,478
49,471
Table 43. Forecasted RE Regional Annual Peak Load (MW) for 2021-2028
Region
2021
2022
2023
2024
2025
2026
2027
2028
MHEB
MISO
Midwest
MISO South
5,520
5,641
5,763
5,889
6,017
6,148
6,282
6,419
107,732
109,133
110,616
112,181
113,819
115,524
117,291
119,117
33,266
33,713
34,167
34,628
35,096
35,571
36,053
36,542
MRO
9,117
9,291
9,470
9,654
9,842
10,034
10,230
10,431
NYISO
33,724
33,799
33,923
34,097
34,315
34,570
34,857
35,174
PJM
180,762
183,321
186,136
189,233
192,578
196,145
199,912
203,861
SERC
109,359
111,651
113,995
116,392
118,843
121,350
123,912
126,532
SPP
51,838
52,257
52,698
53,165
53,653
54,161
54,686
55,227
TVA
50,484
51,519
52,576
53,655
54,756
55,881
57,030
58,202
Table 44. Forecasted LG Regional Annual Peak Load (MW) for 2013-2020
Region
2013
2014
2015
2016
2018
2018
2019
2020
MHEB
MISO
Midwest
MISO South
4,646
4,680
4,714
4,748
4,782
4,817
4,852
4,887
98,842
99,084
99,247
99,351
99,415
99,463
99,521
99,643
29,911
30,042
30,173
30,303
30,434
30,565
30,696
30,829
MRO
7,844
7,892
7,939
7,986
8,033
8,081
8,128
8,177
NYISO
34,076
33,811
33,491
33,134
32,749
32,349
31,952
31,624
PJM
164,912
165,251
165,274
165,007
164,530
163,992
163,530
163,273
SERC
92,720
93,345
93,973
94,606
95,243
95,887
96,537
97,195
SPP
48,831
48,925
48,987
49,022
49,037
49,045
49,054
49,084
TVA
42,936
43,227
43,521
43,817
44,114
44,414
44,717
45,021
MISO
68
MTEP13 Economic Model Assumptions
Table 45. Forecasted LG Regional Annual Peak Load (MW) for 2021-2028
Region
2021
2022
2023
2024
2025
2026
2027
2028
MHEB
MISO
Midwest
MISO South
4,923
4,959
4,995
5,031
5,067
5,104
5,141
5,179
99,819
100,043
100,315
100,638
101,002
101,403
101,836
102,295
30,963
31,098
31,235
31,374
31,513
31,654
31,797
31,940
MRO
8,227
8,277
8,329
8,381
8,435
8,490
8,545
8,601
NYISO
31,352
31,127
30,949
30,811
30,707
30,632
30,583
30,554
PJM
163,189
163,261
163,493
163,892
164,429
165,084
165,839
166,678
SERC
97,861
98,534
99,216
99,906
100,604
101,310
102,024
102,746
SPP
49,130
49,192
49,269
49,364
49,473
49,594
49,726
49,867
TVA
45,328
45,637
45,948
46,261
46,577
46,895
47,215
47,538
Table 46. Forecasted GS Regional Annual Peak Load (MW) for 2013-2020
Region
2013
2014
2015
2016
2018
2018
2019
2020
MHEB
MISO
Midwest
MISO South
4,646
4,680
4,714
4,748
4,782
4,817
4,852
4,887
98,828
99,055
99,201
99,288
99,338
99,376
99,428
99,550
29,910
30,042
30,172
30,303
30,433
30,563
30,695
30,827
MRO
7,844
7,892
7,939
7,986
8,033
8,080
8,127
8,176
NYISO
34,086
33,837
33,540
33,211
32,859
32,494
32,131
31,824
PJM
164,877
165,168
165,134
164,808
164,278
163,700
163,216
162,957
SERC
92,720
93,344
93,972
94,604
95,242
95,885
96,534
97,192
SPP
48,828
48,918
48,973
49,002
49,013
49,016
49,023
49,052
TVA
42,936
43,227
43,521
43,817
44,114
44,414
44,717
45,021
Table 47. Forecasted GS Regional Annual Peak Load (MW) for 2021-2028
Region
2021
2022
2023
2024
2025
2026
2027
2028
MHEB
MISO
Midwest
MISO South
4,923
4,959
4,995
5,031
5,067
5,104
5,141
5,179
99,730
99,961
100,243
100,576
100,950
101,361
101,803
102,272
30,962
31,097
31,234
31,373
31,513
31,654
31,796
31,940
MRO
8,226
8,277
8,328
8,381
8,435
8,489
8,545
8,601
NYISO
31,563
31,342
31,167
31,039
30,950
30,895
30,868
30,864
PJM
162,885
162,981
163,245
163,675
164,245
164,930
165,713
166,579
SERC
97,858
98,532
99,214
99,904
100,603
101,309
102,023
102,746
SPP
49,099
49,163
49,244
49,342
49,454
49,579
49,713
49,857
TVA
45,328
45,637
45,948
46,261
46,577
46,895
47,215
47,538
MISO
69
MTEP13 Economic Model Assumptions
Table 48. Forecasted ENV Regional Annual Peak Load (MW) for 2013-2020
Region
2013
2014
2015
2016
2018
2018
2019
2020
MHEB
MISO
Midwest
MISO South
4,646
4,713
4,782
4,851
4,922
4,993
5,066
5,139
98,380
99,131
99,806
100,425
101,006
101,576
102,159
102,815
29,911
30,178
30,446
30,715
30,987
31,260
31,536
31,815
MRO
7,844
7,943
8,042
8,141
8,242
8,344
8,447
8,553
NYISO
34,094
33,983
33,819
33,614
33,381
33,130
32,879
32,695
PJM
164,898
166,327
167,439
168,255
168,858
169,401
170,035
170,901
SERC
92,720
93,996
95,288
96,599
97,929
99,279
100,650
102,044
SPP
48,831
49,093
49,322
49,525
49,709
49,885
50,063
50,262
TVA
42,936
43,520
44,112
44,713
45,321
45,939
46,565
47,200
Table 49. Forecasted ENV Regional Annual Peak Load (MW) for 2021-2028
Region
2021
2022
2023
2024
2025
2026
2027
2028
MHEB
MISO
Midwest
MISO South
5,214
5,290
5,367
5,445
5,524
5,604
5,685
5,768
103,535
104,313
105,151
106,051
107,005
108,009
109,056
110,142
32,097
32,383
32,672
32,965
33,261
33,560
33,863
34,169
MRO
8,660
8,770
8,882
8,996
9,112
9,230
9,351
9,474
NYISO
32,566
32,485
32,450
32,456
32,498
32,572
32,672
32,795
PJM
171,968
173,220
174,667
176,317
178,145
180,127
182,245
184,484
SERC
103,462
104,903
106,368
107,858
109,372
110,912
112,477
114,067
SPP
50,481
50,715
50,969
51,242
51,532
51,837
52,156
52,486
TVA
47,844
48,497
49,159
49,831
50,512
51,202
51,903
52,613
Region
Table 50. Forecasted Zonal Annual Energy (GWh) for BAU 2013-2020
2013
2014
2015
2016
2018
2018
2019
2020
Zone 1
94,866
95,888
96,853
97,781
98,689
99,600
100,534
101,539
Zone 2
62,983
63,369
63,710
64,019
64,307
64,589
64,879
65,208
Zone 3
45,924
46,371
46,789
47,187
47,573
47,958
48,352
48,779
Zone 4
54,998
56,142
57,274
58,407
59,550
60,716
61,919
63,185
Zone 5
45,304
45,560
45,784
45,984
46,169
46,349
46,535
46,748
Zone 6
94,983
95,473
95,896
96,269
96,611
96,944
97,288
97,691
Zone 7
100,804
101,001
101,121
101,186
101,212
101,224
101,244
101,322
Zone 8
34,089
34,387
34,685
34,985
35,287
35,591
35,898
36,208
Zone 9
122,535
123,683
124,837
125,998
127,169
128,350
129,541
130,748
MISO
70
MTEP13 Economic Model Assumptions
Region
Table 51. Forecasted Zonal Annual Energy (GWh) for BAU 2021-2028
2021
2022
2023
2024
2025
2026
2027
2028
Zone 1
102,606
103,729
104,911
106,152
107,446
108,788
110,172
111,596
Zone 2
65,570
65,962
66,383
66,836
67,315
67,816
68,337
68,875
Zone 3
49,232
49,711
50,215
50,746
51,300
51,874
52,466
53,075
Zone 4
64,510
65,892
67,332
68,832
70,389
72,001
73,665
75,381
Zone 5
46,985
47,242
47,521
47,822
48,141
48,476
48,825
49,185
Zone 6
98,143
98,639
99,180
99,767
100,394
101,054
101,744
102,459
Zone 7
101,447
101,613
101,823
102,078
102,369
102,691
103,039
103,409
Zone 8
36,522
36,839
37,159
37,483
37,811
38,142
38,476
38,814
Zone 9
131,969
133,204
134,454
135,719
136,999
138,293
139,601
140,924
Region
Table 52. Forecasted Zonal Annual Energy (GWh) for RE 2013-2020
2013
2014
2015
2016
2018
2018
2019
2020
Zone 1
94,860
96,356
97,805
99,227
100,641
102,070
103,537
105,093
Zone 2
62,979
63,707
64,393
65,053
65,697
66,342
67,001
67,708
Zone 3
45,921
46,602
47,257
47,897
48,531
49,170
49,824
50,519
Zone 4
54,994
56,360
57,722
59,094
60,486
61,913
63,388
64,942
Zone 5
45,301
45,805
46,279
46,734
47,176
47,618
48,071
48,557
Zone 6
94,977
95,993
96,946
97,857
98,743
99,628
100,533
101,511
Zone 7
100,798
101,585
102,299
102,961
103,589
104,207
104,840
105,542
Zone 8
34,089
34,548
35,010
35,478
35,952
36,431
36,916
37,409
Zone 9
122,535
124,255
125,994
127,754
129,536
131,342
133,173
135,033
Region
Table 53. Forecasted Zonal Annual Energy (GWh) for RE 2021-2028
2021
2022
2023
2024
2025
2026
2027
2028
Zone 1
106,729
108,440
110,230
112,100
114,045
116,058
118,136
120,275
Zone 2
68,458
69,247
70,076
70,947
71,855
72,796
73,768
74,767
Zone 3
51,250
52,015
52,814
53,650
54,519
55,417
56,343
57,296
Zone 4
66,570
68,270
70,046
71,899
73,827
75,828
77,902
80,046
Zone 5
49,073
49,617
50,189
50,791
51,419
52,070
52,742
53,433
Zone 6
102,551
103,648
104,805
106,023
107,295
108,617
109,982
111,387
Zone 7
106,302
107,114
107,981
108,905
109,877
110,893
111,946
113,033
Zone 8
37,909
38,417
38,932
39,455
39,986
40,524
41,070
41,624
Zone 9
136,922
138,840
140,788
142,768
144,778
146,820
148,892
150,996
MISO
71
MTEP13 Economic Model Assumptions
Region
Table 54. Forecasted Zonal Annual Energy (GWh) for LG 2013-2020
2013
2014
2015
2016
2018
2018
2019
2020
Zone 1
94,888
95,368
95,786
96,160
96,503
96,834
97,174
97,564
Zone 2
62,998
63,035
63,028
62,987
62,922
62,844
62,768
62,721
Zone 3
45,935
46,115
46,264
46,389
46,498
46,599
46,703
46,829
Zone 4
55,010
55,908
56,787
57,657
58,526
59,405
60,306
61,252
Zone 5
45,314
45,283
45,220
45,132
45,027
44,913
44,799
44,707
Zone 6
95,005
95,056
95,040
94,973
94,869
94,748
94,628
94,553
Zone 7
100,827
100,671
100,443
100,159
99,835
99,492
99,149
98,852
Zone 8
34,089
34,226
34,362
34,498
34,633
34,769
34,905
35,042
Zone 9
122,535
123,114
123,690
124,266
124,843
125,422
126,003
126,590
Region
Table 55. Forecasted Zonal Annual Energy (GWh) for LG 2021-2028
2021
2022
2023
2024
2025
2026
2027
2028
Zone 1
97,996
98,468
98,981
99,538
100,132
100,759
101,414
102,094
Zone 2
62,699
62,697
62,719
62,765
62,832
62,916
63,013
63,123
Zone 3
46,974
47,135
47,315
47,515
47,730
47,959
48,200
48,451
Zone 4
62,241
63,270
64,341
65,456
66,611
67,805
69,035
70,300
Zone 5
44,631
44,571
44,528
44,502
44,491
44,491
44,502
44,521
Zone 6
94,515
94,509
94,538
94,605
94,703
94,826
94,971
95,134
Zone 7
98,593
98,367
98,177
98,026
97,906
97,813
97,741
97,687
Zone 8
35,180
35,319
35,460
35,601
35,744
35,888
36,033
36,179
Zone 9
127,183
127,781
128,384
128,993
129,608
130,229
130,854
131,484
Region
Table 56. Forecasted Zonal Annual Energy (GWh) for GS 2013-2020
2013
2014
2015
2016
2018
2018
2019
2020
Zone 1
94,878
95,346
95,752
96,113
96,446
96,770
97,106
97,498
Zone 2
62,991
63,021
63,005
62,956
62,884
62,802
62,724
62,678
Zone 3
45,930
46,104
46,247
46,366
46,470
46,568
46,670
46,797
Zone 4
55,004
55,896
56,768
57,630
58,493
59,369
60,268
61,215
Zone 5
45,310
45,273
45,203
45,110
44,999
44,882
44,767
44,675
Zone 6
94,995
95,034
95,005
94,926
94,812
94,683
94,561
94,487
Zone 7
100,817
100,648
100,406
100,109
99,774
99,423
99,077
98,782
Zone 8
34,089
34,226
34,362
34,497
34,633
34,768
34,904
35,041
Zone 9
122,535
123,113
123,688
124,264
124,840
125,419
125,999
126,587
MISO
72
MTEP13 Economic Model Assumptions
Region
Table 57. Forecasted Zonal Annual Energy (GWh) for GS 2021-2028
2021
2022
2023
2024
2025
2026
2027
2028
Zone 1
97,935
98,415
98,937
99,503
100,107
100,742
101,406
102,094
Zone 2
62,658
62,662
62,690
62,742
62,815
62,905
63,008
63,123
Zone 3
46,944
47,110
47,294
47,498
47,718
47,951
48,196
48,451
Zone 4
62,207
63,240
64,316
65,436
66,597
67,796
69,030
70,300
Zone 5
44,602
44,546
44,507
44,485
44,478
44,483
44,498
44,521
Zone 6
94,454
94,456
94,494
94,570
94,677
94,809
94,963
95,134
Zone 7
98,528
98,310
98,130
97,989
97,879
97,795
97,732
97,687
Zone 8
35,179
35,318
35,459
35,601
35,744
35,888
36,033
36,179
Zone 9
127,179
127,777
128,381
128,991
129,607
130,228
130,853
131,484
Region
Table 58. Forecasted Zonal Annual Energy (GWh) for ENV 2013-2020
2013
2014
2015
2016
2018
2018
2019
2020
Zone 1
94,886
95,931
96,921
97,874
98,801
99,725
100,665
101,667
Zone 2
62,997
63,397
63,755
64,080
64,381
64,672
64,966
65,293
Zone 3
45,934
46,392
46,822
47,232
47,627
48,018
48,415
48,840
Zone 4
55,009
56,166
57,313
58,459
59,613
60,787
61,993
63,257
Zone 5
45,314
45,581
45,816
46,028
46,222
46,409
46,597
46,809
Zone 6
95,003
95,517
95,964
96,362
96,724
97,069
97,419
97,819
Zone 7
100,826
101,047
101,194
101,284
101,331
101,357
101,383
101,457
Zone 8
34,090
34,387
34,686
34,986
35,289
35,593
35,900
36,210
Zone 9
122,535
123,685
124,840
126,003
127,175
128,356
129,549
130,755
Region
Table 59. Forecasted Zonal Annual Energy (GWh) for ENV 2021-2028
2021
2022
2023
2024
2025
2026
2027
2028
Zone 1
102,724
103,833
104,997
106,220
107,496
108,820
110,188
111,596
Zone 2
65,649
66,030
66,440
66,881
67,348
67,838
68,347
68,875
Zone 3
49,290
49,761
50,257
50,779
51,324
51,890
52,474
53,075
Zone 4
64,577
65,950
67,381
68,871
70,418
72,019
73,674
75,381
Zone 5
47,041
47,292
47,562
47,854
48,165
48,492
48,832
49,185
Zone 6
98,262
98,743
99,266
99,836
100,444
101,087
101,760
102,459
Zone 7
101,572
101,723
101,915
102,150
102,422
102,726
103,056
103,409
Zone 8
36,524
36,840
37,161
37,484
37,812
38,142
38,476
38,814
Zone 9
131,976
133,210
134,459
135,723
137,001
138,295
139,602
140,924
MISO
73
MTEP13 Economic Model Assumptions
Table 60. Forecasted Regional Annual Energy (GWh) for BAU 2013-2020
Region
2013
2014
2015
2016
2018
2018
2019
2020
MHEB
MISO
Midwest
MISO South
24,981
25,366
25,756
26,153
26,556
26,965
27,380
27,802
499,864
503,805
507,427
510,833
514,112
517,380
520,752
524,472
156,624
158,070
159,522
160,983
162,456
163,941
165,439
166,956
MRO
48,170
48,944
49,727
50,522
51,330
52,152
52,989
53,844
NYISO
163,131
162,459
161,582
160,572
159,468
158,307
157,151
156,225
PJM
838,198
846,709
853,879
859,859
865,053
870,147
875,782
882,539
SERC
465,472
472,244
479,112
486,084
493,162
500,354
507,663
515,099
SPP
231,579
232,877
234,029
235,071
236,037
236,979
237,941
239,004
TVA
220,962
223,227
225,517
227,830
230,167
232,528
234,914
237,325
Table 61. Forecasted Regional Annual Energy (GWh) for BAU 2021-2028
Region
2021
2022
2023
2024
2025
2026
2027
2028
MHEB
MISO
Midwest
MISO South
28,230
28,665
29,107
29,555
30,010
30,473
30,942
31,419
528,493
532,788
537,366
542,233
547,354
552,700
558,248
563,980
168,490
170,043
171,613
173,202
174,810
176,435
178,078
179,738
MRO
54,717
55,608
56,519
57,449
58,399
59,368
60,357
61,366
NYISO
155,488
154,918
154,552
154,409
154,453
154,653
154,986
155,430
PJM
890,262
898,882
908,444
918,985
930,373
942,501
955,282
968,646
SERC
522,664
530,358
538,184
546,146
554,244
562,479
570,854
579,369
SPP
240,153
241,382
242,697
244,103
245,588
247,140
248,751
250,414
TVA
239,761
242,222
244,708
247,221
249,760
252,325
254,917
257,535
Region
Table 62. Forecasted Regional Annual Energy (GWh) for RE 2013-2020
2013
2014
2015
2016
2018
2018
2019
2020
MHEB
MISO
Midwest
MISO South
24,981
25,558
26,149
26,753
27,371
28,003
28,650
29,312
499,832
506,407
512,701
518,823
524,864
530,947
537,194
543,871
156,625
158,802
161,004
163,232
165,488
167,773
170,089
172,442
MRO
48,170
49,348
50,551
51,781
53,042
54,333
55,656
57,016
NYISO
163,239
163,159
162,853
162,380
161,784
161,107
160,430
160,028
PJM
838,309
853,087
866,668
879,142
890,871
902,549
914,863
928,478
SERC
465,473
475,720
486,188
496,887
507,823
519,006
530,445
542,155
SPP
231,596
233,741
235,754
237,663
239,498
241,307
243,133
245,066
TVA
220,962
224,362
227,815
231,322
234,883
238,499
242,170
245,899
MISO
74
MTEP13 Economic Model Assumptions
Region
Table 63. Forecasted Regional Annual Energy (GWh) for RE 2021-2028
2021
2022
2023
2024
2025
2026
2027
MHEB
MISO
Midwest
MISO South
32,117
32,859
33,618
34,395
35,189
550,932 558,350 566,141 574,315
582,837
591,679
600,819
610,238
174,831 177,257 179,720 182,223
184,764
187,344
189,962
192,620
62,842
64,401
66,003
67,648
69,338
NYISO
159,859 159,891 160,120 160,550
161,152
161,900
162,777
163,764
PJM
943,267 959,189 976,338 994,877 1,014,659 1,035,570 1,057,516 1,080,425
SERC
554,140 566,407 578,963 591,816
604,973
618,438
632,218
646,321
SPP
247,093 249,208 251,423 253,755
256,189
258,715
261,321
264,000
TVA
249,685 253,530 257,434 261,399
265,425
269,513
273,665
277,881
MRO
Region
29,990
58,414
30,682
59,849
31,391
2028
61,325
Table 64. Forecasted Regional Annual Energy (GWh) for LG 2013-2020
2013
2014
2015
2016
2018
2018
2019
2020
MHEB
MISO
Midwest
MISO South
24,981
25,173
25,367
25,563
25,759
25,958
26,158
26,359
499,978
501,437
502,568
503,458
504,179
504,835
505,526
506,478
156,625
157,340
158,052
158,764
159,477
160,191
160,908
161,632
MRO
48,171
48,547
48,924
49,303
49,686
50,071
50,461
50,857
NYISO
163,157
162,003
160,623
159,085
157,434
155,717
154,013
152,583
PJM
838,538
841,360
842,876
843,193
842,643
841,822
841,298
841,595
SERC
465,475
468,787
472,123
475,484
478,873
482,294
485,749
489,245
SPP
231,603
232,117
232,489
232,749
232,926
233,065
233,207
233,429
TVA
220,962
222,093
223,230
224,373
225,522
226,678
227,840
229,008
MISO
75
MTEP13 Economic Model Assumptions
Region
Table 65. Forecasted Regional Annual Energy (GWh) for LG 2021-2028
2021
2022
2023
2024
2025
2026
2027
2028
MHEB
MISO
Midwest
MISO South
26,562
26,767
26,973
27,181
27,390
27,601
27,814
28,028
507,649
509,018
510,600
512,406
514,405
516,568
518,876
521,310
162,363
163,100
163,844
164,595
165,352
166,117
166,887
167,663
MRO
51,260
51,670
52,087
52,511
52,943
53,381
53,827
54,278
NYISO
151,383
150,376
149,557
148,905
148,395
148,004
147,717
147,516
PJM
842,585
844,213
846,544
849,638
853,376
857,660
862,410
867,559
SERC
492,782
496,361
499,981
503,645
507,351
511,099
514,890
518,723
SPP
233,716
234,063
234,480
234,974
235,535
236,151
236,814
237,517
TVA
230,183
231,364
232,551
233,745
234,946
236,153
237,366
238,587
Region
Table 66. Forecasted Regional Annual Energy (GWh) for GS 2013-2020
2013
2014
2015
2016
2018
2018
2019
2020
MHEB
MISO
Midwest
MISO South
24,981
25,173
25,367
25,563
25,759
25,958
26,158
26,359
499,924
501,322
502,385
503,210
503,878
504,497
505,173
506,131
156,624
157,339
158,050
158,761
159,473
160,187
160,903
161,627
MRO
48,170
48,546
48,923
49,301
49,683
50,068
50,458
50,854
NYISO
163,140
161,983
160,617
159,113
157,509
155,842
154,175
152,730
PJM
838,396
841,031
842,326
842,417
841,672
840,716
840,133
840,452
SERC
465,474
468,785
472,119
475,478
478,866
482,285
485,740
489,236
SPP
231,589
232,086
232,435
232,672
232,828
232,953
233,087
233,310
TVA
220,962
222,093
223,230
224,373
225,522
226,678
227,840
229,008
Region
Table 67. Forecasted Regional Annual Energy (GWh) for GS 2021-2028
2021
2022
2023
2024
2025
2026
2027
2028
MHEB
MISO
Midwest
MISO South
26,562
26,767
26,973
27,181
27,390
27,601
27,814
28,028
507,329
508,738
510,369
512,224
514,271
516,482
518,834
521,310
162,358
163,096
163,840
164,592
165,351
166,115
166,886
167,663
MRO
51,257
51,668
52,085
52,510
52,942
53,381
53,826
54,278
NYISO
151,467
150,364
149,456
148,765
148,252
147,889
147,650
147,516
PJM
841,529
843,297
845,795
849,055
852,953
857,389
862,280
867,559
SERC
492,774
496,354
499,975
503,640
507,347
511,097
514,889
518,723
SPP
233,606
233,967
234,401
234,913
235,491
236,122
236,800
237,517
TVA
230,183
231,364
232,551
233,745
234,946
236,153
237,366
238,587
MISO
76
MTEP13 Economic Model Assumptions
Table 68. Forecasted Regional Annual Energy (GWh) for ENV 2013-2020
Region
2013
2014
2015
2016
2018
2018
2019
2020
MHEB
MISO
Midwest
MISO South
24,981
25,366
25,756
26,153
26,556
26,965
27,380
27,802
499,969
504,031
507,786
511,318
514,700
518,038
521,438
525,143
156,625
158,072
159,526
160,989
162,463
163,950
165,448
166,965
MRO
48,170
48,945
49,730
50,526
51,336
52,158
52,995
53,850
NYISO
163,232
162,641
161,823
160,840
159,734
158,549
157,363
156,442
PJM
838,479
847,364
854,975
861,401
866,977
872,331
878,074
884,787
SERC
465,474
472,248
479,120
486,095
493,177
500,371
507,681
515,117
SPP
231,604
232,937
234,132
235,218
236,223
237,192
238,166
239,227
TVA
220,962
223,227
225,517
227,830
230,167
232,528
234,914
237,325
Table 69. Forecasted Regional Annual Energy (GWh) for ENV 2021-2028
Region
2021
2022
2023
2024
2025
2026
2027
2028
MHEB
MISO
Midwest
MISO South
28,230
28,665
29,107
29,555
30,010
30,473
30,942
31,419
529,115
533,332
537,819
542,591
547,618
552,872
558,332
563,980
168,499
170,050
171,619
173,207
174,813
176,437
178,079
179,738
MRO
54,723
55,613
56,523
57,452
58,401
59,370
60,358
61,366
NYISO
155,743
155,235
154,914
154,764
154,758
154,879
155,107
155,430
PJM
892,343
900,697
909,940
920,157
931,227
943,051
955,547
968,646
SERC
522,680
530,372
538,196
546,155
554,250
562,483
570,856
579,369
SPP
240,361
241,563
242,846
244,220
245,673
247,195
248,778
250,414
TVA
239,761
242,222
244,708
247,221
249,760
252,325
254,917
257,535
MISO
77