United States Air and Radiation EPA 430/R-04-008
Environmental Protection Agency (6204J) October 2004
Documentation Summary for
EPA Base Case 2004 (V.2.1.9)
Using the Integrated Planning Model
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Background: The Integrated Planning Model (IPM) is a multi-regional, dynamic, deterministic linear
programming model of the U.S. electric power sector. It provides forecasts of least- cost capacity
expansion, electricity dispatch, and emission control strategies for meeting energy demand and
environmental, transmission, dispatch, and reliability constraints. IPM can be used to evaluate the cost
and emissions impacts of proposed policies to limit emissions of sulfur dioxide (SO2), nitrogen oxides
(NOX), carbon dioxide (CO2), and mercury (Hg) from the electric power sector. IPM is used by the U.S.
Environmental Protection Agency (EPA) to project the impact of emissions policies on the electric power
sector in the 48 contiguous states and the District of Columbia. The assumptions underlying EPA's Base
Case and associated policy cases were incorporated in IPM under EPA direction by ICF Resources, Inc.
IPM was developed by ICF and is used in support of its public and private sector clients. IPM® is a
registered trademark of ICF Resources, Inc.
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Documentation Summary for
EPA Base Case 2004 (V.2.1.9)
Using the Integrated Planning Model
U.S. Environmental Protection Agency
Clean Air Markets Division
1200 Pennsylvania Avenue, NW (6204J)
Washington, D.C. 20460
(www.epa.gov/airmarkets)
October 2004
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Table of Contents
Documentation Summary 1
Exhibits
Power System Operation
Electric Load Assumptions in EPA Base Case 2004, v.2.1.9 Exhibit 3-1
Derivation of Baseline Electricity Forecast in EPA Base Case 2004, v. 2.1.9 Exhibit 3-2
National Non-Coincidental Net Internal Demand Exhibit 3-3
Transmission Capabilities between Model Regions Exhibit 3-4
Seasonal Hydro Capacity Factors (%) in the EPA Base Case 2.1.9 Exhibit 3-5
Planning Reserve Margins in EPA Base Case 2004, v.2.1.9 Exhibit 3-6
Lower and Upper Limits Applied to Heat Rate Data in NEED 2.1.9 Exhibit 3-7
NOX Rate Development in EPA Base Case 2004, v.2.1.9 Exhibit 3-8
Examples of Base and Policy Nox Rates Occurring in EPA Base Case 2004 Exhibit 3-9
Cutoff and Floor NOX Rates (Ibs/mmBtu) Exhibit 3-10
NOX Removal Efficiencies for Different Combustion Control Configurations Exhibit 3-11
Title IV SO2 Allowance Assumptions in EPA Base Case 2004, v.2.1.9 Exhibit 3-12
NOX SIP Call States and Budget Exhibit 3-13
State Multipollutant Regulations Incorporated in EPA Base Case 2004, v.2.1.9 Exhibit 3-14
New Source Review (NSR) Settlements in EPA Base Case 2004, v.2.1.9 Exhibit 3-15
Emission and Removal Rate Assumptions for Potential (New) Units Exhibit 3-16
International Electricity Imports Exhibit 3-17
Generating Resources
Data Sources for NEEDS 2.1.9 Exhibit 4-1
Data Sources for Unit Configuration in NEEDS 2.1.9 Exhibit 4-2
Hierarchy of Data Sources for Capacity in NEEDS 2.1.9 Exhibit 4-3
Rules Used in Populating NEEDS 2.1.9 Exhibit 4-4
Summary of Population (through 2003) in NEEDS 2.1.9 Exhibit 4-5
Aggregation Profile of Model Plants As Provided at Set Up of EPA Base Case 2004 Exhibit 4-6
Summary of Committed Units in EPA Base Case 2004, v.2.1.9 Exhibit 4-7
Planned/Committed Units in EPA Base Case 2.1.9 by Model Region Exhibit 4-8
Performance and Unit Cost Assumptions for Potential (New) Capacity from Conventional Fossil
Technologies in EPA Base Case 2004, v.2.1.9 Exhibit 4-9
Performance and Unit Cost Assumptions for New Capacity from Renewable and Non-Conventional
Technologies in EPA Base Case 2004, v.2.1.9 Exhibit 4-10
Regional Cost Adjustment Factors for Conventional and Renewable Generating Technologies Exhibit 4-11
Assumptions on Potential Geothermal Electric Capacity Exhibit 4-12
Assumptions on Potential Wind Capacity by Wind Class (MW) Exhibit 4-13
Reserve Margin Contribution and Average Capacity Factor by Model Region Exhibit 4-14
Reserve Margin Contribution and Average Capacity Factor by Wind Class and Model Region Exhibit 4-15
Illustrative* Hourly Generation Profile from Wind (kWh of Generation per MW of Electricity) . . Exhibit 4-16
Illustrative* Hourly Generation Profile From Solar Thermal and Solar Photovoltaic (kWh of Generation per
MW of Electricity) Exhibit 4-17
Average Regional Nuclear Capacity Factors in EPA Base Case 2004, v.2.1.9 Exhibit 4-18
Nuclear Upratings and Scheduled Retirements (MW) as Incorporated in EPA Base Case 2004, v.2.1.9
from AEO 2004 Exhibit 4-19
Key Characteristic of Existing Nuclear Units in NEEDS, v.2.1.9 Exhibit 4-20
Cost and Performance Assumptions for Repowering Options Exhibit 4-21
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Emission Control Technologies
Summary of Emission Control Performance Assumptions Exhibit 5-1
SO2 Scrubber Engineering Cost Equations Exhibit 5-2
Cost (in 1999$) of NOX Combustion Controls for Coal Boilers (300 MW Size) Exhibit 5-3
Post-Combustion NOX Controls for Coal Plants (1999$) Exhibit 5-4
Post-Combustion NOX Controls for Oil/Gas Steam Units (1999$)) Exhibit 5-5
Set-Up Parameters and Rules
Run Years and Analysis Year Mapping Used in the EPA Base Case 2004, v.2.1.9) Exhibit 6-1
First Stage Retrofit Assignment Scheme in EPA Base Case 2004, v.2.1.9 Exhibit 6-2
Second Stage Retrofit Assignment Scheme in EPA Base Case 2004, v.2.1.9 Exhibit 6-3
Trading and Banking Rules in EPA Base Case 2004, v.2.1.9 Exhibit 6-4
Financial Assumptions
Capital Charge Rates and Real Discount Rates by Plant Type Exhibit 7-1
Fuel Assumptions
Map of the Coal Supply Regions in EPA Base Case 2.1.9 Exhibit 8-1
Coal Supply Regions in EPA Base Case 2004 Exhibit 8-2
Coal Demand Regions in EPA Base Case 2004 Exhibit 8-3
Coal Labor Productivity Assumptions Exhibit 8-4
Coal Transportation Cost Escalation Rates Exhibit 8-5
Average Mine-Mouth Coal Prices in the EPA Base Case 2004, v.2.1.9 (1999$/Ton) Exhibit 8-6
Coal Assignments in EPA Base Case 2004, v. 2.1.9 Exhibit 8-7
Natural Gas Supply Curves for EPA Base Case 2004, v.2.1.9 Exhibit 8-8
Natural Gas Transportation Differentials for EPA Base Case 2.1.9 (1999 cents/MMBtu) Exhibit 8-9
Seasonal Natural Gas Price Adders in EPA Base Case 2.1.9 (1999 cents/MMBtu) Exhibit 8-10
US Wellhead and National Average Delivered Natural Gas Prices (1999 $/mmBtu) Exhibit 8-11
Technical Background Paper on the Development of Natural Gas Supply Curves
for EPA Base Case 2004, v.2.1.9 Exhibit 8-12
Fuel Oil Prices in EPA Base Case 2004, v.2.1.9 Exhibit 8-13
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EPA Base Case 2004, v.2.1.9
Documentation Summary
1 Structure
The documentation for EPA Base Case 2004 consists of two components. This summary highlights the
key updates, changes, and enhancements that have been included in the current base case.
Accompanying this summary are a series of tables, figures, exhibits, and reports which provide detailed
information on the updated base case assumptions. Some of the tables are updates of similar tables that
appeared in documentation reports for previous versions of the base case. In such cases the identification
number used in the earlier documentation is referenced to facilitate comparisons with the current table. In
these cross references Doc, v.2.1 refers to Documentation of EPA Modeling Applications (V.2.1) Using the
Integrated Planning Model (EPA 430/R-02-004), March 2002. Doc, v.2.1.6 refers to Documentation
Supplement for EPA Modeling Applications (V.2.1.6) Using the Integrated Planning Model (EPA 430/R-03-
007), July 2003. Both reports can be viewed and downloaded on the web at
www.epa.gov/airmarkets/epa-ipm.
2 Introduction
EPA Base Case 2004 (v.2.1.9) represents a significant update of the assumptions underlying the
Integrated Planning Model (IPM), which is used by the U.S. Environmental Protection Agency to analyze
the impact of emissions policies on the U.S. electric power sector in the contiguous 48 states and District
of Columbia. The update was specifically designed to provide improved capabilities for projecting future
sulfur dioxide and nitrogen oxides emissions for use in assessing the impact of policies like the Clean Air
Interstate Regulation (CAIR) being considered by the agency. Changes reflect comments received on
previous modeling performed for the Clear Skies initiative and the CAIR proposal. Update activities
included incorporating the latest available data on generating units, emissions controls, and state
emissions laws and regulations into the model, expanding modeling capabilities to better capture the
behavior of affected entities, and revising modeling assumptions based on recent technical studies, expert
peer review comments, and input from industry and the public.
This Documentation Summary highlights key changes found in the 2004 update. Detailed information on
these and other elements in EPA Base Case 2004 will be found in the accompanying tables, figures,
exhibits, and reports that are referenced in this summary.
Key features of the 2004 update include the following:
3 Power System Operation
3.1 Electricity Load Growth
The electric load assumptions in EPA Base Case 2004 are shown in Exhibit 3-1. These values were
derived by starting with the electricity sales forecast in the U.S. Energy Information Administration's
Annual Energy Outlook 2004 with Projections to 2025 (AEO 2004) and performing calculations to fully
account for reductions in electricity consumption due to a series of voluntary programs operated by both
the U.S. Department of Energy and EPA. It is estimated that these voluntary programs will produce
energy savings of approximately 382 billion kWh by 2020, 281 billion kWh of which are not reflected in the
AEO 2004 reference case projections. Factoring these additional energy efficiency savings into the AEO
2004 reference case projections would result in an average annual electricity growth rate of approximately
1.6% over the 2007-2020 time horizon covered in EPA Base Case 2004. Exhibit 3-2 shows the resulting
electricity sales (in billion kWh) projected for the run years used in the EPA Base Case together with the
AEO 2004 electricity sales projection for these years. The electricity sales values were translated into the
net energy for load values shown in Exhibit 3-1 by multiplying the electricity sales by the ratio of net
energy for load to total sales as found in AEO 2004.
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3.2 Modeling Regional Peak Demand and Transmission Capability on a Seasonal Basis
Previous EPA base cases employed separate summer and winter load duration curves for each region,
but only a single annual net internal (peak) demand value was derived from those curves. In EPA Base
Case 2004 separate winter and summer peak demand values are derived from each region's load
duration curves and used in modeling. Exhibit 3-3 summarizes the winter and summer national non-
coincidental net internal demand used in the EPA Base Case 2004. The values in Exhibit 3-3 are said to
be "non-coincidental," since they represent the sum of each region's net internal (peak) demand which
need not occur in the same hour across all regions. As shown in Exhibit 3-4, separate winter and summer
transmission capabilities between model regions are also employed in EPA Base Case 2004. These
enhancements should result in a truer representation of electric system operation that could be particularly
important in capturing transmission characteristics in regions with sizable differences in summer and
winter peak demand and between regions with asynchronous peak seasons.
3.3 Capacity Factors for Hydro
Regional and seasonal capacity factors for existing hydro (Exhibit 3-5) were updated based on data
reported in EIA Form 767 from 1998 through 2001.
3.4 Reserve Margins
The planning reserve margins for each IPM region (Exhibit 3-6) were updated based on data reported in
North American Electric Reliability Council (NERC) Reliability Assessment 2003-2012, WECC Information
Summary 2003, and regional NERC documents.
3.5 Heat Rates
In previous EPA base cases the primary data source for heat rates of existing electric generation units
was the 1995 EIA Annual Electric Generation Report (EIA 860). A major update of heat rates was
performed for EPA Base Case 2004. Starting with the heat rates from AEO 2004 a procedure was applied
to ensure that the heat rates used in EPA Base Case 2004 were within the engineering capabilities of the
generating units. Based on engineering analysis, upper and lower heat rate limits were applied to coal
steam, oil/gas steam, combined cycle, gas combustion turbines and oil combustion turbines. If the
reported heat rate for such a unit was below the applicable lower limit or above the applicable upper limit,
the limit was substituted for the value reported. (These limits were not applied to cogenerators. For these
units the AEO 2004 heat rates were directly used.) Exhibit 3-7 shows the limits that were used. The
resulting heat rates can be found in the latest version of the National Electrical Energy Data System
(NEEDS 2.1.9), which accompanies this documentation. NEEDS 2.1.9 is a database of all existing and
committed units that are represented in EPA Base Case 2004.
3.6 Emission Rates
3.6.1 Sulfur Dioxide (SO2): In EPA Base Case 2004 State Implementation Plan (SIP) limits on SO2
emission rates are used initially to establish the sulfur grades of coal that a unit has the option to burn.
For example, if the SIP limit on an unscrubbed unit were 2.5 Ib/mmBtu, it would not be allowed to burn
high sulfur bituminous coals because their SO2 content (3.0 Ib/mmBtu and 5.0 Ib/mmBtu, respectively)
exceed the unit's regulatory emission rate.
These preliminary coal assignments were then reviewed by coal experts at PA Consulting, Inc. and
adjustments were made based on historical usage as reported in FERC Form 423, Platt's Coaldat
database, Platt's Coal Outlook newsletter, company announcements, trade publications, and PA
Consulting's expert knowledge of units that were good economic candidates for using a particular type of
coal, in particular, Powder River Basin sub-bituminous coal. (See section 8.1 below.)
SO2 rates derived from data reported in EPA's Emission Tracking System (ETS) were used to identify
unscrubbed coal units whose emissions were below 0.8 Ib/mmBtu during the July 2002 - June 2003
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period. A factor was assigned to such units to bring their emissions down to the reported ETS SO2
emission rate when in the course of a modeling run such units burn the lowest sulfur coals offered by the
model. This was done to capture the reality that such unscrubbed units actually have access to coals that
produce emissions below 1 Ib/mmBtu, even though the lowest sulfur coal offered under the discrete coal
supply representation in EPA Base Case 2004 was 1 Ib/mmBtu.
3.6.2 Nitrogen Oxides (NOX): In EPA Base Case 2004 a number of significant improvements were made
in the way NOX rates were derived and used. Whereas previous versions of EPA's base case used
procedures that approximated the effect of regulations on NOX rates, the rates in the current base case
were derived, wherever possible, directly from actual monitored NOX emission rate data reported to EPA
under the Acid Rain Program for the last half (i.e., July through December) of 2002 and the first half (i.e.,
January through June) of 2003. The emission rates themselves reflect the impact of the applicable NOX
regulations. For coal-fired units, NOX rates were used in combination with detailed engineering
assessments of NOX combustion control performance to derive "policy NOX rates" that reflect the current
capabilities of combustion controls, picking up differences due to coal rank and the specific configuration
of combustion controls. "Policy NOX rates" refer to the emission rates that would be expected to occur at
generating units in response to NOX control policies without installation of post-combustion controls
beyond those already in place or specifically mandated by existing laws or settlement agreements. "Policy
NOX rates" are intended to capture the impact of NOX combustion controls, the initial cost effective step
undertaken by the regulated community in response to a NOX emission policy.
Four candidate NOX rates (designed as Modes 1, 2, 3 and 4) are include in NEEDS 2.1.9, the database of
existing units that are represented in EPA Base Case 2004. Having these four options in NEEDS allows
the IPM set-up program to assign the appropriate NOX policy rate to each existing unit consistent with the
policy scenario being modeled. For example, units not affected by NOX policies beyond those already
reflected in the baseline emission rate data would be assigned a Mode 1 rate (Uncontrolled Base Rate) if
they do not have post-combustion NOX controls and a Mode 2 rate (Controlled Base Rate) if they do have
post-combustion NOX controls. Units affected by NOX policies that go beyond those already reflected in
the baseline emission rate data would be assigned a Mode 3 rate (Uncontrolled Policy Rate) if they do not
have post-combustion NOX controls and a Mode 4 rate (Controlled Policy Rate) rate if they do have post-
combustion NOX controls. Having four policy NOX rate options right in NEEDS shortens the time it takes to
set-up model runs with different NOX policy scenarios by identifying ahead of time all possible starting NOX
rates that could apply to existing units for all variations in policy scenarios that might be analyzed using the
base case.
Exhibits 3-8 through 3-11 give further details on the procedure employed to derive the four NOX rate
modes found in NEEDS 2.1.9. The specific NOX rates that result from this procedure can be found in the
NEEDS 2.1.9 database, which accompanies this documentation.
3.6.2 Mercury (Hg): Only SO2 and NOX emission rates were updated in EPA Base Case 2004. No
updates of mercury emission rates were included in this version of the base case.
3.7 Existing Environmental Regulations:
3.7.1 SO2 Title IV Allowance Bank Update: Since EPA Base Case 2004 uses year 2007 as the first
analysis year, a projection of the allowance bank going into 2007 is needed. ICF Consulting Inc.'s internal
forecast, which makes use of IPM, was used for this purpose. Starting with an estimated bank of 8.54
million tons going into 20031, ICF projected an SO2 bank of 4.99 million tons going into 2007. Exhibit 3-12
summarizes the total annual allowances in the Title IV SO2 trading program and shows a starting bank of
1 EPA's official accounting of the SO2 bank (8.65 million tons going in into 2003) was not available at the
time that work on EPA Base Case 2004 was concluded.
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4.99 million tons in 2007. Exhibit 6-4 shows how the SO2 caps used in EPA Base Case 2004 were
derived from the allowance assumptions in Exhibit 3-12.
3.7.2 NOX Regulations: In EPA Base Case 2004 Missouri was added to the 20 states and the District of
Columbia that were previously included in the NOX SIP Call region. Missouri was assigned an emissions
budget of 24,365 tons for the ozone season. (Exhibit 3-13)
3.7.3 State Specific Environmental Regulations: For EPA Base Case 2004 a major effort was made to
account for state laws and regulations affecting electricity sector emissions of sulfur dioxide, nitrogen
oxides, mercury, and carbon dioxide. The laws and regulations had to either be on the books or expected
to come into force. As a result of this effort, the EPA Base Case 2004 representation of state specific
environmental regulations in the seven states (Connecticut, Massachusetts, Missouri, New Hampshire,
North Carolina, Texas, and Wisconsin) that had been included in EPA Base Case 2003 were verified and
updated. State laws and regulations in five additional states (Illinois, Maine, Minnesota, New York, and
Oregon) and the Western Region Air Partnership (WRAP) regional haze plan were included in the EPA
Base Case 2004. Exhibit 3-14 summarizes the provisions of the state laws and regulations that are
represented in EPA Base Case 2004.
3.7.4 New Source Review (NSR) Settlements: EPA Base Case 2004 includes NSR settlement
requirements for the following six utility companies: SIGECO, PSEG Fossil, TECO, We Energies
(WEPCO), VEPCO, and Santee Cooper. The settlements are included as they existed on March 19,
2004. At that time the WE Energy, and Santee Cooper settlements hadn't yet been entered by a judge. A
summary of the units affected and how the settlements were modeled can be found in Exhibit 3-15.
3.7.5 Emission Assumptions for Potential (New) Units: For greater consistency with their performance
record, the emission rate for potential (new) conventional pulverized coal units (which are assumed to be
built with SCR for post-combustion NOX control) was set at 0.06 Ib/mmBtu rather than the 0.11 Ib/mmBtu
rate that had been used in EPA Base Case 2003. This is also the floor emission rate (lowest achievable)
when SCR is selected as a retrofit option on existing coal units in EPA Base Case 2004. All the emission
and removal rate assumptions in EPA Base Case 2004 are summarized in Exhibit 3-16.
3.8 International Electricity Imports
The U.S. electric power system is connected with transmission grids in Canada and Mexico and the three
countries actively trade in electricity. Since the EPA Base Case 2004 does not explicitly include any
power markets outside the U.S., international electric trading between U.S., Canada and Mexico is
represented by an assumption of net imports. Exhibit 3-17 summarizes the assumption on net imports
into the U.S. from Canada and Mexico.
4 Generating Resources
4.1 Existing Units
4.1.1 Data Sources: For EPA Base Case 2004, the generating unit population was updated using the
sources indicated in Exhibits 4-1 through 4-3, and the NEEDS v.2.1.9 database of existing and
planned/committed units was populated following the rules indicated in Exhibit 4-4. Notable aspects of this
update include use of the December 2003 release of Platts NewGen database, 2002-03 data from EPA's
Emission Tracking System, and the Energy Information Administration's latest available Annual Energy
Outlook, i.e., AEO 2004.
4.1.2 Model Plant Aggregation: While IPM is comprehensive in representing all the units contained in
NEEDS 2.1.9 (the database of existing and planned/committed units), for computational tractability the
model aggregates actual generating units having similar characteristics into "model plants" and uses these
plants in the actual modeling process. For EPA Base Case 2004 the aggregation scheme was modified
so that each model plant only represents generating units from a single state. This change was made
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possible by hardware and software improvements that allow larger formulations to be solved in an
acceptable solution time. The change should make it easier to obtain state-level results for existing plants
directly from IPM outputs. Exhibit 4-5 provides an overview of the types, numbers, and capacity of existing
units in NEEDS 2.1.9. Exhibit 4-6 provides a crosswalk between model plants in EPA Base Case 2004
and actual generating units in NEEDS 2.1.9. The table shows the type and number of model plants
contained in the base case at start up and the number of actual generating units that each type of model
plant represents.
4.1.3 Emission Controls: Great effort was taken to see that the inventory of existing and committed
controls represented in EPA Base Case 2004 was as comprehensive and up-to-date as possible. The
hierarchy of data sources used is shown in Exhibit 4-2. In addition, to improve the accuracy of the
inventory, representatives from several major utilities (e.g., AEP, Ameren, Cinergy, Dominion, Southern
Company, TVA, TXU, and Xcel) reviewed the emission controls and operating characteristics listed for
coal-fired generating units that they own and/or operate. The complete inventory of existing and
committed emission controls can be found in NEEDS 2.1.9 (the database of existing units represented in
EPA Base Case 2004), which accompanies this documentation.
4.2 Planned/Committed Units
Planned/Committed units are ones that are likely to come on line either because ground has been broken,
financing obtained, or other demonstrable factors indicate a high probability that the unit will get built. A
comprehensive update of planned/committed units was performed for EPA Base Case 2004 using two
information sources: RDI NewGen database (RDI) distributed by Platts (www.platts.com') and the
inventory of planned/committed units assembled by the U.S. Department of Energy, Energy Information
Administration, for Annual Energy Outlook 2004 (AEO 2004). Exhibit 4-7 summarizes the data sources
used to create the inventory of planned/committed units for EPA Base Case 2004 and the generating
capacity identified by unit type. Exhibit 4-8 gives a breakdown of planned/committed units by IPM region,
unit type, number of units, and capacity. A full listing of the planned/committed units in EPA Base Case
2004 can be found in the National Electrical Energy Data System (NEEDS 2.1.9), which accompanies this
documentation.
4.3 Potential Units
Units that IPM "builds" in response to electricity demand and the constraints represented in the model are
called "potential units."
4.3.1 Cost and Performance Assumptions: The cost and performance assumptions for these units
were updated largely based on data from the Annual Energy Outlook 2004 (AEO 2004). In addition to the
generation technologies represented in previous base cases, advanced combined cycle units were
included in EPA Base Case 2004, because an increase in natural gas prices resulting from the update
described below in section 8.2 made this technology an economically viable option to include in the model.
The updated cost and performance assumptions for conventional fossil technologies are shown in Exhibit
4-9. (The included technologies are Conventional Pulverized Coal, Integrated Gasification Combined
Cycle, Combined Cycle, Advanced Combined Cycle, Combustion Turbines, and Advanced Combustion
Turbines.) The updated cost and performance assumptions for renewable and non-conventional
technologies are shown in Exhibit 4-10. (The included technologies are biomass gasification combined
cycle, wind, fuel cells, solar photovoltaic, solar thermal, geothermal, and landfill gas.) The factors used to
convert the generic capital costs shown in Exhibits 4-9 and 4-10 to region-specific costs were also
updated based on AEO 2004. The updated regional cost adjustment factors are shown in Exhibit 4-11. In
the current base case there are no longer separate adjustment factors for renewable and conventional
technologies. Both categories of technologies use the cost adjustment factors shown in Exhibit 4-11.
A number of performance characteristics pertaining to renewable technologies were also updated based
on AEO 2004. These are shown in Exhibits 4-12 through 4-17. Updates of average regional capacity
factors for nuclear units and nuclear upratings and retirements were based on AEO 2004. These are
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shown in Exhibits 4-18 and 4-19. Exhibit 4-20 shows key characteristics of each of the existing nuclear
units that are represented in EPA Base Case 2004.
4.3.2 Repowering Options: EPA contracted Bechtel-affiliated Nexant, Inc. to perform an engineering
study that would provide the basis for updating the cost and performance assumptions underlying three
repowering options offered in EPA Base Case 2004. Nexant analyzed the repowering of coal to combined
cycle and coal to integrated gasification combined cycle. Based on Nexant's work, EPA developed cost
and performance parameters for the repowering of oil/gas steam to combined cycle. The results of the
Nexant study, Performance and Cost Estimates: Repowering Options For Existing Power Plants (June
2004) are reflected in the new cost and performance parameters (shown in Exhibit 4-21) that were
incorporated in EPA Base Case 2004. To derive the values shown in Exhibit 4-21 from the Nexant study,
the following assumptions were made: population weighted elevation = 556 feet, temperature = 60° F,
humidity = 60%, and capacity factor = 85%. In deriving the capital costs shown in Exhibit 4-21, it was
assumed that the same discount rates (6.14% for combined cycle units, 6.74% for IGCC units) and
construction profiles apply to the repowered units as apply to new combined cycle and IGCC units.
Combined cycle units have a 3-year construction period with 10% of capital expenditures occurring in year
1, 20% in year 2, and 70% in year 3. IGCC units have a 4-year construction period with 35% of capital
expenditures occurring in year 1, 30% in year 2, and 25% in year 3, and 10% in year 4.
5 Emission Control Technologies
Exhibit 5-1 summarizes the emission control performance assumptions for the SO2 and NOX control
technologies offered as retrofit options in EPA Base Case 2004. SO2 and NOX control technologies are
offered as retrofit options that existing units may utilize to comply with modeled air regulations. For
potential units, the cost and performance of SO2 and NOX control technologies are included in the total
capital, fixed and variable operations costs of the units.
Discussed below are several new aspects of the control assumptions found in EPA Base Case 2004.
5.1 Sulfur Dioxide Emissions Control
Scrubber efficiencies for existing units were derived from data reported in EIA Form 767. In transferring
this data for use in EPA Base Case 2004 the following changes were made. The maximum removal
efficiency for wet scrubbers was set at 98% and for dry scrubbers at 95%. Existing units reporting
efficiencies above these levels in Form 767 were assigned these maximum removal efficiencies in NEEDS
2.1.9. (Note that, as shown in Exhibit 3-16, new coal-fired units built by the model are assumed to achieve
a 95% removal rate from their scrubbers. As shown in Exhibit 5-1, existing unscrubbed units that are
retrofit by the model with scrubbers achieve removal rates ranging from 90% to 96%, depending on the
type of scrubber used. These assumptions are consistent with previous EPA base cases.) In the current
base case, existing units that report scrubber efficiencies below 50% are considered to have duct injection
technologies and are given the option to retrofit with scrubbers when IPM is run. The engineering cost
equations used to derived scrubber costs in EPA Base Case 2004 are presented in Exhibit 5-2.
5.2 Nitrogen Oxides Emissions Control
5.2.1 Combustion Controls: EPA Base Case 2004 includes a substantial revision in the handling of NOX
combustion controls. These are described above in section 3.6.2 and in Exhibits 3-8 through 3-11. The
cost of adding NOX combustion controls are derived using the updated cost functions shown in Exhibit 5-3.
5.2.2 Post Combustion Controls
5.2.2.1 Selective Catalytic Reduction (SCR): Existing coal-fired units that are retrofit with SCR have a NOX
removal efficiency of 90%, with a minimum controlled NOX emission rate of 0.06 Ib/mmBtu in EPA Base
Case 2004. For consistency with the emission rate achievable by retrofits on existing units, coal-fired
potential (new) units that are built to include SCR have NOX emission rates of 0.06 Ib/mmBtu. The cost
assumptions for SCR retrofits at coal plants were revised based on an engineering assessment of recent
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installations. Revisions were also made to the scaling factors applied to these costs. These revisions are
shown in Exhibit 5-4. No changes were made to the cost and performance assumptions for post-
combustion controls on oil/gas steam units. These are shown in Exhibit 5-5.
5.2.2.2 Selective Non-Catalytic Reduction (SNCR): Revisions were made to the operation and
maintenance costs and the derivation of scaling factors for SNCR retrofits at coal plants. These revisions
are also shown in Exhibit 5-4.
6 Set-Up Parameters and Rules
Exhibit 6-1 shows the mapping between model run years and actual calendar years used in EPA Base
Case 2004. The retrofit assignment scheme for EPA Base Case 2004 is shown in Exhibit 6-2 and 6.3.
Trading and banking rules are summarized in Exhibit 6-4.
7 Financial Assumptions
The financial assumptions in the current base case are the same as those in EPA Base Case 2003
(v.2.1.6). As in v.2.1.6 a 30-year book life is assumed for capital cost recovery. The key financial
assumptions for EPA Base Case 2004 are summarized in Exhibit 7-1.
8 Fuel Assumptions
8.1 Coal
Important features of the coal assumptions in EPA Base Case 2004 are summarized in Exhibits 8-1
through 8-7. Exhibit 8-1 contains a map of the coal supply regions that are used in EPA Base Case 2004.
Exhibit 8-2 provides a key to the two-letter coal supply region names that appear in the map and in IPM
outputs. The key identifies the region and state associated with each two-letter name. Exhibit 8-3 lists the
coal demand regions that are used in EPA Base Case 2004 and provides a crosswalk between each
abbreviation that is used in IPM and a description of the region. The labor productivity assumptions and
coal transportation cost escalation rates were retained from EPA Base Case 2003. These are presented
in Exhibit 8-4 and 8-5. Exhibit 8-6 shows the average mine-mouth coal prices in the base case on a $/ton
basis.
For Base Case 2004, EPA obtained technical input from recognized coal experts at PA Consulting, Inc., to
perform a major review of the coal choices offered to the specific generating units represented in EPA's
application of IPM. Updates were made to coal assignments in EPA Base Case 2004 to enable the model
to better capture recent developments in the use of coal.
The ranks (bituminous, subbituminous, lignite) of coal offered to specific generating units were initially
determined by ICF Consulting, Inc (ICF). based on a detailed review of historical EIA Form 423 and Form
767 plant-level coal consumption data. ICF then applied the procedure described above in section 3.6.1
to determine the grades (differentiated by sulfur content) of coal offered to each generating unit in EPA
Base Case 2004.
PA Consulting Group, Inc. (PA) reviewed the resulting assignments for consistency with recent practices.
Particular attention was given to the assignment of sub-bituminous Powder River Basin (PRB) coal to
coal-fired generating units, since significant changes have been occurring in this area in recent years. In
their review of PRB coal assignments, PA identified units not currently burning PRB coal, units currently
burning 100% PRB coal, units that currently blend (or have blended) PRB coal, units that have tested PRB
coal, units that have announced plans to test PRB coal, units that are known to have an interest in testing
PRB coal, and units that are good economic candidates for PRB coal.
The data sources used for this review included FERC Form 423 and EIA-423 data (as reported in Platts
CoalDat database), trade press reports, and PA's own industry knowledge. For example, units currently
-------
burning 100% PRB coal, units that currently blend (or have blended) PRB coal, and units that have tested
PRB coal were identified primarily based on current and historical FERC Form 423 or EIA-423 data,
although PA's industry knowledge played a role in some cases. For example, PA was aware that FERC
Form 423 does not reflect use of PRB coal by certain TVA plants so recommended giving these units PRB
coal as a fuel choice. Units not currently burning PRB coal, units that have announced plans to test PRB
coal, units that are known to have an interest in testing PRB coal, and units that are good economic
candidates for PRB coal were identified primarily based on trade press reports and PA's industry
knowledge.
As a result of this review and a follow-up evaluation by ICF and EPA, the following changes were made:
• Based on information showing that they were currently burning or previously had burned PRB
subbituminous coal (either 100% or in a blend) or had announced plans to test PRB coal, fifty
generating units, not previously assigned PRB coal were given PRB subbituminous coal as a fuel
option. Subbituminous coal was allowed to be burned at lignite boilers only if it was already being
used.
• PRB coal was given as a fuel option for an additional 23 generating units that PA's analysis
indicated were good economic candidates for PRB coal. Units were included based on a variety of
data sources, including trade press reports, available presentations and reports by coal producers,
users and consultants, and PA's analytical work for private clients.
• PRB coal was dropped as a fuel option for six generating units, known to be unlikely to use PRB
coal in the future. Examples include Georgia Power's Wansley plant (where test burns of PRB coal
were unsuccessful), the Wyandotte plant in Michigan (which has publicly announced that it will not
use PRB coal), and AEP's Mountaineer plant in West Virginia (where a decision was recently made
to retrofit a scrubber and use local high-sulfur coal rather than continuing the use of PRB coal over
the long term).
Exhibit 8-7 provides further details on the coal assignments that were incorporated in EPA Base Case
2004.
8.2 Natural Gas
EPA and ICF Consulting, Inc. performed a major review and update of the natural gas supply curves,
which are one of the critical inputs in EPA Base Case 2004. On October 23-24, 2003 EPA convened a
panel of eight prominent, independent experts for a peer review of the natural gas assumptions used in
EPA's applications of IPM. Detailed background material on the peer review can be found at the following
EPA web site: www.epa.gov/airmarkets/epa-ipm/. In addition, on November 19, 2003 EPA and ICF
Consulting, Inc. were given a briefing by industry and government representatives on the modeling
methods, data usage, and results of the National Petroleum Council's 2003 Natural Gas Study. EPA
subsequently obtained detailed supply and demand data from the NPC study. These were used to
calibrate and update assumptions underlying the gas supply curves that were developed for EPA Base
Case 2004.
As a result of the peer review and data obtained from the NPC study, a completely new set of natural gas
supply curves was produced for use in EPA Base Case 2004. The new supply curves reflect the following
changes.
8.2.1 Resource Data and Reservoir Description: A complete update to the undiscovered natural gas
resource base for the Western Canada Sedimentary Basin (WCSB) and key regional updates within the
U.S. were completed as new data became available in years 2002 and 2003. For the U.S., the primary
data sources were the United States Geological Survey (USGS) and Minerals Management Service
(MMS). ICF investigated the conventional resource assessment of the Canadian Gas Potential
Committee (CGPC), unconventional resource assessments published by the Alberta Energy Utilities
Board (AEUB), publicly available reports, and information available from the provincial energy
departments for Saskatchewan and British Columbia. Key updates included:
-------
• Reviewing assumptions regarding conventional resource plays and, where warranted, modifying the
internal field size distribution procedure so that the maximum undiscovered field size did not exceed
the maximum undiscovered field size class estimates of the USGS for corresponding assessment
units.
• Reducing well spacing assumptions to reflect current production practices.
• Where new data were available, updating reservoir parameters like average depth, gas composition
and impurities, and percent of federal land in play.
• Comparing and calibrating modeled production trends in the Rocky Mountain and Gulf Coast
regions with recent established history, using regional natural gas production reports from Lippman
Consulting, Inc.
• Substantially re-categorizing and updating undiscovered Canadian resources based on recent
estimates published by CGPC, including a complete update of undiscovered resources for
established plays in the Western Canadian Sedimentary Basin.
8.2.2 Treatment of Frontier Resources: Using a variety of recent publicly available data sources, ICF
updated the representation of Alaska North Slope, Mackenzie Delta, Sable Island, and existing and
potential liquified natural gas (LNG) terminals in the North American Natural Gas Analysis System
(NANGAS), the model used to generate the natural gas supply curves for EPA Base Case 2004.
8.2.3 Exploration and Production (E&P) Characterization: Among the key revisions in E&P
characterization that resulted from the peer review process were:
• Increasing the required rate of return (hurdle rate) from 10% to 15% for exploration projects and
12% for development projects.
• Setting success rate improvement assumptions of 0.5% per year for onshore projects and 0.8% per
year for offshore projects.
• Establishing operating cost decline rates of 0.54% per year and drilling cost decline rates of 1.9%
per year for onshore and 1.2% per year for offshore.
• Making use of the research and development (R&D) program evaluation undertaken by the U.S.
Department of Energy's Strategic Center for Natural Gas to identify key technology levers and
advancement rates.
8.2.4 Natural Gas Demand: Based on the peer review recommendations the following improvements
were made to the representation of end use demand for natural gas:
• Capturing demand destruction in the industrial feedstock sector by incorporating into NANGAS the
natural gas demand forecasts for the feedstock and process heat sectors developed for the NPC
natural gas study.
• Revising the macroeconomic equations for residential and commercial sector demand for natural
gas and capturing income elasticity in the representation of residential demand.
These updates of the natural gas supply assumptions resulted in the new natural gas supply curves,
transportation differentials, and seasonal adders which are shown in Exhibit 8-8, 8-9, and 8-10,
respectively. Exhibit 8-11 shows the wellhead and national average delivered natural gas prices that result
when the EPA Base Case 2004 is run with the updated supply curves and transportation differential and
seasonal adders.
A technical background paper, prepared by ICF Consulting, Inc., on the development of the natural gas
supply curves for EPA Base Case 2004 is included in Exhibit 8-12.
8.3 Fuel Oil
Exhibit 8-13 shows the distillate and residual (low and high sulfur) fuel oil prices used in EPA Base Case
2004. Prices, which are based on AEO 2004, are only shown for two IPM model regions: Mid-Atlantic
Area Council - East (MACE) and New England Power Pool (NENG). Under the EPA Base Case 2004,
these are the only regions where fuel oil is offered as an option for oil/gas steam boilers.
-------
8.3 Nuclear Fuel
EPA Base Case 2004 uses the AEO 2004 nuclear fuel price (1999$) forecast of $0.41/mmBtu for the
2007-2020 modeling horizon.
10
-------
Section 3
Power System Operation
List of Exhibits
3-1 Electric Load Assumptions in EPA Base Case 2004, v.2.1.9.
3-2 Derivation of Baseline Electricity Forecast in EPA Base Case 2004, v. 2.1.9.
3-3 National Non-Coincidental Net Internal Demand.
3-4 Transmission Capabilities between Model Regions.
3-5 Seasonal Hydro Capacity Factors (%) in the EPA Base Case 2.1.9.
3-6 Planning Reserve Margins in EPA Base Case 2004, v.2.1.9.
3-7 Lower and Upper Limits Applied to Heat Rate Data in NEED 2.1.9.
3-8 NOX Rate Development in EPA Base Case 2004, v.2.1.9
3-9 Examples of Base and Policy Nox Rates Occurring in EPA Base Case 2004.
3-10 Cutoff and Floor NOX Rates (Ibs/mmBtu).
3-11 NOX Removal Efficiencies for Different Combustion Control Configurations.
3-12 Title IV SO2 Allowance Assumptions in EPA Base Case 2004, v.2.1.9.
3-13 NOX SIP Call States and Budget.
3-14 State Multipollutant Regulations Incorporated in EPA Base Case 2004, v.2.1.9.
3-15 New Source Review (NSR) Settlements in EPA Base Case 2004, v.2.1.9.
3-16 Emission and Removal Rate Assumptions for Potential (New) Units.
3-17 International Electricity Imports
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Exhibit 3-1. Electric Load Assumptions in EPA Base Case 2004, v.2.1.9.
(Table 3.2 in Doc, v.2.1. Attachment B in Doc, v.2.1.6.)
Year
2007
2010
2015
2020
EPA Base Case 2.1. 9 Net
Energy for Load
(Billions of kWh)
3,966
4,144
4,458
4,810
Note: For specific runs built upon EPA Base Case 2004, v.2.1.9, the total national net energy for load resulting from
the run may differ slightly from the assumptions shown in Exhibit 3-1 due to the exports of electricity and
computational rounding.
-------
Exhibit 3-2. Baseline Electricity Sales Forecast Used for EPA Base Case 2004, v. 2.1.9.
(Table A3.1 in Doc, v.2.1. Attachment B in Doc, v.2.1.6.)
2007 2010 2015 2020 AAGR
GDP AEO2004 (Billion $1996) 11,129 12,190 14,101 16,188 2.92%
Electricity Sales Forecasts (Billion kWh)
AEO2004 3827 4051 4425 4807 1.77%
IPM Initial RefCase 3827 4051 4425 4807 1.77%
IPMwith Average Annual Growth Adjusted to 3714 3889 4200 4536 1.55%
1.55% to account for additional energy efficiency
savings not reflected in AEO 2004
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Exhibit 3-3. National Non-Coincidental Net Internal Demand
(Table 3.3 in Doc, v.2.1.)
Year
2007
2010
2015
2020
Net Internal Demand (GW)
Winter Summer
649
681
730
785
725
762
818
881
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Exhibit 3-4. Transmission Capabilities between Model Regions
(Table 3.4 in Doc v.2.1.)
From
To
Winter
MW
Summer
MW
From
To
Winter
MW
Summer
MW
From
To
Winter
MW
Summer
MW
MECS
ECAO
ERCT
MACE
MACS
MACW
MANO
WUMS
MAPP
NENG
ECAO
MECS
MACW
MANO
TVA
VACA
SPPS
MACW
DSNY
MACW
VACA
ECAO
MACE
MACS
UPNY
ECAO
WUMS
SPPN
TVA
ENTG
MANO
MAPP
WUMS
SPPN
ENTG
NWPE
RMPA
DSNY
3000
3000
3494
4331
3672
2350
959
2000
1000
2400
2960
4706
6200
4100
494
3969
825
1478
3972
2870
1125
270
800
2093
2000
200
310
1600
3000
3000
3546
2495
3275
4022
1009
2000
1000
2400
3900
3904
6200
4100
494
4105
825
985
2828
2765
1125
270
800
2044
2000
200
310
1600
UPNY
DSNY
NYC
LILC
SPPN
SPPS
ENTG
SOU
MACW
DSNY
LILC
MACE
NENG
UPNY
NYC
LILC
DSNY
DSNY
NYC
MANO
MAPP
SPPS
ENTG
ERCT
SPPN
AZNM
ENTG
SOU
TVA
MANO
SPPS
SPPN
MAPP
FRCC
TVA
VACA
ENTG
51
4950
950
1000
1425
4950
6050
1050
6050
950
1050
1822
2000
700
462
641
1200
420
3372
3050
2883
1530
716
1443
1200
3600
2746
187
2750
51
4950
950
1000
1425
4950
6050
1050
6050
950
1050
2115
1006
700
462
631
1200
420
3372
650
2171
885
716
1443
600
3600
2761
1530
2550
FRCC
TVA
VACA
CALI
PNW
RMPA
NWPE
AZNM
SOU
ECAO
MANO
SOU
ENTG
VACA
ECAO
MACS
SOU
TVA
PNW
NWPE
CALI
NWPE
MAPP
AZNM
NWPE
RMPA
CALI
MAPP
AZNM
PNW
CALI
NWPE
RMPA
SPPS
2700
1328
1528
2854
2517
514
4428
5640
2463
2986
6563
1577
7870
1500
310
690
1150
860
2097
150
600
2600
7550
1364
690
420
2000
1425
2428
1639
2629
2014
4428
4390
2170
2986
6563
1577
7870
1500
310
690
1150
860
2097
150
600
2600
7550
1364
690
420
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Exhibit 3-5. Seasonal Hydro Capacity Factors (%) in the EPA Base Case 2.1.9
(Table 3.7 in Doc, v.2.1.)
IPM Region
AZNM
CALI
DSNY
ECAO
ENTG
ERCT
FRCC
LILC
MACE
MACS
MACW
MANO
MAPP
MECS
NENG
NWPE
NYC
PNW
RMPA
SOU
SPPN
SPPS
TVA
UPNY
VACA
WUMS
National Weighted Average
Winter Capacity
Factor (%)
32.3%
34.7%
51 .0%
24.1%
36.1%
9.9%
33.5%
N/A
41 .8%
12.4%
37.1%
48.2%
38.8%
46.0%
28.8%
34.3%
N/A
34.9%
36.0%
25.1%
17.6%
27.8%
40.5%
48.2%
20.5%
28.6%
34.6%
Summer Capacity
Factor (%)
35.4%
47.2%
37.2%
22.8%
37.1%
1 4.5%
36.1%
N/A
21 .9%
1 2.2%
20.5%
49.7%
44.8%
39.6%
23.8%
45.0%
N/A
34.0%
47.1%
1 7.3%
21 .6%
27.4%
40.8%
45.3%
1 6.4%
29.7%
35.6%
Annual Capacity Factor
(%)
33.6%
39.9%
45.2%
23.5%
36.5%
1 1 .8%
34.6%
N/A
33.5%
12.3%
30.1%
48.8%
41 .3%
43.3%
26.7%
38.8%
N/A
34.5%
40.7%
21 .8%
19.3%
27.6%
40.6%
47.0%
18.8%
29.1%
35.0%
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Exhibit 3-6. Planning Reserve Margins in EPA Base Case 2004, v.2.1.9.
(Table 3.8 in Doc. v.2.1.)
Region Description
Reserve Margin
Michigan Electric Coordination System
East Central Area Reliability Coordination Agreement - South
Electric Reliability Council of Texas
Mid-Atlantic Area Council - East
Mid-Atlantic Area Council - West
Mid-Atlantic Area Council - South
Wisconsin-Upper Michigan
Mid-America Interconnected Network - South
Mid-Continent Area Power Pool
Upstate New York
Downstate New York
New York City
Long Island Power Authority
New England Power Pool
Florida Reliability Coordinating Council
Virginia-Carolinas
Tennessee Valley Authority
Southern Company
Entergy
Southwest Power Pool - North
Southwest Power Pool - South
Western Electricity Coordinating Council - California
Western Electricity Coordinating Council - Pacific Northwest
Western Electricity Coordinating Council - AZ / NM / SNV
Western Electricity Coordinating Council - Rocky Mountain Power Area
Western Electricity Coordinating Council - Northwest Power Pool East
15.0%
15.0%
12.5%
17.0%
17.0%
17.0%
17.0%
17.0%
15.0%
18.0%
18.0%
18.0%
18.0%
18.0%
19.0%
12.4%
12.4%
12.4%
12.4%
13.6%
13.6%
15.1%
13.2%
13.6%
14.2%
13.2%
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Exhibit 3-7. Lower and Upper Limits Applied to Heat Rate Data in NEED 2.1.9
Heat Rate (Btu/kWh)
Lower Limit Upper Limit
Coal Steam
Oil/Gas Steam
Combined Cycle - Natural Gas
Combined Cycle - Oil
Combustion Turbine - Natural Gas
Combustion Turbine - Oil
8,300
8,300
5,500
6,000
8,700
9,200
14,500
14,500
15,000
15,000
16,500
18,000
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Exhibit 3-8. NOX Rate Development in EPA Base Case 2004, v.2.1
In EPA Base Case 2004 and the policy model runs built upon this base case (as in previous EPA base cases) NOX
combustion controls are not represented as retrofit options that the model chooses. Instead, in setting up each
model run, the presence or absence of combustion controls is captured in the NOX rates assigned to existing units.
State-of-the-art NOX combustion controls are assumed to be used in geographical areas that are subject to NOX
control limits that go into effect after 2003. Within the NOX SIP Call region, however, no additional combustion
controls were assumed, so the controlled base and controlled policy NOX rates are the same.
Each existing fossil-fuel-fired generating unit in the NEEDS, v.2.1.9 database has four NOX emission rates
associated with it from which the IPM set-up program assigns the rate applicable for each specific model scenario.
A "Base Rate" for NOX is said to apply, if under a particular modeled scenario, a unit is not located in a
geographical area affected by NOX control limits beyond those already reflected in the baseline emission rate data
incorporated into NEEDS from the sources described in Steps 2-5 below. A "Policy Rate" for NOX applies if a unit
is located in a geographical area affected by NOX control limits beyond those reflected in the baseline emission
rate data. This results in four NOX rates being associated with each generating unit:
Mode 1= Uncontrolled Base Rate
Mode 2= Controlled Base Rate
Mode 3= Uncontrolled Policy Rate
Mode 4 = Controlled Policy Rate
There are several things to note about the Modes 1-4 designations. "Controlled" refers to the rates provided by
post combustion NOX controls, i.e., selective catalytic reduction (SCR) or selective non-catalytic reduction (SNCR),
if they are present at the unit. For generating units that do not have post-combustion controls, the controlled rate
will be the same as the uncontrolled rate. For generating units that do have post-combustion controls, the
controlled and uncontrolled rates will differ unless the post-combustion controls are operated year round. In such
cases, the "uncontrolled rates" are assigned the "controlled" NOX emission rate. Base and Policy NOX rates will be
same if the unit has state-of-the-art NOX combustion controls or is in the SIP Call region where current combustion
controls are assumed to be retained. Base and policy rates will differ if a unit does not currently have state-of-the-
art combustion controls that would be installed in response to a NOX policy. Examples of each of these instances
are shown in Exhibit 3-9.
The list below enumerates the procedure that is used to derive the four emission rates. Several aspects of the list
are worth noting. (1) Winter NOX rates reported in EPA's Emission Tracking System were used as proxies for the
uncontrolled base NOX rates. (2) There were several units covered by New Source Review (NSR) settlements that
were required to run their SCR year round. This was implemented by making their Mode 1, Mode 2, Mode 3 and
Mode 4 NOX rates all equal to the rate resulting from annual application of SCR. (3) If a unit does not report having
combustion controls, but has an emission rate below a specific cut-off rate (shown in Exhibit 3-9), it is considered
to have combustion controls. (4) For units with combustion controls that were not state-of-the-art, emission rates
without those combustion controls were back calculated and then policy rates were derived assuming the
reductions provided by state-of-the art combustion controls. (5) The NOX rates achievable by state-of-the-art
combustion controls vary by coal rank (bituminous and sub-bituminous) and boiler type. The equations used to
derive these rates are shown in Exhibit 3-10.
Step 1: Four modes for NOX rates were defined:
Mode 1= Uncontrolled Base Rate
Mode 2= Controlled Base Rate
Mode 3= Uncontrolled Policy Rate
Mode 4 = Controlled Policy Rate
Step 2: NOX rates were derived for the summer and winter seasons from the data reported to EPA under Title
IV of the Clean Air Act Amendments of 1990 (Acid Rain Program) and NOX budget program. This data
is maintained in EPA's Emission Tracking System (ETS) and, consequently, the resulting values are
called ETS emission rates.
Step 3: ETS winter NOX rates were used as proxies for uncontrolled baseline NOX rates (Mode 1).
Step 4: For non-coal units in NEEDS without ETS NOX rates, defaults were developed from similar units with
ETS rates. This was done by state, plant type, and post combustion control. If state level defaults were
not available for certain generating units then national level defaults by plant type and post combustion
control were used.
Step 5: For coal units without ETS NOX rates, defaults were developed from similar units with ETS rates. This
was done by state, firing, bottom, combustion control, and post combustion control. If state level
defaults were not available for certain boilers then national level defaults by firing, bottom, combustion
control, and post combustion control were used.
Step 6: Mode 2 was calculated by applying a 90% reduction to the Mode 1 rate of coal units with an SCR as
long as this result was higher than the floor rate of .06 Ib/mmBtu. For units with SNCR the Mode 2 rate
was derived by applying a 35% reduction to the Mode 1 rate. No floor rate was used.
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Step 7: There were several units covered by New Source Review (NSR) settlements that were required to run
their SCR year round. This was implemented by making their Mode 1, Mode 2, Mode 3 and Mode 4
NOX rates all equal to the rate resulting from annual application of SCR.
Step 8: For boilers that were not listed as having either combustion or post-combustion controls, an additional
engineering check was performed to determine if they should be considered to have combustion
controls. Their Mode 1 NOX rate was compared with the cut-off NOX rate indicative of the presence of
combustion controls in similar boilers. If the units Mode 1 NOX rate was less than or equal to the cut-
off rate (in columns 2-4 of Exhibit 3-10), then the boiler was assumed to have a NOX combustion
control and the Mode 3 rate was assigned the same value as the Mode 1 rate.
Step 9: The technology configuration for units listed as having combustion controls were checked to see if
they reflected the presence of state of the art NOX controls. If not, calculations were performed to
provide a NOX rate that would result with state of the art combustion controls. The calculations
(described in Step 10) were tailored to the specific configuration of controls that were in place. This
rate was used as the Mode 3 Uncontrolled Policy NOxRate. This step was not applied to units in the
SIP Call region* since they already had their combustion controls in operation and were unlikely to
move to a higher level of control. The step was also not applied to units that had SCR and to units
whose Mode 1 rate was lower than the cut-off rate (as described in Step 8). All such boilers that were
excluded from this step, were assigned identical Mode 1 and Mode 3 NOX rates.
Step 10: For wall- and tangentially fired units the following procedure was used to calculate the state-of-the-art
combustion control NOX rates required in Step 9. Based on the specific controls in place, one of
several candidate equations (column 4 in Exhibit 3-11) was first used to back-calculate the
uncontrolled emission rate that would have resulted without the existing controls. (In cases where the
applicable equation could not be solved a default removal rate (column 5 in Exhibit 3-11) was used to
back-calculate the uncontrolled emission rate.) Once the uncontrolled NOX rate was calculated, a
removal efficiency equation for the applicable state of the art NOX combustion control was applied to
derive the Mode 3 policy rate. The specific removal equation used depended on the type of boiler and
the predominant coal rank (bituminous orsubbituminous) consumed by the unit. (It is one of those
shown in bold italic in column 4 of Exhibit 3-11)
Step 11: The rate derived in Step 10 was compared to the applicable NOX rate floor (columns 5-7 of Exhibit 3-
10) that engineering analysis indicated applied to each burner type. If the rate derived in Step 10 was
below the applicable floor rate, the floor rate, not the Step 10 rate, was used as the Mode 3 rate.
Step 12: The removal rates for combustion controls on cell, cyclone, and vertically fired boilers were assumed
to be 60%, 50%, and 40% respectively. These were the same assumptions used in EPA Base Case
2003. (See Table A.5..2.2 in Documentation Supplement for EPA Modeling Applications (V.2.1.6)
Using the Integrated Planning Model (EPA 430/R-03-007), July 2003.)
Step 13: The Mode 4 emission rate was calculated by applying a 90% reduction to the Mode 3 rate of coal
units with an SCR as long as this result was higher than the floor rate of .06 Ib/mmBtu. For units with
SNCR the Mode 4 rate was derived by applying a 35% reduction to the Mode 3 rate. No floor rate was
used. (This is the same procedure used to derive the Mode 2 rate from the Mode 1 rate in Step 6.)
The SIP Call region includes Alabama, Connecticut, Delaware, Illinois, Indiana, Kentucky, Maryland, Massachusetts,
Michigan, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Rhode Island, South Carolina, Tennessee, Virginia,
West Virginia, District of Columbia, Georgia, and Missouri.
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Exhibit 3-9. Examples of Base and Policy NOX Rates Occurring in EPA Base Case 2004.
Plant Name
Unique
ID
Post-
CombCo
ntrol
Uncontrol
led NO.
Base Rate
Controlle
dNOx
Base Rate
Uncontrol
led NOX
Policy
Rate
Controlle
dNOx
Policy
Rate
Explanation
Situation 1 : For generating units that do not have post-combustion controls, the controlled and uncontrolled rates will be the same.
JACK
WATSON
2049 B
5
None
0.55
0.55
0.41
0.41
Situation 4 also applies, i.e., unit had LNB and now
added OFA so see drop in policy rates.
Situation 2a: For generating units that do have post-combustion controls, the controlled and uncontrolled rates will differ . . ..
BIG SANDY
1353 B
BSU2
SCR
0.48
0.06
0.48
0.06
(1) Has SCR so see difference between
uncontrolled and controlled rates
(2) Situation 3b also applies.
Situation 2b: ... unless the post-combustion controls are operated year round. In such cases, the "uncontrolled rates" are assigned
the "controlled" NOX rate.
ECAO_KY_Co
al Steam
013 C 0
13
SCR
0.06
0.06
0.06
0.06
Planned/Committed unit so run SCR year-round
Situation 3a: Base and Policy NOX rates will be same if the unit has state-of-the-art NOX combustion controls or ...
SOUTH OAK
CREEK
W A PARISH
4041 B
5
3470 B
WAP5
None
SCR
0.18
0.14
0.18
0.06
0.18
0.14
0.18
0.06
Situationl also applies.
Situation 2a also applies.
Situation 3b: . . . is in the SIP Call region where current combustion controls are assumed to be retained.
WIDOWS
CREEK
SIBLEY
50_B_7
2094 B
3
SCR
None
0.42
0.68
0.06
0.68
0.42
0.68
0.06
0.68
Situation 2a also applies.
(1) Has NOX combustion control and is in SIP so
doesn't get added combustion control. High NOX
rate because it is a cyclone unit
(2) Situation 1 also applies.
Situation 4: Base and policy rates will differ if a unit does not currently have state-of-the-art combustion controls and would install
such controls in response to a NOX policy.
SCHILLER
2367 B
4
SNCR
0.37
0.24
0.32
0.21
(1) Drop in uncontrolled policy NOX rate compared to
uncontrolled base rate is due to addition of
combustion controls. (Note 0.32 is floor.)
(2) Unit has SNCR so Situation #2a also applies
and you see a 35% drop between uncontrolled and
controlled NOX rates.
-------
Exhibit 3-10. Cutoff and Floor NOX Rates (Ibs/mmBtu)
(Table A 5.2.3 in Doc, v.2.1.)
Boiler Type
Wall-Fired Dry-Bottom
Tangentially-Fired
Cell-Burners
Cyclones
Vertically-Fired
Cutoff Rate (Ibs. per MMBtu)
Bit Sub Lig
0.43
0.34
0.43
0.62
0.57
0.33
0.24
0.43
0.67
0.44
0.29
0.22
0.43
0.67
0.44
Floor rate (Ibs. per MMBtu)
Bit Sub Lig
0.32
0.24
0.32
0.47
0.49
0.18
0.12
0.32
0.49
0.25
0.18
0.17
0.32
0.49
0.25
Bit = bituminous, Sub = subbituminous, Lig = lignite
-------
Exhibit 3-11. NOX Removal Efficiencies for Different Combustion Control Configurations.
(State-of-the-art configurations are shown in bold italic.)
Boiler Type
Dry Bottom
Wall-Fired
Dry Bottom
Wall-Fired
Tangentially-Fired
Tangentially-Fired
Coal Type
Bituminous
Sub-bituminous/Lignite
Bituminous
Sub-bituminous/Lignite
Combustion
Control
Technology
LNB
LNB + OF A
LNB
LNB + OF A
LNC1
LNC2
LNC3
LNC1
LNC2
LNC3
Fraction of Removal
0.1 63 + 0.272* Base NOX
0.373 + 0.272* Base NOX
0.135 + 0.541* Base NOX
0.285 + 0.547* Base NOX
0.1 62 + 0.336* Base NOX
0.21 2 + 0.336* Base NOX
0.362 + 0.336* Base NOX
0.20 + 0.71 7* Base NOX
0.25 + 0.71 7* Base NOX
0.35 + 0.717* Base NOX
Default
Removal
0.568
0.718
0.574
0.724
0.42
0.47
0.62
0.563
0.613
0.773
LNB = low NO, burner. OFA = overfire air. LNC = low NO, control
-------
Exhibit 3-12. Title IV SO2 Allowance Assumptions in EPA Base Case 2004, v.2.1.9.
(Table 3.9 in Doc, v.2.1.)
Starting Bank in 2007 4.99 million tons
Annual Allowances: 2007 - 2009 9.47 million tons
Annual Allowances: 2010 - 8.95 million tons
-------
Exhibit 3-13. NOX SIP Call States and Budget
(Table 3.11 in Doc, v.2.1.)
State
Budget (Tons)
AL
CT
DC
DE
GA
IL
IN
KY
MA
MD
Ml
MO
NC
NJ
NY
OH
PA
Rl
SC
TN
VA
WV
29,022
2,652
207
5,250
30,253
32,372
47,731
36,503
15,146
14,656
32,228
24,365
31,821
10,250
31,036
48,990
47,469
997
16,772
25,814
17,187
26,859
Total
527,580
-------
Exhibit 3-14. State Multipollutant Regulations Incorporated in EPA Base Case 2004, v.2.1.9.
(Tables 3.13, 3.14, and 3.15 in Doc, v.2.1. Attachment C in Doc, v.2.1.6.)
State/Region
Arizona, New
Mexico,
Oregon, Utah,
Wyoming
Connecticut
Illinois
Maine
Massachusetts
Minnesota
Missouri
Bill
WRAP
Executive Order
22
Executive Order
19
Public Act No. 30-
72
Title 35, Section
217.706
Chapter 145 NOx
Control Program
310 CMR 7.29
Agreement
between
Minnesota
Pollution Control
Agency and Xcel
Energy
Title 10, Div
Emission
Type
SO2
NOx
SO2
Hg
NOx
NOx
NOx
NOx
SO2
Hg
CO2
NOx, SO2, Hg
NOx
Emission Specifications
Cap of 198,900 tons on all fossil > 25 MW
Emission rate of 0.15 Ib/mmBtu for fossil units
> 15 MW
Emission rate of 0.33 Ib/mmBtu for fossil units
> 15 MW
Emission rate of 0.0000006 Ib/mmBtu for all
coal-fired plants, alternatively can meet a 90%
emission reduction
Emission rate of 0.25 Ib/mmBtu for fossil units
> 25 MW. Some units are allowed to average
their emissions; others must meet the rate on a
facility basis.
Emission rate of 0.22 Ib/mmBtu for fossil units
> 25 MW built before 1995 with a heat input
capacity between 250 and 750 mmBtu/hr
Emission rate of 0.15 Ib/mmBtu for fossil units
>25MW built before 1995 with a heat input
capacity greater than 750 MmBtu/hr
Emission rate of 1 .5 Ib/MWh for the 6
grandfathered units in state
Emission rate of 3.0 Ib/MWh for the 6
grandfathered units in state
Included in bill but limits not yet decided
Emission rate of 1,800 Ib/MWh for the 6
grandfathered units in state
Specific Xcel Energy plants must repower or
install controls
Summer season cap of 43,950 tons on all units
Implementation
Status
2018
2007
2007
2008
2007
2007
2007
2007
2007
-
2007
2007-2009
2007
Status
Added in v.2.1.9
Retained from v.2.1
Retained from v.2.1
Added in v.2.1.9
Added in v.2.1.9
Added in v.2.1.9
Added in v.2.1.9
Retained from v.2.1.6
Retained from v.2.1.6
-
Retained from v.2.1.6
Added in v. 2.1.9
Retained from v.2.1
-------
State/Region
New
Hampshire
New York
North Carolina
Bill
10, Ch 6.350
ENV-A2900
ENV-A3200
Part 237
Clean
Smokestacks
Act
Emission
Type
NOx
SO2
Hg
CO2
NOx
NOx
NOx
SO2
NOx
NOx
SO2
SO2
Emission Specifications
>25MW
Cap of 3,644 tons on all existing fossil steam
units
Cap of 7,289 tons on all existing fossil steam
units
No HG state emission cap on existing fossil
steam units
Cap of 5,425,866 tons on all existing fossil
steam units
Emission rate of 0.15 Ib/mmBtu for fossil plants
> 15 MWin Hillsborough, Merrimack,
Rockingham, and Stafford counties
Emission rate of 0.15 Ib/mmBtu for fossil plants
> 15 MW in all other counties
Non-ozone season cap of 39,908 tons on fossil
units > 25 MW
Annual cap of 197,046 tons starting in 2007
and 131,364 tons starting in 2008 on fossil
units > 25 MW
Cap of 25,000 tons on coal-fired units
belonging to CP&L >25MW
Cap of 35,000 tons starting in 2007 and 31 ,000
starting in 2009 on coal-fired units belonging to
Duke Energy >25MW
Cap of 100,000 tons on 14 coal-fired units
belonging to CP&L >25MW by 2009 and
50,000 tons by 2013 [Title IV allowances
allocated to North Carolina units that exceed
the State's cap will be retired from the federal
program in IPM]
Cap of 150,000 tons on 14 coal-fired units
belonging to Duke Energy >25MW by 2009
and 80,000 tons by 2013 [Title IV allowances
allocated to North Carolina units that exceed
the State's cap will be retired from the federal
program in IPM]
Implementation
Status
2007
2007
—
2007
2007
2007
2007
2007
2007
2007
2009
2009
Status
Retained from v.2. 1.6
Retained from v.2. 1.6
—
Retained from v.2. 1.6
Added in v. 2.1.9
Added in v. 2.1.9
Added in v. 2.1.9
Added in v. 2.1.9
Retained from v.2. 1.6
Retained from v.2. 1.6
Retained from v.2. 1.6
Retained from v.2. 1.6
-------
State/Region
Oregon
Texas
Bill
Oregon
Administrative
Rules, Chapter
345, Division 24
Senate Bill 7
Ch. 117
Emission
Type
CO2
NOx-
East
NOx-
West
NOx - El
Paso
SO2 - East
SO2-
West
SO2 - El
Paso
NOx-
Houston
NOx-
Dallas/For
t Worth
NOx-
East/Cent
ral
Emission Specifications
Annual emission rate of 675 Ib/MWh for new
Combustion turbines burning natural gas with
a CF >75%, and all new non-base load plants
(with a CE <=75%) emitting CO2
Annual emission cap of 58,365 tons for all
grandfathered fossil > 25MW[all of Texas
traversed by or east of Rt 35]
Annual emission cap of 18,028 tons for all
grandfathered fossil > 25MW[all of Texas not
in East region or El Paso
county]
Annual emission cap of 1 ,058 tons for
All grandfathered fossil > 25MW[EI Paso
county]
Annual emission cap of 111,183 tons for all
grandfathered
fossil > 25MW [all of Texas traversed by or
east of Rt 35]
25% reduction from 1997 baseline for all
grandfathered
fossil > 25MW [all of Texas not in East region
or El Paso
county]
25% reduction from 1997 baseline for all
grandfathered
fossil > 25MW [El Paso county]
Cap of 8,459 tons applied to all fossil units
unit-specific rate limits that can alternatively be
met by a system-wide averaging cap of 2,164
tons applied to all fossil units
unit-specific rate limits that can alternatively be
met by a system-wide averaging cap of
123,528 tons applied to all fossil units
Implementation
Status
2007
2007
2007
2007
2007
2007
2007
2007
Status
Added in v.2.1.9
Retained from v.2. 1.6
Retained from v.2. 1.6
Retained from v.2. 1.6
Retained from v.2. 1.6
Retained from v.2.1
Retained from v.2.1
Retained from v.2.1
-------
State/Region
Wisconsin
We Energies
(WEPCO)
owns
5 coal and 3
natural gas
facilities
affected by
agreement
Bill
Cooperative
agreement
between
WEPCO and
DNR
Wisconsin
Dept of
Natural
Resources
(PUB-AM-
3162001)
Emission
Type
SO2
NOx
Hg
Emission Specifications
System-wide emission limit of .70 Ib/mmBtu in
2008 and .45
Ib/mmBtu in 2013 for WEPCO coal plants
System-wide emission limit of .25 Ib/mmBtu in
2008 and .15
Ib/mmBtu in 2013 for WEPCO coal plants
Planned 10% reduction from '98-00 levels by
2007 and 50%
Reduction by 2012, but no cap approved yet
Implementation
Status
2007/2012
2007/2012
Status
Retained from v.2. 1.6
Retained from v.2. 1.6
-------
Exhibit 3-15. New Source Review (NSR) Settlements in EPA Base Case 2004, v.2.1.9. (Attachment D in Doc, v.2.1.6.)
Company and Plant
Unit
Settlement Actions
Retire/Repower
Action
Effective
Date
SO2 Control
Equipment
Percent
Removal
or Rate
(Ib/mmBtu)
Effective
Date
NOx Control
Equipment
Rate
(Ib/mmBtu)
Effective
Date
PM or Mercury Control
Equipment
Rate
(Ib/mmBtu)
Effective
Date
Notes
SIGECO
F B Culley
Unitl
Unit 2
Units
Repower to natural
gas (or retire)
31-Dec-06
Improve &
Continuously
Existing FGD
(shared by units
2&3)
Improve &
Continuously
Operate
Existing FGD
(shared by units
2 & 3)
95%
95%
30-Jun-04
30-Jun-04
Operate
Existing SCR
Continuously
0.1
1-Sep-03
Install &
Continuousl
y Operate a
Baghouse
0.015
30-Jun-07
Settlement requires that unit 1
must either shutdown or repower
to natural gas. In EPA Base
Case 2004 EPA assumed that
the unit will be repowered.
Improved operation of the FGD is
hardwired into EPA Base Case
2004
Improved operation of the FGD,
continuous operation of the SCR,
and installation of the baghouse
are hardwired into EPA Base
Case 2004.
PSEG FOSSIL
Bergen
Hudson
Mercer
Unit 2
Unit 2
Unitl
Unit 2
Repower to
combined cycle
31-Dec-02
Install Dry FGD
(or approved alt
tech) & Operate
at All Times Unit
Operates
Install Dry FGD
(or approved alt
tech) & Operate
at All Times Unit
Operates
Install Dry FGD
0.15
0.15
0.15
31-Dec-
06
31-Dec-
10
31-Dec-
Install SCR
(or approved
alt tech) &
Operate
Year-Round
Install SCR
(or approved
alt tech) &
Operate
Year-Round
Install SCR
0.1
0.13
0.13
1 -May-07
Install
Baghouse
(or
approved alt
tech)
0.015
Ozone season only - 2005;
annually May 1, 2006
Ozone season only - 2004;
31-Dec-
06
This action is hardwired into EPA
Base Case 2004.
The FGD and baghouse are
hardwired into EPA Base Case
2004. The SCR is modeled as
an individual emissions
constraint. The settlement
requires coal with monthly avg
sulfur content no greater than 2%
at units operating FGD — this
limit is modeled as a coal choice
exception in EPA Base Case
2004.
The SCR is hardwired into EPA
Base Case 2004; the FGD is
modeled as an individual
emissions constraint. The
settlement requires coal with
monthly avg sulfur content no
greater than 2% at units
operating FGD - this limit is
modeled as a coal choice
exception in EPA Base Case
2004.
The SCR is hardwired into EPA
-------
Exhibit 3-15. New Source Review (NSR) Settlements in EPA Base Case 2004, v.2.1.9. (Attachment D in Doc, v.2.1.6.)
Company and Plant
Unit
Settlement Actions
Retire/Repower
Action
Effective
Date
SO2 Control
Equipment
(or approved alt
tech) & Operate
at All Times Unit
Operates
Percent
Removal
or Rate
(Ib/mmBtu)
Effective
Date
12
NOx Control
Equipment
(or approved
alt tech) &
Operate
Year-Round
Rate
(Ib/mmBtu)
Effective
Date
PM or Mercury Control
Equipment
Rate
(Ib/mmBtu)
annually May 1, 2006
Effective
Date
Notes
Base Case 2004; the FGD is
modeled as an emission
constraint. The settlement
requires coal with monthly avg
sulfur content no greater than 2%
at units operating FGD - this
limit is modeled as a coal choice
exception in EPA Base Case
2004.
TECO
Big Bend
Unit 1
Unit 2
Units
Unit 4
Existing
Scrubber
(shared by units
1 &2)
Existing
Scrubber
(shared by units
1 &2)
Existing
Scrubber
(shared by units
3&4)
Existing
Scrubber
(shared by units
3&4)
95%
(95% or
0.25)
95%
(95% or
0.25)
93% if
units 3 &
4 are
operating
; 95% or
an
emission
rate of
0.3 if unit
3 alone
is
operating
(95% or
0.25)
93% if
units 3 &
4 are
operating
Sept 1 ,
2000
(Jan 1 ,
2013)
Sept 1 ,
2000
(Jan 1 ,
2013)
2000 (Jan
1 , 201 0)
year 2000
Install SCR
(or other
approved
tech)
Install SCR
(or other
approved
tech)
Install SCR
(or other
approved
tech)
Install SCR
(or other
approved
tech)
0.1
0.1
0.1
0.1
1 -May-09
1 -May-09
1 -May-09
1-Jun-07
Settlement requires that units 1 ,
2, 3 and 4 elect to either
shutdown repower or remain
coal-fired (and install SCR), and
advise EPA of decision by May 1 ,
2007 for units 1 through 3 and by
May 1 , 2005 for unit 4. The FGD
are already in place thus are built
into EPA Base Case 2004. The
SCR requirements are modeled
as individual emissions
constraints. SCR effective dates
in the settlement for units 1
through 3 are: (1 ) for the first unit
to remain coal fired or if only one
is to be coal-fired, May 1 , 2008;
(2) for the second unit to remain
coal-fired, if there is one, May 1,
2009; (3) for the third unit, if there
is one, May 1, 2010. For
simplification EPA assumed an
effective date in 2009 for all three
units.
-------
Exhibit 3-15. New Source Review (NSR) Settlements in EPA Base Case 2004, v.2.1.9. (Attachment D in Doc, v.2.1.6.)
Company and Plant
Gannon
Unit
Six
Units
Settlement Actions
Retire/Repower
Action
Retire all six coal
units and repower
at least 550 MW of
coal capacity to
natural gas
Effective
Date
31-Dec-04
SO2 Control
Equipment
Percent
Removal
or Rate
(Ib/mmBtu)
Effective
Date
NOx Control
Equipment
Rate
(Ib/mmBtu)
Effective
Date
PM or Mercury Control
Equipment
Rate
(Ib/mmBtu)
Effective
Date
Notes
Settlement requires all six coal
units to shutdown by Dec 31 ,
2004. By May 1 , 2003 at least
200 MW of coal capacity must be
repowered and by Dec 31 , 2004
additional coal capacity must be
repowered such that total coal
capacity repowered is at least
550 MW. Retirement of all coal
units and repowering as two
natural gas units are built into
EPA Base Case 2004. New
plant is called Bayside Station.
We Energies (WEPCO)
Presque Isle
Units
1,2,3
and 4
Units 5
& 6
Retire or install
S02 and NOx
controls
31-Dec-12
Install FGD (or
approved equiv
control tech) &
Operate
Continuously
95% or
0.1
31-Dec-
12
Install SCR
(or approved
equiv control
tech) &
Operate
Continuously
Install &
Operate Low
NOx Burner
0.1
31-Dec-
12
31-Dec-
03
WEPCO may elect to retire or
install controls at Presque Isle
units 1 through 4. For EPA Base
Case 2004, we imposed the SO2
and NOx limits as individual
emission constraints.
LNBs on Presque Isle units 5 & 6
are hardwired in EPA Base Case
2004.
-------
Exhibit 3-15. New Source Review (NSR) Settlements in EPA Base Case 2004, v.2.1.9. (Attachment D in Doc, v.2.1.6.)
Company and Plant
Plssssnt Prsiris
Oak Creek
Unit
Units 7
&8
Unit 9
Unit 1
Unit 2
Units 5
&6
Settlement Actions
Retire/Repower
Action
Retire or install
SO2and NOx
controls
Effective
Date
31-Dec-12
SO2 Control
Equipment
Install FGD (or
approved equiv
control tech) &
Operate
Continuously
Install FGD (or
approved equiv
control tech) &
Operate
Continuously
Install FGD (or
approved equiv
control tech) &
Operate
Continuously
Percent
Removal
or Rate
(Ib/mmBtu)
95% or
0.1
95% or
0.1
95% or
0.1
Effective
Date
31-Dec-
06
31-Dec-
07
31-Dec-
12
NOx Control
Equipment
Operate
Existing Low
NOx Burner
Operate
Existing Low
NOx Burner
Install SCR
(or approved
equiv control
tech) &
Operate
Continuously
Install SCR
(or approved
equiv control
tech) &
Operate
Continuously
Install SCR
(or approved
equiv control
tech) &
Operate
Continuously
Rate
(Ib/mmBtu)
0.1
0.1
0.1
Effective
Date
31 -Dec-
OS
31-Dec-
06
31-Dec-
06
31-Dec-
03
31-Dec-
12
PM or Mercury Control
Equipment
Install
Baghouse
Install
Baghouse
Rate
(Ib/mmBtu)
Effective
Date
Notes
LNBs on units Presque Isle 7, 8
& 9 are hardwired in EPA Base
Case 2004. The settlement
requires demonstration of full-
scale TOXECON with activated
carbon injection for mercury
removal at units 7, 8 & 9.
Baghouses are being installed for
the TOXECON, and these units
already have ESP in place. In
EPA Base Case 2004, ESP and
baghouses are hardwired on
these units, and mercury
emissions modification factor
(EMF) for ESP & baghouse
combination is applied. Future
versions of IPM may include a
greater mercury removal
efficiency at these units,
depending on the outcome of the
TOXECON demonstration.
(Settlement requires compliance
with the specified SO2 & NOx
efficiency or limit by one-month
after the required installation date
shown in this table for Pleasant
Prairie units 1 & 2.) In EPA Base
Case 2004, FGD on unit 1 and
SCR on units 1 & 2 are
hardwired. FGD on unit 2 is
modeled as an individual
emissions constraint.
WEPCO may elect to retire or
install controls at Oak Creek
units 5 & 6. For EPA Base Case
2004, we imposed the SO2 and
NOx limits as individual emission
constraints.
-------
Exhibit 3-15. New Source Review (NSR) Settlements in EPA Base Case 2004, v.2.1.9. (Attachment D in Doc, v.2.1.6.)
Company and Plant
Port Washington
Valley
Unit
Unit?
Units
Units
1,2,3
and 4
Settlement Actions
Retire/Repower
Action
Retire (also have
option to install
S02 and NOx
controls but have
opted to retire &
repower - see
notes column)
Boilers 1, 2, 3 & 4
Effective
Date
SO2 Control
Equipment
Install FGD (or
approved equiv
control tech) &
Operate
Continuously
Install FGD (or
approved equiv
control tech) &
Operate
Continuously
Percent
Removal
or Rate
(Ib/mmBtu)
95% or
0.1
95% or
0.1
Effective
Date
31-Dec-
12
31-Dec-
12
NOx Control
Equipment
Install SCR
(or approved
equiv control
tech) &
Operate
Continuously
Install SCR
(or approved
equiv control
tech) &
Operate
Continuously
Rate
(Ib/mmBtu)
0.1
0.1
Units 1 , 2 & 3 by Dec 31 , '04; unit 4 by entry of the consent decree
Operate Existing Low
NOx Burner
Effective
Date
31-Dec-
12
31-Dec-
12
PM or Mercury Control
Equipment
Rate
(Ib/mmBtu)
Effective
Date
30-days after date of lodging of the Consent
Decree
Notes
(Settlement requires compliance
with the specified SO2 & NOx
efficiency or limit by one-month
after the required installation date
shown in this table for Oak Creek
units 7 & 8.) In EPA Base Case
2004, the required SO2 & NOx
controls on these units are
modeled as individual emission
constraints.
WEPCO announced plans to
retire Port Washington and
repower with two natural gas
units. Retirement of the four coal
units and repowering of the first
natural gas unit are hardwired in
EPA Base Case 2004.
LNBson units 1, 2, 3 & 4 are
hardwired in EPA Base Case
2004.
VEPCO
Mount Storm
Chesterfield
Units 1, 2 and 3
Unit 4
Units
FGD (Construct
or Improve, as
Applicable)
FGD (Construct
or Improve, as
Applicable)
95%
(can opt
to meet
0.1 5 rate
in lieu of
percent
removal,
pending
demonstr
ation)
95%
(can opt
to meet
0.1 3 rate
in lieu of
percent
removal,
pending
1-Jan-05
1 2-Oct-1 2
Install SCR &
Operate
Year-Round
Install SCR &
Operate
Year-Round
Install SCR &
Operate
Year-Round
0.11
0.1
0.1
1-Jan-08
1-Jan-13
1-Jan-12
Units 1 , 2 and 3 have installed
FGD. Units 1 & 2 have installed
SCR. These controls are built
into EPA Base Case 2004. The
SCR requirement for unit 3 is
modeled as an emissions
constraint.
SCR on this unit is modeled as
an individual emission constraint
in EPA Base Case 2004.
SCR and FGD on this unit are
modeled as individual emission
constraints in EPA Base Case
2004.
-------
Exhibit 3-15. New Source Review (NSR) Settlements in EPA Base Case 2004, v.2.1.9. (Attachment D in Doc, v.2.1.6.)
Company and Plant
Chesapeake Energy
Center
Clover
Possum Point
Unit
Unite
Units 3
snd 4
Units 1
and 2
Units 3
and 4
Settlement Actions
Retire/Repower
Action
Retire and
Repowerto
Natural Gas
Effective
Date
2-May-03
SO2 Control
Equipment
FGD (Construct
or Improve, as
Applicable)
Improve
Existing FGD
Percent
Removal
or Rate
(Ib/mmBtu)
demonstr
ation)
95%
(can opt
to meet
0.1 3 rate
in lieu of
percent
removal,
pending
demonstr
ation)
95%
(can opt
to meet
0.1 3 rate
in lieu of
percent
removal,
pending
demonstr
ation)
Effective
Date
1-Jan-10
1-Sep-03
NOx Control
Equipment
Install SCR &
Operate
Year-Round
Install SCR &
Operate
Year-Round
Rate
(Ib/mmBtu)
0.1
0.1
Effective
Date
1-Jan-11
1-Jan-13
PM or Mercury Control
Equipment
Rate
(Ib/mmBtu)
Effective
Date
Notes
SCR and FGD on this unit are
modeled as individual emission
constraints in EPA Base Case
2004.
SCR on these units are modeled
as individual emission constraints
in EPA Base Case 2004.
Settlement requires system-wide
interim NOx control actions, but
the interim actions occur before
the initial model run year so EPA
didn't include them in EPA Base
Case 2004. FGD on Clover units
1 & 2 are hardwired into EPA
Base Case 2004.
This action is hardwired into EPA
Base Case 2004
Santee Cooper
Cross
Unitl
Unit 2
Upgrade
Existing FGD &
Continuously
Operate
Upgrade
Existing FGD &
Continuously
Operate
95%
87%
30-Jun-06
30-Jun-06
Install &
Continuously
Operate SCR
(or approved
equiv control
tech)
Install &
Continuously
Operate SCR
(or approved
equiv control
tech)
0.1
0.11 /0.1
31-May-
04
May 31 ,
2004 /
May 31 ,
2007
SCR must be in operation on unit
1 upon entry of the consent
decree. FGD must be upgraded
by Dec 31 , '05. Effective dates
for NOx rate & SO2 efficiency are
as shown in table. SCR and
FGD are hardwired into EPA
Base Case 2004.
SCR must be in operation on unit
2 upon entry of the consent
decree; effective date for 0.1 1
NOx rate is May 31 , '04 & for 0.1
NOx rate is May 31 , '07. FGD
must be upgraded by Dec 31 ,
'05; effective date for SO2
-------
Exhibit 3-15. New Source Review (NSR) Settlements in EPA Base Case 2004, v.2.1.9. (Attachment D in Doc, v.2.1.6.)
Company and Plant
Winy ah
Unit
Unit 1
Unit 2
Unit 3
Unit 4
Settlement Actions
Retire/Repower
Action
Effective
Date
SO2 Control
Equipment
Install &
Continuously
Operate FGD
(or approved
equivtech)
Install &
Continuously
Operate FGD
(or approved
equivtech)
Upgrade
Existing FGD &
Continuously
Operate
Upgrade
Existing FGD &
Continuously
Operate
Percent
Removal
or Rate
(Ib/mmBtu)
95%
95%
90%
90%
Effective
Date
31 -Dec-
OS
31 -Dec-
OS
31-Dec-
12
31-Dec-
07
NOx Control
Equipment
Install &
Continuously
Operate SCR
(or approved
equiv control
tech)
Install &
Continuously
Operate SCR
(or approved
equiv control
tech)
Install &
Continuously
Operate SCR
(or approved
equiv control
tech)
Install &
Continuously
Operate SCR
(or approved
equiv control
tprhl
ICUI If
Rate
(Ib/mmBtu)
0.11 /0.1
0.12
0.14/
0.12
0.13/
0.12
Effective
Date
NovSO,
2004 /
NovSO,
2007
30-Nov-
04
NovSO,
2005 /
NovSO,
2008
NovSO,
2005 /
NovSO,
2008
PM or Mercury Control
Equipment
Rate
(Ib/mmBtu)
Effective
Date
Notes
efficiency is as shown in table;
FGD upgrade must be designed
to 91% removal efficiency. SCR
is hardwired into EPA Base Case
2004.
SCR must be in operation on unit
1 by May 31 , '04; effective date
for 0.1 1 NOx rate is Nov 30, '04
& for 0.1 rate is NovSO, '07.
FGD must be in operation by
June 30, '08; effective date for
SO2 efficiency is as shown in
table. SCR is hardwired into
EPA Base Case 2004. SCR is
modeled as individual emissions
constraint.
SCR must be in operation on unit
2 by May 31 , '04. FGD must be
in operation by June 30, '08;
effective date for NOx rate &
SO2 efficiency are as shown in
table. SCR is hardwired into
EPA Base Case 2004. FGD is
modeled as individual emissions
constraint.
SCR must be in operation on unit
3 by May 31 , '05; effective date
for 0.14 NOx rate is Nov 30, '05
& for 0.12 rate is Nov 30, '08.
FGD must be upgraded by June
30, '12; effective date for SO2
efficiency is as shown in table.
SCR is hardwired into EPA Base
Case 2004. FGD is modeled as
individual emissions constraint.
SCR must be in operation on unit
4 by May 31 , '05; effective date
for 0.13 NOx rate is Nov 30, '05
& for 0.12 rate is Nov 30, '08.
FGD must be upgraded by June
30, '07; effective date for SO2
efficiency is as shown in table.
SCR is hardwired into EPA Base
Case 2004. FGD is modeled as
-------
Exhibit 3-15. New Source Review (NSR) Settlements in EPA Base Case 2004, v.2.1.9. (Attachment D in Doc, v.2.1.6.)
Company and Plant
Grainger
Jefferies
Unit
Unitl
Unit 2
Units 3
&4
Settlement Actions
Retire/Repower
Action
Effective
Date
SO2 Control
Equipment
Percent
Removal
or Rate
(Ib/mmBtu)
Effective
Date
NOx Control
Equipment
Operate Low
NOx Burner
(or More
Stringent
Technology)
Operate Low
NOx Burner
(or More
Stringent
Technology)
Operate Low
NOx Burner
(or More
Stringent
Technology)
Rate
(Ib/mmBtu)
Effective
Date
Upon
Entry of
the
Consent
Decree
1 -May-04
Upon
Entry of
the
Consent
Decree
PM or Mercury Control
Equipment
Rate
(Ib/mmBtu)
Effective
Date
Notes
individual emissions constraint.
LNBson units 1 & 2 are
hardwired in EPA Base Case
2004.
LNBson units 3 & 4 are
hardwired in EPA Base Case
2004.
Notes
1. This summary table describes New Source Review settlement actions as they are represented in EPA Base Case 2004. The settlement actions are simplified for representation in the model. This table is not
intended to be a comprehensive description of all elements of the actual settlements agreements.
2. Settlement actions for which the required emission limits will be effective by the time of the first model run year (before January 1, 2007) are built into the database of units used in EPA Base Case 2004
("hardwired"). However, future actions are generally modeled as individual constraints on emission rates in EPA Base Case 2004, allowing the modeled economic situation to dictate whether and when a unit
would opt to install controls versus retire.
3. Some control installations that are required by these NSR settlements have already been taken by the affected companies, even if deadlines specified in their settlement haven't occurred yet. Any controls that
are already in place are built into EPA Base Case 2004.
4. If a settlement agreement requires installation of PM controls, then the controls are shown in this table and reflected in EPA Base Case 2004. If settlement requires optimization or upgrade of existing PM
controls those actions aren't included in EPA Base Case 2004. EPA doesn't model PM emissions in EPA Base Case 2004.
5. For units for which an FGD is modeled as an emissions constraint in EPA Base Case 2004, EPA used the assumptions on removal efficiencies that are shown in Exhibit 5-1 of this documentation report.
6. For units for which an FGD is hardwired in EPA Base Case 2004, EPA assumed installation of an FGD with a percent removal of 95% (except for PSEG Hudson unit 2 and Mercer units 1 & 2, for which the
settlement specifies dry FGD and EPA assumes a percent removal of 90%).
7. For units for which an SCR is modeled as an emissions constraint or is hardwired in EPA Base Case 2004, EPA assumed an emissions rate equal to 10% of the unit's uncontrolled rate, with a floor of 0.06
Ib/mmBtu or used the emission limit if provided.
8. The applicable low NOx burner reduction efficiencies are shown in Exhibit 3-11 in this documentation report.
9. EPA included in EPA Base Case 2004 the requirements of the settlements as they existed on March 19, 2004. At that time the WEPCO and Santee Cooper settlements hadn't yet been entered by judge.
10. Some of the NSR settlements require the retirement of SO2 allowances. For Base Case 2004, EPA estimated the amount of allowances to be retired from these settlements and adjusted the total Title IV
allowances accordingly. See Exhibit 6-4.
-------
Exhibit 3-16. Emission and Removal Rate Assumptions for Potential (New) Units In EPA Base Case 2004, v.2.1.9.
(Table 3.16 in Doc, v.2.1. Attachment E in Doc, v.2.1.6.)
Gas
S02
NOX
C02
Controls, Removal,
and Emissions Rates
Removal/Emissions
Rate
Emission Rate
Emission Rate
Conventioal Pulverized
Coal
95% from sulfur
content of coal
0.06 Ib/mmBtu
205.3-215.4
lb/mmBtu2
Integrated
Gasification
Combined Cycle
99%
0.02 Ib/mmBtu
205.3-215.4
Ib/mmBtu
Conventional
and Advanced
Combined
Cycle
None
0.02 Ib/mmBtu
117.08
Ib/mmBtu
Conventional and
Advanced
Combustion
Turbine
None
0.08 Ib/mmBtu
117.08
Ib/mmBtu
Biomass
Integrated
Gasification
Combined Cycle
0.08
Ibs/mmBtu
0.02 Ib/mmBtu
No net
emissions
Geothermal
None
None
Landfill
Gas
100%
0.246 Ib/mmBtu
-------
Exhibit 3-17. International Electricity Imports.
(Table 3.5 in DOC, v.2.1)
Net International Imports (billion kWh)
2007
41
2010
44
2015
40
2020
27
Source: Based on AEO 2004
-------
Section 4
Generating Resources
List of Exhibits
Exhibit 4-1 Data Sources for NEEDS 2.1.9
Exhibit 4-2 Data Sources for Unit Configuration in NEEDS 2.1.9.
Exhibit 4-3 Hierarchy of Data Sources for Capacity in NEEDS 2.1.9
Exhibit 4-4 Rules Used in Populating NEEDS 2.1.9
Exhibit 4-5 Summary of Population (through 2003) in NEEDS 2.1.9
Exhibit 4-6 Aggregation Profile of Model Plants As Provided at Set Up of EPA Base Case 2004.
Exhibit 4-7 Summary of Committed Units in EPA Base Case 2004, v.2.1.9.
Exhibit 4-8 Planned-Committed Units in EPA Base Case 2.1.9 by Model Region.
Exhibit 4-9 Performance and Unit Cost Assumptions for Potential (New) Capacity from Conventional
Fossil Technologies in EPA Base Case 2004, v.2.1.9
Exhibit 4-10 Performance and Unit Cost Assumptions for New Capacity from Renewable and Non-
Conventional Technologies in EPA Base Case 2004, v.2.1.9.
Exhibit 4-11 Regional Cost Adjustment Factors for Conventional and Renewable Generating
Technologies.
Exhibit 4-12 Assumptions on Potential Geothermal Electric Capacity.
Exhibit 4-13 Assumptions on Potential Wind Capacity by Wind Class (MW).
Exhibit 4-14 Reserve Margin Contribution and Average Capacity Factor by Model Region
Exhibit 4-15 Reserve Margin Contribution and Average Capacity Factor by Wind Class and Model
Region.
Exhibit 4-16 Illustrative* Hourly Generation Profile from Wind (kWh of Generation per MW of
Electricity)
Exhibit 4-17 Illustrative* Hourly Generation Profile From Solar Thermal and Solar Photovoltaic (kWh of
Generation per MW of Electricity).
Exhibit 4-18 Average Regional Nuclear Capacity Factors in EPA Base Case 2004, v.2.1.9.
Exhibit 4-19 Nuclear Upratings and Scheduled Retirements (MW) as Incorporated in EPA Base Case
2004, v.2.1.9 from AEO 2004.
Exhibit 4-20 Key Characteristic of Existing Nuclear Units in NEEDS, v.2.1.9.
Exhibit 4-21 Cost and Performance Assumptions for Repowering Options in EPA Base Case 2004,
v.2.1.9.
-------
Exhibit 4-1. Data Sources for NEEDS 2.1.9
(Table 4.1 in Doc, v.2.1.)
Data Source
Data Source Documentation
DOE's Form EIA-860
DOE's Form EIA-767
NERC Electricity Supply
and Demand (ES&D)
database
DOE's Annual Energy
Outlook (AEO) 2004
Platts' NewGen
Database
EPA's Emission
Tracking System (ETS)
NEEDS 2.1.6
DOE's Form EIA-860 is an annual survey of power plants at the
generator level. It contains data such as summer, winter and
nameplate capacity, location (state and county), status, prime mover,
primary energy source, in-service year, and a plant-level cogenerator
lag.
DOE's Form EIA-767 is an annual survey, "Steam-Electric Plant
Operation and Design Report", that contains data for utility nuclear and
bssil fuel steam boilers such as fuel quantity and quality; boiler
dentification, location, status, and design information; and post-
sombustion NOX control, FGD scrubber and particulate collector device
nformation. Note that boilers in plants with less than 10 MWdo not
•eport all data elements. The relationship between boilers and
generators is also provided, along with generator-level generation and
nameplate capacity. Note that boilers and generators are not
necessarily in a one-to-one correspondence.
The NERC ES&D is released annually. It contains generator-level
nformation such as summer, winter and nameplate capacity, state,
NERC region and sub-region, status, primary fuel and on-line year.
The Annual Energy Outlook 2004 (AEO2004) presents midterm
Forecasts of energy supply, demand, and prices through 2025 prepared
by the Energy Information Administration (EIA). The projections are
based on results from ElA's National Energy Modeling System (NEMS).
nformation from AEO2004, such as heat rate, RPS induced renewable
builds, etc. is adopted in NEEDS 2.1.9.
NEWGen delivers a comprehensive, detailed assessment of the current
status of proposed power plants in the United States. NEWGen
nformation is continually updated by Platts' research staff and NEEDS
2.1.9 used the information updated in December 2003.
The Emission Tracking System (ETS) database is updated quarterly. It
contains boiler-level information such as primary fuel, heat input, SO2
and NOX controls, and SO2, NOX and CO2 emissions. NEEDS 2.1.9
used Quarters 3&4 of 2002 and Quarters 1&2 of 2003 for developing
mission rate and used Quarter 4 of 2003 for developing post-
combustion control information.
NEEDS 2.1.6 was developed by US EPA for the EPA Base Case 2003
(v. 2.1.6). NEEDS 2.1.9 is an update to NEEDS 2.1.6.
(Detailed descriptions of the data sources used in NEEDS 2.1.6 can be
:ound in the following U.S. Environmental Protection Agency reports:
Documentation Supplement for EPA Modeling Applications (V.2.1.6)
Using the Integrated Planning Model (EPA 430/R-03-007), July 2003
(see item 8 of the "Summary Table of V.2.1.6 Updates"), and
Documentation of EPA Modeling Applications (V.2.1) Using the
integrated Planning Model (EPA 430/R-02-004), March 2002 (see
sections 4.1 and 4.2). Both reports are available on the web at
iwww.epa.gov/airmarkets/epa-ipm.
-------
Exhibit 4-2. Data Sources for Unit Configuration in NEEDS 2.1.9
(Table 4.6 in Doc, v.2.1.)
Unit Component
Firing Type
Bottom Type
SO2 Pollution Control*
NOx Pollution Control*
Particulate Matter
Control
Primary Data Source
2001 EIA 767
2001 EIA 767
EPA's Emission Tracking System
(ETS)- 4th Quarter of 2003.
EPA's Emission Tracking System
(ETS) -4th Quarter of 2003.
NEEDS 2. 1.6
Secondary Data Source
NEEDS 2. 1.6
NEEDS 2. 1.6
2001 EIA 767
2001 EIA 767
Default
—
—
No control
No control
No control
*ln addition to the primary and secondary data sources listed here, the following sources were consulted and
emission controls were updated when corroborating information could be found: Mcllvaine Utility Upgrade
Database, M.J. Bradley & Associates (for NOX controls), Argus Media Environmental Controls Directory and
Resource Guide, Argus Media SCR Update April 1, 2003, ICAC (Institute of Clean Air Companies), National
Park Service survey, and web sites of generating unit owners and operators.
-------
Exhibit 4-3. Hierarchy of Data Sources for Capacity in NEEDS 2.1.9
(Table 4.4 in Doc, v.2.1.)
Sources Presented in Hierarchy
NEEDS 2.1.6
2001 EIA 860 Summer Capacity
NERC ES&D 2003 Summer Capacity
2001 EIA 860 Winter Capacity
NERC ES&D 2003 Winter Capacity
2001 EIA 860 Nameplate Capacity
Notes:
1. Presented in hierarchical order that applies.
2. If capacity is zero, do not include unit.
-------
Exhibit 4-4. Rules Used in Populating NEEDS 2.1.9
(Table 4.2 in Doc, v.2.1.)
Scope
Geographic
Excluded units in Alaska or Hawaii
Capacity _ Excluded units with reported nameplate, summer and winter capacity of zero
Status _ Excluded units on long-term scheduled maintenance or units with forced
outages for greater than three months or retired (i.e. units with status codes
"OS" or "RE" in EIA Forms)
Excluded five units with status standby or cold standby that no longer reported
emissions to the Acid Rain or NOX Budget Programs
Status of boiler(s) and associated generator(s) were taken into account for
determining operation status
Planned or _ Included planned units that had broken ground or secured financing and were
Future Units expected to be online by the end of 2006
Firm/Non-firrr^ Excluded non-utility onsite generators that do not produce electricity for sale to
Electric Sales the grid.
Excluded all mobile and distributed generators
-------
Exhibit 4-5. Summary of Population (through 2003) in NEEDS 2.1.9
(Table 4.3 in Doc, v.2.1.)
Plant Type
Biomass
Coal Steam
Combined Cycle
Fossil Waste
Geothermal
Hydro
IGCC
Import
Landfill Gas
Non-Fossil Waste
Nuclear
O/G Steam
Other
Pumped Storage
Solar
Turbine
Wind
Total
Number of Units
121
1,237
994
6
197
3,886
3
5
187
114
104
785
15
141
37
5,453
322
13,607
Capacity (MW)
1,528
303,007
129,261
404
2,675
89,876
612
9,000
440
2,427
100,220
127,254
45
19,765
336
132,025
5,996
924,870
-------
Exhibit 4-6. Aggregation Profile of Model Plants As Provided at Set Up of EPA Base Case 2004.
(Table 4.7 in Doc., v.2.1 and Attachment A, Table A-1 in Doc, v.2.1.6.)
Existing and Planned/Committed Units
Plant Type
Coal Steam
Oil/Gas Steam
Combined Cycle
Turbine
Integrated Gas Combined Cycle (IGCC)
Nuclear
Hydro
Pumped Storage
Biomass
Wind
Fuel Cell
Solar
Geothermal
Landfill Gas
Fossil Waste
Non-Fossil Waste
Total
Number of Units
1,242
785
1,025
5,479
3
104
3,886
141
144
351
0
87
217
210
8
132
13,814
Number of IPM model Plants
694
244
243
513
3
104
74
21
40
33
0
5
5
23
7
44
2,053
Retrofits
Coal To Scrubber Retrofit
Retrofit Coal to Scrubber+SCR
Retrofit Coal to Scrubber+SNCR
Retrofit Coal to Gas Reburn
Retrofit Coal to Gas Reburn + Scrubber
Retrofit Coal to Selective Catalytic Reduction (SCR)
Retrofit Coal to Selective Noncatalytic Reduction (SNCR)
Retrofit Coal to Activated Carbon Injection (ACI)
Retrofit Coal to ACI + SCR
Retrofit Coal to ACI + SNCR
Retrofit Coal to ACI+Scrubber
Retrofit Coal to ACI+Scrubber+SCR
Retrofit Coal to ACI+Scrubber+SNCR
Retrofit Oil and Gas to SCR
Retrofit Oil and Gas to SNCR
Retrofit Nuclear - 1 0 year extension at age 30
Retrofit Nuclear - 20 year extension at age 40
Retrofit Nuclear - 10 and 20 year extensions
Total
Number of Units
—
—
—
—
...
...
...
—
—
—
—
—
—
—
—
...
...
...
—
Number of IPM model Plants
533
1,171
475
0
0
313
258
1,080
547
473
1,116
836
332
228
228
0
0
0
7,590
-------
New Units
Conventional Pulverized Coal
IGCC
Combined Cycle
Combustion Turbine
Advanced Combustion Turbine
Biomass
Wind
Fuel Cells
Solar Photovoltaics
Solar Thermal
Geothermal
Landfill Gas
Total
—
...
...
...
—
—
—
—
—
—
...
—
—
93
93
192
96
96
26
144
26
26
11
36
72
911
Repowerings
Coal to Combined Cycle repowering
Coal to IGCC repowering
Oil and Gas to Combined Cycle repowering
Total
...
...
—
694
694
244
1,632
Early Retirements
Coal Early Retirement
Oil and Gas Earlv Retirement
Combined Cycle Early Retirement
Combustion Turbine Earlv Retirement
Nuclear Early Retirement
Total
—
—
—
—
—
—
694
244
243
513
104
1,798
Grand Total
(Existing and Planned/Committed + New +
Retrofits + Repowerings + Early Retirements)
14,062
-------
Exhibit 4-7. Summary of Committed
(Attachment G, Table G-1 in Doc,
Units in EPA Base Case 2004, v.2.1.9.
v.2.1.6.)
Year Range
Type Capacity (MW) Described
Renewables/Non Conventional
Biomass
Geothermal
Landfill Gas
Solar
Other
Wind
Fossil/Conventional
Coal Steam
Combined Cycle
Turbine
Fossil Waste
Grand Total
293
723
137
156
50
1,280
1,948
36,622
6,065
523
47,797
2004-2009
2004-2015
2004-2009
2004-2013
2007-2009
2004-2015
2004-2008
2004-2007
2004-2007
2004-2007
Data Source
in NEEDS 2.1. 9
AEO 2004
AEO 2004
AEO 2004
AEO 2004
AEO 2004
AEO 2004
RDI
RDI
RDI
RDI
-------
Exhibit 4-8. Planned-Committed Units in EPA Base Case 2004, v.2.1.9, by Model
Region. (Table 4.10 in Doc, v.2.1 and Attachment G in Doc,v.2.1.6.)
IPM Region
AZNM
AZNM
AZNM
AZNM
AZNM
AZNM
CALI
CALI
CALI
CALI
CALI
CALI
CALI
DSNY
ECAO
ECAO
ECAO
ENTG
ENTG
ERCT
ERCT
ERCT
FRCC
LILC
MACE
MACE
MACE
MACE
MACE
MACE
MACW
MACW
MACW
MANO
MANO
MANO
MANO
MAPP
MAPP
MAPP
MAPP
MAPP
Unit Type
Biomass
Coal Steam
Combined Cycle
Geothermal
Solar
Wind
Biomass
Combined Cycle
Geothermal
Landfill Gas
Solar
Turbine
Wind
Combined Cycle
Coal Steam
Combined Cycle
Turbine
Combined Cycle
Turbine
Combined Cycle
Turbine
Wind
Combined Cycle
Turbine
Biomass
Combined Cycle
Landfill Gas
Solar
Turbine
Wind
Combined Cycle
Fossil Waste
Turbine
Coal Steam
Combined Cycle
Landfill Gas
Turbine
Biomass
Coal Steam
Combined Cycle
Turbine
Wind
Number of Units
3
1
2
13
35
3
5
1
7
9
10
1
5
1
1
3
3
3
3
3
2
1
1
1
5
2
5
5
2
2
1
1
1
1
1
1
2
1
1
2
2
14
Capacity (MW)
50
380
3120
281
133
60
87
3346
442
100
20
235
339
1830
268
3398
692
2839
254
1982
950
25
4822
92
5
1805
5
3
1212
20
1150
520
23
500
521
4
180
48
790
1300
350
712
-------
IPM Region
NENG
NENG
NENG
NENG
NENG
NWPE
NYC
NYC
PNW
PNW
RMPA
RMPA
SOU
SOU
SPPS
SPPS
TVA
TVA
VACA
VACA
VACA
WUMS
WUMS
WUMS
WUMS
Total
Unit Type
Biomass
Combined Cycle
Landfill Gas
Other
Wind
Turbine
Combined Cycle
Turbine
Coal Steam
Combined Cycle
Combined Cycle
Wind
Combined Cycle
Turbine
Combined Cycle
Turbine
Combined Cycle
Turbine
Combined Cycle
Landfill Gas
Turbine
Combined Cycle
Fossil Waste
Landfill Gas
Turbine
Number of Units
9
1
5
3
3
2
1
1
1
1
1
1
2
1
1
1
1
1
2
2
2
1
1
1
1
212
Capacity (MW)
103
544
20
50
120
142
742
368
10
248
585
5
2883
95
1200
7
700
274
2217
6
1000
1390
3
3
192
47797
-------
Exhibit 4-9. Performance and Unit Cost Assumptions for Potential (New) Capacity from Conventional Fossil
Technologies in EPA Base Case 2004, v.2.1.9 (Table 4.12 in Doc, v.2.1.)
Size (MW)
First Year Available
Lead Time(years)
Vintage #1 (years covered)
Vintage #2 (years covered)
Vintage #3 (years covered)
Availability
Conventional
Pulverized Coal
600
2010
4
201 0-201 4
201 5-201 9
2020-2030
85%
Vintaae #1
Heat Rate (Btu/kWh)
Capital ($/kW)
Fixed O&M ($/kW/yr)
Variable O&M ($/MWh)
8,689
1,074
23.36
2.92
Integrated
Gasification
Combined Cycle
550
2010
4
201 0-201 4
201 5-201 9
2020-2030
87.7%
Advanced
Combined Cycle
400
2010
3
2010-2014
2015-2019
2020-2030
90.4%
Combined
Cycle
250
2007
3
2007-2014
2015-2019
2020-2030
90.4%
Advanced
Combustion
Turbine
230
2007
2
2007-2014
2015-2019
2020-2030
92.3%
Combustion
Turbine
160
2007
2
2007-201 4
201 5-201 9
2020-2030
92.3%
7,378
1,266
32.12
1.95
6,422
564
9.74
1.95
7,056
503
9.74
1.95
8,550
425
7.79
2.92
10,450
383
9.74
3.90
Vintage #2
Heat Rate (Btu/kWh)
Capital ($/kW)
Fixed O&M ($/kW/yr)
Variable O&M ($/MWh)
8,600
1,056
23.36
2.92
7,200
1,220
32.12
1.95
6,350
535
9.74
1.95
7,000
496
9.74
1.95
8,550
392
7.79
2.92
10,450
378
9.74
3.90
Vintage #3
Heat Rate (Btu/kWh)
Capital ($/kW)
Fixed O&M ($/kW/yr)
Variable O&M ($/MWh)
8,600
1,041
23.36
2.92
7,200
1,171
32.12
1.95
6,350
519
9.74
1.95
7,000
491
9.74
1.95
8,550
374
7.79
2.92
10,450
374
9.74
3.90
Notes: (1) Capital cost represents overnight capital cost.
-------
Exhibit 4-10. Performance and Unit Cost Assumptions for New Capacity from Renewable and Non-Conventional Technologies in
EPA Base Case 2004, v.2.1.9. (Table 4.13 in Doc., v.2.1.)
Size (MW)
First Year Available
Lead Time (years)
Vintage #1 (years
Vintage #2 (years
Availability
Generation capability
Vintage #1
Heat Rate (Btu/kWh)
Capital ($/kW)
Fixed O&M ($/kW/yr)
Variable O&M ($/MWh)
Biomass
Gasification
Combined
Cycle
100
2010
4
2010-2030
-
87.7%
Economic
Dispatch
8,911
1,574
43.75
2.79
Wind
50
2007
4
2007-2030
-
95%
Generation
Profile
0
863-1 ,396
16.12
0.00
Fuel
Cells
10
2007
3
2007-2030
-
90.7%
Economic
Dispatch
6,750
1,762
6.81
19.46
Solar
Photovoltaic
5
2007
2
2007-2030
-
90%
Generation
Profile
0
3,587
9.49
0.00
Solar
Thermal
100
2007
3
2007-2030
-
90%
Generation
Profile
0
2,333
47.00
0.00
Geothermal
50
2010
4
2010-2030
-
87%
Economic
Dispatch
28,392-
1 ,887-8,987
68-2,274
0.00
Landfill
Gas
30
2007
2
2007-2030
-
85%
Economic Dispatch
Hi
13,648
1,369
93.75
0.0094
Lo
1 3,648
1,725
93.75
0.0094
VLo
1 3,648
2,656
93.75
0.0094
-------
Exhibit 4-11. Regional Cost Adjustment Factors for Conventional and Renewable
Generating Technologies. (Table 4.11 in Doc, v.2.1.)
Model Region Name
Michigan Electric Coordination System
East Central Area Reliability Coordination Agreement-South
Electric Reliability Council of Texas
Mid-Atlantic Area Council - East
Mid-Atlantic Area Council - West
Mid-Atlantic Area Council - South
Wisconsin-Upper Michigan
Mid-America Interconnected Network- South
Mid-Continent Area Power Pool
Upstate New York
Downstate New York
New York City
Long Island Power Authority
New England Power Pool
Florida Reliability Coordinating Council
Virginia-Carolinas
Tennessee Valley Authority
Southern Company
Entergy
Southwest Power Pool - North
Southwest Power Pool - South
Western Electricity Coordinating Council - California
Western Electricity Coordinating Council - Pacific Northwest
Western Electricity Coordinating Council - AZ / NM / SNV
Western Electricity Coordinating Council - Rocky Mountain
Power Area
Western Electricity Coordinating Council - Northwest Power
Pool East
Region
Code
MEGS
ECAO
ERCT
MACE
MACW
MACS
WUMS
MANO
MAPP
UPNY
DSNY
NYC
LILC
NENG
FRCC
VACA
TVA
SOU
ENTG
SPPN
SPPS
CALI
PNW
AZNM
RMPA
NWPE
Regional
Factor
1.004
1.004
0.986
0.996
0.996
0.996
1.004
1.004
1.004
1.043
1.043
1.043
1.043
1.043
0.961
0.96
0.96
0.96
0.96
0.997
0.997
1.058
1.028
1.003
1.003
1.028
-------
Exhibit 4-12. Assumptions on Potential Geothermal Electric Capacity.
(Table 4.16 in Doc, v.2.1.)
Region Capacity (MW)
AZNM 1,385
CALI 12,500
NWPE 4,770
PNW 3,125
RMPA 2,370
Grand Total 24,150
-------
Exhibit 4-13a. Assumptions on Potential
Wind Capacity by Wind Class (MW)
(Table 4.17a in Doc, v.2.1.)
Exhibit 4-13b. Assumptions on Potential
Wind Capacity by Cost Class (MW)
(Table 4.17b in Doc, v.2.1.)
Wind Class
Model
Region
AZNM
CALI
DSNY
ECAO
ENTG
ERCT
MACE
MACS
MACW
MANO
MAPP
MECS
NENG
NWPE
PNW
RMPA
SOU
SPPN
SPPS
TVA
UPNY
VACA
WUMS
4
95,986
13,468
627
1,612
390
52
199
199
199
2,005
1,388,836
1,612
4,492
167,606
167,606
95,986
390
308,519
308,519
390
627
390
2,005
5
6,078
5,811
153
536
33
293,339
536
2,412
71,819
71,819
6,078
150
150
153
150
33
6
1,547
5,311
2,795
41,685
41,685
1,547
101
187
187
Model
Region
AZNM
CALI
DSNY
ECAO
ENTG
ERCT
MACE
MACS
MACW
MANO
MAPP
MECS
NENG
NWPE
PNW
RMPA
SOU
SPPN
SPPS
TVA
UPNY
VACA
WUMS
Cost Class
1
2,072
3,688
78
215
2
11
20
20
20
204
8,411
215
970
7,028
7,028
2,072
69
1,543
1,543
73
78
73
204
2
2,072
984
78
215
4
8
20
20
20
204
16,822
215
970
12,088
12,088
2,072
65
3,085
3,085
73
78
73
204
3
4,144
984
156
215
12
18
20
20
20
204
50,465
215
1,940
7,871
7,871
4,144
130
9,256
9,256
145
156
145
204
Grand Total 2,561,715 459,250 95,045
Grand Total
35,637 54,543 97,591
-------
Exhibit 4-14. Reserve Margin Contribution and Average Capacity Factor by Model Region.
(Table 4.18 in Doc, v.2.1.)
Model
Region
AZNM
CALI
DSNY
ECAO
ENTG
ERCT
FRCC
LILC
MACE
MACS
MACW
MANO
MAPP
MEGS
NENG
NWPE
NYC
PNW
RMPA
SOU
SPPN
SPPS
TVA
UPNY
VACA
WUMS
Solar Thermal
Summer
Average CF
42%
51%
36%
34%
41%
41%
42%
35%
35%
Average 40%
Winter
Average CF
33%
36%
30%
21%
26%
26%
33%
25%
25%
28%
Reserve Margin
Contribution
49%
64%
44%
39%
43%
39%
52%
42%
42%
46%
Solar Photovoltaic
Summer
Average CF
28%
28%
22%
23%
24%
25%
23%
22%
22%
22%
22%
23%
24%
23%
22%
26%
22%
26%
28%
24%
25%
25%
24%
22%
24%
23%
24%
Winter
Average CF
31%
27%
20%
21%
25%
26%
27%
20%
22%
22%
22%
23%
25%
21%
23%
22%
20%
22%
31%
25%
27%
27%
25%
20%
25%
23%
24%
Reserve Margin
Contribution
34%
46%
30%
31%
32%
33%
34%
28%
32%
30%
32%
34%
36%
34%
36%
35%
34%
33%
47%
32%
35%
33%
32%
33%
31%
37%
34%
-------
Exhibit 4-15. Reserve Margin Contribution and Average Capacity Factor by Wind Class and
Model Region. (Table 4.19 in Doc, v.2.1.)
Reserve Margin Contribution
Model Region
Wind Class 6 Wind Class 5 Wind Class 4
AZNM
CALI
DSNY
ECAO
ENTG
ERCT
MACE
MACS
MACW
MANO
MAPP
MEGS
NENG
NWPE
PNW
RMPA
SOU
SPPN
SPPS
TVA
UPNY
VACA
WUMS
38%
42%
46%
46%
49%
46%
45%
46%
45%
34%
38%
44%
43%
40%
39%
43%
42%
42%
44%
42%
40%
42%
46%
41%
42%
30%
34%
39%
38%
36%
34%
33%
33%
36%
36%
35%
39%
38%
38%
39%
38%
36%
34%
34%
37%
41%
37%
38%
Averge Summer CF
Average Winter CF
35%
45%
32%
42%
29%
38%
-------
Exhibit 4-16. Illustrative* Hourly Generation Profile from Wind (kWh of Generation per MW of
Electricity) (Table A4.2.1 in Doc, v.2.1.)
Wind Class
Winter Hour 1
Winter Hour 2
Winter HourS
Winter Hour 4
Winter HourS
Winter Hour 6
Winter Hour 7
Winter HourS
Winter Hour 9
Winter Hour 10
Winter Hour 11
Winter Hour 12
Winter Hour 13
Winter Hour 14
Winter Hour 15
Winter Hour 16
Winter Hour 17
Winter Hour 18
Winter Hour 19
Winter Hour 20
Winter Hour 21
Winter Hour 22
Winter Hour 23
Winter Hour 24
Winter Average
6
438
438
438
438
438
451
451
582
582
582
582
582
582
582
582
582
582
582
451
451
451
451
451
451
508
5
396
396
396
396
396
408
408
526
526
526
526
526
526
526
526
526
526
526
408
408
408
408
408
408
460
4
355
355
355
355
355
365
365
471
471
471
471
471
471
471
471
471
471
471
365
365
365
365
365
365
412
Wind Class
Summer Hour 1
Summer Hour 2
Summer HourS
Summer Hour 4
Summer HourS
Summer Hour 6
Summer Hour 7
Summer HourS
Summer Hour 9
Summer Hour 10
Summer Hour 11
Summer Hour 12
Summer Hour 13
Summer Hour 14
Summer Hour 15
Summer Hour 16
Summer Hour 17
Summer Hour 18
Summer Hour 19
Summer Hour 20
Summer Hour 21
Summer Hour 22
Summer Hour 23
Summer Hour 24
Summer Average
6
227
227
227
227
227
282
282
448
448
448
448
448
448
448
448
448
448
448
282
282
282
282
282
282
347
5
205
205
205
205
205
255
255
405
405
405
405
405
405
405
405
405
405
405
255
255
255
255
255
255
313
4
183
183
183
183
183
228
228
363
363
363
363
363
363
363
363
363
363
363
228
228
228
228
228
228
281
-------
Exhibit 4-17. Illustrative* Hourly Generation Profile From Solar
Photovoltaic (kWh of Generation per MW of Electricity). (Table
Thermal and Solar
A4.2.2inDoc, v.2.1.)
Solar Thermal p^oltaic
Winter Hour 1
Winter Hour 2
Winter Hour 3
Winter Hour 4
Winter Hour 5
Winter Hour 6
Winter Hour 7
Winter HourS
Winter Hour 9
Winter Hour 10
Winter Hour 11
Winter Hour 12
Winter Hour 13
Winter Hour 14
Winter Hour 15
Winter Hour 16
Winter Hour 17
Winter Hour 18
Winter Hour 19
Winter Hour 20
Winter Hour 21
Winter Hour 22
Winter Hour 23
Winter Hour 24
Winter Average
2
2
2
2
2
144
144
535
535
535
535
535
535
535
535
535
535
535
144
144
144
144
144
144
294
0
0
0
0
0
24
24
518
518
518
518
518
518
518
518
518
518
518
24
24
24
24
24
24
245
Solar Thermal p^oltaic
Summer Hour 1
Summer Hour 2
Summer HourS
Summer Hour 4
Summer HourS
Summer Hour 6
Summer Hour 7
Summer HourS
Summer Hour 9
Summer Hour 10
Summer Hour 1 1
Summer Hour 12
Summer Hour 13
Summer Hour 14
Summer Hour 15
Summer Hour 16
Summer Hour 17
Summer Hour 18
Summer Hour 19
Summer Hour 20
Summer Hour 21
Summer Hour 22
Summer Hour 23
Summer Hour 24
Summer Average
19
19
19
19
19
352
352
736
736
736
736
736
736
736
736
736
736
736
352
352
352
352
352
352
459
0
0
0
0
0
21
21
611
611
611
611
611
611
611
611
611
611
611
21
21
21
21
21
21
287
Based on model region NWPE
-------
Exhibit 4-18. Average Regional Nuclear Capacity Factors in
EPA Base Case 2004, v.2.1.9. (Table 4.20 in Doc, v.2.1)
IPM Region/Year
2007
2010
2015
2020
AZNM
CALI
DSNY
ECAO
ENTG
ERCT
FRCC
LILC
MACE
MACS
MACW
MANO
MAPP
MECS
NENG
NWPE
NYC
PNW
RMPA
SOU
SPPN
SPPS
TVA
UPNY
VACA
WUMS
91.1%
90.7%
85.3%
83.9%
91.1%
90.7%
92.2%
NA
91 .6%
93.1%
91 .0%
94.3%
85.1%
83.2%
89.4%
NA
NA
90.0%
NA
91 .4%
94.2%
NA
77.8%
87.4%
90.5%
86.8%
91 .2%
91 .4%
85.3%
84.6%
91.1%
91.1%
92.7%
NA
92.0%
93.1%
91 .0%
94.3%
85.6%
83.9%
90.2%
NA
NA
90.0%
NA
91 .4%
94.2%
NA
90.8%
88.4%
90.8%
86.8%
91 .2%
92.0%
84.9%
85.1%
91 .0%
91 .0%
92.3%
NA
91 .7%
93.1%
90.9%
93.8%
85.9%
83.4%
90.6%
NA
NA
90.0%
NA
91 .6%
94.2%
NA
91 .4%
88.1%
90.8%
85.5%
91 .2%
92.0%
83.0%
84.2%
90.7%
91 .0%
90.8%
NA
90.9%
91 .2%
90.3%
93.3%
85.0%
82.7%
89.6%
NA
NA
90.0%
NA
91.1%
94.2%
NA
91 .3%
86.7%
89.9%
83.4%
National Weighted
Average
89.4%
90.7%
90.7%
90.0%
-------
Exhibit 4-19. Nuclear Upratings and Scheduled Retirements (MW) as Incorporated in EPA Base Case 2004, v.2.1.9 from AEO 2004.
(Attachment J in Doc, v.2.1.6.)
Plant Name
Arkansas Nuclear One
Braidwood
Braidwood
Browns Ferry
Browns Ferry
Browns Ferry
Brunswick
Brunswick
Byron
Byron
Calvert Cliffs
Calvert Cliffs
Clinton
Columbia
Comanche Peak
Comanche Peak
Cook
Cook
Farley
Farley
Grand Gulf
Harris
Hatch
Hatch
Hope Creek
Indian Point 2
Indian Points
Limerick
Limerick
McGuire
McGuire
North Anna
Unit
1
1
2
1
2
3
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
1
1
2
1
2
3
1
2
1
2
1
2003
0
0
0
0
0
0
42
54
0
0
0
10
0
0
0
0
16
17
0
0
0
0
0
13
0
14
14
0
0
0
0
15
2004
0
0
0
0
0
0
47
0
0
0
30
0
0
0
0
0
0
0
18
18
0
0
13
0
37
0
0
0
0
0
0
0
2005
49
0
0
0
126
0
0
40
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2006
0
0
0
0
0
126
0
0
0
0
0
0
55
0
0
0
0
0
0
0
0
0
0
0
84
0
0
0
0
0
0
0
2007
0
0
0
120
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2008
0
0
0
0
0
0
0
0
60
58
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2009
0
0
0
0
0
0
0
0
0
0
0
0
0
10
0
0
0
0
0
0
31
0
0
0
0
0
0
0
0
0
0
0
2010
0
0
0
0
0
0
0
0
0
0
0
0
0
0
40
40
0
0
0
0
0
51
0
0
0
0
0
0
0
0
0
0
2011
0
40
40
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2012
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
120
2013
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2014
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
120
0
0
2015
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
120
0
2016
0
0
0
0
0
0
0
0
120
120
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2017
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
120
120
0
0
0
-------
Plant Name
North Anna
Palo Verde
Palo Verde
Palo Verde
Peach Bottom
Peach Bottom
Pilgrim
Point Beach
Point Beach
River Bend
Robinson
Salem
Salem
Sequoyah
Sequoyah
South Texas
South Texas
St Lucie
St Lucie
Summer
Surry
Surry
Susquehanna
Susquehanna
Vogtle
Vogtle
Waterford 3
Watts Bar
Wolf Creek
Unit
2
1
2
3
2
3
1
1
2
1
2
1
2
1
2
1
2
1
2
1
1
2
1
2
1
2
3
1
1
2003
0
30
0
0
12
12
23
7
7
17
0
30
0
13
0
18
18
0
0
0
0
0
0
29
0
0
0
0
0
2004
15
0
0
0
0
0
0
0
0
0
0
0
65
0
0
0
0
0
0
0
12
12
35
0
0
0
0
0
0
2005
0
0
30
0
0
0
0
0
0
0
0
0
0
0
13
0
0
0
0
0
0
0
0
0
0
0
68
0
0
2006
0
0
0
0
0
0
0
0
0
0
0
20
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2007
0
0
0
30
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2008
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
10
10
10
0
0
0
0
0
0
0
0
0
2009
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
10
10
0
0
0
10
0
2010
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2011
0
0
0
0
0
0
0
0
0
0
22
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
10
2012
120
0
0
0
0
0
0
0
0
0
0
0
0
120
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2013
0
0
0
0
0
0
0
0
0
0
0
0
0
0
120
0
0
0
0
0
0
0
0
0
120
120
0
0
0
2014
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
120
120
0
0
0
0
0
0
0
2015
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
120
120
0
0
0
0
0
0
0
0
0
0
0
0
2016
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2017
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-------
Exhibit 4-20. Key Characteristic of Existing Nuclear Units in NEEDS, v.2.1.9.
(Appendix 4.4, Table A4.4.1 in Doc, v.2.1.)
Plant Name I
Browns Ferry Nuclear
Browns Ferry Nuclear
Browns Ferry Nuclear
Clinton Nuclear
Wolf Creek Nuclear
San Onofre Nuclear
San Onofre Nuclear
Wnp-2 Nuclear
Vlillstone
Vlillstone
Turkey Point
Turkey Point
Crystal River
Vogtle Nuclear
Vogtle Nuclear
Dresden Nuclear
Dresden Nuclear
Quad Cities Nuclear
Quad Cities Nuclear
Duane Arnold Nuclear
3ilgrim Nuclear
3alisades Nuclear
=ermi Nuclear
vlonticello Nuclear
3rairie Island Nuclear
3rairie Island Nuclear
=ort Calhoun Nuclear
Oyster Creek Nuclear
Salem Nuclear
Salem Nuclear
ndian Point Nuclear
Mine Mile Point Nuclear
Mine Mile Point Nuclear
3each Bottom Nuclear
3each Bottom Nuclear
H B Robinson
Oconee Nuclear
Oconee Nuclear
Oconee Nuclear
Vermont Yankee Nuclear
Surry Nuclear
Surry Nuclear
3oint Beach Nuclear
3oint Beach Nuclear
Waterford #3 Nuclear
Donald C Cook Nuclear
Donald C Cook Nuclear
Joseph M Farley Nuclear
Joseph M Farley Nuclear
3alo Verde Nuclear
3alo Verde Nuclear
3alo Verde Nuclear
Calvert Cliffs Nuclear
Calvert Cliffs Nuclear
Brunswick Nuclear
Brunswick Nuclear
Harris Nuclear
3erry Nuclear
Braidwood Nuclear
Braidwood Nuclear
Byron Nuclear
Byron Nuclear
_a Salle County Nuclear
_a Salle County Nuclear
Catawba Nuclear
ORIS Code
46
46
46
204
210
360
360
371
566
566
621
621
628
649
649
869
869
880
880
1060
1590
1715
1729
1922
1925
1925
2289
2388
2410
2410
2497
2589
2589
3166
3166
3251
3265
3265
3265
3751
3806
3806
4046
4046
4270
6000
6000
6001
6001
6008
6008
6008
6011
6011
6014
6014
6015
6020
6022
6022
6023
6023
6026
6026
6036
Unit ID
1N
2N
3N
RPVN
WC1RN
2N
3N
1N
CE2N
WE3N
PTP3N
PTP4N
3N
UT1N
UT2N
2N
3N
1N
2N
1
RPVN
1
B21N
1
1
2
1N
OC1N
1N
2N
2N
1N
2N
2N
3N
2N
1N
2N
3N
1N
1N
2N
1N
2N
W3-1N
1N
2N
FNP-1N
FNP-2N
1N
2N
3N
1N
2N
1N
2N
1N
1N
1N
2N
1N
2N
1N
2N
1N
Region Name
TVA
TVA
TVA
MANO
SPPN
CALI
CALI
PNW
NENG
NENG
FRCC
FRCC
FRCC
SOU
SOU
MANO
MANO
MANO
MANO
MAPP
NENG
MECS
MECS
MAPP
MAPP
MAPP
MAPP
MACE
MACE
MACE
DSNY
UPNY
UPNY
MACE
MACE
VACA
VACA
VACA
VACA
NENG
VACA
VACA
WUMS
WUMS
ENTG
ECAO
ECAO
SOU
SOU
AZNM
AZNM
AZNM
MACS
MACS
VACA
VACA
VACA
ECAO
MANO
MANO
MANO
MANO
MANO
MANO
VACA
State Name
Alabama
Alabama
Alabama
Illinois
Kansas
California
California
Washington
Connecticut
Connecticut
Florida
Florida
Florida
Georgia
Georgia
Illinois
Illinois
Illinois
Illinois
Iowa
Massachusetts
Michigan
Michigan
Minnesota
Minnesota
Minnesota
Nebraska
New Jersey
New Jersey
New Jersey
New York
New York
New York
Pennsylvania
Pennsylvania
South Carolina
South Carolina
South Carolina
South Carolina
Vermont
Virginia
Virginia
Wisconsin
Wisconsin
Louisiana
Michigan
Michigan
Alabama
Alabama
Arizona
Arizona
Arizona
Maryland
Maryland
North Carolina
North Carolina
North Carolina
Ohio
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
South Carolina
On Line Year
2007
1975
1977
1987
1985
1983
1984
1984
1975
1986
1972
1973
1977
1987
1989
1970
1971
1972
1972
1975
1972
1972
1988
1996
1974
1997
1973
1969
1977
1981
1973
1969
1988
1974
1974
1971
1973
1974
1974
1972
1972
1973
1970
1972
1985
1975
1978
1977
1981
1986
1986
1988
1975
1977
1977
1975
1987
1987
1988
1988
1985
1987
1984
1984
1985
I Capacity MW
1,185
1,239
1,239
1,072
1,170
1,070
1,080
1,108
872
1,136
693
693
842
1,148
1,149
850
850
762
855
565
690
767
1,110
597
525
524
476
605
1,161
1,175
985
619
1,135
1,105
1,105
710
846
846
846
506
822
827
512
514
1,159
1,017
1,077
851
860
1,273
1,273
1,277
875
850
909
904
900
1,238
1,185
1,177
1,194
1,162
1,128
1,131
1,129
Heat Rate
Btu / kwh
10,430
10,430
10,430
10,029
9,762
9,887
9,887
10,064
10,152
9,963
1 1 ,023
11,015
10,670
10,873
10,873
11,139
11,113
10,946
10,967
10,888
10,177
10,367
12,868
10,452
10,746
10,770
10,643
10,740
10,782
10,687
10,117
10,740
10,740
10,436
10,545
10,163
10,410
10,315
10,350
10,123
10,068
10,068
10,400
10,505
10,539
10,721
10,686
1 1 ,000
1 1 ,000
10,635
10,499
10,439
10,857
10,878
10,017
10,469
10,123
10,264
10,295
10,295
10,399
10,191
10,585
10,716
10,084
-------
Plant Name 1
Catawba Nuclear
Vlcguire Nuclear
Vlcguire Nuclear
Beaver Valley Nuclear
Beaver Valley Nuclear
St Lucie Nuclear
St Lucie Nuclear
Edwin 1 Hatch
Edwin 1 Hatch
Grand Gulf Nuclear
Diablo Canyon Nuclear
Diablo Canyon Nuclear
Susquehanna Nuclear
Susquehanna Nuclear
-imerick Nuclear
-imerick Nuclear
James A Fitzpatrick
Seabrook Nuclear
Hope Creek Nuclear
Ginna
Summer Nuclear
Comanche Peak Nuclear
Comanche Peak Nuclear
Davis-Besse
Sequoyah Nuclear
Sequoyah Nuclear
Callaway Nuclear
Slorth Anna Nuclear
Slorth Anna Nuclear
South Texas Nuclear
South Texas Nuclear
River Bend Nuclear
Watts Bar Nuclear
Three Mile Island Nuclear
-------
Exhibit 4-21. Cost and Performance Assumptions for Repowering Options in EPA Base Case 2004, v.2.1.9.
(Table 4.22 in Doc, v.2.1.)
Repower Coal to Coal IGCC
Size (MW)
First Year Available
Lead Time(years)
Vintage #1 (years covered)
Availability
Repowering Ratio
Heat Rate (Btu/kWh)
Capital (1999$/kW)
Fixed O&M (1 999$/kW-yr)
Variable O&M (1 999$/MWh)
100
2010
4
2010 and after
87.7%
59%
8,781
1,997
34.3
1.84
250
2010
4
2010 and after
87.7%
75%
8,671
1,672
34.3
1.84
500
2010
4
2010 and after
87.7%
85%
8,599
1,509
34.3
1.84
1000
2010
4
2010 and after
87.7%
78%
8,424
1,416
34.3
1.84
Size (MW)
First Year Available
Lead Time(years)
Vintage #1 (years covered)
Availability
Repowering Ratio - Coal
Repowering Ratio - Oil & Gas
Heat Rate (Btu/kWh)
Capital ($/kW)
Fixed O&M ($/kW-yr)
Variable O&M ($/MWh)
Repower Coal and Oil & Gas Steam to Combined Cycle
100
2010
4
2010 and after
90.4%
195%
185%
8,893
646
13.7
1.38
250
2010
4
2010 and after
90.4%
183%
174%
7,776
542
13.7
1.38
500
2010
4
2010 and after
90.4%
175%
166%
6,742
497
13.7
1.38
1000
2010
4
2010 and after
90.4%
173%
164%
6,770
475
13.7
1.38
-------
Section 5
Emission Control Technologies
List of Exhibits
5-1 Summary of Emission Control Performance Assumptions in EPA Base Case 2004, v.2.1.9
5-2 SO2 Scrubber Engineering Cost Equations
5-3 Cost (in 1999$) of NOX Combustion Controls for Coal Boilers (300 MW Size)
5-4 Post-Combustion NOX Controls for Coal Plants (1999$)
5-5 Post-Combustion NOX Controls for Oil/Gas Steam Units (1999$)
-------
Exhibit 5-1. Summary of Emission Control Performance Assumptions in EPA
Base Case 2004, v.2.1.9. (Table 5.1 in Doc, v.2.1.)
Percent Removal
Capacity Penalty '
Heat Rate Penalty =
Cost (1999$)
Applicable
Population
SO2 Scrubbers
Limestone
Forced
Oxidation
(LSFO)
95%
-2.1%
+2.1%
See Table 5.2
Coal boilers >
100MW
Magnesium
Enhanced
Lime
(MEL)
96%
-2.1%
+2.1%
See Table 5.2
Coal boilers <
550 MW and
>100MW
Lime Spray
Dryer (LSD)
90%
-2.1%
+2.1%
See Table
5.2
Coal boilers
> 550 MW
NOX Post -Combustion
Controls
SCR
Coal: 90%
down to
0.06
Ib/mmBtu
Gas: 80%
Coal boilers
>1 00 MW
All oil/gas
steam units.
SNCR
Coal: 35%
Gas: 50%
See Tables
5. 3 and 5.4
All coal and
oil/gas steam
units
Notes
1The capacity penalty captures the fact that the electricity required to operate the scrubber reduces the
maximum capacity available for sale to the grid by 2.1 %.
2The heat rate penalty is a modeling procedure used to scale up a unit's heat rate in order to capture the
fuel used in generation both for internal load and sale to the grid. It does not represent an increase in the
unit's actual heat rate (i.e., a decrease in the unit's generation efficiency).
-------
Exhibit 5-2. SO2 Scrubber Engineering Cost Equations
(Appendix 5-1 in DOC, v.2.1)
Below is an abbreviated summary of the engineering cost equations for the three flue gas desulfurization
technologies represented in EPA Base Case 2004: limestone forced oxidation (LSFO), lime spray drying
(LSD), and magnesium enhanced lime (MEL). These equations are based on those presented in U.S.
Environmental Protection Agency, Office of Research and Development, Controlling SO2 Emissions: A
Review of Technologies (EPA-600/R-00-093), October 2000 with additional information published in a
subsequent journal article1. These equations provided the basis for deriving the capital, FOM, and VOM
cost of SO2 scrubbers in EPA Base Case 2004.
Capital Costs
Predicted Total Capital Requirement (Predicted TCR)
Predicted TCR ($/kW) =
MW
where MW is the capacity of the retrofitted generating unit in megawatts
Total Capital Requirement (TCR)
TCR ($)= 1.02x7P/ + ^^ + VOM + INVENTORY
12 CF x 12
where FOM ($) is the fixed operation and maintenance cost,
VOM ($) is the variable operation and maintenance cost,
CF is the plant capacity factor, i.e., the ratio of average output to rated output of a plant on
an annual basis,
INVENTORY ($) is the inventory capital, i.e., the cost of reagent required to meet the bulk
storage requirement. A 30-day limestone inventory and $15/ton limestone cost was
assumed for LSFO. Similarly, a 30-day lime inventory and $50/ton lime cost was
assumed.
Total Plant Investment (TPI)
TPI = TPC x (FTCE + FAPD^
where FTCE is the financial factor "Total cash expended" which de-escalates cost for inflation, and
FAFDC 's tne financial factor "Funds during construction" which accounts for interest during
construction.
Total Plant Cost (TPC)
A A A
I
100 100 100 100 100
where BM is sum of the "bare module" capital cost of the five major equipment areas. It is
multiplied by the following contingency factors to obtain the TPC:
A1 is the general facilities contingency (assumed to be 5%),
A2 is the engineering home office contingency (assumed to be 10%),
A3 is the process contingency (assumed to be 5%),
1Srivastava, R.K. and W. Jozewicz, "Flue Gas Desulfurization: The State of the Art," Journal of the Air and
Waste Management Association, December 2001, pp. 1676-1688.
1
-------
8 is the project contingency (assumed to be 15%), and
C is the prime contractor's fee (assumed to be 3%)
RF is the retrofit factor (assumed to be 1.3).
Capital Cost (BM)
BM = BMF + BMR + BMG + BMW + BME
where BMF is the bare module capital cost of the reagent feed equipment,
BMR is the bare module capital cost of the SO2 removal equipment,
BMG is the bare module capital cost of the flue gas handling equipment,
BMW is the bare module capital cost of the waste handling equipment, and
BME is the bare module capital cost of the support equipment.
-------
Bare Module Capital Cost (BM) for State-of-the-Art Model
Limestone Forced Oxidation
Reagent Feed Equipment (BMF)
BMF=
4
where
CB&H=:
FR, I4 [ FR, ?
00031* + ^ 11^8*
[lOOOj |—— [joooj J
[ FR, }2 FR,
- /IQ/I SS» +fiR1fi1 7t
[ lOOOj J 1000
- 7118470+ CB&H+ CDBA
CB&H is the cost of the ball mill and
hydrocyclones
CDBA is the cost of the DBA tank
FRL is the reagent feed rate
(Ib/hr)
FRS02 is the SO2 flow rate
(Ibs/hr)
Wt%S is the coal sulfur content
HR is the heat rate (Btu/kWh)
MWe is the LSFO size (MWe)
HHV is the coal heating value
(Btu/lb) - fixed at 1 1,900 Btu/lb
[ FRL j2 [ FRL |
2000J +™ ~ [200oJ +
[ . 0.95-20 |°'283
s°2 2000
c -161607. 8.34.(1+0.5)
^nn^-jOtOZ/ •
DBA [ 60 J
FR-F» .,nc. 100. 0.90
Wt%S. 1000. 64
HHV 32
Lime Spray Drying
Reagent Feed Equipment (BMF)
[ FR, }
Dflyf 1 '7AAO'2 • L j-IHfiAfi] 1
DM.-- 1 /UUZ3 • + J/O4O11
[ 10°° J
+ 72338 •F%1™\
L J
where FRL is the reagent feed rate
(Ib/hr)
-FGPM is the slurry flow rate (gpm)
FRS02 is the SO2 flow rate
Wt%S is the coal sulfur content
HR is the heat rate (Btu/kWh)
MWe is the LSD size (MWe)
HHV is the coal heating value
(Btu/lb) - fixed at 1 1,900 Btu/lb
FR,=FRm .1.75 •— +FRm*1.75
Li "^-'2 t*A "^2
56 1-0.9
64 0.9
c, _ L 56 L 56 0.3
GPM ' „_'
331 - 1+0'3
60
Fff "•%"• 1000^ 64 i^r TTD
^-^SOj WWl^ 10 e
flfl V J 2,
Magnesium-Enhanced Lime
Reagent Feed Equipment (BMF)
FR
BM -170023 • L +3764
F 1000
.p 0.3195
r GPM
where FRL is the reagent
(Ib/hr)
FGPM is the slurry
Wt%S is the coal s
HR is the heat rate
MWe is the MEL
ffifFisthecoalh
(Btu/lb) - fixed at
FR-FR -10-56-°'9i
611+72338
feed rate
ilow rate (gpm)
ulfur content
(Btu/kWh)
size (MWe)
sating value
11, 900 Btu/lb
J
L s°2 64 0.94
I7D 74 I7D 74 i-0-3
F _ L 56 L 56
°PM 331-1+0-3
60
s°2 ffffy 32
0.3
«r..™
-------
Removal Equipment (BM
Removal Equipment (BM
Removal Equipment (BM
BM0=BARE MODULE,, +ABSORBER »N
K. K. a
+PUMP »N
where BARE MOD ULER is the auxiliary
cost for the SO2 removal area
ABSORBER is the absorber cost,
1 or 2 depending on RLCS or
alloy material construction
respectively. Model assumes
average.
Na is the number of absorbers
PUMPS is the cost of the pumps
Np is the number of pumps
FGPM is the slurry flow rate
ACFMis the flue gas flow into the
absorber (in cfm)
P is the % O2 in the stack
assumed)
BARE MODULE^=0.8701'
FR
•so.
FR
-so.
1000
+34809.
1000
FR..
-188.2
1000
+1905302
ABSORBER 1= 173978
ABSORBER 2= 230064
ACFM]°-
.5575
1000 J
ACFM]°-
.5638
1000 J
PUMPS = 910.85 •
GPM
3.5954
,= 1 OOP . 9780. (460 + 295). 100
106 * 60 " 528 '(100-6)'
•HR>
0.04 + 0.209. (f-0.04)
P (0.209 -P)
N = Roundup
MW
Q(\(\
BMR= BARE MODULER +SPRAY DRYERS
where BARE MOD ULER is the auxiliary
cost for the SO2 removal area
SPRAYDRYER1 is the cost of SO2
removal (1 or 2) depending on RLCS
or alloy material construction
respectively.
ACFMis the flue gas flow into the
absorber (in cfm)
P is the % O2 in the stack (8%
assumed)
Nfl is the number of absorbers
BARE MODULER=Na[58l877809»Wt%S3-36531
•Wt%Sz+693335 •ffr%5'+214198]+67742
• wt%s-°-m66
AI 'H I\A
-3.57«
SPRAY DRYER1 =
ACFM
ACFM
#•1000
+ 9246
+791896
BMR= BARE MODULER+ABSORBER+PUMPS
where BARE MOD ULER is the auxiliary
cost for the SO2 removal area
ABSORBER is the absorber cost,
1 or 2 depending on RLCS or
alloy material construction
respectively. Model assumes
average.
Na is the number of absorbers
PUMPS is the cost of the pumps
Np is the number of pumps
ACFMis the flue gas flow into the
absorber (in cfm)
P is the % O2 in the stack (8%
7 assumed)
BARE MODULER=
0.825-
FR.
•so.
FR
so.
1000
0.870r
1000
FR
+ 34809-
-188.2
1000
+1905302
ACFM- 1000. 9780. (460+295). 100
106 60 528 (100-6)
•HR>
0.04 + 0.209. (f-0.04)
P (0.209 -P)
ABSORBER 1= 173978 »0.9«
ABSORBER 2= 230064 • 0.9»
ACFM
1000
ACFM
0.5575
0.5638
,, _ , {MW\
N = Roundup
(275
PUMPS = 0.8» 910.85 •
GPM
1000
X5954
100° 978° (460 + 295) 100
= • »-i '-• »
106 60 528 (100-6)
•HR>
0.04 + 0.209. (f-0.04)
P (0.209 -P)
N = Roundup
MW
-------
Flue
BMG=
where
BARE
•
+
•
where
ID FA]
ACFM
Gas Handling Equipment (BMG)
BARE MODULEG + ID FANS
BAREMODULEG is the auxiliary
cost of the flue gas handling area
ID FANS is the cost of fans
Nfis the number of fans
MDFtTTF F - 0 1 1 95* ALFM + 777 7*
G [ 1000 J
ACFM + 23 8203 +0 000012* A(~FM
1000 J 1000
0 \65\\ACFM2 + P888°- ACFM
1000 1000
ACFM1 l
<5<5Qfio-j n °009» + 1°fifi 4
1000»A^J
^^1+120111
1000* AT,]
ACFM1 is the flue gas flow rate
out of the absorber (cfm)
xC/rMl°-6842
yc- 01 o/i . A^raa „
[ Nf \ J
fA£f\j- nTi f1f>f> £\
- ACFM*^™ 127> (10° 6'
(460 + 295 (100-14)
Flue Gas Handling Equipment (BMG)
BMG= BARE MODULEG + ID FANS
where BAREMODULEG is the auxiliary
cost of the flue gas handling area
ID FANS is the cost of fans
TVf is the number of fans
BARE MODULEG =
\ 0. ACFM°™ , ^ ACFM1 0'71311
[ 1000 1000 J "
Jl533S- ACFMT +176So4^C/rM;r576l
1000 J [ 1000 J
+ mQ^^CFM2}0-5 \ACFM3}0-5
[ 1000 J [ 1000 J J
where ACFM1, ACFM2, and ACFM3
are flue gas flow rates at the exit
from the absorber, particulate
control device, and ID fans,
respectively (cfm)
L4CFM210'6842
77~> F4N1- 91 '"I » •fL\^rjYL& -^
[ Nf \ '
iCFM- 4CFM-(460+147)>(10°-6)-
1 (460+295 (100-14)
29.92
(29.4-17»7.355jc70 )
iCFM- 1CF^(460+147>)-(10°-6)-
2 (460+295 (100-14)
29.92
(29.4-23»7.355jt70-2)
iCFM- 4cFM-(460+152)V(10°-6)-
3 (460+295 (100-14)
29.92
(29.4+l»7.355jt70-2)
Flue Gas Handling Equipment (BMG)
BMG= BARE MODULEG + ID FANS
where BAREMODULEG is the auxiliary
cost of the flue gas handling area
ID FANS is the cost of fans
TVf is the number of fans
D/fpc- A/rnnTTTF 011QS* ACrM „„„ _ ,
G 1000 J
\ACFM] +01R001 _/_0oftft9\J^c^M/f
[ 1000 J [lOOO«JVaj
+ 1°fifi/l» +/I')01/I1 +0 00001°
[lOOO»Na\
_ ACFM nlfi,, ^CFM nppo0
1000 [ 1000
ACFM ssqfiq.
• +JJ:70:7J
[ 1000 J
where ACFM1 is the flue gas flow rate
out of the absorber (cfm)
NrFJtfl0'6842
rr> EM Arc 01 o/i . vior'jKi Ar
[ ^/ J '
4CFM- 4CFM. (460+127), (100-6)
1 (460 + 295 (100-14)
-------
Waste/By-product Handling Area
(BMW)
Waste/By-product Handling Area
(BMW)
Waste/By-product Handling Area
(BMW)
BMW= BARE MODULEW + THICKENER
where BARE MOD ULEW depends on the
disposal option:
Wl is the system with gypsum
stacking
W2 is the system with landfill
W3 is the system with wallboard
gypsum production
THICKENER is the cost of
thickener
W= 0.5 [BMm + BMm]
BMm= -4.0567-
+80700
FR
•so.
1000
+ 1788
FR
•so.
1000
BMm= 0.325*
FR
•so2
1000
FR
^29091
-168.77 •
•so,
1000
FR
so.
1000
H773243
BMW3= BMm .1.25
172
THICKENER^ 9018.7 »FRm »0.95 •-
s°2 64-2000
+114562
BMW= 2051841884 'Wt%S2 -1443163
•Wt%S +1026479
BMW= BARE MODULEW + THICKENER
where BARE MODULE w is the auxiliary
cost of the waste disposal
THICKENER is the cost of
thickener
Wallboard production is assumed
BARE MODULE^
0.325.
FR
SO2
1000
-168.77
FR.
1000
+29091-
FR
S02
1000
+773243
•1.25»0.825
172
THICKENER^ 9018.7 »FRm »0.95
s°2 64-2000
+ 114562.0.825
-------
Support Equipment Area (BME)
Support Equipment Area (BME)
Support Equipment Area (BME)
BME= BARE MODULEE + CHIMNEY
where BAREMODULEE was the
auxiliary cost
CHIMNEY 1 was chimney cost
with reheat
CHIMNEY2 was chimney cost
without reheat
BARE MODULEE=0.0003 *MW] -1.0677 •MW*
+ 1993.8 »MW_ +1177674
CHIMNEY^ 40208 •ACFM10™9
CHIMNEY2 = 23370 'ACFM1 °-3908
CHIMNEY^ 0.5[CHIMNEYl + CHIMNEY^
EME= -1.211
+2704.2- MW
+ 1354716.2+ CHIMNEY
where CHIMNEY was based on the
chimney cost without reheat
CHIMNEY=23370 'ACFM30-390*
BME= BARE MODULEE + CHIMNEY
where BAREMODULEE was the
auxiliary cost
CHIMNEY 1 was chimney cost
with reheat
CHIMNEY2 was chimney cost
without reheat
BARE MODULE^
0.825-
0.0003'MW! -1.0667'MW?
+1993.8* MWe +1177674
CHIMNEY^ 40208 •ACFM103339
CHIMNEY2= 23370 *ACFM1 °-3908
CHIMNEY^ 0.5[CHIMNEYl + CHIMNEY^
-------
Fixed Operation and Maintenance (FOM) Cost
FOM =OL+ ML&M + A&S
where OL is the cost of operating labor
ML&M is the maintenance and materials cost
A&S is the administration and support cost
Limestone Forced Oxidation
Lime Spray Drying
Magnesium-Enhanced Lime
OL = 41.69041-MT
-0.322307
MW» 30- 40-52
100
OL = [18.25-2.278«ln(MF)]«-
. 3Q.40* 52
LOO
OL = 41.69041-MT
-0.322307 m"e
AflP>30»40»52
100
ML&M = 0.03.BM
ML&M = 0.02.BM
ML&M = 0.03.BM
A&S = 0.3»(0.4 •
QL)
= 0.3»(0.4 • ML&M + OL)
A&S = 0.3»(0.4 •
OL)
-------
Variable Operation and Maintenance (VOM) Cost
Limestone Forced Oxidation
VOM = CCaC03 + CDBA + 0.5[CDS- CREDIT]
+ STEAM + POWER
where CCaC03 is the cost of limestone
(unit price at $15/ton)
CDBA is the cost of dibasic acid
(unit price at $430/ton)
CDS is the cost of disposal using
gypsum stacking ($6/ton)
CREDIT is the by-product credit with
wallboard production ($2/ton)
STEAM is the cost of steam
($3.50/1000 Ib). Average of reheat
and no reheat.
POWER is the cost of electrical
power consumed for LSFO
TER is the thermal energy required to
reheat steam (Ib/hr). Assumed 25°
reheat, cp=0.244 Btu/(lb °F) from air,
density = 0.0765 (lb/ft3)
Reagent Cost
FR
C - L • R760 * CF » 1S
CaC03 20QO
where FRL is the limestone feed rate
CF is the capacity factor
Dibasic Acid Cost
Lime Spray Drying
VOM = CCa0 + CDL+ POWER+
FRESH WATER COST
where CCa0 is the cost of lime (unit price at
$65/ton)
CDL is the cost of disposal
($30/ton)
POWER is the cost of energy
consumed for LSD
FRESH WATER is the cost of
water
Reagent Cost
FR,
C - • R760 * CF » SO
Ca° 2000
where FRL is the lime feed rate
CF is the capacity factor
Disposal Cost
Magnesium-Enhanced Lime
VOM = CCa0 + POWER- CREDIT^ STEAM
where CCa0 is the cost of magnesium
enhanced lime (unit price at
$50/ton)
POWER is the cost of energy
consumed for MEL
Reagent Cost
FR,
C - • R760 • CF » SO
Ca° 2000
where FRL is the limestone feed rate
CF is the capacity factor
CREDIT
-------
DBA
• •_
zo
2000 2000
where FRSO 2 is the SO2 flow rate
CDL =
8760
2000
— + MW* 1000* 0.1*-^-)
2 64
where FRSO 2 is the SO2 flow rate
CREDIT
where P
.FRso.0.95.-±™-
s°2 64*2000
2 is the SO2 flow rate
Disposal Cost
Fresh Water Cost
Energy Cost
= 6*8760*CF*F/?^*O.S
172
1 8
FRESH WATER COST=FRT»\.\'— *CF*8760
64*2000
CREDIT = 2'8760'CF •/?» »0.95*
s°2 64-2000
3.785 1000
Assumes the unit cost of water = 0.6 mills/gal
(from cue cost)
(lOOO*JtffFe*0.823l)
* 1000
•8760 »CF *25
DISPOSAL = 0.5[CDS - CREDIT]
Steam Cost
Energy Cost
Steam Cost
STEAM = O.f
TER =0.:
855.14*1000
(460+60) ,Q 0765.6Q
1 (460+127)
Energy Cost
(lOOO*Mfe* 0.8231)
" 1000
1000
= O.f
TFB
855.14*1000
= 0.:
•ACFM,
1 (460+127)
3.0765*60
10
-------
Exhibit 5-3. Cost (in 1999$) of NOX Combustion Controls for Coal Boilers (300 MW Size)
(Table A 5.2.1 in Doc, v.2.1.)
Boiler Type
Dry Bottom
Wall-Fired
Tangentially-
Fired
Technology
Low NOX Burner without Overfire Air (LNB without
OFA)
Low NOX Burner with Overfire Air (LNB with OFA)
Low NOX Coal-and-Air Nozzles with Close-Coupled
Overfire Air (LNC1)
Low NOX Coal-and-Air Nozzles with Separated
Overfire Air (LNC2)
Low NOX Coal-and-Air Nozzles with Close-Coupled
and Separated Overfire Air (LNC3)
Capital
($/kW)
17.26
23.43
9.10
12.71
14.52
Fixed
O&M
($/kW-yr)
0.26
0.36
0.14
0.19
0.22
Variable
O&M
(mills/kWh)
0.05
0.07
0.00
0.024
0.024
Scaling Factor
For all of the above combustion controls the following scaling factor is used to obtain the capital and fixed operating
and maintenance costs applicable to the capacity (in MW) of the unit taking on combustion controls. No scaling
factors is applied in calculating the variable operating and maintenance cost.
f 300^1 °'359
($ forX MW Unit) = ($ for 300 MW Unit) x
v ' v ' \ X J
where
($ for 300 MW Unit) is the value obtained using the factors shown in the above table and
X is the capacity (in MW) of the unit taking on combustion controls.
-------
Exhibit 5-4. Post-Combustion NOX Controls for Coal Plants (1999$)
(Table 5.3 in Doc, v.2.1.)
Post-Combustion
Control Technology
SCR2
SNCR3 - Term 1
Term 2
Capital
($/kW)
$100
$17.1
$19.5
Fixed O&M
($/kW/Yr)
$0.66
$0.25
$0.30
Variable O&M
(mills/kWh)
0.6
See Note 3
See Note 3
Percent
Gas
Use
-
-
Percent
Removal
90%1
35%
35%
SNCR4 (Cyclone)
$9.9
$0.14
1.31
35%
Notes:
1 Cannot provide reductions any further beyond 0.06 Ibs/mmBtu.
2 SCR Cost Scaling Factor:
SCR Capital and Fixed O&M Costs: (242.72/MW) °27
SCR Variable O&M Costs: (242.72/MW) °11
Scaling factor applies up to 600 MW.
3 SNCR Cost Scaling Factor:
SNCR Capital and Fixed O&M Costs: (Termr(200/MW) °577 + Term2*(100/MW)0681 )/2
VO&M = 0.88
4 Cyclone Cost Scaling Factor:
High NOX Coal SNCR—Cyclone Capital and Fixed O&M Costs: (300/MW)C
VO&M = 1.27 for MW< 300,
VO&M = 1.27 - ((MW- 300)/100) * 0.015 for MW > 300.
References
Khan, S. and Srivastava, R. "Updating Performance and Cost of NOX Control Technologies in the Integrated Planning
Model," Mega Symposium, August 30, 2004 - September 2, 2004, Washington, D.C.
-------
Exhibit 5-5. Post-Combustion NOX Controls for Oil/Gas Steam Units (1999$)
(Table 5.4 in Doc, v.2.1.)
Post-Combustion
Control Technology
SCR1
SNCR2
Notes:
1 SCR Cost Scaling Factor:
Capital
($/kW)
28.9
9.7
SCR and Gas Reburn Capital Cost and fixed O&M:
Scaling factor applies up to 500 MW
2 SNCR Cost Scaling Factor: :
Fixed O&M
($/kW/Yr)
0.89
0.15
(200/MW)035
Variable O&M
(mills/kWh)
0.10
0.45
Percent
Removal
80%
50%
SNCR Capital Cost and fixed O&M: (200/MW)0577
Scaling factor applies up to 500 MW
-------
Section 6
Set-Up Parameters and Rules
List of Exhibits
6-1 Run Years and Analysis Year Mapping Used in the EPA Base Case 2004, v.2.1.9.
6-2 First Stage Retrofit Assignment Scheme in EPA Base Case 2004, v.2.1.9.
6-3 Second Stage Retrofit Assignment Scheme in EPA Base Case 2004, v.2.1.9
6-4 Trading and Banking Rules in EPA Base Case 2004, v.2.1.9.
-------
Exhibit 6-1. Run Years and Analysis Year Mapping Used in
the EPA Base Case 2004, v.2.1.9. (Table 6.1 in Doc, v.2.1.)
Run Year
2007
2010
2015
2020
Years Represented
2007
2008-2012
2013-2017
2018-2022
-------
Exhibit 6-2. First Stage Retrofit Assignment Scheme in EPA Base Case 2004, v.2.1.9.
(Table 6.2 in Doc, v.2.1.)
IPIant Type
Retrofit Option 1st Stage
Criteria
jCombined Cycle
Early Retirement
All combined cycle units
ICombustion Turbine
Early Retirement
All combustion turbine units
lO/G Steam
Early Retirement
Combined Cycle Repowering
SCR
SNCR
All O/G steam units
All O/G steam units
All O/G steam units that do not possess an existing post
combustion NOX control option
All O/G steam units that do not possess an existing post
combustion NOy control option
ICoal Steam Plant
Early Retirement
Combined Cycle Repowering
IGCC Repowering
SCR
SNCR - Non Cyclone
SNCR -Cyclone
LSFO Scrubber
LSD Scrubber
VIEL Scrubber
Low Sulfur Bituminous Hg Control
Option
High Sulfur Bituminous Hg Control
Option
Sub-Bituminous Hg Control Option
Lignite Hg Control Option
LSD Scrubber + SCR
LSFO Scrubber + SCR
VIEL Scrubber + SCR
LSFO Scrubber + SNCR
VIEL Scrubber + SNCR
All coal units
All coal units
All coal units
All coal steam units that are 100 MW or larger and do not
possess an existing post combustion NOX control option
All coal steam units that are 25 MW or larger and smaller than
200 MW, and do not possess an existing post combustion NOX
control option
All cyclone coal steam units that are 25 MW or larger and
smaller than 200 MW, and do not possess an existing post
combustion NOX control option
All unscrubbed coal steam units 100 MWor larger and burning
BF or BG coal
All unscrubbed coal steam units 550 MWor larger and burning
non BG coal
All unscrubbed coal steam units 100 MWor larger and smaller
than 550 MWand burning non BG coal
All coal plants larger than 25 MWand burning non BF and BG
bituminous coal
All coal plants larger than 25 MWand burning BF and BG coal
All coal plants larger than 25 MWand burning Sub Bituminous
coal
JAN coal plants larger than 25 MW and burning Lignite coal
All unscrubbed coal steam units 550 MWor larger and burning
non BG coal, and do not possess an existing post combustion
NOX control option
All unscrubbed coal steam units 100 MWor larger, burning BF or
BG coal, and do not possess an existing post combustion NOX
control option
All unscrubbed coal steam units 100 MWor larger and
mailer than 550 MW, burning non BG coal, and do not possess
an existing post combustion NOX control option
All unscrubbed coal steam units 100 MWor larger and smaller
than 200 MW, burning BF or BG coal, and do not possess an
existing post combustion NOX control option
All unscrubbed coal steam units 100 MWor larger and smaller
than 200 MW, burning non BG coal, and do not possess an
existing post combustion NOX control option
-------
Exhibit 6-3. Second Stage Retrofit Assignment Scheme in EPA Base Case 2004, v.2.1.9.
(Table 6.3 in Doc, v.2.1.)
Plant Type
Coal Steam Plant
Retrofit Option 1st Stage
NOV Control
SO2 Control Option
SO2 Control Option + SCR
SO2 Control Option + SNCR
Hg Control Option
Retrofit Option 2nd Stage
SO, Control Option or Hg Control Option
NOX Control Option or Hg Control Option
Hg Control Option
Hg Control Option
None
-------
Exhibit 6-4. Trading and Banking Rules in EPA Base Case 2004, v.2.1.9.
(Table 6.4 in Doc, 2.1.)
Coverage
Timing
Size of initial bank
S02
All SO2 - emitting sources >
25 MW in the U.S.
Annual
4.99 million tons in 2007
NOX
Fossil units in the SIP Call states*
>25MW
Summer (May - September)
The bank starting in 2007 is assumed to
be zero.
Rules
Total Allowances
Total Allowances Less NSR SO2
Allowance Retirement**
Total Allowances Less NSR and
North Carolina SO2 Allowance
Retirements***
2007 - 2009: 9.47 million tons
2010 - 2030: 8.95 million tons
2007 - 2007: 9.40 million tons
2008 - 2009: 9.38 million tons
2010 -2012: 8.86 million tons
2013 - 2030: 8.78 million tons
2007 - 2007: 9.40 million tons
2008 - 2008: 9.38 million tons
2009 - 2009: 9.31 million tons
2010 -2012: 8.85 million tons
2013 - 2030: 8.64 million tons
527.58 thousand tons
527.58 thousand tons
527.58 thousand tons
527.58 thousand tons
527.58 thousand tons
527.58 thousand tons
527.58 thousand tons
527.58 thousand tons
527.58 thousand tons
527.58 thousand tons
527.58 thousand tons
*Alabama, Connecticut, District of Columbia, Delaware, Georgia, Illinois, Indiana, Kentucky,
Massachusetts, Maryland, Michigan, Missouri, North Carolina, New Jersey, New York, Ohio,
Pennsylvania, Rhode Island, South Carolina, Tennessee, Virginia, and West Virginia.
"Allowances assumed to retire due to NSR were 69,260 tons in the years that are mapped to model run
year 2007, 87,510 tons in the years that are mapped to model run year 2010, and 169,600 tons in the
years that are mapped to model run year 2015.
***Allowances assumed to retire due to the North Carolina Clean Smokestacks Rule are 30.2 thousand
tons in the years that are mapped into 2010 and 137 thousand tons in the years that are mapped into
2015.
-------
Section 7
Financial Assumptions
List of Exhibits
7-1 Capital Charge Rates and Real Discount Rates by Plant Type
-------
Exhibit 7-1. Capital Charge Rates and Real Discount Rates by Plant Type
(Table 7.1 in Doc, v.2.1.)
Investment Technology
Environmental Retrofits
Repowering Coal & Oil/Gas to Combined Cycle
Repowering Coal to Integrated Gasification Combined Cycle
Coal - Conventional Pulverized Coal
Coal - Integrated Gasification Combined Cycle
Combined Cycle
Combustion Turbine
Renewable Generation Technologies
Capital
Charge Rate
12.0%
12.9%
13.4%
12.9%
13.4%
12.9%
13.4%
13.4%
Discount Rate
5.34%
6.14%
6.74%
6.14%
6.74%
6.14%
6.74%
6.74%
Financing
Structure
Corporate
Project
Project
Project
Project
Project
Project
Project
-------
Section 8
Fuel Assumptions
List of Exhibits
8-1 Map of the Coal Supply Regions in EPA Base Case 2.1.9.
8-2 Coal Supply Regions in EPA Base Case 2004.
8-3 Coal Demand Regions in EPA Base Case 2004.
8-4 Coal Labor Productivity Assumptions
8-5 Coal Transportation Cost Escalation Rates.
8-6 Average Mine-Mouth Coal Prices in the EPA Base Case 2004, v.2.1.9 (1999$/Ton)
8-7 Coal Assignments in EPA Base Case 2004, v. 2.1.9
8-8 Natural Gas Supply Curves for EPA Base Case 2004, v.2.1.9.
8-9 Natural Gas Transportation Differentials for EPA Base Case 2.1.9 (1999 cents/MMBtu).
8-10 Seasonal Natural Gas Price Adders in EPA Base Case 2.1.9 (1999 cents/MMBtu).
8-11 US Wellhead and National Average Delivered Natural Gas Prices in EPA Base Case 2004,
v.2.1.9(1999 $/mmBtu).
8-12 Technical Background Paper on the Development of Natural Gas Supply Curves for EPA Base
Case 2004, v.2.1.9.
8-13 Fuel Oil Prices in EPA Base Case 2004, v.2.1.9.
-------
Exhibit 8-1. Map of the Coal Supply Regions in EPA Base Case 2004, v.2.1.9.
(Figure 8.1 in Doc, v.2.1.)
WA
Northwest
Western Northern
Great Plains
/
Southwest
-------
Exhibit 8-2. Coal Supply Regions in EPA Base Case 2004.
Region State
Appalachia Alabama
Appalachia Kentucky
Appalachia Maryland
Appalachia Ohio
Appalachia Pennsylvania
Appalachia Pennsylvania
Appalachia Tennessee
Appalachia Virginia
Appalachia West Virginia
Appalachia West Virginia
Interior Illinois
Interior Indiana
Interior Kentucky
Interior Louisiana
Interior Texas
West Arizona
West Colorado, Green River
West Colorado, Raton
West Colorado, San Juan
West Colorado, Uinta
West Montana
West Montana
West New Mexico
West North Dakota
West Utah
West Utah
West Wyoming
West Wyoming
West Washington
Imports
Supply Region
AL
KE
MD
OH
PC
PW
TN
VA
WN
WS
IL
IN
KW
LA
TX
AZ
CG
CR
CS
CU
ME
MP
NS
ND
UC
US
WG
WP
WA
IM
-------
Exhibit 8-3. Coal Demand Regions in EPA Base Case 2004.
Abbreviation Fuel Demand Region Name
ALRL Alabama rail plants
AMMM Arizona and New Mexico mine mouth plants
AMNR Arizona, New Mexico and Southern Nevada rail plan
GFRL Arkansas / Louisiana / Mississippi / Houston rail plants
CARL Carolinas rail plants
CAIN Central Appalachia Interior Rail Plants
CC East Colorado plants
IMBG East Iowa and East Missouri and Illinois River bar
EIMR East Iowa and East Missouri rail plants
PE East Pennsylvania
FLBG Florida barge plants
FLRL Florida rail plants
GARL Georgia rail plants
GFBG Gulf barge plants
MIR Indiana, Illinois, West Kentucky Interior rail plants
INT Indiana, Illinois, West Kentucky Interior truck plants
PC Indina County, Pennsylvania
IBBG Kentucky, Indiana, Southern Illinois river plants
DALG Lignite Dakotas plant
TXLG Lignite Louisiana and Texas
MIBG Michigan Upper Penninsula barge plants
MNRL Minnesota rail plants
WTXR N. and W. Texas rail plants
NE New England / Hudson River plants / Hudson plant
NORL North Ohio rail plants
NIIR Northern Indiana and Illinois rail plants
ORPB Pennsylvania-Ohio River plants
PRB PRB plants
MARL South PJM Rail plants
MABG South PJM-VEPCO Barge plants
TKIN Tennessee and Kentucky interior plants
TABG Tennessee and Northern Alabama river plants
NU Upstate New York plants
VEPR VEPCO rail plants
MWRL W Iowa / W Missouri / Kansas / Nebraska / NW Oklahoma rail
WONR Washington / Oregon / N. Nevada rail plants
CU West Colorado and Utah plants
WOMR West Ohio and Michigan rail plants
NAIN Western Pennsylvania / Northern West Virginia
WIRL Wisconsin rail plants
WYGR Wyoming Green River plants
-------
Exhibit 8-4. Coal Labor Productivity Assumptions
(Table M-1 in Doc, v.2.1.6)
EPA Base Case 2004, v.2.1.9, uses the same coal supply curves as EPA Base Case 2003, v.2.1.6.
These curves incorporate the percentage change in labor productivity assumed in AEO 2003, which were
developed through expert judgement based on historic experience derived from the data reported in Form
EIA-7A Coal Production Report. The productivity assumptions are shown in the following table. To
incorporate the AEO productivity assumptions in EPA Base Case 2004, AEO and IPM coal supply regions
were first matched up. Then, the AEO 2003 data for each coal supply region was used to derive the
percentage change in labor productivity between each of the model run years in EPA Base Case 2004
(i.e., 2007 to 2010, 2010 to 2015, and 2015 to 2020). Finally, these calculated percentage changes in
labor productivity were incorporated into the EPA Base Case 2004 coal supply curves for each region.
The AEO 2003 labor productivity assumptions are shown in the following table.
-------
LABOR PRODUCTIVITY (Short Tons per Miner Hour)
NEMS run aeo2003.d110502c Preliminary
Coal Market Module
Region
States
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Northern Appalachia (NA)
Central Appalachia (CA)
Southern Appalachia (SA)
East Interior (El)
West Interior (Wl)
Gulf
Dakota Lignite (DL)
Powder & Green River
Basins (PG)
Rocky
Southwest (ZN)
Northwest (AW)
PA, OH, MD,
WV (North)
WV (South), KY
(East), VA
AL, TN
IL, IN, KY
(West), MS
IA, MO, KS, AR,
OK, TX (Bit)
TX, LA
ND, SD, MT
(East)
WY,
CO, UT
NM,AZ
AK, WA
4.29
4.17
2.79
4.72
3.58
9.89
17.64
35.86
7.66
8.01
4.28
4.21
3.83
2.81
4.73
3.94
8.85
17.07
37.30
8.67
7.92
4.32
4.22
3.96
2.80
4.77
3.94
9.07
17.43
38.24
9.02
8.08
4.34
4.33
4.02
2.81
4.80
3.92
9.27
17.74
39.12
9.38
8.27
4.35
4.43
4.10
2.83
4.88
3.91
9.46
18.03
39.94
9.67
8.32
4.37
4.52
4.18
2.85
4.99
3.90
9.62
18.28
40.70
9.95
8.38
4.38
4.61
4.24
2.86
5.06
3.89
9.76
18.50
40.95
10.20
8.39
4.39
4.70
4.29
2.87
5.12
3.89
9.88
18.70
41.54
10.44
8.46
4.40
4.76
4.34
2.89
5.21
3.89
9.99
18.89
42.09
10.61
8.51
4.40
4.84
4.38
2.90
5.26
3.89
10.06
19.06
42.61
10.75
8.55
4.41
4.91
4.43
2.91
5.34
3.89
10.10
19.21
43.09
10.84
8.55
4.41
4.97
4.45
2.91
5.39
3.89
10.15
19.35
43.32
10.95
8.61
4.41
5.01
4.46
2.92
5.48
3.89
10.19
19.46
43.32
11.07
8.62
4.41
5.05
4.47
2.92
5.53
3.90
10.23
19.56
43.32
11.16
8.64
4.41
5.10
4.47
2.93
5.60
3.90
10.26
19.66
43.29
11.24
8.67
4.41
5.13
4.48
2.93
5.68
3.89
10.29
19.73
43.29
11.34
8.67
4.41
Appalachia (NA,CA,SA)
Interior (EI,WI,GL)
Northern
Other West (RM,ZN,AW)
4.10
5.81
33.23
7.44
3.87
5.57
34.43
7.93
3.97
5.62
35.17
8.15
4.04
5.62
36.04
8.43
4.12
5.81
36.81
8.60
4.20
5.93
37.51
8.77
4.26
5.99
37.86
8.92
4.32
6.08
38.50
9.09
4.36
6.15
39.07
9.17
4.41
6.22
39.61
9.28
4.46
6.22
40.18
9.32
4.49
6.20
40.47
9.43
4.50
6.28
40.53
9.56
4.52
6.30
40.57
9.63
4.54
6.34
40.60
9.69
4.55
6.39
40.64
9.78
East of the Mississippi River
West
4.19
17.67
4.00
18.34
4.10
19.26
4.17
19.61
4.25
19.78
4.34
20.01
4.41
20.42
4.46
20.94
4.51
21.51
4.56
21.94
4.61
22.82
4.64
23.33
4.67
23.41
4.69
23.63
4.72
23.90
4.74
24.02
Underground
Surface
4.17
11.05
4.03
10.64
4.20
10.65
4.35
10.80
4.46
11.04
4.58
11.10
4.68
11.30
4.76
11.63
4.80
11.94
4.87
12.30
4.94
12.78
5.02
13.10
5.11
13.37
5.15
13.43
5.20
13.60
5.26
13.69
|U.S. Total/Average
7.02 6.85 7.08 7.20 7.39 7.49 7.62 7.80 7.99 8.20 8.47 8.66 8.82 8.87 8.96 9.03
Source: Energy Information Administration, Annual Energy Outlook 2003 (January 2003),
Reference Case forecast, National Energy Modeling System run, AEO2003.D110502C.
LABOR PRODUCTIVITY continued (Short Tons per Miner Hour)
-------
NEMS run aeo2003.d110502c
Coal Market Module States
Region
Northern Appalachia (NA)
Central Appalachia (CA)
Southern Appalachia (SA)
East Interior (El)
West Interior (Wl)
Gulf
Dakota Lignite (DL)
Powder & Green River
Basins (PG)
Rocky
Southwest (ZN)
Northwest (AW)
PA, OH, MD,
WV (North)
WV (South), KY
(East), VA
AL, TN
IL, IN, KY
(West), MS
IA, MO, KS, AR,
OK, TX (Bit)
TX, LA
ND, SD, MT
(East)
WY,
CO, UT
NM,AZ
AK, WA
Appalachia (NA,CA,SA)
Interior (EI,WI,GL)
Northern
Other
East of the Mississippi River
West
Underground
Surface
AVG AVG AVG
2016 2017 2018 2019 2020 2021 2022 2023 2024 202501-0501-1001-25
5.17
4.48
2.94
5.76
3.89
10.30
19.81
43.30
11.41
8.68
4.41
5.19
4.49
2.94
5.84
3.88
10.31
19.87
43.31
11.50
8.69
4.41
5.24
4.49
2.93
5.91
3.89
10.32
19.93
43.34
11.56
8.68
4.41
5.27
4.49
2.93
6.00
3.88
10.32
19.97
43.38
11.66
8.69
4.41
5.29
4.50
2.93
6.07
3.87
10.32
20.01
43.45
11.75
8.69
4.41
5.31
4.51
2.92
6.15
3.86
10.32
20.05
43.52
11.81
8.69
4.41
5.33
4.52
2.92
6.23
3.85
10.32
20.09
43.55
11.86
8.69
4.41
5.36
4.53
2.91
6.31
3.85
10.32
20.13
43.59
11.93
8.69
4.41
5.39
4.54
2.91
6.40
3.84
10.32
20.17
43.62
11.98
8.69
4.41
5.42
4.54
2.90
6.50
3.83
10.32
20.21
43.62
12.04
8.69
4.41
1 .8%
2.2%
0.3%
1 .4%
-0.3%
2.1%
1 .7%
2.2%
3.5%
1 .4%
0.3%
1 .7%
1 .6%
0.4%
1 .4%
-0.1%
1 .5%
1 .3%
1 .6%
2.5%
0.9%
0.2%
1.1%
0.7%
0.1%
1 .3%
0.1%
0.6%
0.7%
0.7%
1 .4%
0.4%
0.1%
4.57
6.48
40.71
9.82
4.58
6.54
40.78
9.87
4.60
6.60
40.85
9.89
4.61
6.64
40.93
9.98
4.63
6.71
41.04
10.03
4.64
6.76
41.11
10.05
4.66
6.82
41.21
10.10
4.68
6.88
41.29
10.16
4.70
6.94
41.34
10.19
4.70
7.03
41.39
10.25
2.1%
1 .6%
2.2%
2.5%
1 .6%
1 .2%
1 .7%
1 .8%
0.8%
1 .0%
0.8%
1.1%
4.78
24.25
4.80
24.52
4.83
24.79
4.85
25.05
4.87
25.32
4.90
25.38
4.93
25.72
4.96
25.85
4.99
25.97
5.01
26.07
2.1%
2.2%
1 .6%
2.5%
0.9%
1 .5%
5.31
13.90
5.35
14.09
5.40
14.25
5.46
14.45
5.50
14.62
5.56
14.68
5.61
14.91
5.67
15.02
5.72
15.07
5.74
15.16
3.3%
1.1%
2.3%
2.1%
1 .5%
1 .5%
|U.S. Total/Average
9.16 | 9.28 | 9.37 | 9.48 | 9.60 | 9.68 | 9.82 | 9.91 | 9.95 | 9.97 | 2.2%| 2.4%| 1.6%|
Source: Energy Information Administration, Annual Energy Outlook 2003 (January 2003),
Reference Case forecast, National Energy Modeling System run, AEO2003.D110502C.
-------
Exhibit 8-5. Coal Transportation Cost Escalation Rates.
(Table M-2 in Doc, v.2.1.6)
The coal transportation cost escalation assumptions in EPA Base Case 2004, v.2.1.9, are the same as in
EPA Base Case 2003, v.2.1.6. The percentage changes in coal transportation cost rates between v.2.1.9
model run years (i.e., 2007 to 2010, 2010 to 2015, and 2015 to 2020) match the percentage changes in
transportation costs for corresponding years in AEO 2003. The AEO coal transportation cost escalation
rates are based on "projected variations in reference case fuel costs (No. 2 diesel fuel in the industrial
sector), labor costs, the user cost of capital for transportation equipment, and a time trend." (Assumptions
to the Annual Energy Outlook: Coal Market Module at www.eia.doe.gov/oiaf/aeo/assumption/coal.html.)
The transportation rate multipliers in AEO 2003 are presented in the following table. They are applied
across all modes of transport.
Transportation Rate Multipliers, 2001-2025
(2001=1.000)
year
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Reference
Case
1.0000
0.9914
0.9783
0.9622
0.9661
0.9609
0.9526
0.9455
0.9376
0.9304
0.9241
0.9134
0.9014
0.8892
0.8739
0.8587
0.8440
0.8282
0.8127
0.7954
0.7864
0.7773
0.7673
0.7577
0.7487
Source: Energy Information Administration, Annual Energy Outlook 2003 (January 2003), Reference Case
forecast, National Energy Modeling System run AEO2003.D110502C.
-------
Exhibit 8- 6. Average Mine-Mouth Coal Prices in the EPA Base Case 2004, v.2.1.9 (1999$/Ton).
(Table 8.3 in Doc, 2.1.)
2007 2010 2015 2020
Appalachia $22.21 $21.39 $21.31 $20.46
Interior $14.82 $14.11 $13.08 $12.19
West $6.67 $6.82 $6.80 $6.47
National Average $12.74 $12.24 $11.85 $10.84
-------
Exhibit 8-7. Coal Assignments in EPA Base Case 2004, v. 2.1.9
Key to Coal Grade Designation in the EPA Base Case 2004
Bituminous
Low Sulfur Bituminous (Western) (BB)
Low Sulfur Bituminous (Eastern) (BA)
Low Medium Sulfur Bituminous (BD)
Medium Sulfur Bituminous (BE)
Medium High Sulfur Bituminous (BF)
High Sulfur Bituminous (BG)
Subbituminous
Low Sulfur Subbituminous (SB)
Low Medium Sulfur Subbituminous (SD)
Medium Sulfur Subbituminous (SE)
Lignite
Low Medium Sulfur Lignite (LD)
Medium Sulfur Lignite (LE)
Medium High Sulfur Lignite (LF)
Sulfur Dioxide
(Ibs./mmBtu)
1.0
1.1
1.5
2.2
3.0
5.0
1.0
1.4
2.1
1.4
2.1
2.9
The preceding table shows the sulfur grade designations represented in EPA Base Case 2004 for the three ranks
(bituminous, Subbituminous, and lignite) of coal used for electricity generation.
The table below presents illustrative examples of the fuel options resulting from the coal assignment procedures described
in sections 3.6.1 and 8.1 of the Documentation Summary. Four situations are depicted in the following table.
For unscrubbed units (all entries except entry 6) the State Implementation Plan (SIP) limit on SO2 emissions
determines the coal sulfur grade choices available to a unit. For example, Salem Harbor, Unit 1 (entry 1 in the
following table) with a SIP SO2 limit of 1.2 Ibs/MMBtu has two coal choices (BA and BB) that will keep its
emissions below this SIP SO2 limit, whereas R.E. Burger, Unit 5 (entry 5 in the following table) with a higher SIP
SO2 limit of 9.0 Ibs/MMBtu has six bituminous coal choices (BA, BB, BD, BE, BF, and BG).
The sixth entry in the table shows the type of coal options available to scrubbed units. The presence of a scrubber
at Mountaineer, Unit 1, gives it the option to burn grades of bituminous coal with the highest SO2 content (BD, BE,
BF, and BG). Due to the presence of a scrubber, its fuel options include BG coal whose 5.0 Ib/mmBtu sulfur
content exceeds the unit's 3.2 Ib/mmBtu SIP SO2 limit.
The seventh entry in the table gives an example of the coal choices offered to lignite burning units in EPA Base
Case 2004. Big Brown Unit 1 has the option of burning lignite and Subbituminous coals .
Entry 8 (Minnesota Valley, Unit 4) is an example of a unit that was given Subbituminous PRB coal as a fuel option
in EPA Base Case 2004 based on data showing that the unit had already used such coal. Entries 9 and 10 are
examples of two units (E. D. Edwards, Unit 1, and R. Gallagher, Unit 1) that PA Consulting Inc.'s industry
knowledge found to be good economic candidates for Subbituminous PRB coal.
-------
Entry
ID
1
2
3
4
5
6
7
8
9
10
Plant Name
Salem Harbor
Dickerson
Glen Lyn
Danskammer
R E Burger
Mountaineer
Big Brown
Minnesota Valley
E D Edwards
R Gallagher
Uniaue ID
1626 B 1
1572_B_3
3776_B_51
2480_B_3
2864_B_5
6264_B_1
3497_B_1
1918 B 4
856_B_1
1008_B_1
SIP SO2 Limit
(Ibs/MMBtu)
1.2
1.5
2.6
3.8
9.0
3.2
3.0
4.0
4.7
4.7
Scrubber?
No
No
No
No
No
Yes
No
No
No
No
Fuels Allowed
BA BB
BA BB BD
BA BB BD BE
BA BB BD BE BF
BA BB BD BE BF BG
BG BF BE BD
LD LE SB SD SE
BA BB BD BE BF SB SD SE
BA BB BD BE BF SB SD SE
BA BB BD BE BF SB SD SE
For a complete listing of the coal assignments made to the model plants in EPA Base Case 2004, see the "# NAME
FUELS ALLOWED" section found in file EPA219b_BC_16b.DAT which accompanies this documentation report.
-------
Exhibit 8-8. Natural Gas Supply Curves for EPA Base Case 2004, v.2.1.9.
(Attachment N, Table N1, in Doc, v.2.1.6.)
EPA Base Case 2004, v.2.1.9, uses supply curves to provide a price-quantity relationship for natural gas
supplies in the United States. The gas supply curves shown below were derived using the North
American Natural Gas Analysis System (NANGAS), a detail-rich natural gas model developed by ICF
Consulting, Inc. Curves representing total gas supply and non-electric sector demand are produced
through a series of NANGAS model runs, where natural gas supply, demand, and transportation are
equilibrated under a variety of electricity growth rate assumptions. These are used to derive gas supply
curves for the electric sector. A separate supply curve is provided for each IPM model run year. (See
Exhibit 8-12 for a detailed discussion of the components and assumptions of the NANGAS model and the
procedures followed to obtain the natural gas supply curves presented here.)
The supply curves below specify annual price and volume relationships at the Henry Hub. (The Henry
Hub is a gas pipeline junction in Louisiana, which interconnects with nine interstate and four intrastate
pipelines and offers shippers access to pipelines that have markets in U.S. Gulf Coast, Southeast,
Midwest, and Northeast regions. Due to the Hub's strategic centralized location, the price of natural gas at
the Henry Hub serves as the generally accepted reference point for U.S. natural gas trading.) For each
listed step the price applies for all increments of supply greater than the value shown in the preceding step
up to and including the supply level indicated in the current step. For example, in 2007 a price of $3.40
would secure natural gas supplies for the electric sector beyond the 5422 TBtu provided in the preceding
step and up to a level of 5511 TBtu.
Non Gas
Electric Supply to
PRICE Gas Total Gas Electric
(1999 Demand Supply Sector
YEAR $/MMBtu) (TBtu) (TBtu) (TBtu)
2007 2.75 19411 23560 4149
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2.80
2.85
2.90
2.95
3.00
3.05
3.10
3.15
3.20
3.25
3.26
3.30
3.35
3.40
3.44
3.45
3.50
3.55
3.57
3.60
3.65
3.70
3.75
3.80
3.85
19314
19220
19128
19038
18950
18863
18778
18695
18614
18534
18514
18457
18378
18299
18243
18224
18157
18090
18066
18021
17952
17884
17818
17753
17689
23580
23600
23620
23640
23660
23680
23700
23720
23730
23740
23740
23790
23800
23810
23820
23820
23830
23840
23840
23850
23860
23870
23880
23890
23900
4266
4380
4492
4602
4710
4817
4922
5025
5116
5206
5226
5333
5422
5511
5577
5596
5673
5750
5774
5829
5908
5986
6062
6137
6211
-------
Non Gas
Electric Supply to
PRICE Gas Total Gas Electric
(1999 Demand Supply Sector
YEAR $/MMBtu) (TBtu) (TBtu) (TBtu)
2007 3.90 17626 23910 6284
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
3.95
4.00
4.05
4.10
4.15
4.20
4.25
4.30
4.35
4.40
4.45
4.50
4.55
4.60
4.65
4.70
4.75
4.80
4.85
4.90
4.95
5.00
5.05
5.10
5.15
5.20
5.25
5.30
5.35
5.40
5.41
2.75
2.80
2.85
2.90
2.95
3.00
3.05
3.10
3.15
3.16
3.20
3.25
3.29
3.30
3.35
3.40
3.45
3.46
17564
17503
17443
17384
17326
17269
17212
17156
17101
17047
16994
16941
16889
16838
16788
16738
16689
16641
16593
16546
16500
16454
16409
16364
16320
16276
16233
16190
16148
16106
16064
19727
19621
19517
19415
19316
19219
19124
19031
18940
18916
18856
18766
18691
18678
18597
18516
18435
18411
23920
23930
23940
23950
23960
23970
23980
23990
24000
24010
24020
24030
24040
24050
24060
24070
24080
24090
24100
24110
24120
24130
24140
24150
24160
24170
24180
24190
24200
24210
24220
23780
23890
23990
24090
24190
24290
24390
24490
24590
24620
24850
24970
25070
25080
25130
25180
25230
25240
6356
6427
6497
6566
6634
6701
6768
6834
6899
6963
7026
7089
7151
7212
7272
7332
7391
7449
7507
7564
7620
7676
7731
7786
7840
7894
7947
8000
8052
8104
8156
4053
4269
4473
4675
4874
5071
5266
5459
5650
5704
5994
6204
6379
6402
6533
6664
6795
6829
-------
Non Gas
Electric Supply to
PRICE Gas Total Gas Electric
(1999 Demand Supply Sector
YEAR $/MMBtu) (TBtu) (TBtu) (TBtu)
2010 3.50 18355 25300 6945
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
3.55
3.60
3.65
3.70
3.75
3.80
3.85
3.90
3.95
4.00
4.05
4.10
4.15
4.20
4.25
4.30
4.35
4.40
4.45
4.50
4.55
4.60
4.65
4.70
4.75
4.80
4.85
4.90
4.95
5.00
5.05
5.10
5.15
5.20
5.25
5.30
5.35
5.40
5.41
2.75
2.80
2.85
2.90
2.95
3.00
3.05
3.08
3.10
3.15
18277
18200
18125
18051
17978
17907
17837
17768
17700
17633
17567
17502
17438
17375
17313
17252
17192
17133
17075
17018
16962
16906
16851
16797
16744
16691
16639
16588
16538
16488
16439
16390
16342
16295
16248
16202
16156
16111
16066
20148
20060
19974
19890
19808
19727
19648
19599
19569
19489
25390
25480
25570
25660
25740
25820
25900
25980
26060
26140
26220
26300
26380
26460
26540
26620
26700
26770
26840
26910
26980
27050
27120
27190
27260
27330
27400
27470
27540
27610
27680
27750
27820
27890
27960
28020
28080
28140
28200
24960
25140
25320
25500
25670
25840
26010
26120
26210
26460
7113
7280
7445
7609
7762
7913
8063
8212
8360
8507
8653
8798
8942
9085
9227
9368
9508
9637
9765
9892
10018
10144
10269
10393
10516
10639
10761
10882
11002
11122
11241
11360
11478
11595
11712
11818
11924
12029
12134
4812
5080
5346
5610
5862
6113
6362
6521
6641
6971
-------
Non Gas
Electric Supply to
PRICE Gas Total Gas Electric
(1999 Demand Supply Sector
YEAR $/MMBtu) (TBtu) (TBtu) (TBtu)
2015 3.18 19442 26610 7168
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2020
2020
3.20
3.25
3.30
3.35
3.39
3.40
3.45
3.50
3.55
3.60
3.65
3.70
3.70
3.75
3.80
3.85
3.90
3.95
4.00
4.05
4.10
4.15
4.20
4.25
4.30
4.35
4.40
4.45
4.50
4.55
4.60
4.65
4.70
4.75
4.80
4.85
4.90
4.95
5.00
5.05
5.10
5.15
5.20
5.25
5.30
5.35
5.40
2.75
2.80
19413
19343
19273
19203
19144
19134
19069
19004
18939
18874
18809
18744
18741
18683
18623
18564
18506
18449
18393
18338
18283
18229
18176
18124
18073
18022
17972
17923
17874
17826
17779
17732
17686
17641
17596
17552
17508
17465
17422
17380
17338
17297
17256
17216
17176
17137
17098
20782
20695
26680
26850
27020
27190
27330
27350
27480
27610
27740
27870
28000
28130
28140
28280
28430
28580
28730
28880
29020
29160
29300
29440
29580
29720
29860
30000
30140
30280
30410
30540
30670
30800
30930
31060
31190
31320
31450
31580
31710
31840
31960
32080
32200
32320
32440
32560
32680
27560
27720
7267
7507
7747
7987
8186
8216
8411
8606
8801
8996
9191
9386
9399
9597
9807
10016
10224
10431
10627
10822
11017
11211
11404
11596
11787
11978
12168
12357
12536
12714
12891
13068
13244
13419
13594
13768
13942
14115
14288
14460
14622
14783
14944
15104
15264
15423
15582
6778
7025
-------
Non Gas
Electric Supply to
PRICE Gas Total Gas Electric
(1999 Demand Supply Sector
YEAR $/MMBtu) (TBtu) (TBtu) (TBtu)
2020 2.85 20610 27870 7260
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2.90
2.95
2.95
3.00
3.05
3.10
3.15
3.20
3.25
3.29
3.30
3.35
3.40
3.45
3.49
3.50
3.55
3.60
3.65
3.70
3.75
3.80
3.85
3.90
3.95
4.00
4.02
4.05
4.10
4.15
4.20
4.25
4.30
4.35
4.40
4.45
4.50
4.55
4.60
4.65
4.70
4.75
4.80
4.85
4.90
4.95
5.00
5.05
5.10
20527
20449
20445
20369
20293
20217
20141
20065
19989
19935
19914
19844
19774
19704
19646
19636
19577
19518
19459
19400
19341
19282
19223
19164
19105
19046
19024
18990
18936
18883
18830
18778
18727
18677
18627
18578
18530
18482
18435
18389
18343
18298
18253
18209
18165
18122
18080
18038
17997
28020
28160
28170
28320
28470
28620
28770
28920
29070
29180
29230
29400
29570
29740
29880
29900
30010
30120
30230
30340
30450
30560
30670
30780
30890
31000
31040
31120
31240
31360
31480
31600
31720
31840
31950
32060
32170
32280
32390
32500
32610
32720
32830
32940
33050
33160
33270
33370
33470
7493
7711
7725
7951
8177
8403
8629
8855
9081
9245
9316
9556
9796
10036
10234
10264
10433
10602
10771
10940
11109
11278
11447
11616
11785
11954
12016
12130
12304
12477
12650
12822
12993
13163
13323
13482
13640
13798
13955
14111
14267
14422
14577
14731
14885
15038
15190
15332
15473
-------
Non Gas
Electric Supply to
PRICE Gas Total Gas Electric
(1999 Demand Supply Sector
YEAR $/MMBtu) (TBtu) (TBtu) (TBtu)
2020 5.15 17956 33570 15614
2020
2020
2020
2020
2020
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
5.20
5.25
5.30
5.35
5.40
2.75
2.80
2.85
2.90
2.95
3.00
3.05
3.10
3.15
3.20
3.24
3.25
3.30
3.35
3.40
3.45
3.50
3.55
3.57
3.60
3.65
3.70
3.75
3.80
3.85
3.90
3.92
3.95
4.00
4.05
4.10
4.15
4.20
4.25
4.30
4.35
4.37
4.40
4.45
4.50
4.55
4.60
4.65
4.70
17916
17876
17837
17798
17759
21087
21004
20923
20844
20767
20691
20617
20544
20473
20403
20346
20336
20278
20220
20162
20104
20046
19988
19965
19925
19859
19793
19727
19661
19595
19529
19507
19476
19429
19382
19335
19288
19241
19194
19147
19100
19081
19053
19006
18960
18914
18869
18825
18781
33670
33770
33870
33970
34070
27750
27910
28070
28220
28370
28520
28670
28820
28970
29110
29230
29270
29480
29690
29900
30110
30320
30530
30610
30660
30740
30820
30900
30980
31060
31140
31170
31250
31370
31490
31610
31730
31850
31970
32090
32210
32260
32330
32440
32550
32660
32770
32880
32990
15754
15894
16033
16172
16311
6663
6906
7147
7376
7603
7829
8053
8276
8497
8707
8884
8934
9202
9470
9738
10006
10274
10542
10645
10735
10881
11027
11173
11319
11465
11611
11663
11774
11941
12108
12275
12442
12609
12776
12943
13110
13179
13277
13434
13590
13746
13901
14055
14209
-------
Non Gas
Electric Supply to
PRICE Gas Total Gas Electric
(1999 Demand Supply Sector
YEAR $/MMBtu) (TBtu) (TBtu) (TBtu)
2026 4.75 18738 33100 14362
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
4.80
4.85
4.90
4.95
5.00
5.05
5.10
5.15
5.20
5.25
5.30
5.35
5.40
18695
18653
18611
18570
18529
18489
18449
18410
18371
18333
18295
18258
18221
33210
33320
33430
33540
33650
33760
33860
33960
34060
34160
34260
34360
34460
14515
14667
14819
14970
15121
15271
15411
15550
15689
15827
15965
16102
16239
-------
Exhibit 8-9. Natural Gas Transportation Differentials for EPA Base Case 2.1.9 (1999 cents/MMBtu).
(Attachment N, Table N2, in Doc, v.2.1.6.)
EPA Base Case 2004, v.,2.1.9 includes explicit transportation to reflect the cost of moving gas from the source to the plant. The tables below show
the transportation differentials for each IPM model region relative to the Henry Hub price. These transportation differentials were produced by
analyzing daily gas price data for key pricing points in North America as reported in the Platts (McGraw-Hill) publication "Gas Daily". A charge (22
cents/MMBtu in NYC and CALI and 7 cents/MMBtu in all other regions) was included in the values shown in Exhibit 8-9 to capture Local
Distribution Company (LDC) transportation charges from the city gate. The key natural gas pricing points were mapped into IPM regions to
produce the average annual differentials that appear in these tables.
2007
2010
2015
2020
MECS
20.40
20.40
20.40
20.40
ECAO
26.10
26.10
26.10
26.10
ERCT
-5.00
-5.00
-5.00
-5.00
MACE
38.60
38.60
38.60
38.60
MACW
43.40
43.40
43.40
43.40
MACS
38.60
38.60
38.60
38.60
WUMS
15.60
15.60
15.60
15.60
MANO
16.60
16.60
16.60
16.60
MAPP
-10.00
-10.00
-10.00
-10.00
UPNY
24.20
24.20
24.20
24.20
DSNY
39.50
39.50
39.50
39.50
NYC
86.00
86.00
86.00
86.00
LILC
47.20
47.20
47.20
47.20
2007
2010
2015
2020
NENG
43.40
43.40
43.40
43.40
FRCC
36.70
36.70
36.70
36.70
VACA
45.30
45.30
45.30
45.30
TVA
10.80
10.80
10.80
10.80
SOU
8.90
8.90
8.90
8.90
ENTG
8.90
8.90
8.90
8.90
SPPN
-12.00
-12.00
-12.00
-12.00
SPPS
-10.00
-10.00
-10.00
-10.00
CALI
37.20
37.20
37.20
37.20
PNW
-29.00
-29.00
-29.00
-29.00
AZNM
-8.00
-8.00
-8.00
-8.00
RMPA
-27.00
-27.00
-27.00
-27.00
NWPE
-40.00
-40.00
-40.00
-40.00
-------
Exhibit 8-10. Seasonal Natural Gas Price Adders in EPA Base Case 2.1.9 (1999 cents/MMBtu)
(Attachment, Table N3 in Doc, v.2.1.6.)
EPA Base Case 2004, v.,2.1.9 includes explicit seasonal adders, which are applied relative to the Henry Hub price obtained from the gas supply
curves to account for the seasonality in gas prices. The tables below show the seasonal gas adders used in the v.2.1.9 base case. The values
were derived from daily price data for key pricing points as reported in the Platts (McGraw-Hill) publication "Gas Daily". These seasonal adders are
used to distinguish summer and winter delivered gas prices. Seasonal gas adders vary by IPM model region. In general, seasonal gas adders for
winter are higher than those for summer. In winter, due to lower temperatures, there is higher demand for gas by the residential sector for space
heating. This results in higher gas pipeline utilization and higher delivered gas prices. The appearance of negative values in Exhibit 8-10 means
that based on the "Gas Daily" data, the price of gas (without consideration of the Transportation Differentials captured in Table 8-9) is projected to
be lower than the Henry Hub price by the amount shown for the indicated region in the specified season.
Winter
2007
2010
2015
2020
MECS
0.00
0.00
0.00
0.00
ECAO
1.91
1.91
1.91
1.91
ERCT
-1.90
-1.90
-1.90
-1.90
MACE
5.74
5.74
5.74
5.74
MACW
5.74
5.74
5.74
5.74
MACS
4.78
4.78
4.78
4.78
WUMS
1.91
1.91
1.91
1.91
MANO
1.91
1.91
1.91
1.91
MAPP
2.87
2.87
2.87
2.87
UPNY
3.83
3.83
3.83
3.83
DSNY
7.65
7.65
7.65
7.65
NYC
7.65
7.65
7.65
7.65
LILC
9.57
9.57
9.57
9.57
Summer
2007
2010
2015
2020
MECS
0.00
0.00
0.00
0.00
ECAO
-2.90
-2.90
-2.90
-2.90
ERCT
2.87
2.87
2.87
2.87
MACE
-7.70
-7.70
-7.70
-7.70
MACW
-7.70
-7.70
-7.70
-7.70
MACS
-6.70
-6.70
-6.70
-6.70
WUMS
-1.90
-1.90
-1.90
-1.90
MANO
-2.90
-2.90
-2.90
-2.90
MAPP
-3.80
-3.80
-3.80
-3.80
UPNY
-5.70
-5.70
-5.70
-5.70
DSNY
-7.70
-7.70
-7.70
-7.70
NYC
-10.50
-10.50
-10.50
-10.50
LILC
-10.50
-10.50
-10.50
-10.50
Winter
2007
2010
2015
2020
NENG
7.65
7.65
7.65
7.65
FRCC
-5.70
-5.70
-5.70
-5.70
VACA
7.65
7.65
7.65
7.65
TVA
0.00
0.00
0.00
0.00
sou
-1.00
-1.00
-1.00
-1.00
ENTG
0.00
0.00
0.00
0.00
SPPN
0.96
0.96
0.96
0.96
SPPS
0.96
0.96
0.96
0.96
CALI
-3.80
-3.80
-3.80
-3.80
PNW
10.52
10.52
10.52
10.52
AZNM
0.00
0.00
0.00
0.00
RMPA
8.61
8.61
8.61
8.61
NWPE
22.96
22.96
22.96
22.96
Summer
2007
2010
2015
2020
NENG
-7.70
-7.70
-7.70
-7.70
FRCC
5.74
5.74
5.74
5.74
VACA
-9.60
-9.60
-9.60
-9.60
TVA
0.00
0.00
0.00
0.00
sou
0.00
0.00
0.00
0.00
ENTG
0.00
0.00
0.00
0.00
SPPN
0.00
0.00
0.00
0.00
SPPS
-1.00
-1.00
-1.00
-1.00
CALI
4.78
4.78
4.78
4.78
PNW
-13.40
-13.40
-13.40
-13.40
AZNM
0.00
0.00
0.00
0.00
RMPA
-12.40
-12.40
-12.40
-12.40
NWPE
-26.80
-26.80
-26.80
-26.80
-------
Exhibit 8-11. US Wellhead and National Average Delivered Natural Gas Prices
in EPA Base Case 2004, v.2.1.9 (1999 $/mmBtu)
(Attachement N, Table N4, in Doc, v.2.1.6.)
In IPM plants using natural gas for electric generation face market clearing prices.
This price is endogenously determined in the model by equating demand and
supply. In every IPM run, the market clearing price (derived from the natural gas
supply curves in Exhibit 8-8) and transportation (Exhibit 8-9) and seasonal cost
adders (Exhibit 8-10) all enter into the calculation of total expenditures on natural
gas consumption for electric generation. The table below shows the Henry Hub and
national average delivered natural gas prices resulting under EPA Base Case 2004,
v.2.1.9.
Year
2007
2010
2015
2020
Wellhead Gas
Price (at Henry
Hub)
3.20
3.20
3.25
3.16
Delivered Gas
Price
3.35
3.34
3.42
3.33
-------
Exhibit 8-12. Technical Background Paper on the Development
of Natural Gas Supply Curves for EPA Base Case 2004, v.2.1.9
(Appendix 8.1 Doc, v.2.1.)
Prepared by ICF Consulting, Inc.
1. Introduction
2. Brief Synopsis of NANGAS
3. Resources Data and Reservoir Description
4. Treatment of Frontier Resources
5. Natural gas Assumption Used for Oil Sands Recovery in Western Canada
6. E&P Technology Characterization
7. Fuel Prices
8. End Use Demand Characterization
9. Discussion of Final Results
10. Supply Curves, Transportation Adders for EPA Base Case 2004, v. 2.1.9
-------
1. Introduction
One of the primary tools that EPA's Clean Air Markets Division uses to evaluate air
emissions policies is the Integrated Planning Model (IPM). IPM, a large linear program of
the electric power sector, provides a detailed representation of power plant
characteristics, operating regimes, plant dispatch, fuel use, and air emissions. IPM is
used to evaluate the economic and emissions impact of alternative air emissions
policies. IPM forecasts over a 20-25 year time horizon. A key input to IPM is the price of
natural gas. IPM's gas price assumptions are developed using the North American
Natural Gas Analysis System (NANGAS). Like IPM, NANGAS is a large-scale linear
programming model that incorporates a detailed representation of gas supply
characteristics, demand characteristics and an integrating pipeline transportation model
to develop forecasts of gas supply, demand, prices and flows. Exhibit 1 shows the
interaction of IPM and NANGAS.
Exhibit 1: IPM/NANGAS Interaction
Natural Gas Modeling Power Sector Modeling
Natural Gas Supply Curves
orth American
Natural Gas
nalysis Syste
Power Sector Gas Demand
Assumption Updates
Peer Review
Scenario Analysis
Integrated
Planning
Model
Assumption Updates
Peer Review
Scenario Analysis
Products
Natural Gas Projections
Natural Gas Supply Curves
Products
Environmental Policy Assessments
Inputs for Air Quality Modeling
The two models are operated in tandem and are iterated to develop a consistent Henry
Hub gas price and total gas demand forecast. IPM uses natural gas data in electric
market modeling as follows:
• IPM takes the natural gas supply curves and non-electric demand curves, which
are developed within NANGAS and specified as a function of Henry Hub prices.
• The seasonal and annual natural gas transportation differentials are added to the
supply and non-electric demand curve elements to generate the final delivered
curves by IPM region.
• IPM finds the electricity demand for gas. To this is added the non-electric
demand. The resulting combined demand is used with the supply curve to find
the clearing price for gas.
• IPM linear programming formulation takes into consideration these curves as well
as coal supply curves and detailed electric power plant modeling in determining
-------
electric market equilibrium conditions. Oil usage is modeled as a function of
price which is exogenously supplied to IPM.
In 2003, EPA sponsored an extensive peer review of NANGAS, conducted by an
independent panel of prominent natural gas experts. NANGAS was updated based on
all primary recommendations made by the peer reviewers and supply curves were
generated for use in EPA Base Case 2004, v. 2.1.9.
This report is divided into the following sections. The report starts with a brief synopsis
of NANGAS, the primary tool used for generating the supply curves. This is followed by
detailed discussions of modeling methodologies and data used in NANGAS. The
methodologies and data description are grouped in the following six sections:
i) Resources data and reservoir description
ii) Treatment of frontier resources
iii) Natural gas assumptions for oil sands recovery in Western Canada
iv) Exploration and Production (E&P) technology characterization
v) Fuel prices (oil, coal)
vi) End use demand characterization
This is followed by discussion of natural gas results and supply curves used for EPA
Base Case 2004, v. 2.1.9.
2. Brief Synopsis of NANGAS
ICF's integrated natural gas model, NANGAS, is designed to perform comprehensive
assessments of the entire North American gas flow pattern. It is a large-scale dynamic
linear program that models economic decision-making to minimize the overall cost of
meeting natural gas demand.
Exhibit 2: Geographic Coverage of NANGAS
A/
-------
Important features of NANGAS are described below.
Natural Gas Market Prices in NANGAS are calculated based on the concept of
"shadow prices". The model's material balance constraints calculates this shadow price
indicating "How much better would the natural gas grid be with one additional unit of
gas." These calculations take into account all regions and future years simultaneously in
minimizing the cost of meeting demand. The calculations reflect the value of each
potential activity that could be performed relative to adding one unit of gas or reducing
one unit of demand to arrive at a "marginal activity".
Reservoir level analysis uniquely evaluates exploration, development and production
at the level of over 20,000 individual reservoirs and undiscovered accumulations.
NANGAS is distinguished by its detailed representation of reservoirs and reservoir
characteristics and the use of type-curves to generate production profiles from the
economics and technologies of production. (Type-curves are curves that are typically
used in well testing to represent trends in pressure transient responses with different,
layered geological structures.) NANGAS does not employ "decline rates" as an input in
the forecasting of production. Rather "decline rates" are an output of the model and are
a function of resource characteristics, production economics, and technology.
E&P technology performance is modeled by simulating the effect of E&P technologies
on ultimate gas recovery and production profiles. Potential improved technologies and
practices are characterized as explicit changes in reservoir or economic parameters.
This approach is designed to allow for detailed assessments of future potential from
individual reservoirs and to allow explicit changes to the technology be represented
consistently across various practices for the entire North American resource.
Regional demand is modeled on a sectoral and seasonal basis, including the role gas
storage can play in meeting gas demand. Demand is primarily represented by Census
region. Some regions are further disaggregated in more detail either by state or regions
within states. Demand is represented within each of its 26 regions as a load duration
curve with four seasons.
End use demand is modeled for residential, commercial, industrial and electric utility
sectors. Econometric equations define demand by sector. Industrial and electric sectors
incorporate fuel competition, dispatch decisions, and new power plant builds. NANGAS
iterates with IPM to better capture electric sector demand for natural gas.
Electric generation is modeled regionally with plant dispatch based upon operating
cost. Competing power generation technologies are evaluated on a full-cost basis to
determine lowest cost capacity additions.
Transportation is modeled by over 135 transportation links between supply and
demand regions, balancing seasonal, sectoral, and regional demand and prices,
including pipeline tariffs and capacity allocation. The pipeline network is largely
represented as bundles of pipes, though in some regions individual pipes are
represented. Gas moves over the network at variable cost. Pipeline expansion levels
are modeled either as specified user input to the model or, alternatively, the user can let
the model expand capacity endogenously whenever the market justifies expansion.
-------
NANGAS is developed and maintained by ICF for use by both private as well as public
sector clients. It is routinely updated and has been used to examine strategic issues
relating to natural gas supply, pipeline infrastructure, pricing, adequacy, and demand
characteristics.
3. Resources Data and Reservoir Description
As noted above, NANGAS underwent an extensive peer review process during 2003 in
which the analytic framework, modeling methodologies, and data were thoroughly
examined. In response to peer review comments, ICF revised and updated the resource
module in NANGAS, to incorporate new data on resources, reserves, and reservoir
parameters for the L-48 states and Canada. This section describes the approach used
in NANGAS and documents the changes to the resource data and reservoir
characterization that were implemented for EPA Base Case 2004, v. 2.1.9.
Undiscovered resource data used in NANGAS are consistent with the latest resource
assessments conducted by governmental and private agencies within U.S. and Canada.
A complete update to the undiscovered natural gas resource base for the Western
Canada Sedimentary Basin (WCSB) and key regional updates within US was completed
as new data became available in years 2002 and 2003. For the US, the primary data
sources were the United States Geological Survey (USGS) and Minerals Management
Service (MMS). For Canada ICF investigated the conventional resources assessment
of the Canadian Gas Potential Committee (CGPC), and unconventional resources
assessments published by the Alberta Energy Utilities Board (AEUB), publicly available
reports and the provincial energy departments for Saskatchewan and British Columbia.
A particular area of update was the estimate of undiscovered resource base attributed to
conceptual geologic plays in Canada. A conceptual play (or hypothetical play) is a
geologic play that has not yet been 'proved by commercial oil and gas production. A
conceptual play in Canada may have had some exploratory drilling and discoveries of
non-commercial accumulations. Re-estimation and re-interpretation of existing data as
well as availability of new data in year 2003 by CGPC and the National Energy Board
(NEB) of Canada indicates significantly lower estimate for these plays than previously
estimated.
Before describing the details of resources data used in NANGAS, it is important to
explain the E&P forecasting methodology used in NANGAS. This discussion helps in
understanding the resources data requirements for NANGAS and the rationale behind
the resources data collection efforts.
Field Development and Production Forecast Methodology in NANGAS
Field development and production forecast methodology in NANGAS is as follows: Total
resources are estimated for individual geologic plays. The undiscovered resources for
each geologic play are distributed among size classes. Fields are discovered and
developed subject to economic and reservoir and production engineering constraints.
Reservoir engineering constraints are determined by the resource type and reservoir
parameters such as porosity, permeability, pay thickness, water saturation, and reservoir
area.
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The NANGAS resource module estimates average reservoir parameters (such as
porosity, permeability, water saturation, thickness, areal extent, reservoir pressure, etc.)
for discovered (known) reservoirs and extrapolates these average reservoir parameters
to undeveloped (unknown) reservoirs in the same or comparable geologic play. A
production history match is obtained for developed reservoirs in producing fields utilizing
production type curves for specific resource types (such as conventional, tight gas,
coalbed methane, naturally fractured, etc.). These production type curves are also used
to project future production from discovered reservoirs. The production type curves are
also applied to undiscovered resources to generate typical production profiles based on
estimated resource type, average reservoir properties and E&P technologies. Use of
this approach helps in quantifying production potential based on reservoir depth, quality,
and size as well as E&P technology.
The most important assumption influencing the production forecast is the resource size
and the distribution of the undiscovered resource base into field or pool size classes and
the economic field size class cutoff. Special efforts were taken to determine an accurate
distribution of resources within appropriate size classes.
L-48 U.S. Resources and Reserves
This section describes the U.S. resource data sources and methodology used in
NANGAS for EPA Base Case 2004, v. 2.1.9. The primary data source for the
undiscovered resource base in NANGAS is the comprehensive national resource
estimate completed by USGS in the year 1995. Resource data in NANGAS was
updated to be consistent with the recently revised USGS resource assessments for nine
oil and gas producing basins in the Rocky Mountain, Appalachia, and the states of
Mississippi and Alabama. This update reduced the undiscovered resource base by 61
Tcf than previously estimated by USGS in 1995, and redistributed undiscovered
resources between conventional, coalbed methane, and tight resource types in the
Rockies and Appalachia consistent with latest USGS estimates. Exhibit 3 summarizes
the U.S. Lower-48 undiscovered resource base used in NANGAS.
Exhibit 3: Undiscovered Resource by Play
Resource Type
L-48 Onshore Conventional
(non-associated)
L-48
"Tight"/ Continuous
L-48 Coalbed Methane/
Fractured Shale
Total L-48 Onshore
Offshore
(Gulf of Mexico OCS)
Associated Dissolved Gas
Total U.S. Lower-48
Undiscovered
Recoverable
Resources, Tcf
137
208.2
119.9
465.1
192.9
85.0
743.0
Number of Plays
230
28
47
305
17
NA
322
USGS and MMS Resource Assessments. NANGAS incorporates the 1995 USGS
assessment of undiscovered resources for the onshore lower-48 states reported in the
1995 U.S. National Assessment of Oil and Gas Resources. The geologic plays, supply
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producing areas and supply regions identified in the 1995 National Assessment provide
the underlying structure for the resource database for the onshore U.S. The USGS is in
the process of revising the National Assessment and as of the fourth quarter of 2003.
New resource assessments were completed and available for nine onshore basins:
Appalachian Basin, Powder River Basin, Denver Basin, Florida Peninsula, Montana
Thrust Belt, Powder River Basin, San Juan Basin, Southwestern Wyoming, and Uinta-
Piceance Basin. In addition, the new National Assessment incorporates the latest
concepts in basin stratigraphy and petroleum-producing systems. As a result, the unit of
the 'geologic play', which rolled-up to a 'geologic province' in the 1995 National
Assessment has been replaced by 'assessment units' that comprise 'total petroleum
systems' within geologic basins. An assessment unit in the new 2005 National
Assessment corresponds approximately to a geologic play. Although the new USGS
National Assessment will not be completed until late 2005, the new data for the
completed basins were obtained and incorporated into the model for this effort.
NANGAS will be updated periodically with the latest USGS resource assessments for
individual basins as they become available.
For the Gulf of Mexico Outer Continental Shelf (OCS), NANGAS incorporates the
estimated undiscovered recoverable resources from the U.S. Minerals Management
Service 2000 Assessment of Oil and Gas Resources of the Outer Continental Shelf. A
methodology was developed that distributed these undiscovered resources into
seventeen geographical plays defined by water depth and Gulf of Mexico Planning Area.
The MMS is currently updating the OCS resource assessment, which is expected to be
available in 2005 and will be incorporated in future versions of NANGAS. Currently,
resources from emerging deep shelf gas plays in the Gulf of Mexico are not included in
NANGAS as detailed data has not been published by MMS. An MMS press release
from November 2003, however, estimates that undiscovered resources for deep shelf
gas range from 5 trillion cubic feet (Tcf) to 20 Tcf.1 The next version of the model will
include resources in the deep shelf plays when additional data becomes available.
Crosswalk Geologic Plays and New USGS Assessment Units. The resource base in the
model contains all of the results of the USGS 2005 National Assessment that were
available to the public in late 2003. The changes to the undiscovered resource base are
most apparent in the Appalachian and Rocky Mountain supply regions. The first step to
incorporate the new USGS resource assessments was to crosswalk the geologic plays
in NANGAS with the 'assessment units' identified in the 2003 resource assessments.
There is often a one-to-one correspondence between the geologic plays defined in 1995
and the 2003 assessment units. In some cases, the 1995 geologic plays are omitted in
the 2003 assessment, or are combined with other plays to correspond to a single
assessment unit. In other cases, completely new assessment units are defined in 2003,
which do not correspond to any 1995 geologic plays. The new USGS resource
assessments were incorporated into NANGAS by creating a crosswalk between geologic
plays and the 2003 assessment units. Once geologic plays and assessment units were
matched, the estimated resources for the assessment units replace the resources
United States Minerals Management Service Press Release, Deep shelf gas may be more abundant in Gulf than
earlier forecast, Press Release Number 3012, November 19, 2003. United States Minerals Management Service, 2003,
Gulf of Mexico OCS Deep Shelf Gas Update: 2001 - 2002.
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associated with the corresponding geologic plays. Some geologic plays were deleted,
others were combined, and new assessment units were added.
The new USGS National Assessment replaces the resource type of 'tight' or 'low-
permeability' gas sands, with the concept of 'continuous' resources, which may be
fractured gas shales, or low permeability sandstone and carbonate reservoirs.
Continuous resources are extensive; contain no obvious structural component or
downdip gas/ water contact; are often abnormally pressured; and are economically
developed using large numbers of closely-spaced producing wells and well stimulation
techniques such as hydraulic fracturing. The resource types for the new USGS
assessment units are designated as 'conventional', 'continuous', or 'coalbed methane'.
Each new assessment unit incorporated in NANGAS is assigned as either coal/
fractured shale, tight, or conventional. USGS assessment units designated as a
'continuous' were re-designated either as 'tight' or 'coal/fractured shale', in NANGAS
depending upon the primary reservoir lithology of the assessment unit. The new USGS
resource assessments show significant shifts in undiscovered resources between
resource type categories in some producing basins, compared to the 1995 National
Assessment. Conventional undiscovered resources are reduced in many plays and
some hypothetical conventional plays are deleted. A few significant new conventional
plays are added in the Montana Thrust Belt. Undiscovered coalbed methane resources
are increased substantially in the Rocky Mountain region and Appalachian Basin
compared to the 1995 National Assessment and continuous resources attributed to tight
gas plays are reduced significantly compared to the 1995 National Assessment.
Field Size Distribution. For conventional resource plays or assessment units, the new
USGS assessment continues to estimate a minimum, maximum, and median field size
for undiscovered hydrocarbon accumulations in the play. The new USGS minimum,
maximum, and median field size classes (FSC) were compared with the NANGAS field
size distributions for corresponding geologic plays. The field size distributions for
conventional resources in NANGAS compared favorably with the minimum, maximum,
and median field size classes estimated by the USGS. In a few conventional plays the
field size distribution appeared to be shifted towards larger field sizes in NANGAS
compared to the new USGS assessment unit corresponding to the play. For these
conventional plays, the internal field size distribution procedure was modified so that the
maximum undiscovered field size in the NANGAS distribution does not exceed the
maximum undiscovered field size class estimated by the USGS for the corresponding
assessment unit.
The new USGS resource assessment does not apply the concept of a producing field to
continuous and coalbed methane resource types. Instead, the remaining undiscovered
resource is divided into conceptual cells representing the minimum, maximum, and
median volume of reservoir that could be drained by a single well. The minimum,
maximum, and median estimated ultimate recovery (EUR) is estimated for each cell, in
addition to the drainage area (or well spacing) represented by a single cell. The cell
EURs do not correspond directly to field size class or the field size distributions used in
NANGAS for tight or coalbed methane plays. For unconventional plays, undiscovered
resources were distributed in categories (or classes) by assuming a typical field
containing 24 wells. This was found to be generally reasonable for most plays,
compared to the corresponding USGS assessment units. Individual well spacing
assumptions were reduced to reflect current production practices.
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Reservoir Properties. The discovered reservoir database in NANGAS contains average
reservoir parameters for known reservoirs in a geologic play. The average reservoir
parameters from discovered producing reservoirs in a play are applied to undiscovered
reservoirs in the play so that production can be projected using production type curves
and a production history match. If porosity or permeability is unknown or unspecified for
an undiscovered reservoir, the missing parameter is estimated using a porosity-
permeability correlation. While a comprehensive re-evaluation of reservoir parameters
in the NANGAS reservoir databases was not completed, some reservoir parameters
were updated as new data were provided by the new USGS resources assessments.
The updated reservoir parameters included average reservoir depth, more complete
data on gas composition and impurities, and percent of federal land in the play.
While there are inherent limitations and uncertainties in estimating average reservoir
parameters for known producing reservoirs and applying these parameters to
undiscovered resource base, ICF has found that it is a better approach than applying
econometrically determined finding rates or reserves-to-production (R/P) ratios. This
approach is also useful to correctly model the impacts of technology improvement and
certain policy initiatives influenced by technology. ICF recognizes that in modeling the
long-term development of resources, smaller fields are found in the future as larger fields
are discovered and developed first. Reservoir properties of smaller fields may not be
same as the larger fields, so the average reservoir parameters applied to small fields
such as permeability, porosity, and water saturation should be adjusted over time, which
would impact the field production profiles. This issue may be particularly important in
some mature conventional producing regions such as the Permian Basin and Gulf
Coast, which are experiencing rapid depletion of smaller fields in some plays. ICF
tested this idea with some limited sensitivity analyses in which the reservoir quality of
smaller undiscovered fields was reduced in selected regions. While changing the
reservoir parameters for undiscovered reservoirs did impact (and reduce) projected
production, the impacts of other model adjustments, such as resource base and their
size distribution, were more significant.
U.S. Reserves and Reserve Growth. The 1995 USGS National Assessment estimates
that approximately 294 Tcf of the U.S. resource base will come from reserves growth of
existing fields. Approximately 200 Tcf of reserve growth will be from onshore non-
associated gas production in the Lower-48 states. The U.S. MMS estimates that 67 Tcf
of future resources will be contributed by reserve growth in existing offshore fields in the
OCS. The reserve growth resources in NANGAS are consistent with the USGS and
MMS estimates. Reserves are booked as a function of development drilling.
Canada Resources and Reserves
This section describes the Canadian resource data sources and methodology used in
NANGAS for EPA Base Case 2004, v. 2.1.9. The NANGAS methodology for projecting
production from discovered and undiscovered resources of the WCSB is similar to the
methodology for projecting production from the U.S. resource base. Total resources are
estimated for individual geologic plays. The undiscovered resources for each geologic
play are distributed among field size classes. Fields are discovered and developed
subject to economic and reservoir and production engineering constraints. The reservoir
engineering constraints are determined by the resource type and reservoir parameters
such as porosity, permeability, pay thickness, water saturation, and reservoir area.
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Other gas-producing regions in Canada, such as the Mackenzie Delta and offshore
Atlantic including Sable Island, are handled in the model as exogenous gas supply
projects. The production forecasts for these regions are based on current and expected
project capacity and planned project expansions. They are explained in detail in a
separate section of this report.
Exhibit 4 summarizes the WCSB resource base used in NANGAS.
Exhibit 4: Undiscovered Resources in WCSB
Conventional Established
Plays
Conventional Conceptual
Plays
Tight' Gas/ Continuous
Coalbed Methane
Total
Undiscovered Resources,
Tcf
(Original Gas in Place)
133.4
40
206
192.3
572
Number of
Plays
79
8
15
24
126
In this effort, a substantial redistribution of undiscovered resources among the various
resource type categories have been conducted consistent with published recent
estimates by the CGPC. Estimated undiscovered resources in conventional conceptual
plays2 have decreased by more than 50% than previously estimated. In part, this is
because the recent CGPC resource assessments represent a more conservative view of
hydrocarbon resources in conceptual plays. Also, some conceptual plays in earlier
WCSB resource assessments now have proved commercial gas production and have
moved to the category of established plays. Estimated unconventional (tight gas and
coalbed methane) resources have increased by 50% than previously estimated based
on better data and analyses completed by various Canadian agencies and private firms.
Conventional Resources in Established Plays. A complete update of the undiscovered
resource base was completed in NANGAS for EPA Base Case 2004, v. 2.1.9. ICF
acquired the most recent resource assessment for the WCSB published by the CGPC3
and updated undiscovered resources data for established plays in WCSB.
The reservoir database in the model is updated with reservoir parameters provided for
each play in the CGPC report. Following is a list of updated reservoir parameters that
are captured in the reservoir database:
Average Recovery Factor
Porosity
Water Saturation
Temperature Gradient
Gas Gravity
Average Z Factor
- Depth
- Pay Thickness
- Formation Volume Factor
- Reservoir Pressure Gradient
- Heat Value
- Gas Composition
Conceptual plays have not been proven to contain commercial hydrocarbon accumulations. Most conceptual plays
have been explored to some extent, but no producing fields have been established.
Canadian Gas Potential Committee, 2001, Natural Gas Potential in Canada - 2001, Calgary, Alberta.
10
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Total conventional undiscovered resources in established plays is 133.4 Tcf and are
distributed to field size class categories using the modified Arps-Roberts methodology.
Conventional Resources in Conceptual Plays. Conceptual plays are geologic plays that
have no significant discoveries to date, but do have favorable geologic features for oil or
gas production. Many conceptual plays have been tested with exploratory drilling and
may have non-commercial discoveries. The 2001 CGPC identifies six conceptual plays
in the WCSB, but provides no quantitative assessments of the resource potential.
NANGAS currently assumes 40 Tcf of resource in eight conceptual plays for the WCSB,
including six conceptual plays identified in the 2001 CGPC study and two conceptual
plays identified in the earlier Geological Survey of Canada (GSC, 1993) resource
assessment. The 40 Tcf of resource assumed for conceptual plays represents the
difference between the 2001 CGPC assessment of total undiscovered resources in the
Western Canada Sedimentary Basin (133.4 Tcf) and an alternate view of undiscovered
WCSB resources (174 Tcf) presented by the Canadian Energy Resource Institute
(CERI).4 The 40 Tcf of resources in conceptual plays is distributed equally among the
eight conceptual plays. Reservoir parameters for the eight conceptual plays are
estimated from known analogous geologic plays.
Tight Gas/Continuous Resources. The definition of 'tight' gas reservoirs in Canada has
not been established by a governmental entity, as is the case in the United States.
Tight' or 'continuous' resources are not limited to reservoirs with average permeability
less than 0.1 millidarcy, but are generally defined as regionally extensive reservoirs that
are sub-economic using normal completion and production standards. Most tight
reservoirs in the WCSB have been identified in the deep basin areas as regionally
pervasive, thick, gas-saturated reservoir sequences that have abnormal reservoir
pressures and no apparent downdip gas/water contact. Three known tight gas regions
in the WCSB include:
• Deep Basin; stacked Mesozoic clastic reservoirs
• Foothills, Disturbed Belt; naturally fractured low-permeability reservoirs
• Northern Plains; areally-extensive, shallow reservoirs with subtle natural
fractures and no apparent local structure; require hydraulic fracturing and
horizontal drilling
Few play-level assessments of the resource potential of tight gas reservoirs in the
WCSB are publicly available, although this situation changing. The tight gas/continuous
resource update completed as part of EPA Base Case 2004, v. 2.1.9 includes gas-in-
place for fifteen identified tight geologic plays.5 The gas-in-place estimated for the
individual plays ranges between one and three billion cubic feet (Bcf) per square
4 CERI maintains that the Canadian Gas Potential Committee (CGPC) was too conservative and excluded a number of
areas in the WCSB "thought to have reasonable prospects for natural gas." CERI commissioned a study to re-evaluate
the WCSB undiscovered resource base, incorporating both the 2001 CGPC study and the earlier Geological Survey of
Canada (GSC) work, with an emphasis on the assessment of gas-in-place for conceptual plays. The reference for the
40 Tcf undiscovered resources attributed to conceptual plays is Canada's Ultimate Natural Gas Potential-Defining a
Credible Upper Bound, Drummond Consulting, March 2002 as reported in Potential Supply and Costs of Natural Gas
in Canada, Canadian Energy Research Institute, 2003.
5 Exploration Assessment of Tight Gas Plays, Northeast British Columbia, 2003, Petrel Robertson Consulting, Calgary,
AB and Hayes, 2003, The Deep Basin- A Hot "Tight Gas" Play for 25 Years, Petrel Robertson Consulting, presented at
American Association of Petroleum Geologists Annual Convention, May 11-14, 2003, Salt Lake City, Utah.
11
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kilometer. A low estimate and a high estimate of gas-in-place were provided for each
play. NANGAS currently contains the low estimate of 206 Tcf for the tight gas resource
base; the total high estimate for total tight gas resources is 546 Tcf. The low estimate is
more reasonable because the WCSB has very little production from tight reservoirs. As
tight gas development proceeds in the future the estimated resource base and its
characterization will be revised, and a larger tight gas resource base may be justified.
Coalbed Methane. The current update greatly improves the representation of the WCSB
coalbed methane resource base in NANGAS, drawing upon recent geologic analysis of
coalbed methane plays and recent resource assessments by the CGPC and provincial
energy agencies in Alberta and British Columbia.6 Twenty-four coalbed methane plays
are specified in the model, ten in Alberta and twelve in British Columbia. Little data are
available for reservoir parameters besides reservoir depth and gas content. Typical
default parameters (langmuir pressure, langmuir volume, sorption time, pressure,
permeability, thickness, porosity etc.) are used based on coalbed methane resources
located in the U.S. These will be updated as reservoir specific and basin specific data
become available in the future. A low estimate and a high estimate of gas-in-place were
provided for each play. EPA Base Case 2004, v. 2.1.9 currently contains the low
estimate of 192 Tcf for the coalbed methane resource base; the high estimate for
coalbed methane resources is 294 Tcf. As more coalbed methane activities are
conducted in Western Canada, the data and size of the resource base will be revised.
Interim Calibration of NANGAS Production Results
As the resource data, its characterization and implementation were updated as part of
EPA Base Case 2004, v. 2.1.9 effort, it was necessary to compare and calibrate regional
production trends achieved in NANGAS with established history. As the effort for
creating EPA Base Case 2004, v. 2.1.9 supply curves progressed, regional NANGAS
results were compared with recent history and reservoir parameters were updated to
ensure consistency with near term production trends. This calibration exercise ensured
that the near-term regional production forecasts did reflect recent production trends. For
example, if regional production is in decline, the model forecast for the supply region
must capture that trend in the initial model years. The Rocky Mountain and Gulf Coast
regions proved to be especially challenging to calibrate the production output and 'fine
tune' the model revisions. Regional natural gas production reports provided by Lippman
Consulting, Inc.7 were helpful for calibrating the model update in these supply regions.
At EPA's suggestion, ICF purchased two Lippman Consulting quarterly production
reports, which contained regional and state monthly gas production data as well as
drilling data and rig utilization. Exhibits 5, 6, and 7 illustrate the production trend
6 Sources: 1. Alberta Geological Survey and Alberta Scientific Research Authority, 2002, Coalbed Methane Potential
of Upper Cretaceous-Tertiary Strata, Alberta Plains, Earth Sciences Report 2002-06. 2. Alberta Geological Survey
and Alberta Scientific Research Authority, 2002, Regional Evaluation of the Coalbed Methane Potential of the
Foothills and Mountains of Alberta, Earth Sciences Report 2002-05. 3. British Columbia Ministry of Energy and
Mines, Fact Sheet: B.C. Coalbed Methane Resources 4. British Columbia Ministry of Energy and Mines, 2003,
Map: Coalfields and Coalbed Methane Potential in British Columbia. 5. Low case gas-in-place estimate for coalbed
methane in Mannville Formation and Paskapoo Formation coals from the 2001 Canadian Gas Potential Committee
assessment of the WCSB.
Lippman Consulting, Inc., 2003, Gulf Region - 2003 2nd Quarter Natural Gas Production Report.
Lippman Consulting, Inc., 2003, Rocky Mountain Region - 2003 2nd Quarter Natural Gas Production Report.
12
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comparison between NANGAS and Lippman Consulting reports. These exhibits
illustrate that the calibration exercises were able to improve consistency between longer
term projected production trends and the shorter term trends recently observed in key
producing basins in the U.S.
An example comparison of production forecasts for the WCSB is shown in Exhibit 8.
The EPA Base Case 2004, v. 2.1.9 forecast for WCSB using NANGAS is compared to
the 2003 National Petroleum Council8 forecast, and the recent production forecasts from
the National Energy Board (NEB).9 The production outlook for WCSB remains flat to
declining and rises modestly after 2015 as unconventional resources become an
increasing component of WCSB production. A decrease in year 2015 is due to Alaska
entering the marketplace and depressing prices in Alberta for a few years. There is a
short run-up of production just before Alaska enters the marketplace as producers
maximize production from existing fields. The NANGAS, NPC 2003, and NEB
Technovert WCSB production outlooks presented in Exhibit 8 are very similar, albeit at a
lower price in NANGAS than in NPC 2003.
Exhibit 5: Production Comparison and Forecast for U.S. Rockies
EPA Base Case 2.1.9
Lippman Consulting (Historical Data: 1996-2003)
Year
National Petroleum Council, 2003, Balancing Natural Gas Policy - Fueling the Demands of a Growing Economy,
Volume II, Integrated Report. U.S. National Petroleum Council, Washington B.C.
9 National Energy Board, 2003, Canada's Energy Future, Scenarios for Supply and Demand to 2025, Calgary, Alberta.
13
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Exhibit 6: Production Comparison and Forecast for Texas Rail Road
Commission (RCC) Districts 1-4
3000
Lippman Consulting (Historical Data:
1996-2003)
§
Year
Exhibit 7: Production Comparison and Forecast for Louisiana, Alabama, Florida
and Mississippi
3,000
EPA Base Case 2.1.9
Lippman Consulting (Historical Data: 1996-2003)
R
Year
14
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7,000
Exhibit 8: Comparison of WCSB Production Forecasts
3,000
2,000
1,000
S
— NPC2003
-A- NEB Technovert
o
8
CO
8
(D
8
NEB Supply Push
EPA Base Case 2.1.9
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4. Treatment of Frontier Resources
In addition to the traditional sources of natural gas resources as described in the
Resources Data and Reservoir Description section, NANGAS also contains resources
located in frontier regions. These frontier resources (or project level supplies) are used
to model large projects, which can have dramatic impact on prices in the near term.
Frontier resources for this modeling effort include Alaska North Slope, Mackenzie Delta,
Sable Island and LNG. We do not start from the resource base in these categories and
do not develop production cost curves; rather we use threshold pricing (trigger prices) for
these supplies to come online. The two attributes of these supply sources, maximum
capacity by year and minimum threshold price, are exogenously provided.
These frontier resources are modeled in NANGAS as market pull, indicating they are
available at threshold prices. These projects are brought on-stream only when the
threshold prices are reached and the discounted net present value of the net revenue
stream (i.e. the marginal price at the demand node less the marginal price at the supply
node plus full cost of transportation) is positive. Once the decision is made, the supply
project is used every year until the end of the model run.
Information used to characterize these frontier resources was obtained from various
publicly available sources. Supply curves were generated for each frontier resource
category.
• Alaska North Slope (ANS): The natural gas resource located in ANS is substantial,
with proven reserves of 35 Tcf in the Prudhoe Bay area where most of the oil
production activities are currently conducted. In addition to the proven reserves,
USGS estimates that ANS contains as much as 100 Tcf of undiscovered resource.
To date, this resource is stranded because it lacks effective commercial access to
markets. In fact, 6-8 Bcf/d of gas that is currently produced as part of the oil
activities in the Slope is re-injected back into the Slope's oil reservoirs as part of the
pressure maintenance programs. As the oil fields mature and produce less oil and
more gas, the need for and the economic viability of gas re-injection diminishes.
ANS producers, various pipeline project proponents, and governments in both the
US and Canada have stepped up efforts to bring to fruition the long-held goal of
monetizing ANS gas. For EPA Base Case 2004, v. 2.1.9, ICF has chosen to show
Alaska North Slope gas being brought to the Lower-48 markets starting in the year
2015 at a threshold wellhead price of $0.75/MMBtu. Alaska supplies start at 4.1 Bcf/d
in year 2015, expands to 4.6 Bcf/d in 2017, and then again in 2019 to a total of 5.2
Bcf/d. We have not assumed any gas supplies from the Arctic National Wldlife
Refuge (ANWR) in this study. Exhibit 9 shows the assumption for Alaska North
Slope.
• Mackenzie Delta (MD): In the Mackenzie delta area of Canada (300 miles east of
Prudhoe Bay), exploration drilling from 1970 and 1989 discovered 53 oil and gas
pools about equally divided between the onshore and offshore areas. The Mackenzie
delta area contains approximately 9-12 Tcf of discovered gas and over 60 Tcf of
undiscovered gas, some of which is in pools sufficiently large to justify construction
of a new gas pipeline to take the gas south to Alberta. Supply potential from
Mackenzie delta can be over 2 Bcf/d. All of the Mackenzie delta discoveries are
stranded at the present time, although several development proposals are under
16
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consideration. There is a renewed interest by Governments, producers, pipeline
companies and Aboriginal peoples in exploiting the natural gas resources and
transporting them to the Lower 48 markets due to projections of strong growth in
natural gas fired generation, and the recent strength of gas prices. For EPA Base
Case 2004, v. 2.1.9, ICF assumed that Mackenzie Delta gas can be brought to the
Lower-48 markets starting in the year 2009 at at a threshold wellhead price of $1.0
/MMBtu. Mackenzie Delta supplies start at 1.2 Bcf/d in year 2009, expand to 1.5
Bcf/d three years later in 2012, and then again in 2021 to a total of 2.0 Bcf/d. On
average, around 75% of Mackenzie Delta volume is used in oil sands recovery
projects in Western Canada. Volume of gas used for oil sands recovery in Western
Canada is not a function of oil price.
Both Alaska as well as Mackenzie Delta supplies are delivered in Alberta and then
re-delivered to L-48 via existing pipelines and expansions. Exhibit 9 shows the
assumption for Mackenzie Delta.
Exhibit 9: Assumptions for Alaska North Slope and Mackenzie Delta
Frontier Resurce Supply
Description
Alaska North Slope
Alaska North Slope (incremental)
Alaska North Slope (incremental)
Alaska North Slope (incremental)
Mackenzie Delta
Mackenzie Delta (incremental)
Mackenzie Delta (incremental)
First Year of
Potential
Expansion
2015
2017
2019
2021
2009
2012
2015
Trigger
Price,
2003$ /MMBtu
0.75
0.75
0.75
0.75
1.00
1.00
1.00
Capacity,
Bcf/d
4.10
0.51
0.58
0.52
1.20
0.30
0.50
Cumulative
Capacity,
Bcf/d
4.1
4.6
5.2
5.7
1.2
1.5
2.0
Sable Island: Estimated recoverable resources in Offshore Nova Scotia is over 30
Tcf. Sizeable quantities of natural gas are believed to be deposited in the Sable
Island Sub Basin, deepwater Laurentian and Sydney channels, Georges Bank and
St. Pierre Island. The Georges Bank and St. Pierre Island are currently under
moratorium and no drilling has taken place. Sable Island shows the most promise
for production, and will be supplemented by deepwater supplies from the region in
the longer term. This study included supply only from Sable Island because of
development activities in the area. Other regions of the area are in early stages of
leasing and data collection, and publicly available gas resource data are incomplete.
According to the CGPC, Sable Island is estimated to contain 3.7 Tcf of proven
reserves, and 8.1 Tcf of undiscovered marketable natural gas. Commercial
production from Sable Island started in December 1999. Sable Island gas is shipped
over Maritimes and Northeast pipeline to the Canadian Maritimes and U.S.
Northeast.
Sable Island is assumed to grow modestly in the near term reflecting the current
difficulties in the productivity of wells located in the offshore fields. A first expansion
of 250 MMcfd is assumed in the year 2008 and the next expansion in the year 2015
making the total volume to 1.0 Bcf/d by the year 2015 (Exhibit 10). A threshold price
of $1.35/MMBtu at the tailgate of Sable Island reflects the minimum threshold cost of
17
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production from Sable Island. Assumptions for Sable Island supplies have a direct
impact on an eastern Canada LNG terminal economics.
Exhibit 10: Assumptions for Sable Island
Frontier Resurce Supply
Description
Sable Island
Sable Island (incremental)
Sable Island (incremental)
First Year of
Potential
Expansion
Existing
2003
2015
Trigger
Price,
2003$,MMBtu
NA
1.35
1.35
Capacity,
Bcf/d
0.50
0.25
0.25
Cumulative
Capacity,
Bcf/d
0.5
0.8
1.0
• Existing and Potential Liquefied Natural Gas (LNG) Terminals: LNG is natural
gas that has been transformed to a liquid by super-cooling it to minus 260 degrees
Fahrenheit, reducing its volume by a factor of 600. LNG is then shipped on board
special carriers, and the process is reversed at a receiving facility with the re-gasified
product delivered via pipeline. Historically, LNG has supplied less than 1% of overall
U.S. gas demand, due to high costs of transportation and liquefaction. Recently,
however, improvements in the liquefaction process, combined with decreasing
shipping costs, have resulted in a 50% decline in supply costs. The decrease in
LNG cost has also come at a time when U.S. natural gas prices have increased over
three folds compared to average price of $2.50-$3.0/MMBtu of the 1990s. In
addition to the increased competitiveness of LNG, stranded gas reserves amounting
to over 4,000 Tcf worldwide are making LNG an attractive gas supply option to meet
rapidly increasing demand. This has led to many U.S. majors such as ExxonMobil,
ConocoPhillips, Shell, BP etc. to look into tapping stranded natural gas resources in
countries like Qatar, Trinidad, Algeria, Indonesia, Australia and others. Over 30 LNG
import terminal proposals have been announced within U.S. in the hope of tapping
these cheaper natural resources (see Exhibit 11). LNG is projected to make up a
growing percentage of imports in coming decade.
18
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Exhibit 11: Existing and Proposed Marine LNG Terminals as of June 2004
Existi n g Marine Terrni n a I
T Pro p a sed M a ri n e Te rrn inal
There are currently four LNG import terminals in the U.S. that are under operation, and
modeled in NANGAS. All four existing LNG terminals are assumed to operate at 85% of
their full rated capacity every year. Planned expansion levels on existing terminals are
taken from publicly available data. Within NANGAS planned expansions are assumed to
occur at no threshold price.
Gulf Coast LNG is assumed to expand at pre-defined threshold prices. These
expansions do not reflect any specific terminal but rather a general increase in LNG
volumes in the region. The Gulf Coast LNG threshold price is set at $3.00-
$3.50/MMBtu. Maximum available LNG volume in the region is 3.3 Bcf/d. NANGAS
solves for the actual volume realized based on supply/demand balancing. Bahamas
LNG is assumed to come online in the year 2008 at 0.50 Bcf/d. Assumptions for existing
and potential LNG capacity are listed in Exhibit 12.
19
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Exhibit 12: Assumptions for Existing and Planned LNG Capacity
Frontier Resurce Supply
Description
Distrigas
Distrigas @85% Capacity Utilization
Distrigas Planned Expansion
Cove Point
Cove Point @25% Capacity Utilization
Cove Point @50% Capacity Utilization
Cove Point @85% Capacity Utilization
Elba Island
Elba Island @85% Capacity Utilization
Elba Island Planned Expansion
Lake Charles/Gulf Coast LNG
Gulf Coast LNG (New Terminal)
Gulf Coast LNG (New Terminal)
Gulf Coast LNG (New Terminal)
Gulf Coast LNG (New Terminal)
Gulf Coast LNG (New Terminal)
Gulf Coast LNG (New Terminal)
Bahamas LNG
First Year of
Potential
Expansion
Existing
2004
2005
Existing
2004
2005
2006
Existing
2005
2006
Existing
2006
2009
2010
2011
2012
2016
2008
Trigger Price,
2003$,MMBtu
NA
0.00
0.00
NA
0.00
0.00
0.00
NA
0.00
0.00
NA
3.00
3.25
3.25
3.25
3.50
3.50
2.50
Capacity,
Bcf/d
0.30
0.07
0.16
0.08
0.12
0.18
0.26
0.22
0.15
0.21
0.53
0.25
0.50
0.50
0.50
0.50
0.50
0.80
Cumulative
Capacity,
Bcf/d
0.3
0.4
0.5
0.1
0.2
0.4
0.6
0.2
0.4
0.6
0.5
0.8
1.3
1.8
2.3
2.8
3.3
0.8
5. Assumption of Natural Gas Used for Oil Sands Recovery in Western Canada
Bitumen resources contained in Western Canada's oil sands deposits offer attractive
opportunities, as the resource is well defined and delineated. The extraction and
upgrading of oil from oil sands needs a large amount of natural gas. Mining and
upgrading projects use natural gas as a source of process heat and feedstock and use
about 0.4 Mcf of natural gas per barrel of oil produced. In situ projects use natural gas
as a source of generating heat to produce steam for thermal operations, using about 1.0
Mcf of natural gas per barrel of oil.
The total natural gas requirement for oil sands recovery is assumed to double by 2025 to
a level of 1.4 Bcf/d by year 2025. This is consistent with the Supply-Push case of the
NEB study (Canada's Energy Future: Scenarios for Supply and Demand to 2025,
published in 2003). The "Supply-Push" NEB case was used because the Henry Hub
price in this case is on average similar to the Henry Hub price resulting under EPA Base
Case 2004, v. 2.1.9.
Exhibit 13 shows natural gas demand assumed for oil sands recovery and Mackenzie
Delta volume in Bcf/d. On average, around 75% of Mackenzie Delta volume is used in
oil sands recovery projects in Western Canada, remaining 25% is exported to L-48 U.S.
As noted earlier in the discussion of Mackenzie Delta gas, the volume of gas used for oil
sands recovery in Western Canada is not a function of oil price.
20
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Exhibit 13: Natural Gas Use for Oil Sands Recovery in Western Canada
2.25
DO 1 .OU
of
"o
w 0.75
CD
O
0.00
• Natural Gas Demand in Oil Sands
Mackenzie Delta Vol.
..............
2004
2007
2010
2013
2016
2019
2022
2025
Natural gas supplies and prices are major factors affecting oil sands recovery in Western
Canada. If natural gas prices become very high or natural gas supplies become short in
supply in Western Canada, then oil sands recovery could lag. Alternatives to natural gas
include: gasification of bitumen, use of coal through clean coal technology, nuclear
energy etc., but these are not currently in use for oil sands recovery.
6. E&P Technology Characterization
NANGAS uses E&P technology levers that are applied to the resource base in order to
forecast productive capacity and production. In order to assure consistent analytical
results from NANGAS and to appropriately address E&P technology issues, data for use
in updating key NANGAS technology assumptions were obtained through a combination
of research and analysis of governmental and industry sources. Key data elements were
derived from the published literature, Energy Information Administration (EIA)
publications, and proprietary sources. The following three general assumptions are
made in developing E&P technology parameters in NANGAS.
• E&P technologies will continue to advance at a rate consistent with historical trends.
• Despite recent declines, we assume that investments in R&D will stabilize (by
private/public partnerships, multi-company research consortia, etc.) with
corresponding technological advances continuing.
• Insights and interpretation of the E&P R&D efforts conducted at the Strategic Center
for Natural Gas (SCNG), U.S. Department of Energy (DOE) were used in
determining technological levers and advancements rates.
The E&P technology assumptions and improvements in NANGAS were developed to
capture gradual technology advances that would impact the North American gas market.
A drastic/sudden improvement in E&P technologies is not assumed. Both current state-
of-the-art as well as possible advanced technology parameters were used to model the
potential impact of expanded technology application on the gas market. The E&P
technology parameters used in NANGAS are as follows:
21
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• Skin Factor: Represents drilling technology (drill bit design, air drilling, mud
drilling etc.), completion/stimulation technology (acidizing, fracturing, perforation
angle and size etc.). Sources of data include trade publications, SPE literature,
and DOE.
• Fracture Length/Conductivity: Represents hydraulic fracturing technology
(such as proppant design, type etc.). Sources of data include SPE literature,
DOE and standard operating procedures.
• Horizontal Well Length: Represents drilling technology. Sources of data include
SPE literature, Oil and Gas Journal.
• Success Rates: Represents seismic technology (3-D, 4-D seismic surveys).
Sources of data include EIA, SPE literature and company press releases.
• Drilling Capacity: Represents drilling footage drilled. Sources of data include
API and professional judgment.
Exhibit 14 shows how the specific E&P technology factors considered were varied in the
analysis. These technology parameters were updated based on peer review
recommendations.
As shown in Exhibit 14, "skin factor," a dimensionless factor representing the restriction
on gas flow in the near-wellbore domain, improves from a current value of 6 to a value of
2 with the application of advanced technology. Completion and stimulation techniques
were also assumed to improve for unconventional resources. Current practices achieve
on average 200 feet of effective fracture half-length (400 feet tip-to-tip). With
improvements in fracturing technology, it increases to 500 feet. In line with the fracture
half-length, the fracture conductivity, a measure of flow capacity of an induced fracture,
was assumed to increase from 1000 md-ft to 3000 md-ft. Onshore success rates
improve at 0.5% per year and offshore at 0.8% per year consistent with AEO 2004
assumptions. As the technology improves over time, the horizontal wells are expected
to increase in utilization and length of laterals. Horizontal wells were assumed to cost on
average 30% more than the vertical wells. Also, the dry hole rates for development as
well as exploration wells were assumed to decline with technology improvement. In this
study, the technology improvements did not affect the rig retirement rate as the rig
drilling capacity for current and advanced technologies was considered to be the same.
Compressor installation costs are assumed to be $1200/BHP.
Cost and economic parameters were also updated in the analysis. Operating costs were
assumed to reduce by 0.54% per year consistent with AEO 2004 assumptions.
Consistent with AEO 2004 assumptions, drilling costs for onshore regions decreased by
1.87% per year and for offshore regions by 1.2% per year.
In NANGAS, these advances in technology do not occur immediately. Time to develop,
test, market, and gain operator acceptance of the practices are considered in developing
the technology penetration curves. Applications are phased into the marketplace with
costs initially being higher and gradually declining as the market expands. The evolution
of E&P technology was analyzed by limiting both the market penetration rate and the
22
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ultimate saturation of key advances. This resulted in typical "S" shaped technology
penetration curves.
Exhibit 14: E&P Technology Assumptions for EPA Base Case 2004, v. 2.1.9
E&P Technology Parameter
Skin Factor (all resource types), dirnensionless
Fracture Half Lengths, ft
Fractrure Conductivity, md-ft
Horizontal Wells, ft
Horizontal Well Applicability for Accumulations
in Field Size Class (USGS definition of Field
Size Class 10 contains average recoverable
resources of 144 Bcfi
Initial Drilling Cost ($/ft)
Annual Drilling Cost Decline (Offshore), %
Annual Drilling Cost Decline (Onshore), %
E&P Operating Cost Decline, %
Compression Installation Cost ($/BHP)
Compression O&M Cost ($/Mcf)
Horizontal Well Cost With Respect to Vertical
'Well Cost, fraction
Exploration Success Rates, %
- Conventional
- Tight
- Natural Fracture
- Water Drive
- Coal and Shale
- Gulf Offshore
Development Success Rate
Current
Technology
6
200
1000
750
10
JAS 2000
1.20
1.87
0.54
1200
0.15
1.3
35
35
35
35
50
35
80
Advanced
Technology
3
500
3000
2500
10
90% of JAS 2000
1.20
1.87
0.54
1200
0.0995
1.17
39
39
39
39
55.5
41.2
90
%
Improvement
per year
2.2
6.5
3.7
10.1
0.0
0.4
1.2
1.9
0.5
0.0
1.2
0.4
0.5
0.5
0.5
0.5
0.5
0.8
0.5
The overriding principle of NANGAS decision-making is that all E&P decisions are based
on purely economic factors as an operator would do in field conditions. All project
investment decisions in NANGAS are based on meeting a specified hurdle rate. Based
on peer reviewer recommendations, this minimum hurdle rate is set at 15% for
exploration projects and 12% for development drilling projects.
7. Fuel Prices
Natural gas prices are forecasted by taking into account both coal as well as petroleum
product prices and demand levels in the industrial and electric sectors. Demand for
natural gas in the residential and commercial sectors are not directly dependent upon
alternative fuels. The following section contains discussions for crude oil, petroleum
products and coal prices used in developing natural gas supply curves for EPA Base
Case 2004, v. 2.1.9.
Crude Oil and Petroleum Product Price. Petroleum product prices play an important
role in determining the relative mix of fuel (oil, gas, coal) for meeting the end-use
demand in the electric and industrial sectors. NANGAS focuses on two petroleum
23
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products, No 2 Fuel Oil (distillate) and No. 6 Fuel Oil (residual fuel oil), the latter with two
different sulfur levels: low sulfur at 1% weight and high sulfur at 3% weight.
The delivered regional costs for both products are calculated as follows: First, the
delivered costs are calculated relative to crude oil prices in the U.S. Gulf. Then,
transportation costs between the U.S. Gulf and other regions of the country are
calculated.
There are two components for calculating the petroleum product prices delivered to the
end-use sector: 1) the price of the petroleum product relative to a reference crude oil
price and, 2) the cost of transportation to move the product from the various points of
manufacture to the end-use geographic location. Transportation movements are
somewhat different for the two products.
Distillate. Distillate products are produced throughout the United States, with the bulk
being produced in the large efficient refineries in the Gulf Coast. From the Gulf Coast,
pipelines radiate out to the East Coast, the Midwest and the Rockies. Petroleum
Administration for Defense Districts (PADD) V, the West Coast region, tends to be a
separate market, with some inter-connection between the Rockies and Spokane, and
between the Gulf Coast and Arizona. (The entire US is divided into five PADDs, PADD I:
East Coast, PADD II: Midwest, PADD III: Gulf Coast, PADD IV: Rocky Mountain, PADD
V: West Coast). In addition, the crude oil used on the West Coast tends to differ
markedly from that used elsewhere, and product specifications, at least in California, are
different.
Residual Fuel Oil. Similar to distillate, residual fuel oil tends to be produced throughout
the United States, with the focus on the Mid Atlantic, the Gulf Coast and the West Coast.
Movements within the country are constrained by the decreasing demand for residual
fuel oil by industry and utilities. Residual fuel oil does not move by pipeline, but by
tanker and barge, and occasionally railroad. The majority of movements are directed to
the East Coast, the area of greatest use, and where imports play a major role. Similar to
the distillate market, the West Coast residual market tends to be separate from the rest
of the United States.
For EPA Base Case 2004, v. 2.1.9, ICF has used the West Texas Intermediate (WTI)
crude oil price forecast from ElA's AEO 2004 with adjustments for year 2004 based on
expected price for year 2004. WTI crude oil is of very high quality and is excellent for
refining a larger portion of gasoline. Its API gravity is 39.6 degrees (making it a "light"
crude oil), and it contains only about 0.24 percent sulfur (making a "sweet" crude oil).
This combination of characteristics, combined with its location, makes it an ideal crude
oil to be refined in the U.S.
Refinery margins for the Gulf Coast region were derived from DOE's WORLD model.
The WORLD model is a linear programming (LP) model that simulates the total global
petroleum supply industry, encompassing crude and non-crude refinery inputs, refinery
production, refinery technologies, transportation, product demand, and quality. The
refinery margin used for this study reflects the move towards ultra-low sulfur distillate.
The regional transportation adders represent both pipeline charges for moving products
between different PADDs and charges for trucks and tankers.
24
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Exhibit 15 shows the WTI crude oil price and refinery margins for distillate, 1% residual
fuel oil and 3% residual fuel oil used in the study. As can be seen, there will be an
increase in the refinery margins for distillates and lowering or leveling-off of refinery
margins for residual fuel.
There are many reasons for this phenomenon. Product quality will be a major factor in
the future and particularly around 2010. By 2010, the OECD nations and the European
Union (EU) will have moved completely to ultra-low sulfur standards, generally less than
10-ppm for diesel and a maximum of 50-ppm for gasoline. Off-road diesel, both in the
United States and the EU will also move towards ultra-low sulfur. Non-OECD regions
are expected to make moves toward tighter gasoline and diesel quality standards such
as:
• Gasoline lead phase-out
• Diesel trends to lower sulfur standards with 500 ppm products becoming common
and availability of some ultra low sulfur diesel
• Sulfur standards are projected to tighten for residual fuels.
As the product specifications tighten, the availability of product imports becomes more
difficult exerting further upward pressure on the margins. In addition, by 2010 the crude
quality entering the U.S. will become heavier and contain more sulfur as imports of
heavy crude oil from countries like Canada, Venezuela and Mexico are expected to
increase. Therefore, greater processing will be required to upgrade the heavier crude to
produce distillates that meet environmental specifications. By the same token, as the
incoming crude oil gets heavier, it is easier to producer heavier residual oils.
Exhibit 15: Crude Oil Price Forecast and Refinery Margins
Year
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Average
(2004-2025)
WTI Crude
Oil Price,
2003$/bbl
36.6
30.9
26.4
26.6
26.8
26.9
27.1
27.3
27.5
27.7
27.8
28.0
28.2
28. 4
28.6
28.8
29.0
29.2
29.4
29.6
29.8
30.0
28.7
Gulf Coast Refinery Margins (2003$ bbl)
Distillate
3.8
3.1
2.5
2.7
2.9
3.1
3.3
3.4
3.6
3.7
3.8
3.9
4.3
4.7
5.1
5.4
5.8
5.8
5.8
5.8
5.8
5.8
4.3
1% Residual
Fuel Oil
-4.1
-4.5
-5.0
-4.8
-4.5
-4.3
-4.1
-4.4
-4.8
-5.1
-5.5
-5.8
-5.8
-5.7
-5.7
-5.7
-5.7
-5.7
-5.7
-5.7
-5.7
-5.7
-5.2
3% Residual Fuel
Oil
-5.2
-5.7
-6.2
-6.1
-6.0
-5.9
-5.7
-6.5
-7.2
-7.9
-8.6
-9.3
-9.3
-9.3
-9.3
-9.2
-9.2
-9.2
-9.2
-9.2
-9.2
-9.2
-7.9
25
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Coal Price. Average realized regional coal prices, based on actual dispatch and
generation patterns of coal plants, are taken directly from IPM outputs for EPA Base
Case 2004, v. 2.1.9 and used in NANGAS.
8. End Use Demand Characterization
NANGAS models natural gas demand in four end-use sectors: residential, commercial,
industrial and electric generation. For the electric generation sectors both utilities as well
as non-utilities are modeled. A total of 139 pipeline corridors connect 83
supply/demand/transfer nodes in the model. Prices are calculated at each of the 83
supply/demand/transfer nodes. The integrating linear program balances supply and
demand for gas based on the concept of maximizing consumer and producer surplus in
each region, year and season. There are following five key drivers for natural gas
demand in NANGAS. They are:
i) Crude oil price: Crude oil price is critical because of inter-fuel competition.
Industrials and electric utilities can switch between residual fuel oil and distillate
as natural gas prices go up. The average crude oil price used for EPA Base
Case 2004, v. 2.1.9 is $28.7/bbl (Data for years 2005-2025 was taken from AEO
2004).
ii) Macroeconmic parameters: A GDP growth rate of 3% per year was assumed
for the U.S., consistent with Bureau of Economic Analysis (BEA). For Canada, a
GDP growth rate of 2.3% per year was assumed consistent with Natural
Resources Canada (NRCAN) estimates. A population growth rate of 0.85% per
year was assumed for the U.S. (source: U.S. Census Bureau) and 0.93% per
year for Canada (Source: NRCAN). The number of households and household
income are derived from GDP and household size.
iii) Electric Demand Growth: Electric sector demand includes utility as well as non-
utility generators supplying electricity to the grid. The electric demand growth
rate was assumed to be 1.55% per year consistent with IPM Version 2.1.9.
iv) Pipeline Infrastructure: New pipeline capacity gets added at 1.25 times the
current reservation charges unless another specified rate is known to be more
accurate.
v) Weather: 30-year normal weather is assumed.
In the following sections, we will describe the modeling methodology, data and updates
completed for each of the end-use sector modeling.
Electricity Sector: Electric sector demand for natural gas in NANGAS was set
consistent with electric sector assumptions from IPM in order to mimic aggregate
regional level IPM decision making with respect to capacity additions, generation levels,
heat rates, and costs. In order for NANGAS and IPM to be consistent, key data from
IPM were incorporated directly into NANGAS. Entries by IPM demand regions were
cross-walked to the corresponding NANGAS demand region to ensure consistency.
The main drivers for natural gas demand in the electric sector are the cost and
performance data as shown below.
• Electricity generation (BKWH) by region and year
• Average realized heat rates (BTU/KWH) by plant type and year
26
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• Capital cost by plant type and year
• Average realized fixed O&M cost by plant type and year
• Average realized variable O&M cost by plant type and year
• Discount rates
• Capital charge rates
• Maximum utilization of existing and new plants
Utilizing data at this detail in NANGAS helped preserve the detailed power sector
dispatch modeling conducted in IPM and captured IPM's forecast of regional and annual
gas demand in NANGAS. The overall gas price forecast generated from NANGAS is
highly dependent upon the characterization of the electric sector. For example: a higher
heat rate assumption for new electric plants would result in higher demand for natural
gas and corresponding higher natural gas prices.
Residential Sector: The main drivers for gas consumption in any year for the residential
sector are number of household, household income, gas price, energy efficiency, and
heating degree-days. The macroeconomic equation was updated based on peer
reviewer recommendations, and the final form is shown below.
R= R * (P IP V-°-598)
yr K0r Vhyr/hOrA
* (HHyr/HH0r) *(HHIyr/HHI0r)(°68°)
* (HDDyr/HDD0r)(°276)
* (Reffyr/ Reff0r)
The equation was econometrically derived using price, demand, and heating degree-
days data from 1977-2002 on individual state level data. Number of U.S. households
and population data from 1967-2002 were used to derive an equation to forecast number
of households in the future. In the above equation the terms are defined as follows:
R - Natural gas demand for the residential sector
P - Natural gas price for the residential sector
HH - Number of households
HHI - Average household income
Reff - Residential efficiency improvement factor
HDD - Heating degree-days
Subscripts notation are as follows: r - Region, y - Year, 0 - Reference year.
The residential demand equation indicates that the price elasticity of demand is -0.598.
This means that when the natural gas price changes by 100%, residential demand for
gas will change by approximately 60%. Natural gas demand in the residential sector
also increases as the number of households and household income increases. In
addition, heating degree-days play an important role in determining the residential gas
demand level. Efficiency improvements play a critical role in determining residential
demand level. The American Gas Association (AGA) reports that the average home
uses 22% less gas than it did in 1980. So the total amount of natural gas delivered to
homes in 2002, was about the same as the amount of natural gas delivered in 1997,
despite the fact that seven million residential customers were added during that time.
27
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This has happened for efficiency improvements in the industry. Residential efficiency
improvement factor used in NANGAS is 1.7% per year.
The number of households and household income is forecasted as follows. First,
average national household size (HHS) is forecasted using the following equation.
HHSy = Exp(0. 873249 +4.74279 * (1/(y-1953)))
The average household size has been decreasing in the U.S. from a high of 3.2
individuals per household in 1967 to around 2.6 individuals per household currently.
This equation fits the historical trend well and forecasts a gradual decline in the
household size to around 2.4 by 2025.
Population is then divided by the household size to generate the number of households
(HH). Gross regional product is divided by the household size to determine average
household income (HHI). Number of households and household income are both used
in determining residential demand for natural gas.
For forecasting purposes, a normal weather is assumed. Natural gas price delivered to
the residential sector is calculated endogenously in NANGAS via the integrating linear
program.
Commercial Sector: The main drivers for gas consumption in any year for the
commercial sector are gross regional product, price and heating degree-days. The
macroeconomic equation used in NANGAS was updated based on peer reviewer
recommendations, and the final form is shown below.
* (GRPyr/GRP0r)° 256
* (HDDyr/HDD0r)° 191
The equation was econometrically derived using price, demand, and heating degree-
days data from 1977-2002 on individual state level data. It was determined that
efficiency improvements in the commercial sector did not factor into overall demand
levels. In the above equation the terms are defined as follows:
C - Natural gas demand for the commercial sector
P - Natural gas price for the commercial sector
GRP - Gross regional product
HDD - Heating degree-days
Subscripts notation are as follows: r - Region, y - Year, 0 - Reference year.
The commercial demand equation indicates that the price elasticity of demand is -0.424.
This means that when natural gas price changes by 100%, the commercial demand for
natural gas will change by 42.4%. Natural gas demand in the commercial sector also
increases as the gross regional product increases. In addition, heating degree-days
28
-------
play an important role in determining the commercial sector gas demand level. As
previously noted, efficiency improvements don't play a critical role in determining the
commercial demand for natural gas.
For forecasting purposes, normal weather is assumed. Natural gas price delivered to
the commercial sector is calculated endogenously in NANGAS via the integrating linear
program.
Industrial Sector: Gas demand in the industrial sector is modeled in NANGAS for three
sub-sectors. They are: boilers, process heat/other and feedstock. The representation
of process heat and feedstock sub-sectors was updated considerably based on peer
review recommendations.
Industrial Boilers: In the industrial boiler sector, NANGAS contains over 30,000 boilers.
The basic operating characteristics of the boilers are derived from EPA's AIRS
database. In NANGAS, the industrial boilers can switch between natural gas and fuel oil
depending upon the relative attractiveness of the fuel prices.
Industrial boilers are divided into two broad categories: small boilers with capacity less
than 250 MMBtu/hr and large boilers with capacity greater than 250 MMBtu/hr. In both
categories, there are three types of boilers; boilers that burn "gas only", "gas or resid"
and "gas or distillate". Altogether there are six separate combinations of boiler size -
fuel type modeled in NANGAS.
Two separate macroeconomic equations are used to forecast gas demand in the
industrial sector. The two equations are based on the two types of fuels used in
industrial boilers.
For gas-only burning units (no fuel switching), the main drivers for gas demand are
Gross Regional Product (GRP, forecasted to be growing at 3%/year), energy intensity
(which is defined as a ratio of industrial sector output to GRP, forecasted to be
decreasing at 1.1% per year), and the gas price (calculated internally within the model).
The macroeconomic equation used to forecast natural gas demand for gas-only burning
boilers is as follows:
= BG0r*(Pyr/P0r)<-a74>
(GRPyr/GRP0rf
Efficiency improvements in the boiler sector are captured through energy intensity.
Energy intensity is projected to decline at an average annual rate of 1.1% per year, as
continuing efficiency gains and structural shifts in the economy offset growth in demand
for energy services. In the above equation the terms are defined as follows:
BG - Natural gas demand for gas-only industrial boilers
P - Natural gas price for the industrial sector
GRP - Gross regional product
El - Energy intensity
29
-------
Subscripts notation are as follows: r - Region, y - Year, 0 - Reference year.
For gas/distillate and gas/residual fuel oil burning units, the regression equation is similar
to the gas-only burning units but the price term in the equation is not only based on the
gas price, but it also is a function of the price of the alternative fuel to gas (either residual
fuel oil or distillate). If the price of the alternative fuel is cheaper than natural gas, then
gas demand for boilers is zero, and the boilers burn the fuel oil and vice versa. This
comparison is done on an annual and seasonal basis in NANGAS. The macroeconomic
equations used to forecast natural gas demand for gas/oil fungible boilers are as follows:
When gas prices are lower than fuel oil price:
BGyr=BG0r*(Py/P0r)(-°-™>
*(GRPyr/GRP0r)(°-48>
*(Elyr/EI0r)(2.n)
BFyr = 0.0
When gas prices are higher than fuel oil price:
BFyr=BF0r*(FPyr/FP0r)(-°-42)
*(GRPy/GRP0r)(1-54>
*(Elyr/EI0r>(2-28>
BGyr = 0.0
In the above equations the terms are defined as follows:
BG - Natural gas demand for industrial boilers
BF - Fuel oil demand for industrial boilers
P - Natural gas price for the industrial sector
FP - Fuel oil price for the industrial sector
GRP - Gross regional product
El - Energy intensity
Subscripts notation are as follows: r - Region, y - Year, 0 - Reference year.
Process Heat/Other and Feedstock Sub-Sectors: Process heat and feedstock sub-
sectors' natural gas demand is exogenously supplied as inputs in NANGAS.
"Process heat" includes all uses of energy that involves direct heating (instead of indirect
heating like steam) while "Other" includes all the remaining direct heating uses, including
non-boiler cogeneration, on-site electricity generation, and space heating.
The feedstock sub-sector of the industrial sector consists of three subcomponents:
ammonia, methanol and hydrogen production. The domestic ammonia industry is highly
affected by high natural gas prices as natural gas accounts for a substantial share of its
30
-------
total production costs. Further, the industry is exposed to global market competition, so
permanent loss of domestic production due to increased imports is possible.
In NANGAS, price effects on natural gas demand from both the feedstock and process
heat/other sub-sectors have not been represented. The peer review process suggested
capturing such price effects by developing macroeconomic equations for use in
forecasting gas demand in these sub-sectors. After extensive data research, it was
determined that data on historical, regional natural gas demand for these sub-sectors
are not publicly available or available for purchase. In the absence of historical data, it
was not possible to develop macroeconomic equations. Instead, the latest natural gas
demand forecasts for the feedstock and process heat/other sub-sectors were obtained
from NPC and exogenously supplied to NANGAS. The NPC forecast reflects the near
term loss of natural gas demand in fertilizer and other energy intensive industries and
forecasts a gradual reduction in demand. Exhibit 16 shows gas demand data used in
NANGAS for these sub-sectors.
Exhibit 16: Assumption for Natural Gas Demand in Process Heat/Other and
Feedstock Sub-Sectors
9. Discussion of Final NANGAS Results
In this section we describe NANGAS results for EPA Base Case 2004, v. 2.1.9. A
typical NANGAS run generates the following outputs:
• Natural gas prices
• Natural gas production by region, resource type
• Natural gas industry activities such as reserves additions, wells drilled, success
rates, pipeline utilization and flows
• Natural gas consumption by region and sector (i.e., the electric sector and the
non-electric sector, which includes residential, commercial and industrial sectors)
• Pipeline capacity expansion levels, electricity capacity expansion levels
Four NANGAS runs were completed at four different electricity growth rates (1.0%,
1.55%, 1.74% and 2.5%) that provided seed prices and volumes to generate the supply
curves for IPM Version 2.1.9. The following discussion covers the results for the 1.55%
electricity growth rate case. Supply/Demand disposition and prices for the other three
-------
cases are shown later in this section. Summary results for the 1.55% electricity growth
rate case are shown in Exhibit 17.
Exhibit 17: Supply/Demand Disposition and Henry Hub Price for the 1.55%
electricity growth rate case used to build the natural gas supply curves
for EPA Base Case 2004, v. 2.1.9
Supply/Demand Disposition, 1.55%
Case, Bcfyr
Northeast
Gulf Coast (Onshore)
Gulf Offshore
Mid-Continent
Permian
Rocky MountainM/est Coast
North Alaska
Total L4B
Total US
Imports from Eastern and Western
Canada
LNG Imports to US
Net Exports to Mexico
TOTAL L48 Supply Available
U.S. Demand, Non-Electric Sector
U.S. Demand, Electric Sector
Total Canadian Demand
2005
1050
51 OB
5320
2563
1669
3291
0
16999
18999
3569
664
5B7
22645
17711
4934
2990
2007
1146
4954
5463
2458
1595
3556
0
19172
19172
3391
927
454
23035
17905
5130
3074
2009
1283
4760
5479
2328
1602
3980
0
19431
19431
3697
1219
351
23997
18520
5476
3261
2010
1383
4681
5544
2296
1613
3912
0
19428
19428
3542
1219
308
238BO
18260
5621
3292
2011
1457
45B2
5618
22B9
1636
4140
0
19721
19721
3365
1467
2B6
24267
10343
5924
3330
2012
1474
4515
5606
2257
1649
4353
0
19B54
19B54
3435
1511
266
24534
16263
6265
3372
2014
1434
4482
5791
2125
1724
4811
0
20367
20367
3433
1511
230
25080
18556
6523
3528
2015
1465
4563
5766
2056
1746
5019
1497
20615
22112
2397
1511
214
25B06
18694
6911
3626
2018
1675
4989
6004
2054
1809
5288
1685
21616
23562
2510
1511
172
27351
19222
6129
3945
2019
1726
5079
6200
2050
1B07
5597
1396
22460
24356
2135
1511
160
27892
19317
3575
3921
2020
1760
5114
6350
2002
1807
5796
1896
22629
24725
19B4
1767
149
2B326
19303
9023
3952
2023
1867
4735
6803
2111
1754
6312
1896
23581
25477
1814
2131
128
29295
19225
10071
4205
2024
1864
4555
6979
2156
1726
6653
1896
23934
25836
1796
2132
121
29630
19276
10353
4296
2025
1887
4360
7077
2186
1690
6580
1896
23780
25676
1753
2132
115
29446
18926
10526
4332
Annual Growth (%)
(2005-2025)
24%
-0 6%
11%
-0.6%
0.1%
2.8%
NA
0.9%
1 .2%
-2.3%
48%
-6 3%
11%
0.3%
3.1%
1 .5%
Henry Hub, 2003WMBtu
2005 2007 2009 2010 2011 2012 2014 2015 2018 2019 2020 2023 2024 2025
3.73 3.54 3.23 3.44 3.46 3.58 3.53 3.41 3.40 3.45 3.54 3.71 3.78 4.07
Average Price (2005-
2025)
3.53
Natural Gas Prices. Representative North American wellhead prices are typically
reported at the Henry Hub. Henry Hub is a pipeline interchange hub in Louisiana Gulf
Coast near Erath, LA, where eight interstate and three intrastate pipelines interconnect.
Liquidity at this point is very high and it serves as the primary point of exchange for the
New York Mercantile Exchange (NYMEX) active natural gas futures markets. Henry
Hub prices are considered as a proxy for U.S. natural gas prices. Natural gas from the
Gulf moves through the Henry Hub onto long-haul interstate pipelines serving demand
centers. Due to the importance and significance of the Henry Hub, NANGAS generated
supply curves are specified at Henry Hub prices.
Henry Hub prices stay above $3.50/MMBtu in real 2003$ for the entire forecasting
horizon, except when Alaskan and Mackenzie Delta gas enters the marketplace (see
Exhibit 18). High prices in the next few years (around $3.75/MMBtu) reflect the current
situation of tight gas supplies and the marginal supply response of drilling activities.
Higher prices trim demand growth and bring forth additional supply. This keeps the
prices from rising appreciably until around 2018. Increase in Henry Hub price after 2018
is driven by demand growth, primarily electric sector demand for natural gas. Average
natural gas price for 2005-2025 timeframe is $3.53/MMbtu.
A decrease in price until year 2009 is due to gas supply outstripping growth in demand.
Total demand increases by 1.3% from year 2004 to year 2009 (from 22.5 Tcf to 24.0 Tcf)
but total L-48 production and LNG supplies increase by around 1.5%/yr. In year 2009,
prices go down due to additional LNG volumes in the Gulf, an increase in L-48
production due to higher prices in earlier years, and introduction of gas from the
Mackenzie Delta (1.2 Bcf/d). Another dip in prices is observed when Alaska comes
online in year 2015.
Even at the moderate price of around $3.50/MMBtu, U.S. total natural gas demand
never reaches 30 Tcf/yr (82.2 Bcf/d). This is because the electricity sector demand
32
-------
growth is a modest 1.55% per year, coal usage for the electricity sector continues to
increase, and petroleum products, not just natural gas, are used throughout the
modeling horizon in the industrial as well as the electricity sectors.
Exhibit 18: Henry Hub Price Forecast
CD
O
CL
.Q
I
c
CD
X
(2003$/MMBtu)
4
4
3
3
2
2
5 n
<
5
V -^ ^r+~*^
\r-+^s-+ *" ^^^-*—
Till
2005 2010 2015 2020 2025
Total Supply: Total supply comes from three sources: production from natural gas fields
located in L-48, Canadian imports, Alaska and LNG imports. Mexico is assumed to be
a small net importer and does not impact the overall pricing levels. Exhibit 19 shows
supply from these sources.
Exhibit 19: Supply Sources for L-48
30 n
82.2
41.1
2005 2010 2015 2020
2025
NANGAS forecasts that the L-48 fields will respond to the sustained natural gas prices of
$3.50/MMBtu or higher. L-48 production will grow at an annual rate of around 1% per
33
-------
year. In the near term (2005-2008), however, NANGAS forecasts a flat production
outlook.
Even at this growth rate, L-48 production will be able to meet only around 80% of
projected natural gas demand. The remaining 20% will be met by increasing LNG,
Alaska and Canadian imports.
a) L-48 Production and Regional Trends L-48 production, an output of NANGAS,
grows from 19 Tcf/yr (52 Bcf/d) in year 2005 to 23.8 Tcf/yr (65.2 Bcf/d) in 2025. This is a
modest growth of around 1% per year (see Exhibit 20). As higher amounts of LNG are
introduced in the marketplace, prices are reduced, which in turn reduces production. L-
48 production grows at 0.6%/yr until 2010, but grows at 1.4%/yr from 2010-2025
timeframe.
Exhibit 20: Annual Total L-48 Production Forecast
68.5
41.1
2005
2010
2015
2020
2025
Regions with supply growth are: Rockies, Northeast and Gulf Offshore. NANGAS
forecasts around 2.7% per year growth in production from Rockies, and 2.4% per year
from Appalachia. NANGAS is bullish on production from coalbed methane and tight gas
resources from these regions as forecasted prices support higher exploration and
development activities in the region.
Gulf offshore supplies remain flat in the near term and then grow at around 1.0%/yr as
additional volumes are brought online from deepwater and deep shelf resources.
NANGAS forecasts a continuing decline in onshore Gulf Coast and Mid-Continent supply
regions as basins mature in the region and additional drilling in the region bring lower
productive fields to the market. Permian basin remains almost flat during the forecast
horizon. Exhibit 21 shows regional production trends.
34
-------
Exhibit 21: L-48 Regional Production Trends
25
D Northeast • Rockies • Gulf Offshore • Gulf Onshore D Others
20
2005
2010
2015
2020
2025
68.5
0.0
b) Canadian and LNG Imports and Exports to Mexico: The model endogenously
calculates LNG and Canadian imports by year. Exhibit 22 shows Canadian and LNG
import levels.
Western Canadian Sedimentary Basin (WCSB) declines on average by 1% per year
throughout the forecasting horizon. During the later timeframe (after 2020), production
in WCSB starts to increase due to unconventional tight and coalbed methane gas
production activities.
Currently, around 83% of total U.S. demand is met by L-48 production, 15% by
Canadian imports and 2% by LNG. By 2025, the L-48 production can only meet 80% of
projected U.S. demand for natural gas. Imports from Canada continue to decline and
contribute to only 6% of total U.S. demand by 2025. On average, net Canadian imports
decline by 3.0% per year (from 3.6 Tcf/yr or 9.9 Bcf/d in 2004 to 1.8 Tcf/yr or 4.8 Bcf/d in
2025). LNG imports rise and fill this widening gap, meeting over 7.0% of U.S. demand
by 2025. Alaskan supplies serve the remaining 7%.
All existing LNG terminals operate to 85% capacity, and new terminals are built and
operate to capacity in Bahamas, and Gulf Coast at pricing thresholds of $3.00 -
$3.50/MMBtu. LNG volumes increase at over 7% per year from 1.32 Bcf/d in 2004 to
5.8 Bcf/d in year 2025. NANGAS shows significant increases in Gulf Coast LNG from
around 0.53 Bcf/d in 2004 to around 3.3 Bcf/d in 2025.
Mexico is assumed to be a net importer for the entire forecasting horizon. For EPA Base
Case 2004, v. 2.1.9, export levels to Mexico from US have been taken from AEO 2004
forecasts. Exports to Mexico from US continue to decrease over the forecasting horizon.
35
-------
Exhibit 22: Canadian and LNG Import Levels and Exports to Mexico
4800
.>,
Ts 4nnn
<-> tUUU
CQ
— ~ ^onn
(D oZUU
o> 9dm
— 1 Z4-UU
t
O 1ROO
X
yd RDD
^ ouu
0
Q. n
1
RDD
D Exoorts to Mexico O LNG Imports D Canadian Imports
13.2
T3
1 1 n T5
.u *-•
GO
8Q — ~
.O (D
fifi ^
D.D — I
•c.
44 o
*T.*T d.
X
22 S
^•^ t
o
on °-
O O
2005 2010 2015 2020 2025
(c) L-48 Demand: Total L-48 natural gas demand grows from around 22.6 Tcf/yr (62.1
Bcf/d) in 2005 to 29.4 Tcf/yr (80.7 Bcf/d) in 2025. This is a modest growth of around
1.1% per year. Total demand never reaches 30 Tcf throughout the modeling horizon.
Canadian demand grows by 1.5% per year from around 3.0 Tcf/yr (8.2 Bcf/d) in 2005 to
4.3 Tcf/yr (11.9 Bcf/d) in year 2025.
Natural gas demand in the core residential and commercial sectors in L-48 grows by
0.2% per year. Gas demand in the industrial sector remains almost flat throughout the
modeling horizon. Total L-48 demand for natural gas in the electric sector grows at
3.1 % per year.
The three other electricity growth rate cases are summarized in Exhibits 23, 24, and 25.
Exhibit 23: Supply/Demand Disposition and Henry Hub Price for 1.0%/Year
Electricity Growth Rate
Siipply'Deiiiiind Disposition. 1.0%
Case. Bcf yi
Northeast
Gulf Coast (Onshore)
Gulf Offshore
Vlid-Contineni
Permian
nji:k"' Iv'jjntain/V'.'H'El Coast
North Alaska
Total L48
Total US
Imports from Eastern and Western
: anada
LNG Imports to US
Net Exports to Mexico
TOTAL L48 Supply Av.iil.ible
J.S. Demand, Non-Electric Sector
U.S. Demand, Electric Sector
Tutal Canadian Demand
Heniy Hub. 2003$ MMBtu
2005
1042
5101
5315
2558
1665
3288
0
18969
18969
3553
664
587
22598
17695
4904
2988
2007
1142
4951
5459
2453
1591
3554
0
19149
19149
3368
927
454
22990
1792B
5062
3076
2009
1275
4756
5477
2323
1599
3979
0
19409
19409
3672
1219
351
23949
18562
5387
3286
2010
1373
4677
5543
2293
1611
3910
0
19407
19407
3507
1219
308
23825
18323
5502
3305
2011
1446
4579
5616
2284
1634
4135
0
19693
19693
3355
1219
286
23381
18278
5703
3321
2005 2007 2009 2010 2011
2012
1459
4508
5605
2249
1644
4349
0
19814
19814
3412
1219
266
24179
18246
5933
3372
2012
2014
1418
4471
5789
2119
1721
4846
0
20363
20363
3391
1219
230
24743
18670
6073
3546
2014
2015
1449
4543
5764
2051
1743
5079
1497.4
20629
22127
2352
1219
214
25484
19165
6320
3643
2018
1642
4906
5973
2032
1797
5252
1685
2 1 602
232B6
2342
1219
172
26675
19755
6920
3989
2019
1689
4969
6172
2024
1790
5508
1836
22152
24048
1987
1219
160
27094
19897
7197
4004
2020
1722
4992
6330
1976
1784
5680
1896
22483
24380
1802
1219
149
27252
19767
7485
4016
2023
1821
4646
6603
2075
1731
6094
1896
23170
25066
1593
1290
128
27821
19463
8338
4233
2024
1817
4480
6949
2110
1708
6352
1896
23414
25310
1568
1467
121
28224
19585
8640
4337
2025
1822
4284
7014
2145
1675
6337
1896
23277
25173
1533
1767
115
28357
19461
8897
4399
2015
2018 2019 2020 2023 2024 2025
3.75 3.52 3.21 3.38 3.51 3.59 3.45 3.23 3.06 3.06 3.19 3.45 3.45 3.58
Aiiiui.il Growth (%}
(20052025)
2.3%
-0.7%
1.1%
-0.7%
0.0%
2.7%
NA
0.8%
1.1%
-3.3%
4.0%
-6.3%
0 9%
0.4%
2.4%
1.6%
Avei,i(je Piice (2005-
20251
3.37
36
-------
Exhibit 24: Supply/Demand Disposition and Henry Hub Price for 1.74%/Year
Electricity Growth Rate
Supply/Demand Disposition, 1.74%
Case, Bcf/yr
Northeast
Gulf Coast (Onshore)
Gulf Offshore
Mid-Continent
Permian
Rockies Mountain/West Coast
North Alaska
Total L48
Total US
Imports from Eastern and Western
Canada
LNG Imports to US
Net Exports to Mexico
TOTAL L48 Supply Available
U.S. Demand, Non-Electric Sector
U.S. Demand, Electric Sector
Total Canadian Demand
200S
1043
5103
5315
2559
1665
3287
0
18972
1B972
3562
664
587
22610
17698
4912
2987
2007
1152
4958
5462
2455
1594
3554
0
19175
19175
3424
927
454
23072
17665
5407
3038
2009
1285
4774
5480
2329
1604
3982
0
19454
19454
3750
1219
351
24072
1B1B7
5885
3239
2010
13S6
4703
5545
2302
1619
3895
0
19449
19449
3570
1584
308
24295
1B175
6119
3281
2011
1462
4614
5617
2294
1646
4144
0
19778
19778
3405
1767
286
24664
18220
6443
3313
2012
1487
4553
5605
2274
1658
4387
0
19964
19964
3474
1767
266
24938
18141
6797
3356
2014
1442
4528
5791
21 B8
1737
4963
0
20647
20647
3504
1767
230
25688
18313
7375
3481
2015
1469
4626
5785
2118
1760
5169
1497
20947
22444
2688
1767
214
26685
18713
7972
3617
2018
1720
5059
6011
2070
1833
5293
1665
21986
23670
2761
1767
172
28026
18873
9153
3919
2019
1776
5151
6203
2072
1835
5561
1896
22601
24497
2347
1849
160
28534
18965
9568
3868
2020
1612
5180
6351
2D27
1832
5774
1696
22976
24672
2214
2132
149
29069
19060
10010
3915
2023
1936
4798
6870
2137
1768
6318
1896
23826
25722
2027
2132
128
29753
18779
10974
4093
2024
1937
4627
7046
2168
1745
6729
1896
24271
26167
2017
2132
121
30194
18798
11396
4167
2025
1946
4444
7114
2223
1708
6680
1696
24115
260 11
1986
2132
115
30014
1B507
11507
4203
Annual Growth (%)
(20053025)
2.5%
-0.6%
1.2%
-0.6%
0.1%
29%
NA
1.0%
1 .3%
-2.3%
4.8%
-6.3%
1.1%
0.2%
3.5%
1.4%
Henrv Hub, 2003$/MMBtu
2005 2007 2009 2010 2011 2012 2014 2015 2018 2019 2020 2023 2024 2025
3.74 3.71 3.44 3.4B 3.53 3.67 3.74 3.56 3.67 3.71 3.73 4.07 4.16 4.45
Average Price (2005-
2025)
3.74
Exhibit 25: Supply/Demand Disposition and Henry Hub Price for 2.5%/Year
Electricity Growth Rate
Supply/Demand Disposition, 2.5%
Case, Bcf/yr
Northeast
Gulf Coast (Onshore)
Gulf Offshore
Mid-Continent
Dermian
Rocky Mountain/West Coast
North Alaska
Total L4B
Total US
Imports from Eastern and Western
Canada
LNG Imports to US
Net Exports to Mexico
TOTAL L48 Supply Available
U.S. Demand, Non-Electric Sector
US Demand, Electric Sector
Total Canadian Demand
2005
1040
5101
5314
2558
1665
3267
0
18964
16964
3553
664
587
22594
17669
4905
2961
2007
1153
4960
5462
2454
1594
3555
0
19177
19177
3438
927
454
23087
17493
5595
3007
2009
1293
4784
6482
2337
1611
3983
0
19489
19489
3787
1402
351
24327
17964
6363
3200
2010
1397
4718
5546
23D4
1628
3893
0
19486
19486
3630
1584
308
24392
17798
6594
3229
2011
1477
4637
5618
2301
1655
4133
0
19822
19822
3463
1767
286
24765
17869
6897
3267
2012
1514
4582
5607
23D4
1671
4376
0
20055
20055
3519
1949
266
25257
17877
7380
3317
2014
1491
4560
5813
2219
1750
4959
0
20791
20791
3616
1949
230
26126
17767
8359
3375
2015
1539
4668
5806
2144
1780
5172
1497
21108
22605
3331
1949
214
27671
18463
9208
3608
2018
1782
5114
6060
2153
1854
5350
1685
22312
23997
3160
2132
172
29116
18375
10741
3725
2019
1645
5216
6274
2151
1856
5629
1896
22971
24667
2672
2132
160
29710
1B360
11330
3761
2020
1899
5261
6436
2103
1851
5935
1896
23485
25381
2729
2132
149
30092
18387
11705
3765
2023
2059
4903
6914
2185
1788
6691
1896
24539
26435
2489
2132
128
30928
18319
12609
3945
2024
2047
4742
7062
2241
1772
6999
1896
24863
26759
2466
2132
121
31226
18339
12888
4017
2025
2050
4555
7147
2280
1735
6693
1896
24660
26556
2397
2132
115
30970
18189
12781
4061
Annual Growth (%)
(2005-2025)
2.8%
-0 5%
1 .2%
-0.5%
0.2%
3.0%
NA
1.1%
1 .4%
-16%
4.8%
-6 3%
1 .3%
0.1%
39%
1 .2%
Henry Hub, 2003$/MMBtu
2005 2007 2009 2010 2011 2012 2014 2015 2018 2019 2020 2023 2024 2025
3.75 3.85 3.58 3.73 3.77 3.86 4.18 3.78 4.14 4.26 4.35 4.57 4.68 4.89
Average Price (2005-
2025)
4.08
37
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10. Supply Curves, Transportation Adders for EPA Base Case 2004, v. 2.1.9
For use in IPM modeling, NANGAS generates a price forecast over a time horizon and a
set of time dependent price/supply curves based on the resulting price path for each
year in the forecast. Exhibit 26 shows a schematic of this methodology.
Exhibit 26: Schematic of Price Path and Time Dependent Supply Curves
Generated in NANGAS
Demand
Log Price
Log Demand
There is an inelastic portion and an elastic portion of the supply and demand curve,
which is assumed to approximate a linear relation when plotted on a log-log scale.
Slopes and intercepts are calculated for every year based on the four points obtained
from the four growth rate cases. The resulting equation is used in deriving the curves at
every $0.05/MMBtu interval.
38
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Supply Curves: IPM's run years for EPA Base Case 2004, v.2.1.9 are 2007, 2010,
2015, 2020 and 2026. NANGAS produces results for every year from 2005 to 2025,
balancing supply/demand and transportation in generating clearing natural gas prices.
To generate prices and supply curves for IPM, NANGAS run year results are weight
averaged to generate data for IPM, according to the following scheme.
IPM run year 2007:
IPM run year 2010:
IPM run year 2015:
IPM run year 2020:
IPM run year 2026:
(Since NANGAS is
run year 2026.)
NANGAS run year 2007
Weight average of prices and supply for years 2008-2012
Weight average of prices and supply for years 2013-2017
Weight average of prices and supply for years 2018-2022
Weight average of prices and supply for years 2023-2025
not run for year 2026, the average of 2023 to 2025 is used for IPM
The final resulting supply curves developed for years 2007, 2010, 2015, 2020 and 2026
are shown in Exhibit 28. Exhibit 28 also shows the converged gas price for EPA Base
Case 2004, v. 2.1.9 for the years. As expected, supply curves for early years are
steeper compared to later year supply curves. For example, the supply curve for year
2007 (shown in yellow) indicates that supply cannot be increased substantially (increase
is from 22.9 Tcf to 23.5 Tcf which represents a modest increase of 2.8%) as prices
increase from around $3.00/MMBtu to over $5.50/MMBtu. The reason is that a
substantial increase in gas price for year 2007 will not result in any substantial increase
in L-48 production, imports etc, as substantial supply increases need lead times. (For
example, a new LNG terminal takes over 4 years to get certificated and built.) After year
2010, there are substantial increases in supplies in response to increases in prices. For
example, in year 2020 if prices rise from $3.00/MMBtu to over $5.50/MMBtu, supply
would increase from 26.8 Tcf to 33.1 Tcf (an increase of almost 25%).
Exhibit 28: Supply Curves for Years 2007, 2010, 2015, 2020 and 2026 and Natural
Gas Price
Total L-48 Supply, Bcf/yr
39
-------
Transportation Adders: To populate IPM with observed basis differentials or
transportation adders, ICF analyzed Platt's "Gas Daily" reported gas pricing data at
approximately 100 pricing points, and selected one and/or a combination of gas daily
pricing point as representative of each of the 26 IPM regions. Exhibit 29 shows all the
pricing points as reported by Platt's "Gas Daily".
Exhibit 29: Platt's "Gas Daily" Pricing Points
gas daily pricing points
Daily gas price data for the time period January 1, 1991 to October 30, 2002 were used
in deriving the transportation adders. For summer, daily gas pricing data for May 1 -
Sept 30 were used and for winter, daily gas pricing data for Oct 1 - April 30 were used.
The transportation adders were calculated by subtracting the Henry Hub price from the
derived regional prices. Data that were greater than two standard deviations of the
mean were considered as indicating some short term phenomena or aberration and
were not used in determining average basis differentials. A simple arithmetic average
was taken for data points within two standard deviation of the mean. Exhibit 30 shows
the overall methodology of generating basis differentials for use in IPM. Exhibit 8-9
earlier in the documentation report shows the resulting natural gas transportation adders
that are used in EPA Base Case 2004, v.2.1.9.
40
-------
Exhibit 30: Overall Flow Chart of Determining Basis Differentials
'Gas Daily' historical prices for each pricing point (station)
for all dates from Jan 1,1991 thru Oct 30, 2002
Calculate weighted average historical prices for
every IPM region for all dates.
Calculate observed transportation adder (basis
differential) for every IPM region for all dates.
If the adder for a specific day is within 2 standard
deviations of average adder then keep data point. If the
adder is more than 2 standard deviations then reject
the data point.
Compute average transportation adder over all
accepted historical data points.
Add distribution charges, if applicable, to average
transportation adder to derive the final transportation
adder to be used in IPM.
41
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Exhibit 8-13. Fuel Oil Prices in EPA Base Case 2004, v.2.1.9
(Attachment O, Table O-1 in Doc, v.2.1.6.)
High Sulfur Resid Prices by IPM Region
1 999$/mmBtu
Year
2007
2010
2015
2020
IPM
MACE
3.51
3.57
3.67
3.76
Region
NENG
2.93
2.98
3.11
3.22
Low Sulfur Resid Prices by IPM Region
1 999$/mmBtu
Year
2007
2010
2015
2020
IPM
MACE
3.73
3.79
3.89
3.99
Region
NENG
3.30
3.35
3.47
3.58
Distillate Prices by IPM Region
1 999$/mmBtu
Year
2007
2010
2015
2020
IPM
MACE
4.72
4.85
5.23
5.58
Region
NENG
4.80
4.94
5.29
5.6
Note: Consistent with AEO 2004, the sulfur content of the
three fuels is as follows:
Fuel
High Sulfur Resid
Low Sulfur Resid
Distillate
Sulfur Content
2.69 Ib/mmBtu.
1.08 Ib/mmBtu
0.3 Ib/mmBtu
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