SEPA
Developing and Updating Output-Based
NOx Allowance Allocations
Guidance for States Joining the NOx Budget Trading Program
under the NOx SIP Call
May 8, 2000
U. S. Environmental Protection Agency
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Preface
Preface
This document assists State environmental agencies as they consider adopting output-
based NOx allowance allocations for their State implementation plan (SIP) in response to the
NOx SIP call. It focuses on technical issues of how to develop and implement output-based
allowance allocations. In particular, this document describes options for developing NOx
allowance allocations for power plants and industrial (or institutional) boilers and turbines using
output (electric generation or thermal energy). The discussions in this document may also help
others plan and understand regulatory requirements.
This document describes how you could allocate NOx allowances using output data and
how you could obtain information that will let you update those allocations periodically. The
focus of this guidance is for States creating a NOx trading program.
The guidance document provides examples of how to calculate NOx allowance
allocations using electric output and thermal output data and how to adjust these allocations to fit
a State's sector budgets for electric generating units and non-electric generating units. The
guidance considers:
• The types of facilities to which the guidance applies
• The assignment of allocations to units, to plants, or to generators
Technical and policy concerns in selecting the location for measuring or calculating
output data to be used in allocations
• Requirements for sources, such as monitoring, recording, and reporting output data
• Potential sources of output data
Regulatory provisions to include in State rules
Finally, the document provides sample regulatory language that would revise the Model NOx
Trading Rule for the NOx SIP call at 40 CFR part 96.
This guidance does not give a comprehensive discussion of policy issues for choosing a
particular approach to allocating NOx allowances. However, it includes a brief discussion of the
analysis we considered while evaluating updating output-based allocations in our January 18,
2000 section 126 final rule.
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Preface
This guidance does not give recommendations about how often you should update
allocations, to which sources you should allocate NOx allowances based on output, or whether
you should use gross or net output data as the basis for allocations. The Updating Output
Emission Limitation Workgroup, which assisted us in developing this guidance, did not address
or resolve such issues. We ourselves are still considering the last two of these issues and intend
to take public comment on them in an upcoming rulemaking in the year 2000. The legal issues
and many policy issues associated with adopting an output-based allocation are beyond the scope
of this document. However, the guidance document does raise issues for you to consider as you
decide on the most appropriate approach to allocating NOx allowances in your State.
In the model rule for the NOx Budget Trading Program under the NOx SIP call, 40 Code
of Federal Regulations (CFR) part 96, we provided an approach to allocating NOx allowances
based on heat input. We did this primarily because we had successfully established allocations
based on heat input for previous programs, and had concerns about issues of implementation and
data quality with output-based allocations. However, in the final NOx SIP call, we also
committed to working together with stakeholders to resolve these issues in order to design an
approach to allocating output-based NOX allowances that States could use as part of their trading
program rules in their SIPs. We said that we would develop a proposed approach to output-based
allocations in 1999 and finalize an output-based option in 2000. We issued draft guidance in
December of 1999. Today's document is the final guidance to States for output-based allocations
that we committed to in the NOx SIP call.
You will find some new challenges in setting allocations based on output, rather than heat
input. This guidance addresses many of these challenges. The guidance document is laid out as
follows:
• Section I describes various output-based emission limitations and references EPA's
analysis of approaches to allocating NOX allowances for the final section 126 rule.
Section II addresses how to calculate NOx allowances for sources that produce both
electricity and heat or steam as useful outputs.
• Section III describes the types of sources to which this guidance applies.
Section IV discusses allocating NOx allowances to units, to generating systems, or to
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 4 NOx Allowance Allocations
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Preface
entire plants.
Section V describes technical and policy concerns in selecting the location for monitoring
or calculating output data to be used for allocations.
Section VI describes where sources do, or could, monitor electric and thermal output at
different types of facilities.
Section VII addresses how sources would monitor and report information on electric or
thermal output.
Section VIII describes potential sources of output data and their limitations.
Section IX suggests changes that you may want to make to your State rule to include
updating, output-based allocations.
Section X gives you background on how we considered issues in preparing this guidance
and suggests additional sources of information.
Appendix A provides language that you may use or modify for use in your State
implementation plan if you determine NOx allowance allocations based on output.
Appendix B is a glossary to help you understand terms and abbreviations.
We hope you will find this draft guidance to be useful and informative.
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Acknowledgments
Acknowledgments
EPA developed this document through the efforts of the Updating Output Emission
Limitation Workgroup. The Updating Output Emission Limitation Workgroup is a workgroup of
the Clean Air, Energy and Climate Change Subcommittee of the Clean Air Act Advisory
Committee. Workgroup members include representatives of the electric power industry, district
energy groups, industrial boiler owners, the natural gas supply industry, environmental groups,
State environmental agencies, labor unions, and other organizations. From December 1998
through December 1999, we held a series of meetings and conference calls. The workgroup
prepared a number of issue papers, discussed issues, and reviewed and provided comments on a
draft version of this guidance document.
Although this document does not reflect all views expressed by the Updating Output
Emission Limitation Workgroup, we could not have developed this document without the
knowledge and the perspectives that the workgroup shared with us. We thank the members of
the Updating Output Emission Limitation Workgroup for their many contributions.
In particular, we thank the following people for their participation:
Jeff Abboud David Bassett
Gas Turbine Association U.S. Department of Energy
Bruce Alexander Robert D. Bessette
PECO Energy Company Council of Industrial Boiler Owners
Praveen K. Amar Ph.D., P.E. Joel Bluestein
Northeast States for Coordinated Air Use Coalition for Gas-Based Environmental
Management (NESCAUM) Solutions
Richard Ayres Esq Andy Bodnarik
Howrey and Simon New Hampshire Department of
Environmental Services
Fred Ballay
New Jersey Department of Environmental Donna Boysen
Protection and Energy MJ Bradley and Associates
Barbara A. Bankoff Mark Brownstein
Siemens Westinghouse Corporation PSEG
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Acknowledgments
Mark L. Buzel
AES-Goudey Station
New Hampshire Dept. of Environmental
Services, Air Resources
Robyn Camp
Energy Resources International, Inc.
Noboru Fujii
Nissan North America, Inc.
Chuck Carlin
Northeast Utilities
Michael Geers
Cinergy Corp.
Mark Carney
U.S. Generating
Dave Gemett
Independent Power Producers of New York
Daniel Chartier
PG&E Generating
William G. Gillespie
Ozone Transport Commission
Richard Chastain
Southern Company
Mark Gray
American Electric Power
Marc Cohen
Massachusetts Department of Environmental
Protection
Bruce Craig
E3 Ventures, Inc.
Mark C. Hall
Trigen Energy Corporation
Paul Hibbard
Massachusetts Department of Environmental
Protection
Arthur Diem
New Jersey Department of Environmental
Protection and Energy
Mark Driscoll
East Coast Power
Stephen Evanoff
Lockheed Martin Corporation
Larry Feldcamp
Baker & Botts, L.L.P.
Linda Hickok
Sithe Energy
Bernard Huff
Cinergy Corp.
Katharine Hornbarger
American Forest and Paper Association
Lisa Jaeger
Bracewell & Patterson, L.L.P.
Joe Fontaine
Chris James
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May 8, 2000
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NOx Allowance Allocations
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Acknowledgments
Connecticut Department of Environmental
Protection
Debra Jezouit
Baker & Botts, L.L.P.
William Nicholson
Potlatch Corporation
Claudia O'Brien
Latham & Watkins
Michael J. Jirousek
FirstEnergy Corporation
John Kinsman
Edison Electric Institute
Maureen Koetz Esq.
Nuclear Energy Institute
Dan A. Lashof
Natural Resources Defense Council
Tom Lawler
American Forest and Paper Association
Arthur Lee
Texaco, Inc.
Jessica LeFevre
National Association of Energy Service
Companies
Miriam Lev-on
ARCO
Ann Mclver
Indianapolis Power & Light
Chris Nelson
Connecticut Department of Environmental
Protection
David W. Parks
Baltimore Gas and Electric Company
Louis Pocalujka
Consumers Energy
John Preczewski
New Jersey Department of Environmental
Protection and Energy
Rhone A. Resch
Natural Gas Supply Association
Gary Risner
Weyerhaeuser Company
Tom Romero
U.S. Generating Company
Leo Sicuranza
U.S. Generating Company
Robert Sliwinski
New York State Dept. of Environmental
Conservation
John E. Smith
Strategic Guidance Association
David W. South
Energy Resources International, Inc.
Mark Spun-
International District Energy Association
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May 8, 2000
PageS
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NOx Allowance Allocations
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Acknowledgments
Robert N. Stavins
Harvard University
Daniel Steen
FirstEnergy
Andrew Stewart
Latham & Watkins
Eugene M. Trisko
United Mine Workers of America
Jean Vernet
U.S. Department of Energy
Michael Walker
E3 Ventures
Samuel A. Wolfe
Public Service Electric and Gas Company
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Table of Contents
Table of Contents
Preface Page 3
Acknowledgments Page 6
Table of Contents Page 11
I. Background: Why should I consider using output-based NOx allowance allocations? . Page 20
II. Calculations: How do I calculate source allocations? Page 23
A. What formula(s) do I use to calculate NOx allowance allocations based on output?
Page 23
B. How do I calculate the unadjusted allocation for each source? Page 31
C. How do I develop unadjusted output-based allocations for sources that produce more than
one form of output (such as, both electricity and steam)? Page 32
D. How do I adjust the unadjusted allocations to fit my State budget? Page 34
E. How should I set up allocations if I choose to allocate to some sources based on output
and to other sources based on heat input? Page 40
IE. Applicability: For which kinds of facilities does this guidance help me develop output-based
allocations? Page 44
IV. Level of Allocations: Should I allocate to units, to generators, or to entire facilities?
Page 46
A. When is it appropriate to allocate to units? Page 46
B. When is it appropriate to allocate to entire facilities? Page 47
C. When is it appropriate to allocate to generators? Page 47
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V. Where should sources determine output to be used for allocations? Page 49
A. Why does it matter where sources measure their output? Page 49
B. What are factors I should consider before deciding on the location where sources
determine output? Page 51
C. How could I incorporate the concept of the location for determining output into my State
rule? Page 53
VI: Monitoring locations: Where could facilities monitor electric and thermal output? . . Page 55
A. Where should output measurement equipment be installed? Page 55
B. How could sources monitor electric output only at a conventional electric power plant?
Page 60
1. Net Electric Output Page 63
2. Gross Electric Output Page 65
Monitoring example for a conventional electric generator (power plant) . Page 67
C. How could sources monitor thermal output at a steam generator? Page 68
The Simplified Approach and the Boiler Efficiency Approach to Monitoring Thermal
Output Page 68
1. Net Thermal Output under the Simplified Approach Page 74
2. Gross Thermal Output under the Simplified Approach Page 76
Monitoring example for a steam generator under the simplified approach
Page 79
Monitoring example for a steam generator with steam reheat under the
simplified approach Page 80
3. Net Thermal Output under the Boiler Efficiency Approach Page 84
4. Gross Thermal Output under the Boiler Efficiency Approach Page 87
Monitoring example for a steam generator under the boiler efficiency
approach Page 90
Monitoring example for a steam generator with steam reheat under the boiler
efficiency approach Page 91
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D. How could sources monitor electric and thermal output at a cogeneration facility?
Page 92
1. Monitoring Electric Output Page 102
2. Monitoring Net Thermal Output under the Simplified Approach .... Page 102
3. Monitoring Gross Thermal Output under the Simplified Approach . . Page 105
Monitoring example for a steam cogeneration facility under the simplified
approach Page 110
Monitoring example for a combustion turbine cogenerator under the
simplified approach Page 112
Monitoring example for a combined cycle cogeneration facility under the
simplified approach Page 113
4. Monitoring Net Thermal Output under the Boiler Efficiency Approach.
Page 124
5. Monitoring Gross Thermal Output under the Boiler Efficiency Approach.
Page 128
Monitoring example for a steam cogeneration facility under the boiler
efficiency approach Page 133
Monitoring example for a combustion turbine cogenerator under the boiler
efficiency approach Page 135
Monitoring example for a combined cycle cogeneration facility under the
boiler efficiency approach Page 136
E. How do I calculate output data from supporting data? Page 138
VTI. Requirements for Sources: How should sources monitor, record, and report output data to
support updating output-based allocations? Page 142
A. What might my State require to ensure that individual sources monitor and report
consistent and accurate output data? Page 142
B. How detailed or prescriptive should output monitoring and reporting requirements be in
my State rule? Page 144
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Option #1 The Detailed Monitoring Option Page 144
Option #2 The Simplified Option Page 147
Option #3 The Intermediate Option Page 148
Choosing Between Options #1, #2, #3 and Other Options Page 149
C. What output measurement equipment must affected facilities use? Page 150
D. When must facilities start measuring output? Page 150
E. What records must affected facilities keep and report to support output-based allocations?
Page 151
F. What should a source be required to report in a monitoring plan? Page 153
G. What Certification, Quality Assurance and Quality Control procedures (QA/QC) should
be required for output monitoring? Page 155
H. How would a source substitute missing data for output? Page 161
I. What other monitoring requirements must facilities meet if they are not fossil fuel-fired?
Page 161
VIII. Data Sources: Where do I get the data for an output-based allocation? Page 163
A. What are potential sources of output data? Page 163
B. What should I consider when choosing a source of output data? Page 164
IX. Rule Changes: What provisions of my State rule may need to be changed to account for output-
based NOx allowance allocations? Page 167
X. How do I learn more about this guidance? Page 169
A. Who do I contact if I have questions about this guidance? Page 169
B. How do I find out more about the NOx SIP Call and the NOx Budget Trading Program?
Page 169
C. How did EPA create this guidance? Page 169
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Appendix A: Sample rule language to account for output-based allocations Page 171
Definitions Page 171
Subpart E - NOx Allowance Allocations Page 173
Case 1
(1) You initially allocate to both EGUs and non-EGUs for 2003
through 2005 based on heat input
(2) You update allocations to EGUs based on output and to non-
EGUs based on heat input beginning in 2006
Page 173
Case 2
(1) You initially allocate to both EGUs and non-EGUs for 2003
through 2005 based on heat input
(2) You update with allocations to both EGUs and non-EGUs based
on output beginning in 2006 Page 182
Case 3
You initially allocate and periodically update allocations to EGUs
based on output and to non-EGUs based on heat input
Page 191
Case 4
You initially allocate and periodically update allocations to both
EGUs and non-EGUs based on output Page 198
Appendix B: Glossary of terms used in this guidance Page 206
Index Page 217
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List of Figures
FIGURE 1: Electric Generator Page 61
FIGURE 2: Steam Generator Page 71
FIGURE 3: Steam Generator (Industrial Boiler with Steam Reheat) Page 72
FIGURE 2 (repeated) Page 81
FIGURE 3 (repeated) Page 82
FIGURE 4: Steam Cogenerator Page 93
FIGURE 5: Combustion Turbine Cogenerator Page 94
FIGURE 6: Combined Cycle Cogenerator Page 95
FIGURE 4 (repeated) Page 115
FIGURE 5 (repeated) Page 116
FIGURE 6 (repeated) Page 117
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Table of Contents
List of Tables
Table II-1: Allocation Factor for Thermal Output by the Simplified Approach,
Based on Boiler Efficiency Page 29
Table II-2: Unadjusted NOx Allowance Allocations
and Supporting Output Data for the EGU Sector Page 35
Table II-3: Unadjusted NOx Allowance Allocations
and Supporting Output Data for the Non-EGU Sector Page 35
Table II-4: NOx Allowance Allocations for the EGU Sector, Adjusted by Sector Page 36
Table II-5: NOx Allowance Allocations for the Non-EGU Sector, Adjusted by Sector . . Page 37
Table II-6: NOx Allowance Allocations for Trading Sources in Columbia,
by Method for Adjustment Page 39
Table II-7: Unadjusted NOx Allowance Allocations
and Supporting Heat Input Data for the Non-EGU Sector Page 41
Table II-8: NOx Allowance Allocations for the Non-EGU Sector Based on Heat Input . Page 42
Table VI-1: Summary of Most Common Approaches to Monitoring Output Page 58
Table E-l, Monitoring Electric Output Only from an EGU Page 62
Table SA-2 Monitoring Thermal Output Only from a Steam Generator under the Simplified
Approach Page 73
Table BE-2 Monitoring Thermal Output Only from a Steam Generator under the Boiler Efficiency
Approach Page 83
Table SA-3, Monitoring Cogenerator for Gross Electric Output and Gross Thermal Output under
the Simplified Approach Page 96
Table S A-4, Monitoring Cogenerator (CHP) for Net Electric Output and Net Thermal Output under
the Simplified Approach Page 98
Table SA-5, Monitoring Cogen (CHP) for Net Electric Output and Gross Thermal Output under the
Simplified Approach Page 100
Table BE-3, Monitoring Cogenerator for Gross Electric Output and Gross Thermal Output under
the Boiler Efficiency Approach Page 118
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Table BE-4, Monitoring Cogenerator (CHP) for Net Electric Output and Net Thermal Output under
the Boiler Efficiency Approach Page 120
Table BE-5, Monitoring Cogen (CHP) for Net Electric Output and Gross Thermal Output under the
Boiler Efficiency Approach Page 122
Table VI-2: Saturated Steam Table (Excerpt) Page 140
Table VI-3: Superheated Steam Table (Excerpt) Page 140
Table VII-1: Consensus Standards for Assuring Accuracy
of Output Measurement Equipment Page 158
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Section L: Why should I consider using output-based NOx allowance allocations?
I. Background: Why should I consider using output-based NOx allowance allocations?
Traditionally, emission limitations have been based on the concentration of pollutant (e.g.,
sulfur) in fuel, on the concentration of pollutant in the flue gas, or on the amount of pollutant per unit
of input to the process; for example, many power plants and industrial boilers meet emission
standards in pounds of pollutant per million British thermal units (mmBtu) of heat input (fuel usage).
In recent years, there has been increasing interest in setting emission limitations based on the amount
of pollutant per unit of useful output or product of a process. Some emission limitations have always
been on the basis of the amount of pollutant produced per unit of output, such as vehicle emission
standards in grams per mile traveled or standards for stationary internal combustion engines in grams
per horsepower-hour. More recently, EPA adopted revised New Source Performance Standards for
new power plants in terms of pounds of NOx per megawatt-hour of electric output.
In theory, a power plant or boiler could reduce pollution by improving its efficiency and
could produce the same amount of electricity or steam from less fuel. This would be an alternative
to complying with an emission limitation by using cleaner inputs to the process or by putting on
emission controls. Advocates of output-based emission limitations have suggested that using output
as the basis for an emission limitation encourages greater efficiency and potentially reduces air
pollution.1
You can also use an output measure when allocating allowances under a cap and trade
system. Such allocations are typically determined using one or more emission rate values and
information on the sources' operating history. In the Acid Rain Program and Phase II of the OTC
NOx Budget Program, regulators calculated allocations for sources using the product of an emission
Others disagree with this point of view. They point out that industry already has a
significant incentive to improve efficiency by saving on fuel costs. Some commenters on the
draft guidance stated that making significant changes to existing facilities may make sources
subject to New Source Review requirements, which could be cost prohibitive. Comments of the
American Forest & Paper Association Regarding the U.S. EPA's Draft Guidance on Output-
Based Allocations for States Joining the NOx Budget Trading Program under the NOx SIP Call;
Technical Comments of Cinergy Corp. on EPA's Draft Guidance on Output-Based Allocations
for States Joining the NOx Budget Trading Program under the NOx SIP Call, January 12, 2000;
Comments on Output Based NOx Allowance Allocations, November 29, 1999 Draft Guidance
Document from Indianapolis Power & Light, January 10, 2000.
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Section I: Why should I consider using output-based NOx allowance allocations?
rate factor in pounds of SO2 or NOX per million Btu (mmBtu) or heat input and the historic heat
input in mmBtu from a particular period of time. However, you could also use an emission rate
factor in Ib SO2 or NOx/MWh and the historic electric output in MWh from a power plant to
determine its allocation. For specific examples of how to calculate allowance allocations, see section
II of this document (pp. 23-43). Note that output-based allowance allocations under a cap and trade
program do not necessarily provide the same incentives or result in the same consequences as an
output-based emission standard using a rate which is applied without a cap. In particular, if you
update output-based allocations periodically using recent data, you may encourage increased
utilization in addition to increased efficiency by sources vying for a larger share of the allocations.
In EPA's section 126 final rule, we created a Federal NOx Budget Trading Program that
covers many of the same States included in the NOx SIP call. Unlike the NOx SIP call, EPA is
responsible for developing NOx allowance allocations under the section 126 final rule. We
evaluated potential impacts of different NOx allowance allocation methods as part of EPA's section
126 final rule (January 18, 2000). See 65 FR 2698-2711 for a detailed discussion of how EPA
decided on the allocation methodology for the section 126 rule. We analyzed impacts of permanent
allocations versus updated allocations. Our analysis of different allocation approaches also
considered the potential impacts of updating allocations using heat input, using output of fossil fuel-
fired electric generating units2, and using output of both fossil fuel-fired electric generating units and
non-emitting electricity generating systems. In particular, the study looked at impacts on emissions
and generation from the electricity industry. It did not examine potential impacts on non-electric
generating units (e.g., industrial or institutional boilers and turbines). You can find the results of the
analysis as well as a description of the methodology in the report, "Economic Analysis of Alternative
Methods of Allocating NOx Emissions Allowances" (EPA Air Docket A 97-43, Category XI-B-01;
this also is available on EPA's web site [http://acidrain/modlrule/main.html#126]). You may
consider this report as you decide whether you wish to use output-based or updating allocations.
2 This includes the sources that EPA defined as "electric generating units" in the final
NOx SIP call of October 18, 1998, including some cogeneration facilities. The D.C. Circuit
Court of Appeals has remanded the definition to EPA for further consideration. See State of
Michigan v. U.S. EPA. No. 98-1497, slip op. at 28-29 (D.C. Cir., March 3, 2000).
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Section I: Why should I consider using output-based NOx allowance allocations?
Our allocation report examined the question of allocations only in the context of NOx
emissions and the NOx Budget Trading Program, and its results should be interpreted only in that
context. Future decisions on allocations for potential future cap-and-trade programs should be based
on analysis specific to those programs.
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Section H.A.: What formula(s) do I use to calculate NOx allowance allocations based on output?
II. Calculations: How do I calculate source allocations?
A. What formula(s) do I use to calculate NOx allowance allocations based on output?
Use the following formulas:
For calculating NOx allowance allocations from electric output:
1.51bNO
Allocation =
x
MWh
Electricity generation during
baseline period, in MWh
2000 Ib / ton
Eq. 1
Where:
"Allocation" is the unadjusted NOx allowance allocation, in tons.
1.5 Ib NOx/MWh is the factor for allocating NOx allowances based on electric output.
"Electricity generation during baseline period, in MWh" is the electricity generation in the time
period that you choose. For example, this could be the average electricity generation during the
ozone season for the two years with the highest generation out of 1995, 1996, and 1997.
For calculating NOx allowance allocations from thermal output:
In this document, we present two general approaches to measuring thermal output.
Depending on the approach you require for monitoring thermal output, the value of the measured
thermal output and the factor used in the formula will vary. The two approaches to monitoring
thermal output, the boiler efficiency approach and the simplified approach, differ in whether sources
must measure and subtract out all thermal energy that returns to a boiler. See the discussion in
section VI., "Where do facilities measure electric and thermal output?"(pp. 55-141, especially pp.
68-69). The derivation of the factor is discussed further below in this section.
If you are using the boiler efficiency approach for monitoring thermal output, use the
following equation:
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Section H.A.: What formula(s) do I use to calculate NOx allowance allocations based on output?
0.24 Ib NO
Allocation =
Measured thermal output during
baseline period, in mmBtuout
2000 Ib / ton
Eq. 2
Where:
"Allocation" is the unadjusted NOx allowance allocation, in tons.
0.24 Ib /mmBtuout is the factor for allocating NOx allowances based on thermal output, as measured
using the boiler efficiency approach.
"Measured thermal output during baseline period, in mmBtuout" is the electricity generation in the
time period that you choose. For example, this could be the average thermal output during the ozone
season for the two years with the highest generation out of 1995, 1996, and 1997. Sources will
measure the thermal output using the boiler efficiency approach as described in section VI (pp. 68-
69, 84-91, and 124-137). (This monitoring approach requires sources receiving allowances based
on thermal output to measure and subtract all thermal energy returning to the boiler.)
If you are using the simplified approach for monitoring thermal output, use the following
equation:
Allocation =
'0.221bNO
2
, mmBtuout
Measured thermal output during
baseline period, in mmBtuout
2000 Ib / ton
Eq.3
Where:
"Allocation" is the unadjusted NOx allowance allocation, in tons.
0.22 Ib /mmBtuout is the factor for allocating NOx allowances based on thermal output, as measured
using the simplified approach.
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Section H.A.: What formula(s) do I use to calculate NOx allowance allocations based on output?
"Measured thermal output during baseline period, in mmBtuout" is the electricity generation in the
time period that you choose. For example, this could be the average thermal output during the ozone
season for the two years with the highest generation out of 1995, 1996, and 1997. A source will
measure the thermal output using the simplified approach, as described in section VI (pp. 68-69, 74-
78, and 102-109). (In this approach, a source does not need to measure the thermal energy going to
the boiler in a boiler feedwater return (condensate return) line.)
Sources of the factors (1.5 Ib/MWh, 0.24 lb/mmBtuout or 0.22 lb/mmBtu0J:
Each allowance allocation includes a factor, in terms of mass of pollutant per measurement
unit of operation. The factor is multiplied by some measure of unit operation during a baseline
period, such as heat input in mmBtu or electric output in MWh. In § 96.42, EPA provided factors
of 0.15 Ib NOx/mmBtu heat input for electric generating units and 0.17 Ib NOx/mmBtu heat input
for non-electric generating units. These factors correspond to the average NOx emission rate across
the entire sector after making reductions. In the model rule for the NOx Budget Trading Program
under the NOx SIP call, every unit in a sector would receive an initial, unadjusted allocation that is
based on the same factor. The initial allocation number is then adjusted up or down so that total
allowances in the sector would not exceed the State emission budget for that sector. Thus, the exact
value of the factor is not important, provided that the allocations are adjusted separately for the
electric generating unit sector and for the non-electric generating unit sector. The factor is not an
emission standard that a source must meet.
The suggested factors based on output are by the type of energy, rather than by the type of
facility. You could use the thermal output emission rate of 0.24 (or 0.22) lb/mmBtuout with thermal
output either from a non-electric generating unit that produces only thermal output or for the thermal
output of a cogeneration unit that produces both electricity and thermal output. You would not use
that factor only for thermal output from non-electric generating units. Likewise, you could use the
electric output emission rate of 1.5 Ib/MWh for setting an output-based allocation from any facility
that generates electricity.
^_ Factor for electric output
If an electricity generating unit with an average heat rate of 10,000 Btu/kWh meets the NOx
SIP call target NOx emission rate of 0.15 Ib/mmBtu heat input, it will also meet a NOx emission rate
Final EPA Guidance Document Developing and Updating Output-Based
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Section H.A.: What formula(s) do I use to calculate NOx allowance allocations based on output?
of 1.5 Ib/MWh. Industry sources and environmental groups have suggested this average heat rate
of 10,000 Btu/kWh3. This is a heat rate value typical of a large coal-fired boiler using a steam
turbine, a commonly-used technology. Utility boilers and turbines typically have heat rates ranging
between 8,500 Btu/kWh and 14,250 Btu/kWh4. If you wish to, you may calculate your own factor
for electric generation using the following equation:
0.15 Ib NOx
mmBtu
1 mmBtu
106 Btu
typical heat rate in
Btu
kWh
103 kWh^ IbNOx
= factor in
1 MWh ) MWh
Eq. 4
Alternatively, you may calculate the factor for electric generation by dividing the emissions budget
for the electric generating unit sector by the total generation from all affected electric generating
units for an ozone season during some baseline period, if you know these numbers.
^_ Factor for thermal output measured by the boiler efficiency approach
We use the term "boiler efficiency" to mean efficiency of imparting thermal energy to steam
in a boiler. This is calculated as the thermal output leaving a boiler (not an entire steam system),
minus any thermal energy reentering the boiler, divided by the heat input from fuel. This is
consistent with the boiler efficiency approach to measuring thermal output, as described in section
VI (pp. 68-69, 84-91, and 124-137).
If an industrial boiler with a boiler efficiency of 70% meets a NOx emission rate of 0.17
Ib/mmBtu heat input, it will also meet a NOx emission rate of 0.24 lb/mmBtuout. Industrial boilers
have efficiencies ranging from 55% to 85%5. Existing fossil fuel-fired boilers can readily achieve
3This value was suggested at the February 3 Meeting of the Updating Output Emission
Limitation Workgroup.
4This is the range of heat rates used in the Integrated Planning Model. EPA has used this
model for much of its economic analysis.
Information provided by the American Forest and Paper Association, in a letter entitled,
"Comments of the American Forest & Paper Association on Output-Based Emission
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 26 NOx Allowance Allocations
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Section H.A.: What formula(s) do I use to calculate NOx allowance allocations based on output?
an efficiency of 70%. Also, an efficiency of 70% is in the middle of the range of efficiencies for
industrial boilers using commonly available technology. If you wish to, you may calculate your own
factor for thermal output using the following equation:
0.17 lb NOx
mmBtu input
= factor in
IbNOx
typical boiler efficiency, as a decimal mmBtu output
Eq. 5
^ Factor for thermal output measured by the simplified approach
In the simplified approach to monitoring thermal output, the owner of a unit measures
thermal output leaving from the boiler, without subtracting thermal output returned to the boiler in
boiler feedwater. See section VI, especially pp.65-70. Therefore, under the simplified approach,
you do not assume an energy balance. Instead of measuring the thermal energy in the boiler
feedwater return directly, one uses a generic value for a typical amount of thermal energy returning
in condensate and incorporates this assumption into the factor used to calculate allocations from
thermal output. As a result, the allocation factor for thermal output is smaller under the simplified
approach than under the boiler efficiency approach. If you use thermal output data that are measured
using the simplified approach, the thermal output values will be higher than under the boiler
efficiency approach.
One could calculate a "pseudo-efficiency" by dividing the thermal output leaving the boiler
and dividing it only by the heat input from fuel (and not including heat input from any hot water or
steam entering the boiler). This "pseudo-efficiency" will be higher than the boiler efficiency
described above.6 Thus, the factor calculated based upon boiler efficiency using Equation 5 above
Limitations."
6The "pseudo-efficiency" can even exceed 100%.
Final EPA Guidance Document Developing and Updating Output-Based
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Section H.A.: What formula(s) do I use to calculate NOx allowance allocations based on output?
will be too high.
Here are steps that we took to calculate an allocation factor for thermal output that
incorporates energy in the boiler feedwater return. First, we assumed a typical actual heat input rate
for an hour is 250 mmBtu/hr.7 A boiler with an efficiency of 70% will actually transfer 175
mmBtu/hr to steam leaving the boiler. In most industrial and institutional applications, steam is
saturated rather than superheated. Therefore, we assume saturated steam conditions and a typical
enthalpy of roughly 1200 Btu per pound of steam leaving the boiler. With a boiler efficiency of
70%, steam leaving the boiler at 250 pounds per square inch (psi), and condensate in the boiler
feedwater return at 150°F and with an enthalpy of 119.2 Btu/lb, we would find a steam flow of
roughly 161,600 lb/hr.8 With a steam flow of 161,600 Ib/hr and an enthalpy of 1202.1 Btu/lb, the
steam leaving the boiler has a thermal energy rate of 194.3 mmBtu/hr.
Now, we compare this to the allocation factor based on heat input and the heat input rate.
The input-based factor is 0.17 Ib NOx/mmBtu and the heat input rate is 250 mmBtu/hr. We can
calculate the output-based factor in proportion:
( output - based factor, Ib / mmBtu output^! _ ( 250 mmBtu input / hr ^
I 0.17 Ib/mmBtu input J U94.3 mmBtu/hr outputJ
Calculation #1
7 The Coalition for Gas-Based Environmental Solutions provided this assumption in a
February 18, 2000 memorandum. We believe this is reasonable. We determined that the most
common design heat input rate for a non-electric generating unit in the NOx SIP call region is
422 mmBtu/hr (both the median and mode value). The mean design heat input rate for a non-
electric generating unit in the NOx SIP call region is 507 mmBtu/hr. Given these typical values
for the design heat input rate of non-electric generating units, and assuming that industrial boilers
typically run at 50 to 60 percent of their design capacity, a heat input rate of 250 mmBtu/hr is
reasonable.
8These assumptions and calculations are provided in a February 18, 2000 memorandum
from the Coalition for Gas-Based Environmental Solutions.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 28 NOx Allowance Allocations
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Section H.A.: What formula(s) do I use to calculate NOx allowance allocations based on output?
Using this calculation, we find that the allocation factor for thermal output is 0.22 Ib NOx/
mmBtu output where the typical boiler efficiency is 70 percent.
If you wish to, you may calculate your own factor for thermal output under the simplified
approach using the same general approach. For higher heat input rates, the steam flow rate would
increase in proportion, as would the energy flow rate in the steam exiting the boiler. The factor will
vary somewhat based upon the efficiency of the boiler in transferring heat to the steam or water
leaving the boiler. You can use this table to determine the allocation factor using an assumed boiler
efficiency, based upon the approach described in the previous two paragraphs:
Table II-1: Allocation Factor for Thermal Output by the Simplified Approach,
Based on Boiler Efficiency
Assumed Typical Boiler Efficiency
85%
80%
75%
70%
65%
60%
55%
Allocation Factor for Thermal Output Measured
by the Simplified Approach
0.18
0.19
0.20
0.22
0.24
0.26
0.28
^_ Other ways to determine a factor for thermal output
Alternatively, you may calculate the factor for thermal output by dividing the emissions
budget for the non-electric generating unit sector in your State by the total thermal output from all
affected non-electric generating units for an ozone season during some baseline period, if you know
these numbers. This would require that sources continue to use the same monitoring approach for
thermal output that they used historically and that is reflected in the thermal output data that you use
in the calculation.
Representatives of the forest and paper products industry have stated that boilers tend to be
less efficient when they combust biomass fuels, such as wood products, instead of fossil fuel. Thus,
Final EPA Guidance Document
May 8, 2000
Page 29
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NOx Allowance Allocations
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Section H.A.: What formula(s) do I use to calculate NOx allowance allocations based on output?
these boilers could be at a disadvantage in an output-based allocation system. This effect will be
greater as the amount of non-fossil fuel burned by the boiler increases. The forest and paper
products industry has claimed that there may be environmental benefits to using biomass fuels, such
as a reduction in carbon dioxide emissions9 and a reduction in solid waste that otherwise might be
buried in a landfill10, depending on the situation. We have not evaluated these claims and issues.
±_ Other notes on derivation of the allocation factors
The exact value of the factor does not matter, if all allocations in a group are calculated using
the same factor, as in the model trading rule for the NOx SIP Call. Because there will be some
sources that produce both thermal and electric output in both the EGU and non-EGU sectors, it will
be more fair to treat the two forms of output as consistently as possible.
Note that the assumptions about the efficiencies of industrial boilers and electrical generation
are not the same. Electric generation is inherently more difficult to produce and less efficient
compared to the original heat input of fuel because of the steps needed to create the commercial
product. For a utility boiler, this would include running steam through the steam turbine and
generator. Industrial boilers measure their thermal output, which is an intermediate step in the
process of creating the final commercial product (paper, chemicals, refined oil, etc.). It would not
be appropriate to compute allocations assuming the same efficiency for an industrial boiler and for
electric generation, because they operate through different processes with different thermodynamic
properties and create different products that generally are not interchangeable. Thus, industrial
boilers are inherently more capable of producing lower emissions for a given amount of energy
coming out of the process than electric generators. This would not necessarily be the case once one
included the inefficiencies involved in converting steam to a sellable product. Thus, we think it is
appropriate to assume a typical operating efficiency for common technologies used in generating
electricity and steam. We assumed an efficiency of roughly 34% (10,000 Btu/kWh) for electric
9 January 12, 2000 Comments of the American Forest & Paper Association Regarding the
U.S. EPA's Draft Guidance on Output-Based Allocations for States Joining the NOx Budget
Trading Program under the NOx SIP Call
10 Presentation by William Nicholson, Potlatch Corporation. See minutes of March 25,
1999 Meeting of the Updating Output Emission Limitation Workgroup.
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May 8, 2000 Page 30 NOx Allowance Allocations
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//. B. How do I calculate the unadjusted allocation for each source?
generation and assuming an efficiency of roughly 70% for steam generation by an industrial boiler.
Throughout the rest of this document, we will use a factor of 0.24 lb/mmBtuout for thermal
output. This value assumes that sources determine their thermal output using the boiler efficiency
approach. However, if you require sources in your state to monitor thermal output using the
simplified approach, then you should use a factor of 0.22 lb/mmBtuout.
Other forms of output:
You should not need other forms of output, unless you bring in additional categories of
sources into the trading program that were not included in 40 CFR part 96. Note that this may
extend the review time of your SIP and may even mean that we will not include you in the interstate
NOx Budget Trading Program administered by EPA under the NOx SIP call. Other forms of output
could include tons of clinker from cement kilns, or mechanical output in horsepower-hours from
machines such as gas compressors or stationary internal combustion engines.
If you were to calculate NOx allowance allocations for other forms of output, you would use
a similar equation with a factor in Ib NOx per unit of output, multiplied by the output during the
baseline period, divided by 2000 Ib/ton. Ideally, the factor should be similar to the target average
NOx emission rate for that form of output. This could be calculated by the emissions budget for the
sector in your State divided by the output for affected sources in that sector during the ozone season
of a baseline period. Again, as long as this other category of sources has a sector budget and as long
as this category produces only one kind of output, the size of the factor does not matter, and in fact,
is not truly necessary. You would still need to define the form of output from the process and
establish a procedure to determine the output.
B. How do I calculate the unadjusted allocation for each source?
Use the emission rate factor based on output (e.g., 1.5 Ib/MWh or 0.24 lb/mmBtuout).
Multiply this emission rate by the output during the ozone season in the baseline period you choose.
For electric output
Multiply 1.5 Ib/MWh by the electric output during the ozone season in the baseline period
you choose. An example of electric output during a baseline period is the average generation from
the two highest ozone seasons of electric generation from the years 1995, 1996, and 1997. Divide
this number of pounds of NOx by 2000 to calculate the source's unadjusted allocation in tons.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 31 NOx Allowance Allocations
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//. B. How do I calculate the unadjusted allocation for each source?
Example. Calculation of unadjusted allocation using electric generation
Unit 1 at the Deep River Generating Station generated 2,287,047 MWh in May 1 through September
30 of 1995, 2,955,019 MWh in May 1 through September 30 of 1996, and 2,633,547 MWh in May
1 through September 30 of 1997. The average generation during the ozone season for the two
highest of the three years is 2,794,283 MWh. Calculate the unadjusted allocation for Unit 1 as
follows:
(1.5 lbNOx^p 2,794,283 MWh]
Allocation =
MWh J L 2000 Ib / ton J
Finally, round up the allocation to the nearest whole ton, for an unadjusted allocation of 2096
allowances.
For thermal output
The same general approach applies for calculating an allocation based on thermal output.
Multiply the emission standard of 0.24 (or 0.22) lb/mmBtuout by the thermal output in mmBtuout
during the baseline period you choose. Then divide this value by 2000 Ib/ton. Generally, round up
fractional tons of 0.5 or greater, or round down fractional tons of less than 0.5 to calculate the
allocation to the nearest whole ton.
C. How do I develop unadjusted output-based allocations for sources that produce more than
one form of output (such as, both electricity and steam)?
Allocate NOx allowances to the unit by each type of energy, rather than once for the type of
facility. Add the initial tonnages for each form of output to get a total unadjusted allocation. For
example, for an electric generating unit that is a combined heat and power proj ect, you will calculate
one tonnage value for the electric output and a second tonnage value for the thermal output. Add
the tonnages before rounding. Generally, round the total tonnage to the nearest whole ton to get the
unadjusted allocation for the unit.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 32 NOx Allowance Allocations
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//. C. How do I develop unadjusted output-based allocations for sources that produce more than one form of output
(such as, both electricity and steam) ?
Example. Calculation by energy type.
Unit 2 at the Rocky Valley Cogeneration Facility produces both electricity and steam. The State
receives its historic electricity and steam generation for May 1 through September 30 of 1995, 1996,
and 1997. The State then drops the lowest electric output value out of the three control periods and
the lowest thermal output value out of the three control periods. For electric output, the State uses
the average electric output from 1995 and 1997. For thermal output, the State uses the average
thermal output from 1995 and 1996. The electric output and the thermal output values that the State
uses to calculate raw allocations are as follows:
Electric and Thermal Output at Rocky Valley Cogeneration Facility Unit 2
Electric output fMWM
11,193
Thermal outout (mmBtu,,,,^
191,008
Unit 2's allocation portion based on electric output is calculated as:
ElectricOutput tonnage = 1.5 }\n,\93MWh\/2QQQlb/ton = 8.4 tons
V MWh)v V
Unit 2's allocation portion based on thermal output is calculated as:
0.24 [l91,008/M/Mflfw 1
™™R/?/ L ' out\
Thermal Output tonnage = — = 22.9 tons
The total tonnage for the unit then equals 8.4 + 22.9 = 31.3 tons. Unit 2's unadjusted allocation is
31 allowances.
It is also possible to "convert" thermal energy to electric output. However, this is not
necessary, as shown by the example above. Any conversion will require assumptions that depend
upon the technology being used.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 33 NOx Allowance Allocations
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Section II.D.: How do I adjust the unadjusted allocations to fit my State budget?
D. How do I adjust the unadjusted allocations to fit my State budget?
There are a number of approaches you can use. In this section, we will describe an approach
that assumes that both electric generating units (EGUs) and industrial and institutional turbines and
boilers (non-electric generating units, or "non-EGUs") receive NOx allowance allocations based on
output. Under this approach, you would keep separate "sector" budgets for electric generating units
and for non-EGUs. Then the total NOx allowances allocated to all sources within each sector must
be equal to the sector budgets for each facility type. If you include electric generating systems that
are not fossil fuel-fired (e.g., non-emitting electric generating systems), you would count allowances
for those generating systems against the electric generating unit sector budget.
Under this approach, you would:
1. Add up all unadjusted allocations for an entire sector.
2. Divide the unadjusted allocation for each unit (or non-emitting generating system) in the
sector by the total unadjusted allocations for the sector.
3. Multiply that fraction times the sector budget.
Example. Adjusting allocations in a sector budget; each sector using both thermal and electric
output
The State of Columbia has an EGU sector budget of 2722 tons and a non-EGU sector budget
of 278 tons. The total State budget for sources in the trading program is 3000 tons. This State does
not have any set-asides for new units or energy efficiency and renewable energy. The State has the
following sources with the following unadjusted allocations:
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 34 NOx Allowance Allocations
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Section II.D.: How do I adjust the unadjusted allocations to fit my State budget?
Table II-2: Unadjusted NOx Allowance Allocations
and Supporting Output Data for the EGU Sector
Name of electric generating
unit
Deep River Unit 1
Deep River Unit 2
Megawatt Station GT-1
Central Power Unit 1
Central Power Unit 2
Journeytown Cogen CT-1
EGU Sector total:
Baseline electric
output (MWh)
1,506,278
400,916
147,982
605,739
971,545
120,013
Baseline thermal
output (mmBtuout)
601,956
Unadjusted
allocation
(tons')
1130
301
111
455
729
162
2888
Table II-3: Unadjusted NOx Allowance Allocations
and Supporting Output Data for the Non-EGU Sector
Name of non-electric
generating unit
Chemical Plant Unit 1
Columbia Paper Boiler 1
Petro Oil Unit 1
Non-EGU Sector total:
Baseline thermal
output (mmBtuout)
1,286,576
283,400
708,037
Baseline electric
output (MWh)
16,607
Unadjusted
allocation
(tons')
154
46
85
285
There will be some differences in individual unit allocations introduced by changing the unit
allocations from a heat input basis to an output basis. These changes will vary depending on how
efficient a particular unit is.
The electric generating unit allocations add up together to 2885 allowances. However, the
EGU sector budget is only 2722 tons. Each electric generating unit's allocation will need to be
adjusted downward in proportion to each unit's share of the total allowances. For example, you
would calculate the adjusted allocation for Journeytown Cogen CT-1 this way:
Final EPA Guidance Document
May 8, 2000
Page 35
Developing and Updating Output-Based
NOx Allowance Allocations
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Section II.D.: How do I adjust the unadjusted allocations to fit my State budget?
Adjusted
Allocation =
Unadjusted Allocation for Unit / Generator
Sector Unadjusted Allocation Total
(Sector Budget) =
162 tons
,2888 tons
[2722 tons] = 153 tons
The next table shows the unadjusted and adjusted NOx allowance allocations in the electric
generating sector using this same calculation:
Table II-4: NOx Allowance Allocations for the EGU Sector, Adjusted by Sector
Name of electric generating unit
Deep River Unit 1
Deep River Unit 2
Megawatt Station GT-1
Central Power Unit 1
Central Power Unit 2
Journeytown Cogen CT-1
EGU Sector total:
Unadjusted allocation
(tons')
1130
301
111
455
729
162
2888
Adjusted allocation
(tons')
1064
284
105
429
687
153
2722
In calculating adjusted allocations, tonnages are rounded up or down to the whole allowance.
Generally, a fractional tonnage that is 0.5 or higher is rounded up; a fraction ton that is less than 0.5
is rounded down. However, the rounding must be done in a way that ensures that the total of the
adjusted allocations equals the sector total. This means that you may not always follow the general
rule for rounding.
You can do similar calculations to determine the adjusted allocations for the units in the non-
EGU sector. Note that in this sector, the unadjusted total allocation for the sector is less than the
non-EGU sector budget; adjusting the allocations gives each source a larger adjusted allocation than
unadjusted allocation. Here is the example calculation for Petro Oil Unit 1:
Final EPA Guidance Document
May 8, 2000
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Section II.D.: How do I adjust the unadjusted allocations to fit my State budget?
Adjusted
Allocation =
85 tons
285 tons,
[278 tons] = 83 tons
Here are the unadjusted and adjusted NOx allowance allocations in the non-EGU sector:
Table II-5: NOx Allowance Allocations for the Non-EGU Sector, Adjusted by Sector
Name of non-electric generating
unit
Chemical Plant Unit 1
Columbia Paper Boiler 1
Petro Oil Unit 1
Non-EGU Sector total:
Unadjusted allocation
(tons')
154
46
85
285
Adjusted allocation (tons)
150
45
83
278
Note that in the example, if the State of Columbia had a 2% new source set-aside, then the
number of allowances for allocations would be 2% less. In that case, the number of allowances to
go to the EGU sector would add up to 2668 tons (98% of 2722, rounded up) and the number of
allowances for the non-EGU sector would add up to 272 tons (98% of 278 rounded down). In the
formula above, these smaller tonnage values would be used as the "Sector Budget" when calculating
the adjusted allowance allocations.
There is sample rule language to support this approach in Cases 2 and 4 of Appendix A to
this document. Case 2 assumes an initial allocation based upon heat input for both EGUs and non-
EGUs with updated allocations based upon output. Case 4 assumes both initial and updated
allocations based upon output for both EGUs and non-EGUs. Both of these cases assume that
allocations are adjusted separately to fit each sector's budget.
Comparison of allocations under different approaches
Another possible approach to adjusting NOx allowance allocations would be to allocate NOx
allowances to each unit (or non-emitting generating system), and then you would adjust the total
Final EPA Guidance Document
May 8, 2000
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Developing and Updating Output-Based
NOx Allowance Allocations
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Section II.D.: How do I adjust the unadjusted allocations to fit my State budget?
NOx allowances allocated to all trading sources within the State so that they equal the State trading
budget. Under this approach, you would:
1. Add up all unadjusted allocations for sources in the trading program.
2. Divide the unadjusted allocation for each unit (or non-emitting generating system) in the
sector by the total unadjusted allocations in the trading program.
3. Multiply that fraction times the trading program budget.
We chose not to implement this approach to NOx allowance allocations in EP A's section 126
rulemaking. We concluded that adjusting allocations within the sector budgets was consistent with
the original levels of emission control that we selected for each sector:
(1) An average NOx emission rate of 0.15 Ib/mmBtu for EGUs and
(2) An average NOx reduction of 60% for non-EGUs, corresponding to an average NOx emission
rateof0.171b/mmBtu.
In contrast, we found that allowances would move from the non-EGU sector to the EGU sector under
an approach where unadjusted allocations are adjusted to fit the entire trading budget. This means
that non-EGUs receive allocations based on a stricter standard than originally selected, while EGUs
receive allocations at a slightly less stringent standard.
Here is a summary of the final adjusted allocations for each unit under the two different
approaches for allocation adjustment: adjustment by source sector and adjustment to the entire
trading budget.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 38 NOx Allowance Allocations
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Section II.D.: How do I adjust the unadjusted allocations to fit my State budget?
Table II-6: NOx Allowance Allocations for Trading Sources in Columbia,
by Method for Adjustment
Name of source
Electric generating units
Deep River Unit 1
Deep River Unit 2
Megawatt Station GT-1
Central Power Unit 1
Central Power Unit 2
Journeytown Cogen
CT-1
EGU Sector subtotal:
Non-electric generating units
Chemical Plant Unit 1
Columbia Paper Boiler 1
Petro Oil Unit 1
Non-EGU Sector subtotal:
Tradins Budset total:
Adjusted allocation,
adjusted by source sector
(tons')
Adjusted allocation,
adjusted for the entire
tradins budset (tons')
1064
284
105
429
687
153
2722
150
45
83
278
3000
1069
285
105
430
689
153
2731
146
43
80
269
3000
You may also want to compare these output-based allocations to the allocations calculated
in the next section, "How should I set up allocations if I choose to allocate to some sources based
on output and to other sources based on heat input?" (pp. 40-43). In that section, the electric
generating units receive allocations based on output, while the non-electric generating units receive
allocations based on heat input. That section also considers adjusting allocations by sector and for
the entire trading budget. A maj or difference between the heat input-based allocation and the output-
based allocation for non-electric generating units is that the cogeneration facility Columbia Paper
Boiler 1 receives higher allocations under an output-based approach. This reflects the cogeneration
Final EPA Guidance Document
May 8, 2000
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Section II. E.: How should I set up allocations if I choose to allocate to some sources based on output and to other
sources based on heat input?
unit's greater efficiency.
E. How should I set up allocations if I choose to allocate to some sources based on output and
to other sources based on heat input?
You can keep separate sector budgets for sources receiving allocations based on heat input
and a separate sector budget for sources receiving allocations based on output. Then the total NOx
allowances allocated to all sources within each sector must be equal to the sector budget. This
approach may be appropriate if you allocate allowances to electric generating units based on output,
and to non-electric generating units based on heat input. It is also possible to have a few individual
units within a sector receiving unadjusted allocations based on heat input, while other units receive
unadjusted allocations based upon output. This approach may be appropriate if you have a few
individual units that cannot be monitored for output, but most units in the State can be monitored
for output. EPA believes that all electric generating units should be able to monitor their output.
In addition, all non-electric generating units can measure their heat input.
Unadjusted allocation of allowances using heat input
For a non-electric generating unit, the formula for calculating an unadjusted allocation using heat
input is:
( O.lVlbNO
Unadjusted Allocation =
Heat input (fuel usage) used during
baseline period, in mrnBtu
2000 Ib / ton
Eq. 6
In general, you will round the allocation up or down to the nearest whole ton.
Fitting unadjusted allocations to a sector budget
To adjust the allocations, you would:
1. Add up all unadjusted allocations for an entire sector.
2. Divide the unadjusted allocation for each unit (or non-emitting generating system) in the
sector by the total unadjusted allocations for the sector.
3. Determine the fraction of the total number of allowances for each unit (or non-emitting
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 40 NOx Allowance Allocations
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Section II. E.: How should I set up allocations if I choose to allocate to some sources based on output and to other
sources based on heat input?
generating system) in the sector, and then multiply that fraction times the sector budget.
Example. Adjusting allocations in a sector budget; one sector using heat input, another using output
The State of Columbia has an EGU sector budget of 2,722 tons and a non-EGU sector budget
of 278 tons. The total State budget for sources in the trading program is 3000 tons. This State does
not have any set-asides for new units or energy efficiency and renewable energy. Columbia has the
same EGUs with the same electric output as described in the previous section II.D., "How do I adjust
the unadjusted allocations to fit my State budget?" (pp. 34-40).
The electric generating unit allocations add up together to 2880 allowances. However, the
EGU sector budget is only 2722 tons. Each electric generating unit's allocation will need to be
adjusted downward in proportion to each unit's share of the total allowances going to electric
generating units, as described in the first example in the previous section II.D. (pp. 34-40)
The non-EGUs in Columbia have the following unadjusted allocations and heat input data:
Table II-7: Unadjusted NOx Allowance Allocations
and Supporting Heat Input Data for the Non-EGU Sector
Name of Non-electric Generating Unit
Chemical Plant Unit 1
Columbia Paper Boiler 1
Petro Oil Unit 1
Non-EGU Sector total :
Baseline Heat Input
fmmBtu heat inouf)
1,715,435
400,094
874,120
Unadjusted Allocation
(tons')
146
34
75
255
You can do calculations to determine the adjusted allocations for the units in the non-EGU
sector. Note that in this sector, the unadjusted total allocation for the sector is less than the non-EGU
sector budget; adjusting the allocations gives each source a larger adjusted allocation than the
original unadjusted allocation. Here is the example calculation for Petro Oil Unit 1:
Adjusted
( 75 tons ^ r -.
Allocation = I TTT 1 [278 tons] = 82 tons
255
Calculation #7
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May 8, 2000
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Developing and Updating Output-Based
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Section II. E.: How should I set up allocations if I choose to allocate to some sources based on output and to other
sources based on heat input?
Here are the unadjusted and adjusted NOx allowance allocations in the non-EGU sector:
Table II-8: NOx Allowance Allocations for the Non-EGU Sector Based on Heat Input
Name of Non-electric generating
unit
Chemical Plant Unit 1
Columbia Paper Boiler 1
Petro Oil Unit 1
Non-EGU Sector total :
Unadjusted Allocation
(tons')
146
34
75
255
Adjusted Allocation (tons)
159
37
82
278
There is sample rule language to support this approach in Cases 1 and 3 of Appendix A to
this document. Case 1 assumes an initial allocation based upon heat input for both EGUs and non-
EGUs with updated allocations based upon output for EGUs and based upon heat input for non-
EGUs. Case 3 assumes both initial and updated allocations based upon output EGUs and based upon
heat input for non-EGUs. Both of these cases assume that allocations are adjusted separately for
each sector's budget.
Allocation to individual sources based upon heat input
You also could calculate an allocation based upon heat input for one or more individual units
in a sector (or in the entire trading budget) while the rest of the sources receive an allocation based
upon output. You would use the factor of 0.17 Ib/mmBtu input times the baseline heat input for
those individual sources to calculate their unadjusted allocation. Other sources would have their
unadjusted allocations calculated based upon the factors of 1.5 Ib/MWh times baseline electric
generation and 0.24 Ib/mmBtu11 output times baseline thermal output. You would then adjust these
unadjusted allocations to fit the size of each sector. However, if you do not treat all sources the
same, you and companies in your State may be concerned about equity. You do not want a situation
11 This factor assumes that sources monitor thermal output using the boiler efficiency
approach, as described in section VI (pp. 68-69, 84-91, and 124-137). If you require sources to
monitor thermal output using the simplified approach, instead use the factor 0.22 Ib/mmBtu
output for thermal output.
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Section II. E.: How should I set up allocations if I choose to allocate to some sources based on output and to other
sources based on heat input?
where relative inefficient sources may receive their allocations based upon heat input, while
relatively efficient sources receive their allocations based upon output. Therefore, you may want to
consider this source-by-source approach only as a last resort for cases where you judge that output
monitoring is unduly expensive for a particularly complicated source.
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Section III: For which kinds of facilities does this guidance help me develop output-based allocations?
III. Applicability: For which kinds of facilities does this guidance help me develop output-
based allocations?
This guidance will assist you in developing and updating output-based allocations from the
core source categories included in the model NOx trading rule under the NOx SIP call:
fossil fuel-fired electric generating units serving a generator greater than 25 MWe, and
fossil fuel-fired non-electric generating units (industrial or institutional boilers and turbines)
with a design heat input greater than 250 mmBtu/hr.
If you join the NOx Budget Trading Program under the NOx SIP call, you will be controlling NOx
emissions from these categories of units. You also may choose to include other facilities in your
State's NOx Budget Trading Program. Note that if you allocate allowances to sources other than
fossil fuel-fired electric generating units, non-emitting electric generating systems, or fossil-fuel fired
non-electric generating units, this may extend the review time of your SIP. This is because there may
be monitoring and applicability issues that need to be resolved before we can administer a trading
program for other types of facilities.
This guidance will allow you to develop output-based allocations and update them for the
following types of facilities:
*• Fossil fuel-fired electric generating units.
*• Non-emitting electric generating systems. This includes nuclear power plants, hydroelectric
plants, wind power plants, geothermal power plants, and power plants using most other
renewable energy resources.
*• Non-fossil fuel-fired boilers (both electric generating and non-electric generating).
*• Most industrial or institutional boilers and turbines that produce steam or hot water as their
forms of thermal output.
> Cogeneration facilities that produce steam or hot water and electricity in sequence.
This guidance will not help you if you decide to allocate NOx allowances to facilities that
produce output in forms other than electricity, steam, or hot water. For example, this would include:
> Industrial boilers that use hot exhaust gases to dry a manufacturing product, such as paper.
> Process heaters where hot exhaust gases are used to heat materials as part of the
manufacturing process. Cement kilns, glass manufacturing, chemical production, and
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Section III: For which kinds of facilities does this guidance help me develop output-based allocations?
production of iron, steel, or other metals may fall into this category.
*• Industrial sources that produce mechanical work, such as gas compressors or internal
combustion engines.
> Nitric acid plants.
Quantification of output from these sources may be very dependent upon the individual process and
could require a case-by-case procedure for determining output.
You may, but do not need to, allocate NOx allowances based on output to all facilities in the
NOx Budget Trading Program in your state. For example, you could issue NOx allowance
allocations to fossil fuel-fired electric generating units based on output and issue allocations to fossil
fuel-fired non-electric generating units based on heat input (that is, fuel usage, in mmBtu). You may
find it is useful to have the flexibility to issue allocations on a different basis for different kinds of
facilities.
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Section IV.A.: When is it appropriate to allocate to units?
IV. Level of Allocations: Should I allocate to units, to generators, or to entire facilities?
In theory, any of these approaches are possible. However, there are practical reasons for
choosing to allocate NOx allowances to units or to entire facilities. For administrative reasons, we
believe it may be simplest to allocate NOx allowances to units. Also take a look at section V of this
guidance document, "Where should sources determine output to be used for allocations?" as you
consider this issue (pp. 49-54).
In this discussion and throughout this document, a unit is an individual combustion device
such as an individual boiler or combustion turbine. A facility is a plant. A facility may have more
than one unit, more than one generator, or more than one configuration of units and generators that
are connected. In many cases, there is one and only one unit for each electric generator, but there
are also other configurations that are more complicated.
A. When is it appropriate to allocate to units?
In general, we think it is simplest to allocate NOx allowances to units for administrative
purposes. In particular, we suggest that you allocate NOx allowances to units and not to entire
facilities or generators if you choose to allocate based upon gross output. For non-electric generating
units, gross output can be measured for each unit. For electric generating units, the gross electric
output is actually measured from the generator rather than the attached unit (boiler or turbine).
However, for units in existing cap and trade programs, our NOx Allowance Tracking System has
allowance accounts for units and plants, but not for generators. Therefore, we believe it would cause
unnecessary administrative work, expense, and potential confusion to create new accounts for
generators. If you were to calculate allocations using data from generators, you still would need to
send allocations to EPA that are assigned to units or entire plants.
In a few cases, more than one unit (boiler or turbine) may serve a single generator or a single
unit may serve more than one generator. In this situation, we recommend that you or the owners or
operators of the units find a simple way to apportion generation from all of the generators to all of
their associated units. One simple approach would be to divide the total generation by the number
of hours that each unit combusted fuel, or by the number of operating hours times the nameplate
capacity of each unit. Another simple way would be to apportion the allowances based on the heat
input combusted by each unit.
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Section IV. B.: When is it appropriate to allocate to entire facilities?
B. When is it appropriate to allocate to entire facilities?
You may want to allocate NOx allowances to an entire facility if you choose to allocate based
upon net output. In general, power plants keep track of the net electric output leaving the plant.
Some power plants measure net output either directly from the entire plant or from individual units.
Other plants calculate the net electric output for the entire plant but do not measure the net output
directly and do not determine the net output from individual units.
EPA has concluded that it is possible to keep plant level allowance accounts. These are
currently built into the NOx Allowance Tracking System as "overdraft" accounts. Therefore, it is
possible for a State to specify that all allowance allocations for a facility go into an account for the
entire facility. However, each unit must still comply, and EPA will determine compliance at the unit
level. Therefore, the owners and operators of the facility will be responsible for distributing
allowances among the unit compliance accounts. Based on our experience implementing the OTC
NOx Budget Program, we found that some sources made errors in distributing their allowances to
their compliance accounts. Thus, we believe it would be simpler for sources and for EPA's
administration if you initially allocate NOx allowances to units, rather than to facilities.
In addition, if you calculate plant level accounts, there may be some situations where one unit
at a facility is not in the NOx Budget Trading Program under the NOx SIP call while another unit
is. In this case, it will be necessary to subtract the output from the unit that is not in the program
from the total plant output in order to obtain the output for the units in the program.
You may want to consider whether the companies in your State have concerns about unit
ownership before allocating NOx allowances at the plant level. In some cases the same plant will
have different owners of different units. An owner of one unit may not have say in how the unit is
operated if another owner or operator controls the units at the plant. It is also possible to have
ownership conflicts concerning a unit if there are multiple owners, so allocating at the unit level may
not necessarily avoid all potential ownership conflicts. However, in many cases, all units at a plant
have the same owner, and this is not an issue.
C. When is it appropriate to allocate to generators?
We suggest that you allocate NOx allowances to generators only if you intend to allocate
allowances to non-emitting electricity generating systems. This could include nuclear power plants,
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Section IV. C.: When is it appropriate to allocate to generators?
hydroelectric plants, wind power generators, geothermal generators, or other generators of electricity
that do not emit NOx. If you include in your trading program boilers or turbines that emit NOx but
that are not fossil fuel-fired, you should treat them as NOx Budget units subject to all requirements
under the trading program (including compliance).
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Section V.A.: Why does it matter where sources measure their output?
V. Where should sources determine output to be used for allocations?
A. Why does it matter where sources measure their output?
The major policy reason for using output-based emission limitations is to encourage
producing useful products for sale while creating less emissions. This also encourages efficiency,
in an environmental sense. Depending on where one measures or calculates output in a process, the
output value will be farther from or closer to linking emissions to the useful product made by the
process. Different locations for determining output have different implications for monitoring and
reporting of output data and for the kinds of incentives sources will receive.
Some State environmental agencies have shown interest in allocations based upon net output
because, theoretically, they would encourage sources to create the same useful output more
efficiently and with less pollution. For example, the Massachusetts Department of Environmental
Protection has stated:
An important goal of the output-based allocation is to minimize the resources
necessary to produce a unit of useful output. In the case of electricity generation,
this requires maximizing the efficiency of plant generation and minimizing the energy
required for plant use and pollution control, since the useful output of an electricity
generator is the unit of electricity that enters the wholesale electricity market....
(January 12, 2000 Comments on EPA's Draft Guidance for States Joining the NOx
Budget Trading Program under the NOx SIP Call)
In principle, to create the closest link between emissions and useful products for sale,
companies would measure or determine the product that they sell as their output. For example, the
owner of a power plant would measure the electricity that the owner sells to the interstate electric
grid. The amount of electricity that the company sells does not include power used inside the plant12
or power losses, such as:
12For a power plant, typically three to six percent of the gross output from the generator
terminals is used internally, depending on the emission controls used at the unit. Auxiliaries and
pollution control equipment could consume as much as twelve percent of gross output.
Information provided in "Measurement Of Net Versus Gross Power Generation
For The Allocation Of NOx Emission Allowances," January 27, 1999, paper by FirstEnergy
Corp.
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Section V.A.: Why does it matter where sources measure their output?
Auxiliaries loads related to electric generation, such as fuel handling and preparation
equipment, pumps, compressors, motors, and fans
• Load used to operate pollution control devices
• House loads (loads used inside the plant to operate the building, such as electricity used to
light the plant or to run office equipment inside the building)
Energy lost by the boiler or steam turbine as electricity is generated
Therefore, the location for determining output that would seem to link the useful electricity sold to
the emissions produced as directly as possible would be at the connection where power is transmitted
and sold from the plant to the grid (net electric output). A boiler at the power plant could combust
the same amount of fuel and produce the same amount of emissions while increasing the amount of
electricity sold if the company can reduce the amount of power used inside the plant.
Electric output measurements do not need to account for:
• Line losses
End use efficiency outside the plant
Although these losses ultimately have an impact upon emissions, the company probably has little
or no control over these factors outside the plant. Therefore, we focus on controlling the source of
the emissions-the boiler or turbine combusting fuel.
In the case of industrial boilers, a boiler makes an intermediate product, steam or hot water,
that then is used in making the final product. There are a large number of industrial processes and
products. In this document, we simplify measuring output from industrial boilers by measuring the
thermal output of the steam or hot water from the boiler. In some cases, steam from a boiler is sold
commercially. However, more often, the thermal output is a proxy for the final product for sale,
whether it is paper, chemicals, or refined oil.
Keep in mind that the ultimate purpose of an output-based emission limitation for an
industrial boiler should be to encourage making products with less pollution. Thus, you are not
simply trying to encourage boiler (energy) efficiency, but encouraging the environmental efficiency
of producing thermal output which is then used to make a final product for sale. Industrial boilers
also have losses (waste heat) and heat used inside the plant for purposes that do not produce the final
product being sold. These include:
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Section V.B.: What are factors I should consider before deciding on the location where sources determine output?
Auxiliaries thermal loads related to thermal energy generation, such as pumps or
compressors
• Thermal output used for air or feedwater preheating
• House loads (heat used inside the steam house to operate the building and to generate thermal
energy)
Energy lost from the boiler or from pipes carrying steam or water
Ideally, a company would measure the thermal output after all these are removed, at the point that
steam or hot water is used to make the final product.
In some cases, plants do not directly measure the net output used in creating a product.
Instead, they might determine the net output by:
1. First, measuring the gross electric output at the generator terminals or the gross thermal
output coming directly from the boiler header.
2. Then, measuring power or steam or hot water used inside the plant for auxiliaries, pollution
control devices, thermal recover, house loads, or any other use that does not actually produce
the product generated for sale.
3. Finally, subtract all the power or steam or hot water listed under number 2 above from the
gross output listed under number 1 above.
Also, in some cases, it is much easier to calculate the electricity or thermal energy at a point inside
the plant instead of directly measuring it. For example, a company may choose to calculate thermal
energy in a high-pressure steam pipe rather than opening it in order to install measurement
equipment.
For companies receiving NOx allowance allocations, the location where they determine
output that you will use for allocations matters because the location affects the size of the output
value and therefore, the size of their allocation. In addition, the location where they determine output
may have existing monitoring equipment or may require new monitoring equipment, and thus cause
greater or less expense in monitoring output.
B. What are factors I should consider before deciding on the location where sources determine
output?
Although the State environmental agencies we have worked with have expressed interest in
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Section V.B.: What are factors I should consider before deciding on the location where sources determine output?
using net output as the basis for allocations, you may choose a different approach. Here are some
addition factors you may want to consider as you make your decision.
Monitoring considerations
In some cases, it can be difficult to measure or even to calculate net output without adding
a significant, and expensive, amount of monitoring equipment. For example, if a series of boilers
is connected to several interconnected steam headers with a number of pipes taking off steam for use
both as house loads and for making the end product, the company will have an extremely
complicated monitoring situation. For many old industrial boilers, it may be much easier for
companies to measure the gross thermal output coming straight from the boiler. In addition, it is
likely that industrial boiler owners already measure the gross thermal output, but it is less likely that
they determine the net thermal output.
As a rule, power plants determine both their gross and their net electric output. They do not
necessarily measure both directly.
Gross output does not take into account factors of unit efficiency related to operating
auxiliary equipment and pollution control equipment. However, gross and net output both take into
account some factors of unit efficiency, such as: age of the unit; type of unit; operating practices and
conditions; capacity factor; and the need to follow customer demand for electric generation. Thus,
allocations based upon gross output still provides some incentive for improving efficiency, compared
to allocations based upon heat input.
Power companies generally measure gross electric output from each electric generator.
For most plants, there is one and only one generator for each unit, so usually you can link gross
output measurements to a unit. However, there are some cases where there are multiple units
(boilers) associated with a single generator, or a unit associated with more than one generator. This
may have an impact on how you decide to allocate allowances.
Net electric output may be measured either for an entire plant or for individual generators,
depending on the facility. Some plants measure gross output and auxiliary usage and then calculate
net output, rather than measuring net output directly.
For some conventional power plants, net electric output is more difficult to determine than
gross electric output. For cogenerators, gross thermal output may be more difficult to measure than
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Section V. C:. How could I incorporate the concept of the location for determining output into my State rule ?
net thermal output because part of the steam is diverted to generate electricity.
Sources of output data
Some data sources provide only gross generation or only net generation, but not both. For
example, the electric generation data that utilities report to EPA currently are only gross electric
output data. The electric generation data the utilities report to the Energy Information Agency (EIA)
on form 759 are net electric output data. Thus, consider the data source you want to use at the same
time that you decide whether to use gross or net output. (See section VIII, "Where do I get the data
for an output-based allocation?", pp. 163-166)
Encouraging specific NOx control strategies
Using net generation as a basis for allocations will tend to benefit facilities that burn cleaner
fuels or that do not burn fuel at all. Net output, or output that excludes power used to operate
pollution control equipment, may encourage pollution prevention more than gross output, or output
that includes power going to pollution controls.
However, if you do not want to discourage sources from installing add-on pollution
controls13, you may want to include the power used to operate pollution control equipment as part
of the calculation of output used in allocations. Consider an example where one coal fired-unit has
a scrubber and a second coal-fired unit of similar size, type, and fuel usage does not have a scrubber.
If the power used to operate the scrubber is not included in your calculation of output, the unit with
no scrubber will receive a larger allocation. If the power used to operate the scrubber is included in
your calculation of output, both units will receive the same size allocation.
C. How could I incorporate the concept of the location for determining output into my State
rule?
You could describe whether you are basing allocations based on gross or net output. You
also could use some variation of net or gross output that includes or excludes certain uses of power
or steam within the plant. For example, you could define electric output to include power sold to
the grid and power used to operate pollution control equipment. You also should define gross output
13 The United Mine Workers of America have claimed that there can be significant social
costs for policies that discourage retrofit controls and cause unemployment among coal miners.
Minutes of the Updating Output Emission Limitations Workgroup, Thursday, March 25, 1999.
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Section V. C:. How could I incorporate the concept of the location for determining output into my State rule ?
or net output. This will help ensure that all facilities are clear what information they need to report
and will treat different facilities as equitably as possible. See section V.A., "Why does it matter
where sources measure their output?" and the definitions in Appendix A for descriptions of net and
gross output (pp. 49-51, 171-172).
You also will need to have consistent monitoring and reporting requirements. Also, see
sections VI, "Where do facilities measure electric and thermal output?" and VII,"How should
sources monitor, record, and report output data to support updating output-based allocations?" in this
guidance document (pp. 55-141, 142-162).
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Section VI.A.: Where should output measurement equipment be installed?
VI: Monitoring locations: Where could facilities monitor electric and thermal output?
A. Where should output measurement equipment be installed?
This will depend on the type of output to be measure: gross or net; and electric or thermal.
Monitoring for both plant and unit level output should be similar with the only difference being how
the measured output is apportioned and reported. In addition, the locations for monitoring vary
based on the type of facility.
Conventional power plants (non-cogeneration) will measure, and will receive allocations
based on, electric output only. These conventional power plants will not need to measure any
additional thermal energy for the purposes of supporting data for allocations, because conventional
power plants use thermal energy to produce electricity, rather than for other useful purposes. Steam
generators (industrial or institutional boilers and turbines that do not generate electricity) will
measure, and will receive allocations based on, thermal output only. Steam generators will not need
to measure any electric output for the purposes of supporting data for allocations.
Facilities that produce both electricity and steam or hot water as useful outputs will need to
measure both thermal and electric output. Most of these are cogeneration facilities, also called
combined heat and power (CHP) facilities. Cogeneration facilities tend to be more efficient because
they produce thermal output and electric output in sequence, from the same heat input. In order to
determine net output, facilities producing both kinds of output will need to account for parasitic and
house loads for both electricity and steam or hot water. Cogeneration facilities can be classified
either as electric generating units or as non-electric generating units, depending on the characteristics
of the unit and the associated generator.
In section VI, we provide tables that describe which locations a source would monitor,
depending on the type of output and the type of facility (pp. 58, 62, 73, 83, 96-101, and 118-123).
The tables describe how to monitor both net and gross electric and thermal output. They also
describe monitoring locations for conventional power plants where a company would measure only
electric output; for steam generators where a company would measure only thermal output; and for
cogeneration facilities where a facility would measure both thermal and electric output. In each case,
we provide a "primary approach" for measuring a type of output. This is the approach that we
understand sources are most likely to use. In addition, we provide alternative approaches in case you
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Section VI.A.: Where should output measurement equipment be installed?
wish to provide extra flexibility that will allow sources to use existing equipment for monitoring
output.
In addition, we provide six simplified diagrams that picture the points for measuring
electricity and thermal energy at six different types of facilities you are likely to see in your State:
a conventional power plant; a steam generator; a steam generator that has a line for reheating steam;
a steam cogenerator; a combustion turbine cogenerator; and a combined cycle cogenerator with a
secondary electric generator after the heat recovery steam generator. Keep in mind that in many real
plants, there may be several places in a plant that are represented with a single point in the diagram.
Thus, output monitoring for some plants may be more difficult and expensive that it appears from
these simplified diagrams. However, the diagrams will help you understand the types of locations
that a source may need to monitor for output.
In section VLB., "How could sources monitor electric output only at a conventional electric
power plant?" (pp. 60-67), we describe monitoring locations for electric output from conventional
power plants (non-cogeneration). These are similar to the monitoring locations for electric output
from cogeneration facilities, which are discussed below in section VI.D., "How could sources
monitor electric and thermal output at a cogeneration facility?" (pp. 92-137).
In section VI.C., "How could sources monitor thermal output at a steam generator?" (pp. 68-
91), we describe monitoring locations for thermal output only from industrial and institutional
boilers (non-cogeneration). This section also describes two different approaches to monitoring
thermal output: the Simplified Approach and the Boiler Efficiency Approach The monitoring
locations and possibly some equipment are different for thermal output under the two approaches.
The boiler efficiency approach utilizes the traditional engineering approach to measuring thermal
output where the thermal output is measured using an energy balance around the boiler or system
to determine the energy transferred to the steam from combustion. The simplified approach
measures thermal output in a single location, using a generic value for the energy returning to the
boiler or system in boiler feedwater return or make up water as part of the allocation factor, rather
than requiring measurement of the boiler feedwater return or make up water. This section explains
how to monitor thermal output using the two approaches and explains why you might prefer one
approach over the other.
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Section VI.A.: Where should output measurement equipment be installed?
In section VI.D., "How could sources monitor electric and thermal output at a cogeneration
facility?" (pp. 92-137), we describe how to monitor both electric and thermal output from three
common types of cogeneration facilities: steam cogenerators, combustion turbine cogenerators, and
combined cycle systems. We describe how to monitor thermal output under both the simplified
approach and the boiler efficiency approach.
Table VI-1 summarizes the most common approaches to monitoring output (pp. 58-59). The
most common approaches and alternative approaches are discussed below in detail in sections VLB,
VI.C., and VI.D.
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Table VI-1; Summary of Most Common Approaches to Monitoring Output
If you look at
this facility tvp1^
Conventional power
plant (Figure 1, p.
61)
Steam generator
(Figures 2 and 3, pp.
71, 81, 72, 82)
Steam cogenerator
with process use of
steam downstream of
the steam turbine
(Figure 4, pp. 93,
115)
Combustion turbine
cogenerator (Figure
5, pp. 94, 116)
and you require this type of output
^f\ ^(^» \]5<^d f^r rillr*'~£itir*iis
net electric
gross electric
net thermal (by simplified approach)
gross thermal (by simplified approach)
net thermal (by boiler efficiency approach)
gross thermal (by boiler efficiency
approach)
net electric
gross electric
net thermal (by simplified approach)
gross thermal (by simplified approach)
net thermal (by boiler efficiency approach)
gross thermal (by boiler efficiency
approach)
net electric
gross electric
net thermal (by simplified approach)
gross thermal (by simplified approach)
net thermal (by boiler efficiency approach)
gross thermal (by boiler efficiency
approach)
there are more
d^* trills h^r^*
VLB. 1 (pp. 63-65)
VI.B.2 (pp. 65-66)
VI.C.l (pp. 74-76)
VI.C.2 (pp. 76-78)
VI.C.3 (pp. 84-86)
VI.C.4 (pp. 87-89)
VI.D.l.aandVI.B.l
(pp. 63-65, 102)
VI.D.l. band VI.B.2
(pp. 65-66, 102)
VI.D.2(pp. 102-105)
VI.D.3 (pp. 105-109)
VI.D.4 (pp. 124-128)
VI.D.5 (pp. 128-132)
VI.D.l.aandVI.B.l
(pp. 63-65, 102)
VI.D.l. band VI.B.2
(pp. 65-66, 102)
VI.D.2(pp. 102-105)
VI.D.3 (pp. 105-109)
VI.D.4 (pp. 124-128)
VI.D.5 (pp. 128-132)
and this is the most common approach to monitoring output
Measure electric power sold and power used in a useful process, less any incoming electricity provided to
the plant during operation of the generator
Measure electric power at the generator terminals
Measure thermal energy sold and thermal energy going into a useful process
Measure thermal energy leaving the boiler
Measure thermal energy sold and thermal energy going into a useful process, less any thermal energy
returned to boiler in boiler feedwater, make up water, or steam return for reheating
Measure thermal energy leaving the boiler, less any thermal energy returned to boiler in boiler feedwater,
make up water, or steam return for reheating
Measure electric power sold and power used in a useful process, less any incoming electricity provided to
the plant during operation of the generator
Measure electric power at the generator terminals
Measure thermal energy sold and thermal energy going into a useful process
Measure thermal energy exiting the steam turbine
Measure thermal energy sold and thermal energy going into a useful process, less any thermal energy
returned to boiler in boiler feedwater, make up water, or steam return for reheating
Measure thermal energy exiting the steam turbine, less any thermal energy returned to boiler in boiler
feedwater, make up water, or steam return for reheating
Measure electric power sold and power used in a useful process, less any incoming electricity provided to
the plant during operation of the generator
Measure electric power at the generator terminals
Measure thermal energy sold and thermal energy going into a useful process
Measure thermal energy leaving the heat recovery steam generator (HRSG)
Measure thermal energy sold and thermal energy going into a useful process, less any thermal energy
returned to HRSG in boiler feedwater, make up water, or steam return for reheating
Measure thermal energy leaving the boiler, less any thermal energy returned to HRSG in boiler feedwater,
make up water, or steam return for reheating
Page 58
-------
If you look at
tliic "Fo^ilihf fainr*
Combined cycle
cogenerator with
process use of steam
downstream of the
steam turbine
(Figure 6, pp. 95,
117)
Steam cogenerator or
combined cycle
cogenerator with
process use of
superheated steam
upstream of the
steam turbine
and you require this type of output
net electric
gross electric
net thermal (by simplified approach)
gross thermal (by simplified approach)
net thermal (by boiler efficiency approach)
gross thermal (by boiler efficiency
approach)
net electric
gross electric
net thermal (by simplified approach)
gross thermal (by simplified approach)
net thermal (by boiler efficiency approach)
gross thermal (by boiler efficiency
accroach)
there are more
Hf^toilc Vif^rv^
VI.D.l.aandVI.B.l
(pp. 63-65, 102)
VI.D.l.bandVI.B.2
(pp. 65-66, 102)
VI.D.2(pp. 102-105)
VI.D.3 (pp. 105-109)
VI.D.4 (pp. 124-128)
VI.D.5 (pp. 128-132)
VI.D.l.aandVI.B.l
(pp. 63-65, 102)
VI.D.l.bandVI.B.2
(pp. 65-66, 102)
VI.D.2(pp. 102-105)
VI.D.3 (pp. 105-109)
VI.D.4 (pp. 124-128)
VI.D.5 (pp. 128-132)
and this is the most common approach to monitoring output
Measure electric power sold and power used in a useful process, less any incoming electricity provided to
the plant during operation of the generator
Measure electric power at the generator terminals
Measure thermal energy sold and thermal energy going into a useful process
Measure thermal energy exiting the steam turbine
Measure thermal energy sold and thermal energy going into a useful process, less any thermal energy
returned to HRSG in boiler feedwater, make up water, or steam return for reheating
Measure thermal energy exiting the steam turbine, less any thermal energy returned to HRSG in boiler
feedwater, make up water, or steam return for reheating
Measure electric power sold and power used in a useful process, less any incoming electricity provided to
the plant during operation of the generator
Measure electric power at the generator terminals
Measure thermal energy sold and thermal energy going into a useful process
Measure thermal energy leaving the boiler or HRSG, less any thermal energy entering the steam turbine
Measure thermal energy sold and thermal energy going into a useful process, less any thermal energy
returned to the boiler or HRSG in boiler feedwater, make up water, or steam return for reheating
Measure thermal energy leaving the boiler, less any thermal energy returned to HRSG in boiler feedwater,
make up water, or steam return for reheating and less anv thermal energy entering the steam turbine
Page 59
-------
Section VLB.: How could sources monitor electric output only at a conventional electric power plant?
B. How could sources monitor electric output only at a conventional electric power plant?
Your State rule will require that electric generating facilities monitor either gross electric
output or net electric output. Monitoring net output is described in section 1, "Net Electric Output"
(pp. 63-65) and monitoring gross output is described in section 2., "Gross Electric Output" (pp. 65-
66). Conventional power plants (non-cogeneration) will monitor only electric output. Table E-l
below (p. 62) describes locations for measuring electric output from a conventional power plant that
receives allocations based upon electric output only. Figure 1 below (p. 61) is a simplified diagram
picturing the measurement points described below at a conventional power plant. Cogeneration units
which generate both electric output and thermal output are discussed below in Section VI.D., "How
could sources monitor electric and thermal output at a cogeneration facility?" (pp. 92-137). In all
cases below except those that specifically state otherwise, we assume that the measured output is
recorded in a datalogger or computer on an hourly basis.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 60 NOx Allowance Allocations
-------
FIGURE 1: Electric Generator
Figure 1
Electric Generator
Heat
Input
Boiler Steam
Out (BSt)
Boiler
Make Up
Water (MUW)
Boiler Feedwater
Return (BFR)
Gross Electric
(GE)
Net Electricity
(UE or SE)
Condenser
_v
(PEandHE)
Parasitic and
House
Electric
Loads
A
(OEO or OEN)
Electric supplies from
outside plant
Page 61
-------
Table E-l, Monitoring Electric Output Only from an EGU
Overall System
Description
In this column are the
various systems
associated with boilers
and electric generators
as defined in the
diagrams.
Column 1
Electric Generation
Electricity Used on Site
Not Generated by the
Facility
Losses Associated with
Electrical Generation
Possible Monitoring Locations
In this column are the specific points
which might need to be monitored
under different approaches.
The letter in the first column
corresponds to letters used on the
associated diagrams
2
GE
SE
UE
OEO
OEN
PE
HE
3
Electric power measured at
generator terminals
Electric power leaving plant to
electric grid
Useful electric power (i.e.,
purposes other than sale,
transmission to the grid, or
generation of electricity)
Electric power for generation
coming from grid or other power
source to plant during operation
Electric power coming from grid
or other source during non
operation
Parasitic electric loads
House electric loads
Net Electric Output
Net measured
directly
(Primary)
4
-
Measure (+)
Measure (+)
Measure (-)
~
~
~
Gross less
parasitic and
house loads
5
Measure(+)
-
Measure(-)
~
Measure or use
estimates which
overstate loads (-)
Measure or use
estimates which
overstate loads (-)
Gross Electric Output
Gross measured
directly
(Primary)
6
Measure (+)
-
~
~
~
~
Measure net plus
parasitic and
house loads
7
-
Measure (+)
Measure (+)
Measure (-)
~
Measure or
estimate (+)
Measure or
estimate (+)
Page 62
-------
Section VLB.: How could sources monitor electric output only at a conventional electric power plant?
1. Net Electric Output.
Monitoring equipment locations are described in Table E-l, columns 4 and 5 for EGUs monitoring
only net electric output (p. 62).
Primary approach a. Measuring net electric output directly. For a source required to monitor net electric
output only, the output monitoring system would monitor the amount of electricity
sold, transmitted from the plant to the grid, or used for a purpose other than sale,
transmission to the grid, or generating electricity at that plant14, and any incoming
electricity provided to the plant from another source (See Table E-l, column 4).
Plants which sell electricity may use the billing meters for measuring electric sales
and should not be required to install additional output monitoring equipment for
record keeping purposes (i.e., datalogger or computer).
^net ~ Ll elect ~ Ll elect
Electricity sold or used Incoming electricity during
generator operation
Where:
Enet is the net electricity generated by the plant
Eelect is the electricity measured at each point
"Electricity sold or used" is the number of places where electricity is sold or is transmitted
from the plant (Location SE in Figure 1) or is used in a process other than generating
electricity (UE in Table E-l)15
"Incoming electricity during generator operation" is the number of places where the plant
14 It is possible that a source would use electricity within the plant in a useful process,
such as operating industrial equipment to manufacture a product. This also should be measured
as net electric output. (Location UE in Figures 4, 5, and 6) As a guideline, if some electricity
used in the plant is used in the process of generating electricity, and if that electricity would not
be used if the generator were removed from the facility, then that electricity should not be
considered net electric output. For example, power used within a power plant to pulverize coal
so that electricity can be generated would not be net electric output.
15Same as footnote 14.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 63 NOx Allowance Allocations
-------
Section VLB.: How could sources monitor electric output only at a conventional electric power plant?
receives electricity from another source during operation of the generator (Location OEO in
Figure 1)
Alternative
b. Determining net electric output using gross output measurements. For a
source required to monitor net electric output which has gross output
monitoring equipment installed on the generator terminals but does not have
net output monitoring equipment installed, you may allow this source to
determine net output as the gross output less all parasitic and house loads and
less any electricity provided to the plant from another source while the
generator produces electricity (See Table E-l, column 5). (It should not be
necessary to measure electricity provided from another source while the
generator is not operating, when there is no gross generation.)
L ^dect L ^dect L ^dect
Gross generation Parasitic and house loads Incoming electricity during
Delect
is the net electricity generated by the plant
is the electricity measured at each point
"Gross generation" is each location where the source measures gross electric directly.
(Location GE in Figure 1)
"Parasitic and house loads" is each location where the source measures or determines losses
of electricity from parasitic (auxiliary) or house loads. (Locations PE and FIE in Figure 1)
"Incoming electricity during generator operation" is each location where the source receives
power from outside the plant while the generator is operating. (Location OEO in Figure 1)
Special case c. Both affected and non-affected units sharing a generator. In some cases, steam to a
generator is supplied by both affected and non-affected units, such as when fossil
fuel-fired and non-fossil fuel fired boilers feed steam to the same generator. It is also
possible to have both affected and non-affected units located at a plant, where the
source measures net electric output for the entire facility. In the first case, the
company must develop an apportionment methodology to determine the amount of
Final EPA Guidance Document
May 8, 2000
Page 64
Developing and Updating Output-Based
NOx Allowance Allocations
-------
Section VLB.: How could sources monitor electric output only at a conventional electric power plant?
net electric output that is attributable to any affected units. In the second case, the
company could opt-in the non-affected boilers or could develop an apportionment
methodology. Several apportionment options exist including:
i. Apportion the electric output by steam energy supplied to the generator from
each unit, or supplied to all generators at the plant. This requires monitoring
steam supplied to each generator from each unit.
ii. Use unit heat input measured, recorded and reported using Part 75
procedures, Appendix F (i.e., stack flow monitor and diluent monitor or fuel
flowmeters for gas and oil fired units). Note that you will be able to use this
option if you measure heat input for individual units, but you will not be able
to use heat input measured at a common stack or a common pipe.
2. Gross Electric Output.
Monitoring equipment locations for EGUs monitoring only gross electric output are described in
Table E-l, columns 6 and 7 (p. 62).
Primary approach a. Measuring gross electric output directly. In the simplest and most common case, a
facility which is required to monitor only gross electric output would measure the
output from the generator at the generator terminals (See Table E-l, column 6).
Alternative b. Determining gross electric output using net output measurements. In the case
where a facility has an existing output monitoring system for net electric
output but does not measure electric output at the generator terminals, the
gross output for this source may be estimated as either:
i. The sales of electricity using existing equipment (same as net electric output
and always less than gross electric output). Under this approach, there should
be no additional requirement for data collections in a datalogger or data
acquisition and handling system (DAHS), as the billing measurement serves
as the official record of output; or
ii The sales of electricity using existing equipment plus any measured parasitic
or house electric load (See Table E-l, column 7). Under this option, a source
may need to install extra electrical measurement equipment.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 65 NOx Allowance Allocations
-------
Section VLB.: How could sources monitor electric output only at a conventional electric power plant?
Special case c. Both affected and non-affected units sharing a generator. If steam to a generator is
supplied by both affected and non-affected units, an apportionment methodology
must be developed to determine the amount of gross electric output that is
attributable to the affected unit. Several apportionment options exist including:
i. Apportion the electric output by steam energy supplied to the generator from
each unit. This requires monitoring steam supplied to the generator from
each unit.
ii. Use unit heat input measured, recorded and reported using Part 75
procedures, Appendix F (i.e., stack flow monitor and diluent monitor or fuel
flowmeters for gas and oil fired units). Note that you will be able to use this
option if you measure heat input for individual units, but you will not be able
to use heat input measured at a common stack or a common pipe.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 66 NOx Allowance Allocations
-------
Section VLB.: How could sources monitor electric output only at a conventional electric power plant?
Monitoring example for a conventional electric generator (power plant) (See Figurel. p. 61).
This is an example of a conventional power plant that produces only electric output. This figure
would be similar for a non-emitting generating system; in that case, the energy source would replace
the location marked "heat input" in the diagram.
The company could measure or estimate electric output as follows:
Primary approach for net electric output: Net electric output measured directly would be
UE+SE-OEO (Table E-l, column 4).
• Net electric output measured as gross electric output less house and parasitic loads would be
GE-HE-PE-OEO (Table E-l, column 5)
Primary approach for gross electric output: Gross electric output would be measured at the
generator terminals GE. (Table E-l, column 6)
• Gross electric output estimated as net electric output would be UE+SE-OEO (Table E-l,
column 7)
Gross electric output measured or estimated as net electric output plus house and parasitic
loads would be UE+SE+HE+PE-OEO (Table E-l, column 7).
Note that when switching from measuring gross output to calculating net output, or vice versa, you
also need to measure any electricity coming into the plant from an outside source during operation
of the generator for use in generating power (point OEO).
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 67 NOx Allowance Allocations
-------
Section VI. C.: How could sources monitor thermal output at a steam generator?
C. How could sources monitor thermal output at a steam generator?
Your State rule will require that sources monitor either gross thermal output or net thermal
output. Non-electric generating units that are not cogeneration facilities (steam generators) will
monitor only thermal output.
The Simplified Approach and the Boiler Efficiency Approach to Monitoring Thermal Output
We recommend that you require sources to monitor thermal output using one of the two
following approaches: the simplified approach or the boiler efficiency approach. The boiler
efficiency approach utilizes the traditional engineering approach to measuring thermal output where
the thermal output is measured using an energy balance around the boiler or system to determine the
energy transferred to the steam from combustion. The simplified approach measures thermal output
in a single location, using a generic value for the energy returning to the boiler or system in boiler
feedwater return or make up water as part of the allocation factor, rather than requiring measurement
of the boiler feedwater return or make up water. Thus, if you compare Table BE-2 and Table SA-2
below, you will find that they are similar. However, four locations are not monitored under the
simplified approach that might have to be monitored under the boiler efficiency approach: the boiler
feedwater return, the make up water to the boiler, steam or hot water exiting a process, and return
condensate or steam from a buyer.
Why do we provide you with two approaches? Both are valid approaches to monitoring
output. However, there are issues you need to consider when deciding whether to require sources
to measure thermal energy in the boiler feedwater return (condensate return) to a boiler. You might
want to use the boiler efficiency approach, measuring the thermal energy in the boiler feedwater
return for these reasons:
• Measuring the thermal energy going into and leaving the boiler reduces the possibility of
"gaming" measurements of thermal output. Sources may perceive this approach as being
more fair.
The boiler efficiency approach is consistent with the approach that EIA takes when it
receives thermal output data.
• Measuring the thermal energy going into and leaving the boiler is consistent with engineering
practice for determining boiler efficiency, a familiar concept for boiler owners.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 68 NOx Allowance Allocations
-------
Section VI. C.: How could sources monitor thermal output at a steam generator?
However, there are good reasons for preferring to use the simplified approach:
The simplified approach encourages sources to take measures that improve the overall
efficiency of making the plant's end product for sale, including returning condensate to the
boiler instead of heating new, cold water.
• The simplified approach is simpler and will not require monitoring thermal energy on the
boiler feedwater return line. This may reduce the overall monitoring burden for companies
compared to the boiler efficiency approach.
• Our preliminary look at the possibility of gaming indicates that it may not be a major
problem.
In deciding which approach to use for your State rule, you might take comment on issues such as:
• How many sources would need to install new monitoring equipment on the boiler feedwater
return (condensate return) line if they monitor using the boiler efficiency approach?
• How much likelihood is there of gaming?
How would companies prefer their competitors to measure their output?
Monitoring net thermal output under the simplified approach is described in section 1, "Net
Thermal Output under the Simplified Approach "(pp. 74-76) and monitoring gross thermal output
under the simplified approach is described in section 2, "Gross Thermal Output under the Simplified
Approach" (pp. 76-78). Monitoring net thermal output under the boiler efficiency approach is
described in section 3, "Net Thermal Output under the Boiler Efficiency Approach' (pp. 84-86), and
monitoring gross thermal output under the boiler efficiency approach is described in section 4,
"Gross Thermal Output under the Boiler Efficiency Approach " (pp. 87-89). Tables SA-2 and BE-2
below describes locations for measuring electric output from a steam generator that receives
allocations based upon thermal output only (pp. 73, 83). Figure 2 below (pp. 71, 81) is a simplified
diagram picturing the measurement points described below at a typical steam generator boiler; Figure
3 is similar, but shows a steam generator with a line returning steam to the boiler to be reheated (pp.
72,82). Figure 3 represents an unusual situation for an industrial boiler. Steam reheat is more
common at EGUs. However, we include this example here to be comprehensive and to provide a
simplified discussion of steam reheat, rather than a more complex, cogeneration situation with steam
reheat. Cogeneration units which generate both electric output and thermal output are discussed
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 69 NOx Allowance Allocations
-------
Section VI. C.: How could sources monitor thermal output at a steam generator?
below in section VI.D., "How could sources monitor electric and thermal output at a cogeneration
facility?" (pp. 92-137). In all cases below except those that specifically state otherwise, we assume
that the measured output is recorded in a datalogger or computer on an hourly basis.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 70 NOx Allowance Allocations
-------
FIGURE 2 Steam Gen
Figure 2
Steam Generator
Heat Input
^
Boiler
i
Make Up
Water (MOW) ^
coner sieam
Out (BSt)
(PSt)|
Parasitic
Steam
Loads
k
i
r
(HS^ (USt+SSt)
1
Hoi
use
Steam Useful
Loads Steam
i
i^uciua
(XSt)
i r
Boiler Feedwater
Return (BFR)
Page 71
-------
Figure 3
Steam Generator
(Industrial Boiler with Steam Reheat)
Heat
Input
>
A
Boi
i
^-
Make Up
Water (MOW)
ler
f
•I
Boiler ]
Retui
Boiler Steam Out (BSt)
i(USt+SSt)
Into Boiler (RStI)
^ Useful
(XSt) Load
Reheat Steam Out (RStO) (
JL (USt + SS
Useful
Load
Feedwater |
-n (BFR) \ (XSt)
k-
i
(PSt + HSt)
r
Parasitic
PSt + HSt) and House
l\ Loads
-
.
Page 72
-------
Table SA-2 Monitoring Thermal Output Only from a Steam Generator under the Simplified Approach
Overall System Description
In this column are the various
systems associated with
boilers and electric generators
as defined in the diagrams.
Column 1
Primary Steam System
Note: flow in feedwater return
and make up water must equal
steam out flow
Steam Return and Reheat System
Note: flow in reheat steam out
must equal flow in reheat steam
entering boiler
Useful Thermal Loads
Losses Associated with
Generation of Thermal Output
Possible Monitoring Locations
In this column are the specific points
which might need to be monitored
under different approaches.
The letter in the first column
corresponds to letters used on the
associated diagrams
2
BSt
BFR
MUW
RStO
RStI
ust
xst
sst
xst
PSt
HSt
o
J
Main boiler steam out
Boiler feedwater
return
Make up water
Reheat steam out
Reheat steam returning to
boiler
Useful steam or hot water
entering a process
Steam or hot water exiting a
process
Steam sold at point of sale
Return condensate or steam
from buyer
Parasitic steam loads
House steam loads
Gross Thermal Output Using the
Simplified Approach
Gross measured
directly (Primary)
4
Measure (+)
Net plus parasitic
and house loads
5
--
Net Thermal Output Using the
Simplified Approach
Net measured
directly (Primary)
6
Gross less parasitic
and house loads
7
Measure (+)
Not monitored under simplified approach
Not monitored under simplified approach
Measure (+)
Measure (-)
--
--
--
Measure (+)
--
--
Measure(+)
Measure (+)
Measure (-)
--
Not monitored under simplified approach
-
Measure(+)
Measure(+)
-
Not monitored under simplified approach
--
-
Measure (+)
Measure(+)
--
-
Measure (-)
Measure (-)
Page 73
-------
Section VI. C.: How could sources monitor thermal output at a steam generator?
1. Net Thermal Output under the Simplified Approach.
Net thermal output monitoring equipment locations are described in Table SA-2, columns
6 and 7 for industrial or institutional sources monitoring only net thermal output (p. 73). The basic
approach is similar to that used for gross thermal output from a boiler, except that useful steam is
measured, not gross steam from the boiler. "Useful steam" is steam (or hot water) used in a process
that makes the product which is the purpose of the plant or steam that the plant sells. In contrast,
steam used to heat the steam plant is a house load and is not considered "useful" because the source
presumably would use that energy anyway, even if it were not making its final product at that time.
Also, any thermal energy used in the process of generating the steam should not be considered net
thermal output. In order to determine the energy in useful steam, a source would follow these steps:
Step 1: For saturated steam, measure or estimate the pressure of each stream of steam
entering the useful process; temperature of saturated steam is determined by pressure.
For superheated steam, measure or estimate the pressure and temperature of each
stream of steam entering the useful process.
Step 2: Determine average hourly enthalpy (Btu/lb) from standard thermodynamic steam
tables16 for each stream of steam or hot water. (See section VIE., "How do I calculate
output data from supporting data?", pp. 138-141, for examples of how to do this.)
Measure or estimate each total hourly flow of steam or hot water (Ib).
Use flow and enthalpy to determine the energy in the steam or hot water in mmBtu.
I? I Df \ TT( mmBtu] / s.
Estm(mmBtu) = H\—^—\> x Q(lb)
Where:
Estm = total energy in steam or water for an hour
H = enthalpy from standard thermodynamic steam table
Q = total mass flow of steam or water for an hour
Determine the net thermal output energy (mmBtu) as the total energy into any useful
16 We recommend using "ASME Steam Tables: Thermodynamic and Tranposrt Properties
of Steam" by the American Society of Mechanical Engineers, or tables from some other
respected source or standard-setting organization.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 74 NOx Allowance Allocations
-------
Section VI. C.: How could sources monitor thermal output at a steam generator?
process.
Approaches for determining net thermal output:
Primary approach: a. Measuring net thermal output directly. Determine the net thermal output
energy (mmBtu) as the total energy into any useful process.
stm
Themal energy in
Where:
Enet is the net thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Thermal energy in" is each location where thermal energy goes into a useful process.
(Locations USt and SSt in Figures 2 and 3)
Alternative: b. Determining net thermal output measuring gross output. In the case where a facility
measures the gross thermal output but does not measure the net thermal output
directly, it is permissible to allow the source to determine net output as the gross
thermal output less parasitic and house steam loads. In some cases it might be easier
or more cost-effective to add monitors to measure or estimate the parasitic and house
loads rather than installing a complete net output monitoring system to take account
of thermal energy in such loads. (See Table SA-2, column 7)
E = ^ E — ^ E
net / * stm / * stm
Boiler thermal energy out Parasitic and house thermal loads
Where:
Enet is the net thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Boiler thermal energy out" is each location where thermal energy leaves the boiler.
(Locations BSt in Figures 2 and 3 and RStO in Figure 3)
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 75 NOx Allowance Allocations
-------
Section VI. C.: How could sources monitor thermal output at a steam generator?
"Parasitic and house thermal loads" is each location where the source measures or determines
losses of thermal energy from parasitic (auxiliary) or house thermal loads. (Locations PSt and
HSt in Figures 2 and 3)
Under this approach, you should require monitoring of the flow and pressure, and
temperature for superheated steam, for each of the major input and output streams.
The energy of small streams or the effects of very minor losses such as small steam
leaks may be estimated or ignored. A good starting point for determining what is a
minor loss might be a value less than 1% of the total gross steam output. The steam
temperature, pressure, and flow rate values should, at a minimum, be recorded as
hourly averages in a datalogger.
2. Gross Thermal Output under the Simplified Approach.
Monitoring locations are described in Table SA-2, columns 4 and 5 for a source monitoring
only gross thermal output (p. 73). Under this approach, companies would measure the energy in
steam leaving the boiler only to determine gross thermal output, in mmBtuout. Companies would not
need to measure the energy in hot water reentering the boiler in the boiler feedwater return. This
approach requires a source to determine the energy in the steam using the procedure below:
Step 1:
Step 2:
Step 3:
Step 4:
For saturated steam, measure or estimate the pressure of each stream of steam leaving
the boiler; temperature of saturated steam is determined by pressure. For superheated
steam, measure or estimate the pressure and temperature of each stream of steam
leaving the boiler.
Determine average hourly enthalpy (Btu/lb) from standard thermodynamic steam
tables17 for each stream of steam. (See section VIE., "How do I calculate output data
from supporting data?", pp. 138-141, for examples of how to do this.)
Measure or estimate each total hourly flow of steam or hot water (Ib).
Use flow and enthalpy to determine the energy in the steam or hot water in mmBtu.
17 Same as footnote 16.
Final EPA Guidance Document
May 8, 2000
Page 76
Developing and Updating Output-Based
NOx Allowance Allocations
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Section VI. C.: How could sources monitor thermal output at a steam generator?
7- / D< \ ,,(mmBtu} ( x
Estm(mmBtu) = H^——J x Q(lb)
Where:
Estm = total thermal energy in steam or water for an hour
H = enthalpy from standard thermodynamic steam table
Q = total mass flow of steam or water for an hour
Step 5: Determine the gross thermal output energy (mmBtuout) as the total energy out of the
boiler.
Note that steps 2 through 5 are the same as steps 2 through 5 for determining net
thermal output in section VI.C.l., "Net Thermal Output under the Simplified
Approach" (p. 74-76)
Approaches for determining gross thermal output:
Primary approach: a. Measuring gross thermal output directly. In the most basic case, a company
would measure the energy leaving a boiler. The company would measure the
output thermal energy of each flow of steam or water out of the boiler (See
Table SA-2, column 4)
gross j stm
Boiler thermal energy out
Where:
Eg,^ is the gross thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Boiler thermal energy out" is each location where thermal energy leaves the boiler.
(Locations BSt in Figures 2 and 3 and RStO in Figure 3)
Alternative: b. Determining gross thermal output by measuring net output. In the case where a
facility sells steam to a non-affiliated source under contract and wishes to use the
output monitoring system associated with these sales to estimate gross output, the
gross thermal output may be estimated as either: (a) the sales of steam converted to
mmBtu using flow and the steam tables, or (b) the sales of steam converted to
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 77 NOx Allowance Allocations
-------
Section VI. C.: How could sources monitor thermal output at a steam generator?
mmBtu plus any other measured steam not sold (See Table SA-2, column 5). Note
that in the case of steam sales if hourly data is recorded for billing purposes, this
record should serve as the official record of output and additional data recording in
a datalogger is not necessary.
= y
gross ^j stm
Thermal energy sold
or
77 _ 77 i 77
gross ~ L^ stm L^ stm
Thermal energy sold Parasitic or house thermal loads
Where:
Eg,.^ is the gross thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Thermal energy sold" is the number of places where steam or thermal energy is sold by the
plant (Location SSt in Figures 2 and 3)
"Parasitic or house thermal loads" is each location where the source measures or determines
losses of thermal energy from parasitic (auxiliary) or house thermal loads. (Locations HSt
and PSt in Figures 2 and 3)
Under this approach, you should require monitoring of the flow and pressure, and
temperature for superheated steam, for each of the major streams leaving the boiler.
The energy of small streams or the effects of very minor losses such as small steam
leaks may be estimated or ignored. A good starting point for determining what is a
minor loss might be a value less than 1% of the total gross steam output. The steam
temperature, pressure, and flow rate values should, at a minimum, be recorded as
hourly averages in a datalogger.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 78 NOx Allowance Allocations
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Section VI. C.: How could sources monitor thermal output at a steam generator?
Monitoring example for a steam generator under the simplified approach (see Figure 2. p. 71)
This is an example of a very simple steam boiler with the ability to measure the gross steam out at
a single location (presumably at the boiler outlet). See Table SA-2, p. 73.
The company could measure or estimate thermal output as follows:
• Primary approach for net thermal output: Net thermal output measured directly would be
(USt+SSt) (Table SA-2, column 6).
Net thermal output determined as gross thermal output less parasitic and house steam
loads would be (BSt-PSt-HSt) (Table SA-2, column 7).
• Primary approach for gross thermal output: Gross thermal output measured directly (Table
SA-2, column 4) would be BSt (Table SA-2, column 4).
Gross thermal output estimated as net output would be USt+SSt (Table SA-2, column 6).
• Gross thermal output measured as net thermal output plus parasitic and house loads would
be (USt+SSt+PSt+HSt) (Table SA-2, column 5).
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 79 NOx Allowance Allocations
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Section VI. C.: How could sources monitor thermal output at a steam generator?
Monitoring example for a steam generator with steam reheat under the simplified approach, (see
Figure 3. p. 72)
This is an example of a more sophisticated steam boiler where the boiler has a steam reheat cycle.
In this case, the boiler has two steam headers from which thermal output must be measured. The
monitoring is similar to that in Figure 2 with additional monitoring required at the inlet and outlet
of the steam reheat cycle. See Table SA-2, p. 73.
The company could measure or estimate thermal output as follows:
• Primary approach for net thermal output: Net thermal output measured directly would be
(USt+SSt-RStI) (Table SA-2, column 6).
Net thermal output determined as gross thermal output less losses would be (BSt+RStO-
RStl-PSt-HSt) (Table SA-2, column 7).
• Primary approach for gross thermal output: Gross thermal output measured directly would
be BSt+RStO-RStI (Table SA-2, column 4).
Gross thermal output measured as net thermal output would be USt+SSt-RStI (Table SA-2,
column 5).
• Gross thermal output measured as net thermal output plus parasitic and house loads would
be USt+SSt+PSt+HSt-RStI (Table SA-2, column 5).
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 80 NOx Allowance Allocations
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Heat Input
Make Up
Water (MOW)
Figure 2
Steam Generator
Boiler
Boiler Feedwater
Return (BFR)
Boiler
Out (BSt)
(USt+SSt)
Useful
Steam
Loads
(XSt)
Page 81
-------
Figure 3
Steam Generator
(Industrial Boiler with Steam Reheat)
Heat
Input
>
A
Boi
i
Make Up
Water (MOW)
ler
f
•I
Boiler Steam Out (BSt)
i(USt
.
Into Boiler (RStI)
^ Useful
(XSt) Load
Reheat Steam Out (RStO)
^-
+ SSt)
1 (USt
Boiler ]
Retui
Useful
Load
(PSt + HSt)
<
+ SSt)
1
(PSt + HSt)
r
Parasitic
and House
Steam
Loads
Feedwater |
-n (BFR) X (xst) i
r
Page 82
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Table BE-2 Monitoring Thermal Output Only from a Steam Generator under the Boiler Efficiency Approach
Overall System Description
In this column are the various
systems associated with
boilers and electric generators
as defined in the diagrams.
Column 1
Primary Steam System
Note: flow in feedwater return
and make up water must equal
steam out flow
Steam Return and Reheat System
Note: flow in reheat steam out
must equal flow in reheat steam
entering boiler
Useful Thermal Loads
Losses Associated with
Generation of Thermal Output
Possible Monitoring Locations
In this column are the specific points
which might need to be monitored
under different approaches.
The letter in the first column
corresponds to letters used on the
associated diagrams
2
BSt
BFR
MUW
RStO
RStI
ust
xst
sst
xst
PSt
HSt
3
Main boiler steam out
Boiler feedwater
return
Make up water
Reheat steam out
Steam returning to boiler for
reheating
Useful steam or hot water
entering a process
Steam or hot water exiting a
process
Steam sold at point of sale
Return condensate or steam
from buyer
Parasitic Steam Loads
House Steam Loads
Gross Thermal Output Using the Boiler
Efficiency Approach
Gross measured
directly (Primary)
4
Measure (+)
Measure or
estimate(-)
Measure or
estimate(-)
Measure (+)
Measure (-)
--
--
--
--
-
-
Net plus parasitic
and house loads
5
--
Measure or estimate
(-)
Measure or estimate
(-)
--
--
Measure (+)
--
Measure(+)
--
Measure (+)
Measure(+)
Net Thermal Output Using the Boiler
Efficiency Approach
Net measured
directly (Primary)
6
Measure (-)
Measure (-)
--
--
Measure(+)
--
Measure(+)
--
-
-
Gross less parasitic
and house loads
7
Measure (+)
Measure (-)
Measure (-)
Measure (+)
Measure (-)
--
--
--
--
Measure (-)
Measure (-)
Page 83
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Section VI. C.: How could sources monitor thermal output at a steam generator?
3. Net Thermal Output under the Boiler Efficiency Approach.
Net thermal output monitoring equipment locations are described in Table BE-2, columns
6 and 7 (p. 83) for industrial or institutional sources monitoring only net thermal output (non-
cogeneration). The basic approach is similar to that used for gross thermal output from a boiler,
except that the energy balance developed is around the useful steam, not the boiler. "Useful steam"
is steam (or hot water) used in a process that makes the product which is the purpose of the plant or
steam that the plant sells. In contrast, steam used to heat the steam plant is a house load and is not
considered "useful" because the source presumably would use that energy anyway, even if it were
not making its final product at that time. Also, any thermal energy used in the process of generating
the steam should not be considered net thermal output. In order to determine the energy in useful
steam, a source would follow these steps:
Step 1: Perform a mass balance on water and steam into each useful process (that is, each
process that makes the plant's product) and water and steam out of each useful
process. One would treat all steam sold as entering a useful process.
Step 2: For saturated steam, measure or estimate the pressure of each stream of steam or hot
water entering or leaving the useful process; temperature of saturated steam is
determined by pressure. For superheated steam, measure or estimate the pressure and
temperature of each stream of steam or hot water entering or leaving the useful
process.
Step 3: Determine average hourly enthalpy (Btu/lb) from standard thermodynamic steam
tables18 for each stream of steam or hot water. (See section VIE., "How do I calculate
output data from supporting data?", pp. 138-141, for examples of how to do this.)
Measure or estimate each total hourly flow of steam or hot water (Ib).
Use flow and enthalpy to determine the energy in the steam or hot water in mmBtu.
18 Same as footnote 16.
Final EPA Guidance Document
May 8, 2000
Page 84
Developing and Updating Output-Based
NOx Allowance Allocations
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Section VI. C.: How could sources monitor thermal output at a steam generator?
7- / D< \ J,mmBtu\ , x
Estm(mmBtu) = H^——-J x Q(lb)
Where:
Estm = total energy in steam or water for an hour
H = enthalpy from standard thermodynamic steam table
Q = total mass flow of steam or water for an hour
Step 6: Determine the net thermal output energy (mmBtu) as the total energy into any useful
process of the boiler less the energy out of the process.
Note that steps 3 through 6 are the same as steps 2 through 5 for determining net
thermal output in section VI.C.l., "Net Thermal Output under the Simplified
Approach" (p. 74-76).
Approaches for determining net thermal output:
Primary approach: a. Measuring net thermal output directly. In the case where a source uses steam
internally or sells steam to an outside party, the energy balance is developed
around all useful processes or sales. The company would measure the input
and output thermal energy of each flow or steam or water into and out of the
useful process (See Table BE-2, column 6)
77 _ X"1 17 _ X"1 17
net ~ L-l stm L-l stm
Themal energy in Thermal energy returning to boiler
Where:
Enet is the net thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Thermal energy in" is each location where thermal energy goes into a useful process.
(Locations USt and SSt in Figures 2 and 3)
"Thermal energy returning to boiler" is each location where thermal energy enters the boiler
in a return line. (Locations BFR in Figures 2 and 3 and RStI in Figure 3)
Note that this is a slightly different estimate of net thermal output than measuring the
steam or water exiting a process or returning from a sales agreement as described in
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 85 NOx Allowance Allocations
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Section VI. C.: How could sources monitor thermal output at a steam generator?
Step 6 above. In Step 6, there could be additional energy added to the condensate
from the house and parasitic loads that are not measured.
Alternative b. Determining net thermal output measuring gross output. In the case where a
facility measures the gross thermal output but does not measure the net steam
directly, it is permissible to allow the source to determine net output as the
gross steam less parasitic and house steam loads. In some cases it might be
easier or more cost-effective to add monitors to measure or estimate the
parasitic and house loads rather than installing a complete net output
monitoring system to take account of thermal energy in and out of such loads.
(See Table BE-2, column 7).
net ~ Zj stm Zj stm Zj stm
Boiler thermal energy out Parasitic and house thermal loads Thermal energy returning to boiler
Where:
Enet is the net thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Boiler thermal energy out" is each location where thermal energy leaves the boiler.
(Locations BSt in Figures 2 and 3 and RStO in Figure 3)
"Parasitic and house thermal loads" is each location where the source measures or determines
losses of thermal energy from parasitic (auxiliary) or house thermal loads. (Locations PSt and
HSt in Figures 2 and 3)
"Thermal energy returning to boiler" is each location where thermal energy enters the boiler
in a return line. (Locations BFR in Figures 2 and 3 and RStI in Figure 3)
Under this approach, you should require monitoring of the flow and pressure, and
temperature for superheated steam for each of the maj or streams entering and leaving
the boiler. The energy of small streams or the effects of very minor losses such as
small steam leaks may be estimated or ignored. A good starting point for
determining what is a minor loss might be a value less than 1% of the total gross
steam output. The steam temperature, pressure, and flow rate values should, at a
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 86 NOx Allowance Allocations
-------
Section VI. C.: How could sources monitor thermal output at a steam generator?
minimum, be recorded as hourly averages in a datalogger.
4. Gross Thermal Output under the Boiler Efficiency Approach.
Monitoring locations are described in Table BE-2, columns 4 and 5 for a source monitoring
only gross thermal output (p. 83). Under this approach, boilers would measure the energy imparted
to the steam from combustion to determine gross thermal output, in mmBtuout. This approach
requires a source to determine the energy imparted to the steam from combustion using the procedure
below:
Step 1: Perform a mass balance on water and steam into the boiler and water and steam out
of the boiler.
Step 2: For saturated steam, measure or estimate the pressure of each stream of steam or hot
water entering or leaving the boiler; temperature of saturated steam is determined by
pressure. For superheated steam, measure or estimate the pressure and temperature
of each stream of steam or hot water entering or leaving the boiler.
Step 3: Determine average hourly enthalpy (Btu/lb) from standard thermodynamic steam
tables19 for each stream of steam or hot water. (See section VIE., "How do I
calculate output data from supporting data?", pp. 138-141, for examples of how to
do this.)
Measure or estimate each total hourly flow of steam or hot water (Ib).
Use flow and enthalpy to determine the energy in the steam or hot water in mmBtu.
I? I Df \ TT(mmBtu] i x
Estm(mmBtu) = H^——J x Q(lb]
Where:
Estm = total thermal energy in steam or water for an hour
H = enthalpy from standard thermodynamic steam table
Q = total mass flow of steam or water for an hour
Determine the gross thermal output energy (mmBtuout) as the total energy out of the
boiler less the energy into the boiler.
Note that steps 3 through 6 are the same as steps 3 through 6 for determining net
19
Same as footnote 16.
Final EPA Guidance Document
May 8, 2000
Page 87
Developing and Updating Output-Based
NOx Allowance Allocations
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Section VI. C.: How could sources monitor thermal output at a steam generator?
thermal output in section VI.C.3., "Net Thermal Output under the Boiler Efficiency
Approach" (p. 84-86) and steps 2 through 5 for determining gross thermal output in
section VI.C.2., "Gross Thermal Output under the Simplified Approach" (p. 76-78).
Approaches for determining gross thermal output:
Primary approach: a. Measuring gross thermal output directly. In the most basic case, a company
would develop an energy balance around a boiler. The company would
measure the input and output thermal energy of each flow of steam or water
into and out of the boiler (See Table BE-2, column 4)
Y F Y
L^ stm L^
gross ^ stm ^ stm
Boiler thermal energy out Thermal energy returning to boiler
Where:
£^3 is the gross thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Boiler thermal energy out" is each location where thermal energy leaves the boiler.
(Locations BSt in Figures 2 and 3 and RStO in Figure 3)
"Thermal energy returning to boiler" is each location where thermal energy enters the boiler
in a return line. (Locations BFR in Figures 2 and 3 and RStI in Figure 3)
Alternative b. Determining gross thermal output by measuring net output. In the case where
a facility sells steam to a non-affiliated source under contract and wishes to
use the output monitoring system associated with these sales to estimate gross
output, the gross thermal output may be estimated as either: (a) the sales of
steam converted to mmBtu using flow and the steam tables minus the input
energy to the boiler in the return condensate or make up water, or (b) the sales
of steam converted to mmBtu plus any other measured steam not sold minus
the input energy to the boiler in the return condensate and make-up water
(See Table BE-2, column 5). Note that in the case of steam sales if hourly
data is recorded for billing purposes, this record should serve as the official
record of output; thus, additional data recording in a datalogger is not
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 88 NOx Allowance Allocations
-------
Section VI. C.: How could sources monitor thermal output at a steam generator?
necessary.
gross Lu stm Lu stm
Thennal energy sold Thermal energy returning to boiler
or
^ gross ~ Zj *^ stm + Zj ^ stm ~ Zj ^ stm
Thermal energy sold Parasitic or house thermal loads Thermal energy returning to boiler
Where:
Eg,^ is the gross thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Thermal energy sold" is the number of places where steam or thermal energy is sold by the
plant (Location SSt in Figures 2 and 3)
"Parasitic or house thermal loads" is each location where the source measures or determines
losses of thermal energy from parasitic (auxiliary) or house thermal loads. (Locations HSt
and PSt in Figures 2 and 3)
"Thermal energy returning to boiler" is each location where thermal energy enters the boiler
in a return line. (Locations BFR in Figures 2 and 3 and RStI in Figure 3)
Under this approach, you should require monitoring of the flow and pressure, and
temperature for superheated steam for each of the major streams entering or leaving
the boiler. The energy of small streams or the effects of very minor losses such as
small steam leaks may be estimated or ignored. A good starting point for
determining what is a minor loss might be a value less than 1% of the total gross
steam output. Sources may also rely on the conservation of mass in monitoring flow.
In practice, this is done by measuring the flow of water or steam into a boiler and
assuming that the flow out is equal, as it must be under steady-state conditions. The
steam temperature, pressure, and flow rate values should, at a minimum, be recorded
as hourly averages in a datalogger.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 89 NOx Allowance Allocations
-------
Section VI. C.: How could sources monitor thermal output at a steam generator?
Monitoring example for a steam generator under the boiler efficiency approach (see Figure 2. p. 81)
This is an example of a very simple steam boiler with the ability to measure the gross steam out at
a single location (presumably at the boiler outlet). See Table BE-2, p. 83.
The company could measure or estimate thermal output as follows:
• Primary approach for net thermal output: Net thermal output measured directly would be
(USt+SSt-BFR-MUW) (Table BE-2, column 6).
Net thermal output determined as gross thermal output less parasitic and house steam
loads would be (BSt-BFR-MUW-PSt-HSt) (Table BE-2, column 7).
• Primary approach for gross thermal output: Gross thermal output measured directly (Table
BE-2, column 4) would be BSt-BFR-MUW (Table BE-2, column 4).
Gross thermal output estimated as net output would be USt+SSt-BFR-MUW (Table BE-2,
column 6).
• Gross thermal output measured as net thermal output plus parasitic and house loads would
be (USt+SSt+PSt+HSt-BFR-MUW) (Table BE-2, column 5).
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 90 NOx Allowance Allocations
-------
Section VI. C.: How could sources monitor thermal output at a steam generator?
Monitoring example for a steam generator with steam reheat under the boiler efficiency approach.
(see Figure 3. p. 82)
This is an example of a more sophisticated steam boiler where the boiler has a steam reheat cycle.
In this case, the boiler has two steam headers from which thermal output must be measured. The
monitoring is similar to that in Figure 2 with additional monitoring required at the inlet and outlet
of the steam reheat cycle. See Table BE-2, p. 83.
The company could measure or estimate thermal output as follows:
• Primary approach for net thermal output: Net thermal output measured directly would be
(USt+SSt-BFR-MUW-RStl) (Table BE-2, column 6).
Net thermal output determined as gross thermal output less losses would be (BSt+RStO-
BFR-MUW-RStl-PSt-HSt) (Table BE-2, column 7).
• Primary approach for gross thermal output: Gross thermal output measured directly would
be BSt+RStO-BFR-MUW-RStI (Table BE-2, column 4).
Gross thermal output measured as net thermal output would be USt+SSt-BFR-MUW-RStl
(Table BE-2, column 5).
• Gross thermal output measured as net thermal output plus parasitic and house loads would
be USt+SSt+PSt+HSt-BFR-MUW-RStI (Table BE-2, column 5).
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 91 NOx Allowance Allocations
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Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
D. How could sources monitor electric and thermal output at a cogeneration facility?
Your State rule should require that cogeneration or combined heat and power (CHP) sources
monitor both electric output and thermal output when a facility produces electricity and steam. You
must also decide whether net or gross output should be monitored. You could allow sources to
monitor a combination of net and gross output. These combinations are described in tables in this
section20: monitoring net electric and net thermal output (Tables SA-4 and BE-4, pp. 98-99, 120-
121); monitoring gross thermal and gross electric output (Tables SA-3 and BE-3, pp. 96-97, 118-
119); and monitoring net electric and gross thermal output (Tables SA-5 and BE-5, pp. 100-101,
122-123).
Note that throughout this section for cogeneration facilities, the maj or difference between the
simplified approach and the boiler efficiency approach is that under the simplified approach, it is not
necessary to measure the thermal energy in the boiler feedwater return, the make up water to the
boiler, condensate returned by a buyer, or the steam exiting a useful process. We have simplified
the diagrams and discussion for cogeneration facilities by not including extra steam return to a boiler
for reheating. However, in a situation including steam reheating, the source would need to measure
the return line and the reheated steam exiting the boiler when measuring gross thermal output. The
source also would need to measure the return line entering the boiler when measuring net thermal
output.
20We also considered the possibility of measuring net thermal output and gross electric
output. However, we decided that this was not a likely combination. Since it appears to be
possible for sources to determine net electric output in all cases, a State is likely choose to
require sources to determine gross electric output for policy reasons, rather than for practical
reasons, and to require gross thermal output for the same policy reasons.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 92 NOx Allowance Allocations
-------
FIGURE4 Steam Cogeneratcr
Figure 4
Steam Cogenerator
Heat
Input
Boiler
Boiler
Steam
Out (BSt)
(ESt)
(PSt)
Steam
Turbine
Parasitic
and house
electric
loads
(PE+HE)
House electric
loads from grid
OEO or OEN
(GE)
Gross
electric
(SE + UE)
Useful
Electric
Load
Parasitic
Steam
Loads
(XTSt)
(PSt) (USt
+ SSt)
Useful
Steam
Loads
(HSt)
House
Steam
Loads
Make Up
Water (MUW)
(XSt)
Boiler Feedwater
Return (BFR)
Page 93
-------
FIGURE 5 Combustioi
Figure 5
Combustion Turbine Cogenerator
Electric from outside plant OEO or OEN
Gross Electric (GE)
(PE)
Combustion
Turbine
v
(HE)
(UE + SE)
Heat Input
Parasitic Electric
Loads
Steam
Out (BSt)
Make Up
Water (MUW)
HRSG Feedwater
Return (BFR)
(USt + SSt)
(XSt
Page 94
-------
FIGURE 6
Cogenerator
Figure 6
Combined Cycle Cogenerator
Electric from outside plant OEO or OEN
(XSt)
Make Up
Water (MUW)
HRSG Feedwater
Return (BFR)
Page 95
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Table SA-3, Monitoring Cogenerator for Gross Electric Output and Gross Thermal Output under the Simplified Approach
Overall System Description
In this column are the various
systems associated with boilers
and electric generators as defined
in the diagrams
Column 1
Primary Steam System
Note: flow in feed water return and
make up water must equal steam out
flow
Steam Return and Reheat System
Note: flow in reheat steam out must
equal flow in reheat steam entering
boiler
Steam Used to Generate Electric
Power in a Steam Turbine
Useful Thermal Loads
Losses Associated with Generation of
Thermal Output
Possible Monitoring Locations
In this column are the specific
points which might need to be
monitored under different
approaches.
The letter in the first column
corresponds to letters used on
the associated diagrams
2
BSt
BFR
MUW
RStO
RStI
ESt
XTSt
ust
xst
sst
xst
PSt
HSt
3
Main boiler steam out
Boiler feedwater
return
Make up water
Reheat steam out
Steam returning to boiler
for reheating
Steam entering a turbine
Steam exhaust from a
turbine
Useful steam or hot water
entering a process
Steam or hot water exiting
a process
Steam sold at point of sale
Return condensate or
steam from buyer
Parasitic steam loads
House steam loads
Gross Thermal Output for Allocation
Gross thermal
output
measured
directly at exit
from steam
turbine
(Primary)
4
-
Gross thermal
output
measured
directly at
HRSG/boiler
less steam used
for electric
generation
5
Measure(+)
Net thermal
output plus
parasitic and
house loads
less steam
used for
electric
generation
6
-
Gross thermal
output
measured
directly at
HRSG/boiler
less equivalent
electric output
inmmBtu.
7
Measure(+)
Gross Electric Output
Gross
electric
output
measured
directly
(Primary)
8
-
Net electric
output plus
parasitic and
hours loads
9
-
Not monitored under simplified approach
Not monitored under simplified approach
Measure(+)
Measure(-)
-
Measure (+)
-
Measure(+)
Measure(-)
Measure(-)
Measure (+)
-
-
-
-
-
Measure (+)
Measure(+)
Measure(-)
-
-
-
-
-
-
-
-
-
-
-
-
-
Not monitored under simplified approach
-
-
Measure (+)
-
-
-
Not monitored under simplified approach
-
-
-
-
Measure (+)
Measure (+)
-
-
-
-
-
-
Page 96
-------
Table SA-3, Monitoring Cogenerator for Gross Electric Output and Gross Thermal Output under the Simplified Approach
Overall System Description
In this column are the various
systems associated with boilers
and electric generators as defined
in the diagrams
Column 1
Electric Generation
Electric Power Used on Site Not
Generated by the Facility
Losses Associated with
Generation of Electricity
Possible Monitoring Locations
In this column are the specific
points which might need to be
monitored under different
approaches.
The letter in the first column
corresponds to letters used on
the associated diagrams
2
GE
SE
UE
OEO
OEN
PE
HE
3
Electric power
measured at generator
terminals
Electric power leaving
plant to electric grid
Electric power used
internal to a
cogenerator or
industrial facility for a
useful purpose
Electric power coming
from grid or other
power source to plant
during operation
Electric power coming
from grid or other
source during non
operation
Parasitic electric loads
House electric loads
Gross Thermal Output for Allocation
Gross thermal
output
measured
directly at exit
from steam
turbine
(Primary)
4 con't
--
--
"
-
-
Gross thermal
output
measured
directly at
HRSG/boiler
less steam used
for electric
generation
5 con't
--
--
"
-
-
Net thermal
output plus
parasitic and
house loads
less steam
used for
electric
generation
6 con't
--
--
-
-
Gross thermal
output
measured
directly at
HRSG/boiler
less equivalent
electric output
inmmBtu.
7 con't
Measure and
convert to
mmBtu (-)
-
-
-
Gross Electric Output
Gross
electric
output
measured
directly
(Primary)
8 con't
Measure
(+)
--
-
-
Net electric
output plus
parasitic and
hours loads
9 con't
-
Measure (+)
Measure (+)
Measure (-)
Measure (+)
Measure (+)
Page 97
-------
Table SA-4, Monitoring Cogenerator (CHP) for Net Electric Output and Net Thermal Output under the Simplified Approach
Overall System Description
In this column are the
various systems associated
with boilers and electric
generators as defined in the
diagrams
Column 1
Primary Steam System
Note: flow in feed water return
and make up water must equal
steam out flow
Steam Return and Reheat
System
Note: flow in reheat steam out
must equal flow in reheat
steam entering boiler
Steam Used to Generate
Electric Power in a Steam
Turbine
Useful Thermal Loads
Losses Associated with
Generation of Thermal Output
Possible Monitoring Locations
In this column are the specific
points which might need to be
monitored under different
approaches.
The letter in the first column
corresponds to letters used on the
associated diagrams
2
BSt
BFR
MUW
RStO
RStI
ESt
XTSt
ust
xst
sst
xst
PSt
HSt
3
Main boiler steam out
Boiler feedwater
return
Make up water
Reheat steam out
Steam returning to boiler for
reheating
Steam entering a turbine
Steam exhaust from a turbine
Useful steam entering a
process
Steam or hot water exiting a
process
Steam sold at point of sale
Return condensate or steam
from buyer
Parasitic steam loads
House steam loads
Net Thermal Output for Allocation
Net thermal
output
measured
directly less
steam used
for electric
generation
(Primary)
4
-
Gross
thermal
output from
exit of steam
turbine less
parasitic and
house loads
5
-
Gross thermal
output from
HRSG/boiler
less parasitic
and house loads
less steam used
for electric
generation
6
Measure (+)
Measure gross thermal
output from
HRSG/boiler less
parasitic loads, house
loads, return feedwater
and equivalent electric
output expressed in
mmBtu.
7
Measure (+)
Net Electric Output
Net
electric
output
measured
directly
(Primary)
8
-
Gross
electric
output less
parasitic
and hours
loads
9
-
Not monitored under the simplified approach
Not monitored under the simplified approach
-
-
Measure (-)
-
Measure (+)
Measure (+)
Measure (-)
-
Measure (+)
-
Measure (+)
Measure (-)
Measure (-)
-
-
Measure (+)
Measure (-)
-
-
-
-
-
-
-
-
-
-
-
-
-
Not monitored under the simplified approach
Measure (+)
-
-
-
-
-
Not monitored under the simplified approach
-
-
Measure (-)
Measure (-)
Measure (-)
Measure (-)
Measure (-)
Measure (-)
-
-
-
-
Page 98
-------
Table SA-4, Monitoring Cogenerator (CHP) for Net Electric Output and Net Thermal Output under the Simplified Approach
Overall System Description
In this column are the
various systems associated
with boilers and electric
generators as defined in the
diagrams
Column 1
Electric Generation
Electricity Used on Site
Not Generated by the
Facility
Losses Associated with
Generation of Electricity
Possible Monitoring Locations
In this column are the specific
points which might need to be
monitored under different
approaches.
The letter in the first column
corresponds to letters used on the
associated diagrams
2
GE
SE
UE
OEO
OEN
PE
HE
3
Electric power measured
at generator terminals
Electric power leaving
plant to electric grid
Electric power used
internal to a cogenerator
or industrial facility for a
useful purpose
Electric power coming
from grid or other power
source to plant during
operation
Electric power coming
from grid or other source
during non operation
Parasitic electric loads
House electric loads
Net Thermal Output for Allocation
Net thermal
output
measured
directly less
steam used
for electric
generation
(Primary)
4 con't
--
--
—
--
--
Gross
thermal
output from
exit of steam
turbine less
parasitic and
house loads
5 con't
--
--
—
--
--
Gross thermal
output from
HRSG/boiler
less parasitic
and house loads
less steam used
for electric
generation
6 con't
--
--
—
--
--
Measure gross thermal
output from
HRSG/boiler less
parasitic loads, house
loads, return feedwater
and equivalent electric
output expressed in
mmBtu.
7 con't
Measure and convert to
mmBtu (-)
--
—
--
--
Net Electric Output
Net
electric
output
measured
directly
(Primary)
8 con't
--
Measure
(+)
Measure
(+)
Measure
(-)
-
--
--
Gross
electric
output less
parasitic
and hours
loads
9 con't
Measure (+)
-
Measure
(-)
—
Measure
(-)
Measure
(-)
Page 99
-------
Table SA-5, Monitoring Cogen (CHP) for Net Electric Output and Gross Thermal Output under the Simplified Approach
Overall System Description
In this column are the various
systems associated with boilers
and electric generators as
defined in the diagrams
Column 1
Primary Steam System
Note: flow in feed water return and
make up water must equal steam out
flow
Steam Return and Reheat System
Note: flow in reheat steam out must
equal flow in reheat steam entering
boiler
Steam Used to Generate Electric
Power in a Steam Turbine
Useful Thermal Loads
Losses Associated with Generation
of Thermal Output
Possible Monitoring Locations
In this column are the specific
points which might need to be
monitored under different
approaches.
The letter in the first column
corresponds to letters used on the
associated diagrams
2
BSt
BFR
MUW
RStO
RStI
ESt
XTSt
ust
xst
sst
xst
PSt
HSt
3
Main boiler steam out
Boiler feedwater
return
Make up water
Reheat steam out
Steam returning to boiler
for reheating
Steam entering a turbine
Steam exhaust from a
turbine
Useful steam entering a
process
Steam or hot water exiting a
process
Steam sold at point of sale
Return condensate or steam
from buyer
Parasitic steam loads
House steam loads
Gross Thermal Output for Allocation
Gross
thermal
output
measured
directly from
exit of steam
turbine
(Primary)
4
-
Gross thermal
output
measured
directly from
HRSG/boiler
less steam used
for electric
generation
5
Measure(+)
Net thermal
output plus
parasitic and
house loads
less steam
used for
electric
generation
6
-
Gross thermal
output measured
directly from
HRSG/boiler less
equivalent net
electric output in
mmBtu.
7
Measure(+)
Net Electric Output
Net electric
output
measured
directly
(Primary)
8
-
Gross
electric
output less
parasitic
and house
loads
9
-
Not monitored under the simplified approach
Not monitored under the simplified approach
Measure(+)
Measure(-)
-
Measure (+)
-
Measure(+)
Measure(-)
Measure(-)
Measure (+)
-
-
-
-
-
Measure (+)
Measure(+)
Measure(-)
-
-
-
-
-
-
-
-
-
-
-
-
-
Not monitored under the simplified approach
-
-
Measure (+)
-
-
-
Not monitored under the simplified approach
-
-
-
-
Measure (+)
Measure (+)
-
-
-
-
-
-
Page 100
-------
Table SA-5, Monitoring Cogen (CHP) for Net Electric Output and Gross Thermal Output under the Simplified Approach
Overall System Description
In this column are the various
systems associated with boilers
and electric generators as
defined in the diagrams
Column 1
Electric Generation
Electric Power Used on Site Not
Generated by the Facility
Losses Associated with Generation
of Electricity
Possible Monitoring Locations
In this column are the specific
points which might need to be
monitored under different
approaches.
The letter in the first column
corresponds to letters used on the
associated diagrams
2
GE
SE
UE
OEO
OEN
PE
HE
3
Electric power measured at
generator terminals
Electric power leaving plant
to electric grid
Electric power used internal
to a cogenerator or
industrial facility for a
useful purpose other than
generation of electricity
Electric power coming from
grid or other power source
to plant during operation
Electric power coming from
grid or other source during
non operation
Parasitic electric loads
House electric loads
Gross Thermal Output for Allocation
Gross
thermal
output
measured
directly from
exit of steam
turbine
(Primary)
4 con't
-
-
—
-
-
-
Gross thermal
output
measured
directly from
HRSG/boiler
less steam used
for electric
generation
5 con't
-
-
—
-
-
-
Net thermal
output plus
parasitic and
house loads
less steam
used for
electric
generation
6 con't
-
-
-
-
-
-
Gross thermal
output measured
directly from
HRSG/boiler less
equivalent net
electric output in
mmBtu.
7 con't
Measure and
convert to mmBtu
(-)
-
—
-
-
-
Net Electric Output
Net electric
output
measured
directly
(Primary)
8 con't
-
Measure (+)
Measure (+)
Measure (-)
-
-
-
Gross
electric
output less
parasitic
and house
loads
9 con't
Measure (+)
-
Measure
(-)
-
Measure
(-)
Measure
(-)
Page 101
-------
Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
1. Monitoring Electric Output
Primary approach: a. Monitoring net electric output: A source which is required to monitor net
electric output would measure the output in exactly the same manner as
described in section VI.B.l., "NetElectric Output" (pp. 63-65). (See Table
SA-4, columns 8 and 9, pp. 98-99).
Primary approach: b. Measuring gross electric output. A source which is required to monitor gross
electric output would measure the output in exactly the same manner as
described in section VLB.2., "Gross Electric Output" (pp. 65-66). (See
Table SA-3, columns 8 and 9, pp. 96-97).
2. Monitoring Net Thermal Output under the Simplified Approach
It is important to remember that the net thermal output used for allocations is the thermal
output used to perform useful work in a process excluding thermal output used to generate
electricity. This is referred to as "net thermal output for allocation" to distinguish it from "net
thermal output" which includes thermal output used in electric generation. (See Table SA-4, pp. 98-
99).
Primary approach: a. Measuring net thermal output directly. A cogeneration facility which is
required to determine the net thermal output for allocation may measure the
useful thermal output directly. Monitoring net thermal output directly is
similar to monitoring net thermal output for allocation for a steam generator,
with the additional requirement that thermal energy used to generate
electricity would not be included as net thermal output. In general, a
company would measure the thermal energy going into each useful process
and then calculate the net thermal energy as the sum of the thermal energy
going into the useful processes (Table SA-4, column 4).
*-"stm
Thermal energy for a useful process
Where:
Enet is the net thermal output
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 102 NOx Allowance Allocations
-------
Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
Estm is the thermal energy in steam or hot water measured at a location
"Thermal energy for a useful process" is the number of places where thermal energy is used
to make a product for sale other than electricity or other useful application of steam
(excluding generation of steam itself) (Locations USt and SSt in Figures 4, 5, and 6)
Alternative b. Determining net thermal output measuring gross thermal output. A cogeneration or
CHP facility which is required to monitor net thermal output, which has an existing
gross thermal output system ,and which does not have a system for measuring net
output directly may determine the net thermal output as the gross thermal output after
the steam turbine and generator less parasitic and house thermal loads (Table SA-4,
column 5). (This is appropriate for steam cogenerators and combined cycle
cogenerators where thermal energy is used in a process downstream of a steam
turbine and generator, as in Figures 4 and 6.)
stm
Thermal energy exiting
the steam turbine
y
L^
stm
Parasitic and house thermal loads
Where:
Enet is the net thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Thermal energy exiting the steam turbine" is each location where thermal energy leaves a
steam turbine that is connected to the unit. (Location XTSt in Figures 4 and 6)
"Parasitic and house thermal loads" is each location where the source measures or
determines losses of thermal energy from parasitic (auxiliary) or house thermal loads.
(Location HSt and PSt in Figures 4, 5, and 6)
Alternative
c. Measuring gross thermal output directly from the boiler less steam for electric
generation. For combustion turbine cogenerators, or for the less common
situation where some thermal energy is used in a process upstream of a steam
Final EPA Guidance Document
May 8, 2000
Page 103
Developing and Updating Output-Based
NOx Allowance Allocations
-------
Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
turbine and generator, a source might monitor gross thermal output from the
boiler, minus the thermal output going to electric generation. In this case, a
cogeneration facility which is required to monitor net thermal output and
which does not have a system for measuring net output directly may
determine the net thermal output as the gross thermal output from the heat
recovery steam generator (HRSG) or boiler less house thermal loads, parasitic
thermal loads, and boiler feedwater and the steam used for electric generation
in a steam turbine and generator (Table SA-4, column 6).
net ~ L~l stm ~ L~l stm ~ L~l stm
Boiler thermal energy out Parasitic and house thermal loads Thermal energy used
for electric generation
Where:
Enet is the net thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Boiler thermal energy out" is each location where thermal energy leaves the boiler or
HRSG. (Location BSt in Figures 4, 5, and 6)
"House and parasitic thermal loads" is each location where the source measures or
determines losses of thermal energy from parasitic (auxiliary) or house thermal loads.
(Location HSt and PSt in Figures 4, 5, and 6)
"Thermal energy used for electric generation" is each location where thermal energy goes
into a steam turbine to operate an electric generator. (Location EStin Figures 4 and 6)
Alternative (special case)
d. Measuring gross thermal output from boiler less equivalent electric output. For the
less common situation where some thermal energy is used in a process upstream of
a steam turbine and generator, sources might monitor gross thermal output from the
boiler, including thermal output for electric generation. For a cogeneration facility
in this situation which is required to determine both net electric output for allocations
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 104 NOx Allowance Allocations
-------
Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
and net steam for output allocations that does not monitor net output directly, the net
thermal output may be determined as follows. The source would measure the gross
thermal output from the HRSG or boiler, less the parasitic and house thermal loads,
and less the gross electric output from the generator converted to equivalent steam
energy using the design steam turbine generator efficiency (See Table S A-4, column
7). Note that when converting electric power to an equivalent steam load to deduct
from the net thermal output, a source would convert the gross electric output, not the
net electric output, to an equivalent thermal output.
.413
F } F - > F - > F
^ ~ ^stm /_< ^stm ^
Boiler thermal energy out Parasitic and house thermal loads Converted gross electrical output (JCalgil IU1 UlllC
efficiency
Where:
Enet is the net thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Boiler thermal energy out" is each location where thermal energy leaves the boiler or
HRSG. (Location BSt in Figure 4, 5, and 6)
"Parasitic and house thermal loads" is each location where the source measures or determines
losses of thermal energy from parasitic (auxiliary) or house thermal loads. (Locations PSt
and HSt in Figures 4, 5, and 6)
"Converted electric energy" is the thermal energy for each location where thermal energy
goes into a steam turbine to operate an electric generator. It is calculated by "converting" the
gross electric output to thermal energy. (Location GE in Figures 4, 5, and 6)
"3.413/Design turbine efficiency" is the conversion factor in mmBtu/MWh, calculated using
the manufacturer's design efficiency expressed as a decimal.
3. Monitoring Gross Thermal Output under the Simplified Approach .
It is important to remember that the gross thermal output used for allocations is the total gross
thermal output of the boiler (gross thermal output) less the output used for generation of electricity
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 105 NOx Allowance Allocations
-------
Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
(we refer to this as "gross thermal output for allocation"). (Thermal energy used to generate
electricity will receive an allocation indirectly through the allocation of allowances for electric
output.)
Primary approach for steam cogenerators and combined cycle systems:
a. Measuring gross thermal output directly at the exit from a steam turbine: One method
for monitoring gross thermal output for allocation would be to measure thermal
energy remaining after steam has exited the steam turbine. (This is appropriate for
steam cogenerators and combined cycle cogenerators where thermal energy is used
in a process downstream of a steam turbine and generator, as in Figures 4 and 6. See
Table SA-3, column 4.)
E = YE
allocation L^
stm
Thermal energy exiting
the steam turbine
Where:
Eaiiocation is the gross thermal output for allocation
Estm is the thermal energy in steam or hot water measured at a location
"Thermal energy exiting the steam turbine" is each location where thermal energy leaves a
steam turbine that is connected to the unit. (Location XTSt in Figures 4 and 6)
Primary approach for combustion turbine cogenerators:
b. Measuring gross thermal output directly from the boiler less steam for electric
generation. For combustion turbine cogenerators, or for the less common situation
where some thermal energy is used in a process upstream of a steam turbine and
generator, another method for monitoring gross thermal output for allocations may
be appropriate. In this case, monitoring gross thermal output for allocation directly
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 106 NOx Allowance Allocations
-------
Section VI. D. : How could sources monitor electric and thermal output at a cogeneration facility? _
would be similar to monitoring gross thermal output for allocation for a steam
generator, with the additional requirement that the thermal output used to generate
electricity would be deducted from the gross thermal output. (See section VI. C. 4.,
"Gross Thermal Output under the Boiler Efficiency Approach", pp. 87-89, for a
description of the basic energy balance approach used.) Deducting the gross thermal
energy used to generate electricity may require additional monitoring of the steam
used to generate electricity to determine the gross thermal output for allocation
(Table SA-3, Column 5, pp. 96-97):
E = YE
allocation L^
stm L^ stm
Boiler thermal energy out Thermal energy used for electrical generation
Where:
Eaiiocation is the gross thermal output for allocation
Estm is the thermal energy in steam or hot water measured at a location
"Boiler thermal energy out" is each location where thermal energy leaves the boiler or
HRSG. (Location BSt in Figures 4, 5, and 6)
"Thermal energy used for electric generation" is each location where thermal energy goes
into a steam turbine to operate an electric generator. (Location ESt in Figures 4 and 6)
Alternative c. Determining net thermal output measuring gross thermal output. For a source which
has existing net thermal output monitoring installed and which wishes to use this
equipment to determine gross thermal output for allocation the company can either:
use the monitored net thermal output as an estimate of gross output; or use the
monitored thermal output and add any monitored parasitic and house loads to
estimate the gross thermal output for allocation (Table SA-3, column 6). We think
these are likely options for monitoring thermal output monitoring at cogenerators.
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 107 NOx Allowance Allocations
-------
Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
This is particularly true for steam cogenerators and combined cycle cogenerators,
since most useful thermal loads are located downstream of the steam turbine and
generator.
Y
L^
-
allocation L^ stm
Thermal energy for a useful process
or
E = Y E + Y E
allocation Lu stm Lu stm
Thermal energy for a useful process Parasitic and house thermal loads
Where:
Evocation is the gross thermal output for allocation
Estm is the thermal energy in steam or hot water measured at a location
"Thermal energy for a useful process" is the number of places where thermal energy is used
to make a product for sale other than electricity (Locations USt or SSt in Figures 4, 5, and
6)
"Parasitic and house thermal loads" is each location where the source measures or determines
losses of thermal energy from parasitic (auxiliary) or house thermal loads. (Locations HSt
and PSt in Figures 4, 5, and 6)
Alternative d. Measuring gross thermal output from boiler less equivalent electric output. For a
source which monitors the gross thermal output and the gross electric output from an
electric generator, a simplified option for estimating gross thermal output may be
used. (This approach would not apply to a combustion turbine cogenerator, but it
could apply to a steam cogenerator or to a combined cycle cogenerator with a
secondary electric generator.) A company would estimate the gross thermal output
for allocation by monitoring the gross thermal output from the boiler and the electric
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 108 NOx Allowance Allocations
-------
Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
output only. Under this approach, the company converts gross electric output to
equivalent steam energy using a conversion factor based on the manufacturer's
design efficiency for the steam generator. The company would calculate the
conversion factor as follows:
•j A i •? mmBtu,
c. - , . 3'413 /MWh
Steam equivalent =
design efficiency,
as a decimal
The company then deducts this energy from the gross thermal output of the boiler.
This procedure does not require direct monitoring of the steam loads used to generate
power and may simplify monitoring (Table S A-3, column 7). Obviously, this method
will not be as exact as measuring the thermal output directly. Therefore, we would
not recommend that you allow sources to use this method if they are already
measuring the thermal energy going into the steam turbine directly or if they are
already measuring the thermal energy for useful processes.
vp vp 3.413
E = / E - / Ex
allocation ^j stm ^j sleet
Boiler thermal energy out Converted electrical energy QCSlgll tUTDlUC
efficiency
Where:
Elation is the gross thermal output for allocation
Estm is the thermal energy in steam or hot water measured at a location
"Boiler thermal energy out" is each location where thermal energy leaves the boiler or
HRSG. (Location BSt in Figures 4, 5, and 6)
"Converted electric energy" is the thermal energy for each location where thermal energy
goes into a steam turbine to operate an electric generator. It is calculated by "converting" the
gross electric output to thermal energy. (Location GEin Figure 4)
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 109 NOx Allowance Allocations
-------
Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
"3.413/Design turbine efficiency" is the conversion factor in mmBtu/MWh, calculated
using the manufacturer's design efficiency expressed as a decimal.
Monitoring example for a steam cogeneration facility under the simplified approach (see Figure 4.
p. 93}
This is an example of a steam boiler cogenerator which generates both electricity and steam. See
Tables SA-3 (pp. 96-97), SA-4 (pp. 98-99) and SA-5 (pp. 100-101).
The company could measure or estimate thermal and electric output as follows:
• Primary approach for net electric output: Net electric output for allocation measured directly
would be UE+SE-OEO. (Table SA-4, column 8 or Table SA-5, column 8)
Net electric output for allocation measured as gross electric output less parasitic and house
loads would be GE-PE-HE-OEO. (Table SA-4, column 9 or Table SA-5, column 9)
• Primary approach for gross electric output: Gross electric output for allocations measured
directly would be GE. (Table SA-3, column 8)
Gross electric output for allocations estimated as net electric output would be SE+UE-OEO
(Table SA-3, column 9)
• Gross electric output for allocation measured as net electric output plus parasitic and house
loads would be SE+UE-OEO+PE+HE (Table SA-3, column 9)
Primary approach for net thermal output: Net thermal output for allocation measured directly
would be USt+SSt (Table SA-4, column 4).
• Net thermal output for allocation from cogenerators with process steam used downstream of
a steam turbine, determined as gross thermal output from the exit of the steam turbine less
parasitic and house loads, would be XTSt-PSt-HSt (Table SA-4, column 5).
• Net thermal output for allocation from cogenerators with process steam used upstream of a
steam turbine determined as gross thermal output from the boiler less parasitic and house
loads and steam used to generate electricity would be BSt-PSt-HSt-ESt (Table SA-4, column
6).
• Net thermal output for allocation determined as gross thermal output from the boiler less
parasitic and house loads and measured gross electric output converted to an equivalent
steam output using the conversion factor in mmBtu/MWh would be B St-P St-HSt-GESTM.EQUIV
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 110 NOx Allowance Allocations
-------
Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
(Table SA-4, column 7).
Primary approach for gross thermal output: Gross thermal output for allocation measured
directly from cogenerators with process steam used downstream of a steam turbine would
be XTSt (Table SA-3, column 4, or Table SA-5, column 4)
Gross thermal output for allocation measured directly from cogenerators with process steam
used upstream of a steam turbine or from combustion turbines would be BSt-ESt+XTSt or
BSt-ESt, respectively (Table SA-3, column 5, or Table SA-5, column 5)
• Gross thermal output for allocation measured as net thermal output plus parasitic and house
loads would be USt+SSt+PSt+HSt (Table SA-3, column 6 or Table SA-5, column 6)
Gross thermal output for allocation measured as gross thermal output from the boiler less the
equivalent steam for a measured gross electric load would be BSt-GESTM.EQUIV (Table SA-3,
column 7 or Table SA-5, column 7)
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 111 NOx Allowance Allocations
-------
Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
Monitoring example for a combustion turbine cogenerator under the simplified approach (see Figure
5. p. 94}
This is an example of a combustion turbine cogenerator which generates both electricity and steam.
This cogenerator does not have a steam turbine. See Tables SA-3 (pp. 96-97), SA-4 (pp. 98-99) and
SA-5 (pp. 100-101).
The company could measure or estimate thermal and electric output as follows:
• Primary approach for net electric output: Net electric output for allocation measured directly
would be UE+SE-OEO. (Table SA-4, column 8 or Table SA-5, column 8)
Net electric output for allocation measured as gross electric output less parasitic and house
loads would be GE-PE-HE-OEO. (Table SA-4, column 9 or Table SA-5, column 9)
• Primary approach for gross electric output: Gross electric output for allocations measured
directly would be GE. (Table SA-3, column 8)
Gross electric output for allocations estimated as net electric output would be SE+UE-OEO
(Table SA-3, column 9)
• Gross electric output for allocation measured as net electric output plus parasitic and house
loads would be SE+UE-OEO+PE+HE (Table SA-3, column 9)
Primary approach for net thermal output: Net thermal output for allocation measured directly
would be USt+SSt (Table SA-4, column 4).
• Net thermal output for allocation from combustion turbines determined as gross thermal
output from the boiler less parasitic and house loads would be BSt-PSt-HSt (Table SA-4,
column 6).
Primary approach for gross thermal output: Gross thermal output for allocation measured
directly from combustion turbines would be BSt-ESt (Table SA-3, column 5, or Table SA-5,
column 5)
Gross thermal output for allocation measured as net thermal output plus parasitic and house
loads would be USt+SSt+PSt+HSt (Table SA-3, column 6 or Table SA-5, column 6)
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 112 NOx Allowance Allocations
-------
Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
Monitoring example for a combined cycle cogeneration facility under the simplified approach. (See
Figure 6, p. 95)
This is an example of a combined cycle cogenerator which generates both electricity and steam. See
Tables SA-3 (pp. 96-97), SA-4 (pp. 98-99) and SA-5 (pp. 100-101).
The company could measure or estimate thermal and electric output as follows:
Primary approach for net electric output: Net electric output for allocation measured directly
would be UE+SE-OEO. (Table SA-4, column 8 or Table SA-5, column 8)
• Net electric output for allocation measured as gross electric output less house and parasitic
losses would be GE-PE-HE-OEO. (Table SA-4, column 9 or Table SA-5, column 9)
Primary approach for gross electric output: Gross electric output for allocations measured
directly would be GE. (Table SA-3, column 8)
• Gross electric output for allocations estimated as net electric output would be SE+UE-OEO
(Table SA-3, column 9)
Gross electric output for allocation measured as net electric output plus parasitic and house
loads would be SE+UE-OEO+PE+HE (Table SA-3, column 9)
• Primary approach for net thermal output: Net thermal output for allocation measured directly
would be USt+SSt (Table SA-4, column 4).
Net thermal output for allocation from cogenerators with process steam used downstream of
a steam turbine, determined as gross thermal output from the exit of the steam turbine less
parasitic and house loads, would be XTSt-PSt-HSt (Table SA-4, column 5).
Net thermal output for allocation from cogenerators with process steam used upstream of a
steam turbine determined as gross thermal output from the HRSG less parasitic and house
loads and steam used to generate electricity would be BSt-PSt-HSt-ESt (Table SA-4, column
6).
Net thermal output for allocation determined as gross thermal output from the boiler less
parasitic and house loads and measured gross electric output converted to an equivalent
steam output using a conversion factor in mmBtu/MWh would be BSt-PSt-HSt-GESTM.EQUIV
(Table SA-4, column 7).
Primary approach for gross thermal output: Gross thermal output for allocation measured
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 113 NOx Allowance Allocations
-------
Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
directly from cogenerators with process steam used downstream of a steam turbine would
be XTSt (Table SA-3, column 4, or Table SA-5, column 4)
• Gross thermal output for allocation measured directly from cogenerators with process steam
used upstream of a steam turbine would be BSt-ESt+XTSt (Table SA-3, column 5, or Table
SA-5, column 5)
Gross thermal output for allocation measured as net thermal output plus parasitic and house
loads would be USt+SSt+PSt+HSt (Table SA-3, column 6 or Table SA-5, column 6)
• Gross thermal output for allocation measured as gross thermal output from the boiler less the
equivalent steam for a measured gross electric load would be BSt-GESTM.EQUIV (Table SA-3,
column 7 or Table SA-5, column 7)
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 114 NOx Allowance Allocations
-------
FIGURE 4 (repeated)
Figure 4
Steam Cogenerator
Heat
Input
Boiler
Boiler
Steam
Out (BSt)
(ESt)
(PSt)
House electric
loads from grid
OEO or OEN
Steam
Turbine
(GE)
Gross
electric
(SE + UE)
Useful
Electric
Load
Parasitic
Steam
Loads
i
\l
(XTSt)
r
^
(PSt) (USt
+ SSt)
Useful
Steam
Loads
^
(HSt)
House
Steam
Loads
Make Up
Water (MUW)
(XSt)
Boiler Feedwater
Return (BFR)
Page 115
-------
Figure 5
Combustion Turbine Cogenerator
Combustion
Turbine
Make
Water
Electric from outside plant OEO or OEN
Gross Electric (GE)
(PE)
(UE + SE)
V
Parasitic Electric
Loads
Steam
OutfBSt)
HRSG Feedwater
Return (BFR)
(USt + SSt)
(XSt
Page 116
-------
Figure 6
Combined Cycle Cogenerator
Electric from outside plant OEO or OEN
(XSt)
Make Up
Water (MUW)
HRSG Feedwater
Return (BFR)
Page 117
-------
Table BE-3, Monitoring Cogenerator for Gross Electric Output and Gross Thermal Output under the Boiler Efficiency Approach
Overall System Description
In this column are the various
systems associated with boilers and
electric generators as defined in the
diagrams
Column 1
Primary Steam System
Note: flow in feed water return and
make up water must equal steam out
flow
Steam Return and Reheat System
Note: flow in reheat steam out must
equal flow in reheat steam entering
boiler
Steam Used to Generate Electric
Power in a Steam Turbine
Useful Thermal Loads
Losses Associated with Generation of
Thermal Output
Possible Monitoring Locations
In this column are the specific points
which might need to be monitored
under different approaches.
The letter in the first column
corresponds to letters used on the
associated diagrams
2
BSt
BFR
MUW
RStO
RStI
ESt
XTSt
ust
xst
sst
xst
PSt
HSt
3
Main boiler steam out
Boiler feedwater
return
Make up water
Reheat steam out
Steam returning to boiler
for reheating
Steam entering a turbine
Steam exhaust from a
turbine
Useful steam or hot water
entering a process
Steam or hot water exiting
a process
Steam sold at point of sale
Return condensate or
steam from buyer
Parasitic steam loads
House steam loads
Gross Thermal Output for Allocation
Gross thermal
output
measured
directly at exit
from steam
turbine
4
-
Measure(-)
Measure(-)
Measure(+)
Measure(-)
-
Measure (+)
-
-
-
-
-
-
Gross thermal
output measured
directly at
HRSG/boiler less
steam used for
electric
generation
5
Measure(+)
Measure(-)
Measure(-)
Measure(+)
Measure(-)
Measure(-)
Measure (+)
-
-
-
-
-
-
Net thermal
output plus
parasitic and
house loads less
steam used for
electric
generation
6
-
Measure (-)
Measure (-)
-
-
-
-
Measure (+)
-
Measure (+)
-
Measure (+)
Measure (+)
Gross thermal
output measured
directly at
HRSG/boiler
less equivalent
electric output in
mmBtu.
7
Measure(+)
Measure(-)
Measure(-)
Measure(+)
Measure(-)
-
-
-
-
-
-
-
-
Gross Electric Output
Gross
electric
output
measured
directly
8
-
-
-
-
-
-
-
-
-
-
-
-
-
Net electric
output plus
parasitic and
hours loads
9
-
-
-
-
-
-
-
-
-
-
-
-
-
Page 118
-------
Table BE-3, Monitoring Cogenerator for Gross Electric Output and Gross Thermal Output under the Boiler Efficiency Approach
Overall System Description
In this column are the various
systems associated with boilers
and electric generators as defined
in the diagrams
Column 1
Electric Generation
Electric Power Used on Site Not
Generated by the Facility
Losses Associated with
Generation of Electricity
Possible Monitoring Locations
In this column are the specific
points which might need to be
monitored under different
approaches.
The letter in the first column
corresponds to letters used on
the associated diagrams
2
GE
SE
UE
OEO
OEN
PE
HE
3
Electric power
measured at generator
terminals
Electric power leaving
plant to electric grid
Electric power used
internal to a
cogenerator or
industrial facility for a
useful purpose
Electric power coming
from grid or other
power source to plant
during operation
Electric power coming
from grid or other
source during non
operation
Parasitic electric loads
House electric loads
Gross Thermal Output for Allocation
Gross thermal
output
measured
directly at exit
from steam
turbine
(Primary)
4 (con't)
--
--
--
--
Gross thermal
output
measured
directly at
HRSG/boiler
less steam used
for electric
generation
5 (con't)
--
--
--
--
Net thermal
output plus
parasitic and
house loads
less steam
used for
electric
generation
6 (con't)
--
--
--
--
Gross thermal
output
measured
directly at
HRSG/boiler
less equivalent
electric output
inmmBtu.
7 (con't)
Measure and
convert to
mmBtu(-)
-
-
-
Gross Electric Output
Gross
electric
output
measured
directly
(Primary)
8 (con't)
Measure
(+)
--
--
--
Net electric
output plus
parasitic and
hours loads
9 (con't)
-
Measure (+)
Measure (+)
Measure (-)
Measure (+)
Measure (+)
Page 119
-------
Table BE-4, Monitoring Cogenerator (CHP) for Net Electric Output and Net Thermal Output under the Boiler Efficiency Approach
Overall System Description
In this column are the various
systems associated with
boilers and electric generators
as defined in the diagrams
Column 1
Primary Steam System
Note: flow in feed water return
and make up water must equal
steam out flow
Steam Return and Reheat
System
Note: flow in reheat steam out
must equal flow in reheat
steam entering boiler
Steam Used to Generate
Electric Power in a Steam
Turbine
Useful Thermal Loads
Losses Associated with
Generation of Thermal Output
Possible Monitoring Locations
In this column are the specific points
which might need to be monitored under
different approaches.
The letter in the first column
corresponds to letters used on the
associated diagrams
2
BSt
BFR
MUW
RStO
RStI
ESt
XTSt
ust
xst
sst
xst
PSt
HSt
3
Main boiler steam out
Boiler feedwater
return
Make up water
Reheat steam out
Steam returning to boiler for
reheating
Steam entering a turbine
Steam exhaust from a turbine
Useful steam entering a
process
Steam or hot water exiting a
process
Steam sold at point of sale
Return condensate or steam
from buyer
Parasitic steam loads
House steam loads
Net Thermal Output for Allocation
Net thermal
output
measured
directly less
steam used for
electric
generation
(Primary)
4
-
Measure (-)
Measure (-)
-
-
Measure (-)
-
Measure (+)
-
Measure (+)
-
-
-
Gross
thermal
output from
exit of steam
turbine less
parasitic and
house loads
5
-
Measure (-)
Measure (-)
Measure (+)
Measure (-)
-
Measure (+)
-
-
-
-
Measure (-)
Measure (-)
Gross thermal
output from
HRSG/boiler less
parasitic and house
loads less steam
used for electric
generation
6
Measure (+)
Measure (-)
Measure (-)
Measure (+)
Measure (-)
Measure (-)
-
-
-
-
-
Measure (-)
Measure (-)
Measure gross thermal
output from HRSG/boiler
less parasitic loads,
house loads, return
feedwater and equivalent
electric output expressed
in mmBtu.
7
Measure (+)
Measure (-)
Measure (-)
Measure (+)
Measure (-)
-
-
-
-
-
-
Measure (-)
Measure (-)
Net Electric Output
Net electric
output
measured
directly
(Primary)
8
-
-
-
-
-
-
-
-
-
-
-
-
-
Gross
electric
output less
parasitic
and hours
loads
9
-
-
-
-
-
-
-
-
-
-
-
-
-
Page 120
-------
Table BE-4, Monitoring Cogenerator (CHP) for Net Electric Output and Net Thermal Output under the Boiler Efficiency Approach
Overall System Description
In this column are the
various systems associated
with boilers and electric
generators as defined in the
diagrams
Column 1
Electric Generation
Electricity Used on Site
Not Generated by the
Facility
Losses Associated with
Generation of Electricity
Possible Monitoring Locations
In this column are the specific
points which might need to be
monitored under different
approaches.
The letter in the first column
corresponds to letters used on the
associated diagrams
2
GE
SE
UE
OEO
OEN
PE
HE
3
Electric power measured
at generator terminals
Electric power leaving
plant to electric grid
Electric power used
internal to a cogenerator
or industrial facility for a
useful purpose
Electric power coming
from grid or other power
source to plant during
operation
Electric power coming
from grid or other source
during non operation
Parasitic electric loads
House electric loads
Net Thermal Output for Allocation
Net thermal
output
measured
directly less
steam used
for electric
generation
(Primary)
4 (con't)
--
--
—
--
--
Gross
thermal
output
from exit
of steam
turbine less
parasitic
and house
loads
5 (con't)
--
--
—
--
--
Gross thermal
output from
HRSG/boiler less
parasitic and
house loads less
steam used for
electric
generation
6 (con't)
--
--
—
--
--
Measure gross thermal
output from
HRSG/boiler less
parasitic loads, house
loads, return
feedwater and
equivalent electric
output expressed in
mmBtu.
7 (con't)
Measure and convert
to mmBtu (-)
--
—
--
--
Net Electric Output
Net electric
output
measured
directly
(Primary)
8 (con't)
--
Measure
(+)
Measure
(+)
Measure
(-)
-
--
--
Gross
electric
output
less
parasitic
and hours
loads
9 (con't)
Measure
(+)
-
Measure
(-)
—
Measure
(-)
Measure
(-)
Page 121
-------
Table BE-5, Monitoring Cogen (CHP) for Net Electric Output and Gross Thermal Output under the Boiler Efficiency Approach
Overall System Description
In this column are the various
systems associated with boilers
and electric generators as
defined in the diagrams
Column 1
Primary Steam System
Note: flow in feed water return and
make up water must equal steam out
flow
Steam Return and Reheat System
Note: flow in reheat steam out must
equal flow in reheat steam entering
boiler
Steam Used to Generate Electric
Power in a Steam Turbine
Useful Thermal Loads
Losses Associated with Generation
of Thermal Output
Possible Monitoring Locations
In this column are the specific
points which might need to be
monitored under different
approaches.
The letter in the first column
corresponds to letters used on the
associated diagrams
2
BSt
BFR
MUW
RStO
RStI
ESt
XTSt
ust
xst
sst
xst
PSt
HSt
3
Main boiler steam out
Boiler feedwater
return
Make up water
Reheat steam out
Steam returning to boiler
for reheating
Steam entering a turbine
Steam exhaust from a
turbine
Useful steam entering a
process
Steam or hot water exiting a
process
Steam sold at point of sale
Return condensate or steam
from buyer
Parasitic steam loads
House steam loads
Gross Thermal Output for Allocation
Gross thermal
output
measured
directly from
exit of steam
turbine
(Primary)
4
-
Measure(-)
Measure(-)
Measure(+)
Measure(-)
-
Measure (+)
-
-
-
-
-
-
Gross thermal
output
measured
directly from
HRSG/boiler
less steam used
for electric
generation
5
Measure(+)
Measure(-)
Measure(-)
Measure(+)
Measure(-)
Measure(-)
Measure (+)
-
-
-
-
-
-
Net thermal
output plus
parasitic and
house loads
less steam used
for electric
generation
6
-
Measure (-)
Measure (-)
-
-
-
-
Measure (+)
-
Measure (+)
-
Measure (+)
Measure (+)
Gross thermal
output measured
directly from
HRSG/boiler less
equivalent net
electric output in
mmBtu.
7
Measure(+)
Measure(-)
Measure(-)
Measure(+)
Measure(-)
-
-
-
-
-
-
-
-
Net Electric Output
Net electric
output
measured
directly
(Primary)
8
-
-
-
-
-
-
-
-
-
-
-
-
-
Gross
electric
output
less
parasitic
and house
loads
9
-
-
-
-
-
-
-
-
-
-
-
-
-
Page 122
-------
Table BE-5, Monitoring Cogen (CHP) for Net Electric Output and Gross Thermal Output under the Boiler Efficiency Approach
Overall System Description
In this column are the various
systems associated with boilers
and electric generators as
defined in the diagrams
Column 1
Electric Generation
Electric Power Used on Site Not
Generated by the Facility
Losses Associated with Generation
of Electricity
Possible Monitoring Locations
In this column are the specific
points which might need to be
monitored under different
approaches.
The letter in the first column
corresponds to letters used on the
associated diagrams
2
GE
SE
UE
OEO
OEN
PE
HE
3
Electric power measured at
generator terminals
Electric power leaving plant
to electric grid
Electric power used internal
to a cogenerator or
industrial facility for a
useful purpose other than
generation of electricity
Electric power coming from
grid or other power source
to plant during operation
Electric power coming from
grid or other source during
non operation
Parasitic electric loads
House electric loads
Gross Thermal Output for Allocation
Gross thermal
output
measured
directly from
exit of steam
turbine
(Primary)
4 (con't)
-
-
-
-
-
-
Gross thermal
output
measured
directly from
HRSG/boiler
less steam used
for electric
generation
5 (con't)
-
-
-
-
-
-
Net thermal
output plus
parasitic and
house loads
less steam used
for electric
generation
6 (con't)
-
-
-
-
-
-
Gross thermal
output measured
directly from
HRSG/boiler less
equivalent net
electric output in
mmBtu.
7 (con't)
Measure and
convert to mmBtu
(-)
-
-
-
-
-
Net Electric Output
Net electric
output
measured
directly
(Primary)
8 (con't)
-
Measure (+)
Measure (+)
Measure (-)
-
-
-
Gross
electric
output
less
parasitic
and house
loads
9
Measure
(+)
-
Measure
(-)
-
Measure
(-)
Measure
(-)
Page 123
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Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
4. Monitoring Net Thermal Output under the Boiler Efficiency Approach.
It is important to remember that the net thermal output used for allocations is the thermal
output used to perform useful work in a process only, not thermal output used to generate electricity.
This is referred to as "net thermal output for allocation" to distinguish it from "net thermal output"
which includes thermal output used in electric generation.
Primary approach: (a) Measuring net thermal output directly. A cogeneration (CHP) facility which
is required to determine the net thermal output for allocation may measure the
useful thermal output directly. Monitoring net thermal output directly is
similar to monitoring net thermal output for allocation for a steam generator,
with the additional requirement that thermal energy used to generate
electricity would not be included as net thermal output. In general, a
company would measure the thermal energy going into and out of each useful
process and then calculate the net thermal energy as the sum of the
differences between the thermal energy going into the useful processes and
exiting the useful processes (Table BE-4, column 4, pp. 120-121).
E - V E - V E
net ' ' stm ' ' stm
Thermal energy for a useful process Thermal energy returning to boiler
Where:
Enet is the net thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Thermal energy for a useful process" is the number of places where thermal energy is used
to make a product for sale other than electricity (Locations USt and SSt in Figures 4, 5, and
6)
"Thermal energy returning to boiler" is where thermal energy returns to the boiler or HRSG,
such as in the boiler feedwater return. (Location BFR in Figures 4, 5, and 6)
Alternative b. Determining net thermal output measuring gross thermal output. A cogeneration or
CUP facility which is required to monitor net thermal output which has an existing
gross thermal output system and which does not have a system for measuring net
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 124 NOx Allowance Allocations
-------
Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
output directly may determine the net thermal output as the gross thermal output after
the steam turbine and generator less house thermal loads, parasitic thermal loads, and
boiler feedwater return (Table BE-4, column 5). (This is appropriate for steam
cogenerators and combined cycle cogenerators with process steam used downstream
of a steam turbine and generator, as in Figures 4 and 6.)
^net ~ 2-1 stm ~ 2-1 stm ~ 2-1 stm
Thermal energy exiting Parasitic and house thermal loads Thermal energy returning to boiler
the steam turbine
Where:
Enet is the net thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Thermal energy exiting the steam turbine" is each location where thermal energy leaves a
steam turbine that is connected to the unit. (Location XTSt in Figures 4 and 6)
"House and parasitic thermal loads" is each location where the source measures or
determines losses of thermal energy from parasitic (auxiliary) or house thermal loads.
(Location HSt and PSt in Figures 4, 5, and 6)
"Thermal energy returning to boiler" is where thermal energy returns to the boiler or FtRSG,
such as in the boiler feedwater return. (Location BFR in Figures 4, 5, and 6)
Alternative c. Measuring gross thermal output directly from the boiler less steam for electric
generation. For combustion turbine cogenerators, or for the less common situation
where some thermal energy is used in a process upstream of a steam turbine and
generator, a source might monitor gross thermal output from the boiler, minus the
thermal output going to electric generation. In this case, a cogeneration (CFtP) facility
which is required to monitor net thermal output which does not have a system for
measuring net output directly may determine the net thermal output as the gross
thermal output from the FtRSG or boiler less house thermal loads, parasitic thermal
Final EPA Guidance Document Developing and Updating Output-Based
May 8, 2000 Page 125 NOx Allowance Allocations
-------
Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
loads, and boiler feedwater and the steam used for electric generation in a steam
turbine and generator (Table BE-4, column 6).
2-1 stm Zj stm Zj stm Zj stm
Boiler thermal energy out Parasitic and house thermal loads Thermal energy returning to boiler Thermal energy used
for electric generation
Where:
Enet is the net thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Boiler thermal energy out" is each location where thermal energy leaves the boiler or
HRSG. (Location BSt in Figures 4, 5, and 6)
"House and parasitic thermal loads" is each location where the source measures or
determines losses of thermal energy from parasitic (auxiliary) or house thermal loads.
(Location HSt and PSt in Figures 4, 5, and 6)
"Thermal energy returning to boiler" is where thermal energy returns to the boiler or FtRSG,
such as in the boiler feedwater return. (Location BFR in Figures 4, 5, and 6)
"Thermal energy used for electric generation" is each location where thermal energy goes
into a steam turbine to operate an electric generator. (Location EStin Figures 4 and 6)
Alternative (special case):
d. Measuring gross thermal output from boiler less equivalent electric output. For the
less common situation where some thermal energy is used in a process upstream of
a steam turbine and generator, sources might monitor gross thermal output from the
boiler, including thermal output for electric generation. (This approach would not
apply to a combustion turbine cogenerator, but it could apply to a steam cogenerator
or to a combined cycle cogenerator with a secondary electric generator.) For a
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Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
cogeneration (CHP) facility in this situation which is required to determine both net
electric output for allocations and net steam for output allocations and which does not
monitor net output directly, the net thermal output may be determined as follows.
The source would measure the gross thermal output from the HRSG or boiler, less
the parasitic and house loads, the boiler feedwater return and less the gross electric
output from the generator converted to equivalent steam energy using the design
steam turbine generator efficiency (See Table BE-4, column 7, pp. 120-121). Note
that when converting electric power to an equivalent steam load to deduct from the
net thermal output, a source would convert the gross electric output, not the net
electric output, to an equivalent thermal output. Obviously, this method will not be
as exact as measuring the thermal output directly. Therefore, we would not
recommend that you allow sources to use this method if they are already measuring
the thermal energy going into the steam turbine directly or if they are already
measuring the thermal energy for useful processes.
Y V V V 3.413
Enet = L Estm ~ L E stm ~ L E stm ~ L
Boiler thermal energy out Parasitic and house thermal loads Thermal energy Converted gross electrical output UVSlgll LU1 UlIlC
returning to boiler efficiency
Where:
Enet is the net thermal output
Estm is the thermal energy in steam or hot water measured at a location
"Boiler thermal energy out" is each location where thermal energy leaves the boiler or
HRSG. (Location BSt in Figure 4, 5, and 6)
"Parasitic and house thermal loads" is each location where the source measure or determine
losses of thermal energy from parasitic (auxiliary) or house thermal loads. (Locations PSt
and HSt in Figures 4, 5, and 6)
"Thermal energy returning to boiler" is where thermal energy returns to the boiler or FtRSG,
such as in the boiler feedwater return. (Location BFR in Figures 4, 5, and 6)
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Section VI. D. : How could sources monitor electric and thermal output at a cogeneration facility? _
"Converted electric energy" is the thermal energy for each location where thermal energy
goes into a steam turbine to operate an electric generator. It is calculated by "converting" the
gross electric output to thermal energy. (Location GE in Figures 4, 5, and 6)
"3 .4 1 3/Design turbine efficiency" is the conversion factor in mmBtu/MWh, calculated using
the manufacturer's design efficiency expressed as a decimal.
5. Monitoring Gross Thermal Output under the Boiler Efficiency Approach.
For a cogeneration or combined heat and power (CUP) facility required to monitor both gross
thermal output and gross electric output, the monitoring locations are described in Table BE-3 (pp.
118-119). It is important to remember that the gross thermal output used for allocations is the total
gross thermal output of the boiler (gross thermal output) less the output used for generation of
electricity (we refer to this as "gross thermal output for allocation"). (Thermal energy used to
generate electricity will receive an allocation indirectly through the allocation of allowances for
electric output.)
Primary approach for steam cogenerators or combined cycle systems:
a. Measuring gross thermal output directly at the exit from a steam turbine: One method
for monitoring gross thermal output for allocation would be to measure thermal
energy remaining after steam has exited the steam turbine. (This is a common
configuration for steam cogenerators and combined cycle cogenerators that use
process steam downstream of a steam turbine and generator, as in Figures 4 and 6.
See Table BE-3, column 4.)
E = YE
allocation ^j
stm j stm
Thermal energy exiting Thermal energy returning to boiler
the steam turbine
Where:
Eaiiocation is the gross thermal output for allocation
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Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
Estm is the thermal energy in steam or hot water measured at a location
"Thermal energy exiting the steam turbine" is each location where thermal energy leaves a
steam turbine that is connected to the unit. (Location XTSt in Figures 4 and 6)
"Thermal energy returning to boiler" is where thermal energy returns to the boiler or HRSG,
such as in the boiler feedwater return. (Location BFR in Figures 4, 5, and 6)
Primary approach for combustion turbine cogenerators:
b. Measuring gross thermal output directly from the boiler less steam for electric
generation. For combustion turbine cogenerators, or for the less common situation
where some thermal energy is used in a process upstream of a steam turbine and
generator, another method for monitoring gross thermal output for allocations may
be appropriate. In this case, monitoring gross thermal output for allocation directly
would be similar to monitoring gross thermal output for allocation for a steam
generator, with the additional requirement that the thermal output used to generate
electricity would be deducted from the gross thermal output. (See section VI.C.4,
"Gross Thermal Output under the Boiler Efficiency Approach", pp. 87-89, for a
description of the basic energy balance approach used.) Deducting the gross thermal
energy used to generate electricity may require additional monitoring of the steam
used to generate electricity to determine the gross thermal output for allocation
(Table BE-3, Column 5, pp. 118-119):
77 _ X"1 T7 _ X"1 77 _ X"* 77
allocation ~ Z-( stm Z-( stm L-i stm
Boiler thermal energy out Thermal energy returning to boiler Thermal energy used for electrical generation
Where:
Eaiiocation is the gross thermal output for allocation
Estm is the thermal energy in steam or hot water measured at a location
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Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
"Boiler thermal energy out" is each location where thermal energy leaves the boiler or
HRSG. (Location BSt in Figures 4, 5, and 6)
"Thermal energy returning to boiler" is where thermal energy returns to the boiler or HRSG,
such as in the boiler feedwater return. (Location BFR in Figures 4, 5, and 6)
"Thermal energy used for electric generation" is each location where thermal energy goes
into a steam turbine to operate an electric generator. (Location ESt in Figures 4 and 6)
Alternative c. Determining net thermal output measuring gross thermal output. For a source which
has existing net thermal output monitoring installed and which wishes to use this
equipment to determine gross thermal output for allocation the company can either:
use the monitored net thermal output as an estimate of gross output; or use the
monitored thermal output and add any monitored parasitic and house loads to
estimate the gross thermal output for allocation (Table BE-3, column 6). We think
these are likely options for monitoring thermal output monitoring at cogenerators.
This is particularly true for steam cogenerators and combined cycle cogenerators,
since most useful thermal loads are located downstream of the steam turbine and
generator.
77 _ 77 _ 77
allocation ~ L^ stm L^ stm
Thermal energy for a useful process Thermal energy returning to boiler
or
F = V F + V F - V F
allocation Z_j stm Z_j stm Z_j stm
Thermal energy for a useful process Parasitic and house thermal loads Thermal energy returning to boiler
Where:
Evocation is the gross thermal output for allocation
Estm is the thermal energy in steam or hot water measured at a location
"Thermal energy for a useful process" is the number of places where thermal energy is used
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Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
to make a product for sale other than electricity (Locations USt or SSt in Figures 4, 5, and
6)
"Parasitic and house thermal loads" is each location where the source measures or determines
losses of thermal energy from parasitic (auxiliary) or house thermal loads. (Locations HSt
and PSt in Figures 4, 5, and 6)
"Thermal energy returning to boiler" is where thermal energy returns to the boiler or FtRSG,
such as in the boiler feedwater return. (Location BFR in Figures 4, 5, and 6)
Alternative d. Measuring gross thermal output from boiler less equivalent electric output. For a
source which monitors the gross thermal output and the gross electric output, a
simplified option for estimating gross thermal output may be used. (This approach
would not apply to a combustion turbine cogenerator, but it could apply to a steam
cogenerator or to a combined cycle cogenerator with a secondary electric generator.)
A company would estimate the gross thermal output for allocation by monitoring the
gross thermal output from the boiler and the electric output only. Under this
approach, the company converts gross electric output to equivalent steam energy
using a conversion factor based on the manufacturer's design efficiency for the steam
turbine generator. The company would calculate the conversion factor as follows:
T /i i T mmBtuL
/ivr\A/Vi
Steam equivalent = iviwn
design efficiency,
as a decimal
The company then deducts this energy from the gross thermal output of the boiler.
This procedure does not require direct monitoring of the steam loads used to generate
power and may simplify monitoring (Table BE-3, column 7). Obviously, this method
will not be as exact as measuring the thermal output directly. Therefore, we would
not recommend that you allow sources to use this method if they are already
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Section VI. D.: How could sources monitor electric and thermal output at a cogeneration facility?
measuring the thermal energy going into the steam turbine directly or if they are
already measuring the thermal energy for useful processes.
^ ^ ^ 3.413
/7 — \/7_ \ /7 _ \ /7 v
^allocation Aj ^stm Aj ^stm Aj Delect flaqion tllfhinp
Boiler thermal energy out Thermal energy returning to boiler Converted electrical energy tlcblgll LU1 Ulllc
efficiency
Where:
Eaiiocation is the gross thermal output for allocation
Estm is the thermal energy in steam or hot water measured at a location
"Boiler thermal energy out" is each location where thermal energy leaves the boiler or
HRSG. (Location BSt in Figures 4, 5, and 6)
"Thermal energy returning to boiler" is where thermal energy returns to the boiler or HRSG,
such as in the boiler feedwater return. (Location BFR in Figures 4, 5, and 6)
"Converted electric energy" is the thermal energy for each location where thermal energy
goes into a steam turbine to operate an electric generator. It is calculated by "converting" the
gross electric output to thermal energy. (Location GEin Figure 4)
"3.413/Design turbine efficiency" is the conversion factor in mmBtu/MWh, calculated
using the manufacturer's design efficiency expressed as a decimal.
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Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
Monitoring example for a steam cogeneration facility under the boiler efficiency approach (see
Figure 4. p. 115}
This is an example of a steam boiler cogenerator which generates both electricity and steam. See
Tables BE-3 (pp. 118-119), BE-4 (pp. 120-121), and BE-5 (pp. 122-123).
The company could measure or estimate thermal and electric output as follows:
Primary approach for net electric output: Net electric output for allocation measured directly
would be UE+SE-OEO. (Table BE-4, column 8 or Table BE-5, column 8)
• Net electric output for allocation measured as gross electric output less parasitic and house
loads would be GE-PE-HE-OEO. (Table BE-4, column 9 or Table BE-5, column 9)
Primary approach for gross electric output: Gross electric output for allocations measured
directly would be GE. (Table BE-3, column 8)
• Gross electric output for allocations estimated as net electric output would be SE+UE-OEO
(Table BE-3, column 9)
Gross electric output for allocation measured as net electric output plus parasitic and house
loads would be SE+UE-OEO+PE+HE (Table BE-3, column 9)
• Primary approach for net thermal output: Net thermal output for allocation measured directly
would be USt+SSt-BFR-MUW (Table BE-4, column 4).
Net thermal output for allocation from cogenerators with process stream used downstream
of a steam turbine, determined as gross thermal output from the exit of the steam turbine less
parasitic and house loads, would be XTSt-BFR-MUW-PSt-HSt (Table BE-4, column 5).
Net thermal output for allocation from cogenerators with process steam used upstream of a
steam turbine determined as gross thermal output from the boiler less parasitic and house
loads and steam used to generate electricity would be BSt-BFR-MUW-PSt-HSt-ESt (Table
BE-4, column 6).
Net thermal output for allocation determined as gross thermal output from the boiler less
parasitic and house loads and measured gross electric output converted to an equivalent
steam output using the conversion factor in mmBtu/MWh would be BSt-BFR-MUW-PSt-
HSt-GESTM.EQUIV (Table BE-4, column 7).
Primary approach for gross thermal output: Gross thermal output for allocation measured
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Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
directly from most cogenerators with steam turbines would be XTSt-BFR-MUW (Table BE-
3, column 4, or Table BE-5, column 4)
• Gross thermal output for allocation measured directly from cogenerators with process steam
used upstream of a steam turbine or from combustion turbines would be BSt-BFR-MUW-
ESt+XTSt or BSt-BFR-MUW-ESt, respectively (Table BE-3, column 5, or Table BE-5,
column 5)
• Gross thermal output for allocation measured as net thermal output plus parasitic and house
loads would be USt+SSt+PSt+HSt-BFR-MUW (Table BE-3, column 6 or Table BE-5,
column 6)
Gross thermal output for allocation measured as gross thermal output from the boiler less the
equivalent steam for a measured gross electric load would be BSt-BFR-MUW-GESTM.EQUIV
(Table BE-3, column 7 or Table BE-5, column 7)
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Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
Monitoring example for a combustion turbine cogenerator under the boiler efficiency approach (see
Figure 5. p. 116)
This is an example of a combustion turbine cogenerator which generates both electricity and steam.
This cogenerator does not have a steam turbine. See Tables BE-3 (pp. 118-119), BE-4 (pp. 120-
121), andBE-5(pp. 122-123).
The company could measure or estimate thermal and electric output as follows:
• Primary approach for net electric output: Net electric output for allocation measured directly
would be UE+SE-OEO. (Table BE-4, column 8 or Table BE-5, column 8)
Net electric output for allocation measured as gross electric output less parasitic and house
loads would be GE-PE-HE-OEO. (Table BE-4, column 9 or Table BE-5, column 9)
• Primary approach for gross electric output: Gross electric output for allocations measured
directly would be GE. (Table BE-3, column 8)
Gross electric output for allocations estimated as net electric output would be SE+UE-OEO
(Table BE-3, column 9)
• Gross electric output for allocation measured as net electric output plus parasitic and house
loads would be SE+UE-OEO+PE+HE (Table BE-3, column 9)
Primary approach for net thermal output: Net thermal output for allocation measured directly
would be USt+SSt-BFR-MUW (Table BE-4, column 4).
• Net thermal output for allocation from combustion turbines determined as gross thermal
output from the boiler less parasitic and house loads would be BSt-BFR-MUW-PSt-HSt
(Table BE-4, column 6).
Primary approach for gross thermal output: Gross thermal output for allocation measured
directly from combustion turbines would be BSt-BFR-MUW-ESt, (Table BE-3, column 5,
or Table BE-5, column 5)
Gross thermal output for allocation measured as net thermal output plus parasitic and house
loads would be USt+SSt+PSt+HSt-BFR-MUW (Table BE-3, column 6 or Table BE-5,
column 6)
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Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
Monitoring example for a combined cycle cogeneration facility under the boiler efficiency approach.
(See Figure 6, p. 117)
This is an example of a combined cycle cogenerator which generates both electricity and steam. See
Tables BE-3 (pp. 118-119), BE-4 (pp. 120-121), and BE-5 (pp. 122-123).
The company could measure or estimate thermal and electric output as follows:
Primary approach for net electric output: Net electric output for allocation measured directly
would be UE+SE-OEO. (Table BE-4, column 8 or Table BE-5, column 8)
• Net electric output for allocation measured as gross electric output less house and parasitic
losses would be UE+SE-PE-HE-OEO. (Table BE-4, column 9 or Table BE-5, column 9)
Primary approach for gross electric output: Gross electric output for allocations measured
directly would be GE. (Table BE-3, column 8)
• Gross electric output for allocations estimated as net electric output would be SE+UE-OEO
(Table BE-3, column 9)
Gross electric output for allocation measured as net electric output plus parasitic and house
loads would be SE+UE-OEO-PE+HE (Table BE-3, column 9)
• Primary approach for net thermal output: Net thermal output for allocation measured directly
would be USt+SSt-BFR-MUW (Table BE-4, column 4).
Net thermal output for allocation from cogenerators with process steam used downstream of
a steam turbine, determined as gross thermal output from the exit of the steam turbine less
parasitic and house loads, would be XTSt-BFR-MUW-PSt-HSt (Table BE-4, column 5).
Net thermal output for allocation from cogenerators with process steam used upstream of a
steam turbine determined as gross thermal output from the HRSG less parasitic and house
loads and steam used to generate electricity would be BSt-BFR-MUW-PSt-HSt-ESt (Table
BE-4, column 6).
Net thermal output for allocation determined as gross thermal output from the boiler less
parasitic and house loads and measured gross electric output converted to an equivalent
steam output using a conversion factor in mmBtu/MWh would be B St-BFR-MUW-PSt-HSt-
GESTM.EQUIV (Table BE-4, column 7).
Primary approach for gross thermal output: Gross thermal output for allocation measured
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Section VI.D.: How could sources monitor electric and thermal output at a cogeneration facility?
directly from cogenerators with process steam used downstream of a steam turbine would
be XTSt-BFR-MUW (Table BE-3, column 4, or Table BE-5, column 4)
• Gross thermal output for allocation measured directly from cogenerators with process steam
used upstream of a steam turbine would be B St-BFR-MUW-ESt+XTSt (Table BE-3, column
5, or Table BE-5, column 5)
Gross thermal output for allocation measured as net thermal output plus parasitic and house
loads would be USt+SSt+PSt+HSt-BFR-MUW (Table BE-3, column 6 or Table BE-5,
column 6)
Gross thermal output for allocation measured as gross thermal output from the boiler less the
equivalent steam for a measured gross electric load would be BSt-BFR-MUW-GESTM.EQUIV
(Table BE-3, column 7 or Table BE-5, column 7)
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Section VI. E.: How do I calculate output data from supporting data?
E. How do I calculate output data from supporting data?
Thermal output
You can calculate the thermal energy or thermal output of a stream of steam or hot water as
follows:
Where:
Estm = total thermal energy in steam or water for an hour
H = enthalpy from standard thermodynamic steam table
Q = total mass flow of steam or water for an hour
If you have a flowmeter that measures the volume of steam or water instead of the mass, you
will also need to know the density or specific volume. You can find this information in steam tables
for saturated steam if you know the pressure or the temperature. Mass flow equals the volumetric
flow multiplied by the density.
To use the equation above, you will need to determine the enthalpy using a steam table. Here
is an example of how you would determine the enthalpy of saturated steam or hot water. You can
expect steam to be saturated in most industrial or institutional boilers. You will need to use the
absolute pressure of the steam or hot water, a measured value. For saturated steam, the temperature
is determined by the pressure. Below are example entries from ASME's steam tables in English
units. (The metric units are °C and K, kPa, cm3/kg, and kJ/kg.) Of the columns in the table, the ones
you need to be concerned about are the columns for temperature, absolute pressure, and enthalpy.
Typically, you will only need to use the column for the enthalpy of water or the column for the total
enthalpy of steam. (The column "Evap" refers to the enthalpy or latent heat needed to heat water at
the boiling point until it becomes steam at the boiling point, but you probably won't need to use this
column.)
If you knew you had warm water and a source's measurements gave an absolute pressure
reading of 0.5 psia, then the enthalpy of the warm water would be 47.62 Btu/lb. You would use this
enthalpy value in the equation above to calculate the energy in the water.
In another case, you have an absolute pressure reading of 200 psia. In this case, you will
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Section VI. E.: How do I calculate output data from supporting data?
determine the enthalpy of the steam from the table as 1198.3 Btu/lb of steam. Determining enthalpy
for steam is a more common case than determining enthalpy for hot water.
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Table VI-2: Saturated Steam Table (Excerpt)
Abs.
Pressure
psia
0.0886
0.5
14.696
200
Temp-
erature
°F
32.018
79.586
212
381.80
Specific Volume F(ft3/lb)
Water | Evap. | Steam
0.01602 3302.4 3302.4
0.01607 641.5 641.5
0.01672 26.782 26.80
0.01839 2.2689 2.287
Enthalpy H
(Btu/lb)
Water | Evap. | Steam
0.00 1075.5 1075.5
47.62 1048.6 1096.3
180.17 970.3 1150.5
355.5 842.8 1198.3
Entropy S
(Btu/lb' °F)
Water | Evap. | Steam
0 2.1872 2.1872
0.0925 1.9446 2.0370
0.3121 1.4447 1.7568
0.5438 1.0016 1.5454
Internal Energy U
(Btu/lb)
Water | Steam
0 1021.3
47.62 1036.9
180.12 1077.6
354.8 1113.7
Table VI-3: Superheated Steam Table (Excerpt)
Abs. Press, (psia) Property
(sat. temp, °F)
1 V (ftVlb)
(101.74) H (Btu/lb)
S(Btu/lb«°F)
15 V (ftVlb)
(213.03) H (Btu/lb)
S(Btu/lb«°F)
200 V (ftVlb)
(381.80) H (Btu/lb)
S(Btu/lb«°F)
2000 V (ftVlb)
(635.80) H (Btu/lb)
S(Btu/lb«°F)
Temperature, °F
100
0.0161
68.0
0.1295
0.0161
68.0
0.1295
0.0161
68.52
0.1294
0.0160
73.26
0.1283
200
392.5
1150.2
2.0509
0.0166
168.09
0.2940
0.0166
168.51
02938
0.0165
172.60
0.2916
300
452.3
1195.7
2.1152
29.899
1192.5
1.8134
0.0174
269.96
0.4369
0.0173
273.32
0.4337
400
511.9
1241.8
2.1722
33.963
1239.9
1.8720
2.3598
1210.1
1.5593
0.0184
377.19
0.5621
500 j 600
571.5
1288.6
2.2237
37.985
1287.3
1.9242
2.7247
1269.0
1.6242
0.0201
487.53
0.6834
631.1
1336.1
2.2708
41.986
1335.2
1.9717
3.0583
1322.6
1.6776
0.0233
614.48
0.8091
700
690.7
1384.5
2.3144
45.978
1383.8
2.0155
3.3783
1374.3
1.7239
0.2488
1240.9
1.3794
800
49.964
1433.2
2.0563
3.6915
1425.5
1.7663
0.3072
1353.4
1.4578
900
53.946
1483.4
2.0946
4.0008
1477.0
1.8057
0.3534
1408.7
1.5138
1000
57.926
1534.5
2.1309
4.3077
1529.1
1.8426
0.3642
1474.1
1.5603
Page 140
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Section VI. E.: How do I calculate output data from supporting data?
Here are two examples of how you would determine the enthalpy of superheated steam (also
called "supersaturated steam") using a steam table. You will need to use the measured temperature
and absolute pressure of the steam. Note that there are a number of possible temperatures for a
particular pressure.
In the first example, a stream of superheated steam has a pressure of 15 psi and a temperature
of 400°F, as measured with pressure and temperature transmitters. Its enthalpy from the table, H,
is 1239.9 Btu/lb.
In the second example, a stream of superheated steam at a pressure of 2000 psi and a
temperature of 800°C has an enthalpy of 1353.4 Btu/lb. Now you can multiply this value by the
mass flow of steam to determine the total energy in the steam.
Electric output
Many companies use watt-meters that measure electric power generation directly in MW.
In some cases, sources use current and potential transformers to monitor electric output. These will
measure current in amperes and potential in volts, rather than directly measuring electric power
generation in MW. One can calculate power from current and potential using the following
equation:
P= I-V
Where,
P is the power in megawatts, (MW)
I is the current in amperes (A), and
V is the potential in volts (V).
One can then calculate the MW-hr generation by multiplying the MW value by the length of time
for which it is measured.
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Section VILA.: What might my State require to ensure that individual sources monitor and report consistent and
accurate output data?
VII. Requirements for Sources: How should sources monitor, record, and report output data
to support updating output-based allocations?
If you intend to write your own requirements for companies to monitor, record and report
output data, there are a number of issues for you to consider. They are discussed in this section.
Conventional power plants will measure, and will receive allocations based on, electric
output. These conventional power plants will not need to measure any additional thermal energy for
the purposes of supporting data for allocations, because the conventional power plants use thermal
energy to produce electricity, rather than for other useful purposes. Industrial or institutional boilers
and turbines that do not generate electricity will measure, and will receive allocations based on,
thermal output. These industrial or institutional boilers and turbines will not need to measure any
additional electric output for the purposes of supporting data for allocations.
Facilities that produce both electricity and steam or hot water as useful outputs will need to
measure both thermal and electric output. Most of these are cogeneration facilities, also called
combined heat and power (CHP) facilities. Cogeneration facilities tend to be more efficient because
they produce thermal output and electric output in sequence, from the same heat input. In order to
determine net output, facilities producing both kinds of output will need to account for parasitic and
house loads for both electricity and steam or hot water. Cogeneration facilities can be classified
either as electric generating units or as non-electric generating units, depending on the characteristics
of the unit and the associated generator.
A. What might my State require to ensure that individual sources monitor and report
consistent and accurate output data?
You need to develop a procedure to ensure that output monitoring and reporting are
performed in a clear and consistent manner. For NOx emissions data, the monitoring and reporting
provisions under Part 75, Subpart H specify the requirements which ensure that the data collected
are consistent and accurate. As monitoring of output data is simply another type of monitoring, you
can apply to output monitoring, when appropriate, the existing processes under Part 75 designed to
ensure consistent and accurate monitoring. This will promote both consistent and accurate data and
a more cost-effective compliance process. Where feasible, you should incorporate output monitoring
into the existing framework of Part 75, Subpart H monitoring requirements that you are using to
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Section VILA.: What might my State require to ensure that individual sources monitor and report consistent and
accurate output data?
ensure that emissions are accurately monitored.
Below is a list of the major steps in emissions monitoring which are designed to ensure
consistent and accurate emissions monitoring. Later in section VII.B, "How detailed or prescriptive
should output monitoring and reporting requirements be in my State rule?" (pp. 144-150), we suggest
three different means of incorporating output monitoring into these existing processes.
• Monitoring Plan Review Process: Each source must submit a monitoring plan which
describes how emissions (and possibly output) will be monitored. You will review
each monitoring plan. The primary function of the monitoring plan review process
is to allow you to ensure that each source is monitoring in a manner consistent with
other similar sources in the trading program.
Installation of Monitoring Equipment: This step is necessary if the company has not
already installed monitoring equipment that can meet regulatory requirements.
• Certification Test Protocol Process: Once a company has determined how it will
monitor and has a reviewed monitoring plan, it submits a test protocol for review.
The test protocol describes how all monitoring systems will be certified. The primary
function of the certification test protocol is to allow regulators to ensure that the
testing approach will meet the requirements for certification. For emission monitors,
certification requirements are set forth under Part 75.
Certification Application and Approval Process: Once a source has a reviewed testing
protocol and performs the required certification testing, the NOx authorized account
representative submits the results of the testing for approval. The primary function
of the certification application and review process is to allow you to ensure that each
source has passed the required certifications tests and has a monitoring system
capable of meeting the accuracy requirements in Part 75. While there are exceptions,
collected data generally can be invalidated retroactively until the initial certification
application is approved.
Ongoing QA/QC Procedures: Once a monitor passes the initial certification, it must
also continue to pass different quality assurance (QA) tests and the company must
perform quality control (QC) activities. The primary function of ongoing QA/QC
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Section VII. B.: How detailed or prescriptive should output monitoring and reporting requirements be in my State
rule?
procedures is to ensure that the monitoring systems are not neglected so that accuracy
remains high over the life of the system. Sources must report the results of QA/QC.
Missing Data Substitution During Monitor Outage: For a certified emissions
monitoring system which does not pass a required QA test, data are considered
invalid or missing during the time period that lasts from the end of the failed test
until corrective maintenance has been performed and the required QA test has been
passed for a the monitoring system. A company must substitute emissions data
during the period of missing data. Additionally, if an emissions monitoring system
malfunctions and fails to collect data due to a problem or needs maintenance while
a unit is operating, the use of missing data substitution is required during this period.
You may include all or only some of these requirements in your output monitoring rule. In
the next section, we lay out three different options which use some or all of the procedures above
for output monitoring.
B. How detailed or prescriptive should output monitoring and reporting requirements be in
my State rule?
Here are three options for how a regulator could approach establishing requirements for
monitoring, recording, and reporting output data. These three options differ in how detailed and
extensive requirements are. Each option will require a different level of effort for regulators and for
companies and will result in a different level of quality assurance on the output data.
Option #1 The Detailed Monitoring Option.
Monitoring emissions includes the basic steps outlined above in the previous section,
namely, monitoring plan review, certification test protocol review, certification test results
approval, ongoing QA/QC procedures and reporting of results, hourly and summary output
data reporting, and missing data substitution for a monitoring system outage. You could
choose to apply this approach to monitoring output. If you choose this option, you should
do the following:
Specify what type of output must be monitored and by which sources (for example, net
electric output and net thermal output from electric generating units).
• Define the monitoring and reporting requirements in your State rule. This would include
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Section VII. B.: How detailed or prescriptive should output monitoring and reporting requirements be in my State
rule?
monitor location procedures, certification test protocol requirements, accuracy requirements
for initial certification tests, ongoing QA/QC procedures, reporting procedures, missing data
substitution procedures, and procedures for failure to comply with the above requirements.
• Require each affected source to submit a hardcopy output monitoring plan for State review.
See section VII.F., "What should a source be required to report in a monitoring plan?" (pp.
153-155) for a description of what a monitoring plan would contain. Although Part 75
requires companies to submit monitoring plans no later than 45 days before beginning a
certification test, we recommend that companies should submit monitoring plans at least a
year prior to the date which output monitoring is required. Experience gained in
implementing the Acid Rain Program and the OTC NOx Budget program indicate that few
initial monitoring plan submissions are 100% error-free. Thus, you should plan on having
to comment on and request resubmission of the monitoring plans. The monitoring plan
review process may require several cycles of submission, review and comment and
resubmission before a facility' s monitoring plan is acceptable. If a source has not already
submitted a monitoring plan for emission monitoring equipment, it should incorporate the
portion of the monitoring plan on output monitoring equipment into the monitoring plan for
emission monitoring equipment. If a source has already submitted a monitoring plan for
emissions monitoring, then the submission should be treated as an update to the hardcopy
portion of the monitoring plan.
• Require each affected source to submit a hardcopy test protocol for State review. In general,
a test protocol would describe in detail the standards and procedures used to certify
equipment. See section VII.G., "What Certification, Quality Assurance and Quality Control
procedures should be required for output monitoring?" (pp. 155-161) for a description of
tests, standards or procedures which would be included in a test protocol. An output
monitoring equipment test protocol should be required to be included with the certification
test protocol for emission monitoring equipment at the source unless the emissions
monitoring test protocol has already been submitted. Some States require companies to wait
for approval of their test protocols before proceeding with testing. However, this is not a
requirement of Part 75. If you intend to do this, you must add such a requirement in your
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Section VII. B.: How detailed or prescriptive should output monitoring and reporting requirements be in my State
rule?
State rule.
Require each affected source to submit an initial certification application for each output
monitoring system for your approval.
• Require each affected source to submit ongoing QA/QC test results for output monitoring
equipment to you. You will need to devise a methodology for sources to report the QA/QC
test results for output monitoring equipment outside the electronic format used for reporting
emissions data to EPA.
• Require each affected source to record and report output data. Under this option, a source
would record hourly data. If any data were missing or invalid, the source would perform
missing data substitution on an hourly basis. As the current electronic reporting format does
not fully support reporting output data, you would have to devise your own data reporting
procedure.
Some of the issues which arise if you choose to follow this option are:
This is a proven method of collecting good data and will provide a high level of confidence
that no source under-reports or over-reports output data.
• This methodology ensures that all sources are monitoring in a consistent manner so that all
output data is equivalent.
This option contains built-in incentives to continually ensure that the output data collected
are valid. The primary incentive is the substitution of unfavorable values when monitors
malfunction or fail routine QA tests.
• Reporting of hourly data allows you a high level of detailed information for data analysis for
errors.
The regulated community is accustomed to this option under the Acid Rain Program and the
OTC NOx Budget Program.
• This option can have additional costs for you and for sources that are associated with
implementation and ongoing reporting of output data. In particular there are costs associated
with new data collection and reporting requirements, monitoring plan development,
certification testing, and ongoing QA/QC.
• You may have limited resources for reviewing ongoing QA/QC data. A resource intensive
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Section VII. B.: How detailed or prescriptive should output monitoring and reporting requirements be in my State
rule?
option might be a problem given the limited resources available. In particular the monitoring
plan review process, certification application review process, and hourly data quality
assurance process are resource-intensive for an agency.
Option #2 The Simplified Option
The simplest regulatory option would be to only require reporting of output data with no
associated monitoring methodologies or quality assurance requirements. This option, which is
currently used in the Acid Rain Program to collect gross hourly output in MWh or klb steam, is
associated with a lower level of effort on the part of regulatory agencies and provides the lowest
assurance of quality data of the three options. (Note that output data do not play a major role in the
Acid Rain Program, which does not allocate allowances based on output.) Under this option, you
would need to do the following:
• Specify what type of output must be monitored and by which sources (for example, net
electric output and net thermal output from electric generating units).
Specify the requirements for reporting data to you. The output data should be calculated
from hourly data and reported in hourly, daily, weekly, or monthly format.
• The source does not need to file an output monitoring plan, testing protocol, certification
application, or QA/QC test results for output monitoring equipment.
Carefully review the following list of issues related to this option:
• This option has the lowest assurance of the three options that data reported are accurate.
• This is the easiest option for any sources which already have output monitoring systems.
This option has the lowest assurance of the three options that output monitoring is consistent.
There is little or no standardization of output monitoring under this option.
• This option does not address at all what a source should do if it does not have output data.
• There would be no means available to require sources which over-report output to correct
either their monitoring option or any data which are clearly erroneous, as no requirements
exist.
• This is the simplest and least resource-intensive option.
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Section VII. B.: How detailed or prescriptive should output monitoring and reporting requirements be in my State
rule?
Option #3 The Intermediate Option
In this intermediate option, you would require consistent monitoring and QA/QC through the
monitoring plan submission and review process. You would reduce the oversight on certification
and ongoing QA/QC testing from Option #1 by simply requiring that a source document the QA/QC
plan for the output monitoring system in its monitoring plan. You could also allow the data
collection and reporting requirements to be somewhat less prescriptive than that for monitoring
emissions. Under this option, a source would simply submit an output monitoring plan which
describes the monitoring methodology used, the initial and ongoing QA/QC test procedures, the data
recording procedures, and any provisions which will be used for filling in missing data. Under this
option, you would specify the output monitoring system accuracy. The source would prepare a
document which describes an output monitoring option designed to meet the accuracy requirement
on a system basis. You could require that this document be prepared by a qualified professional
engineer and could require that the NOx authorized account representative sign a statement
indicating he or she certifies that the system meets or exceeds the accuracy requirement. At a
minimum, the "output quality assurance plan" would meet the requirements under the monitoring
plan contents (see section VII.F., "What should a source be required to report in a monitoring plan?",
pp. 153-155) and would describe the QA/QC activities under section VUG., "What Certification,
Quality Assurance and Quality Control procedures should be required for output monitoring?" (pp.
155-161).
Under this option, sources would submit the QA/QC plan for review and approval. You
would have flexibility to require periodic QA/QC testing to ensure that the output system is actually
monitoring output accurately.
Your State rule would clearly define the QA/QC plan approval requirements. It would further
indicate the steps your State would take if the output data were suspected of being inaccurate. You
would have to do the following to implement this option:
Specify what type of output must be monitored and by which sources.
Specify the system accuracy of output monitoring systems.
• Require that sources submit a monitoring plan for your approval. The monitoring plan
includes the necessary data to provide assurance that the source is monitoring in an
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Section VII. B.: How detailed or prescriptive should output monitoring and reporting requirements be in my State
rule?
acceptable fashion and is performing adequate QA/QC on the output monitoring system.
Require each affected source to record output data and report the data to you in a specified
manner and format.
• Provide provisions in your rule which allow you to audit and require changes in output
monitoring if the system does not meet the accuracy requirement.
Some of the issues which arise if you choose to follow Option #3 are:
• This approach could give reasonable assurance that data reported are accurate.
• This is an easy option for any sources that already have output monitoring systems.
You would be able to audit and require a source to follow the QA/QC plan if you suspect that
a source is not reporting output correctly.
• This is a simpler option that the traditional Part 75 approach for emissions.
• It gives you some ability to ensure that the output monitoring generally is consistent and
acceptable. Because you will accomplish this through case-by-case monitoring plan review,
not through regulations, the effort may be more difficult and more resource intensive than
under Option #1.
• Missing data substitution procedures are addressed by sources, although they would not
necessarily be consistent from one source to another.
• This option provides sources with much greater flexibility in designing a system which meets
the accuracy requirement.
Other options exist for you to consider.
Choosing Between Options #1. #2. #3 and Other Options.
The fundamental reason we use Option #1 (the detailed approach) for pollutant emissions
is to ensure consistent and accurate pollution emissions data. The level of agency oversight in using
this approach is necessitated by the need to ensure environmental protection and to ensure that
emissions remain below the level of the "emissions cap". This approach relies heavily on the
incentives provided through the use of missing data substitution procedures and the required QA/QC
provisions to ensure accurate data with any errors being conservative (that is, environmentally
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Section VII. C.: What output measurement equipment must affected facilities use ?
protective) in nature. The missing data substitution procedures under Part 75 for emissions use a
progressive approach where the values are near or at the average emissions when a monitor has a
history of few outages, and the values are at the maximum potential emission when a monitor outage
lasts over an extended period.
Output monitoring is different than emissions monitoring in that, while some ancillary
environmental benefits may result from allocating through output, the "cap" on emissions is fixed
and any error in output would not result in emission exceeding the "cap". Because of this difference,
it may not be necessary to require the same level of agency oversight and required QA/QC for output
monitoring as that required under Option #1 (the detailed monitoring approach).
Another difference between emissions monitoring and output monitoring is that each source
potentially has an interest in ensuring that other sources do not overestimate their output. This is due
to the fact that if one source in a State under a fixed budget for allowance allocations overstates its
output and therefore receives additional allowances, the additional allowances it receives comes at
the expense of other sources in the State.
C. What output measurement equipment must affected facilities use?
The equipment for monitoring electric output is already in place, is in most cases monitored
consistently, and in most cases is sufficiently accurate; thus, this part of monitoring presents
relatively few problems for the State wishing to create a rule for monitoring output. Monitoring
thermal output presents more problems as the monitoring is not performed consistently, the
equipment has varying degrees of accuracy, and in some cases the equipment necessary to monitor
output with a sufficient degree of accuracy is not currently installed. Additionally, sources may not
necessarily monitor output at a location that corresponds to the location where you want to allocate
NOx allowances. Electric generating systems that are not fossil fuel-fired can measure electric
output as described in this section for electric generating units. See section VII.G., "What
Certification, Quality Assurance and Quality Control procedures should be required for output
monitoring?" (pp. 155-161) for a discussion about monitoring technologies and their accuracy.
D. When must facilities start measuring output?
Sources would need to measure and record output-related information no later than May 1
of the year four years before the first year for which you plan to update allocations based on output
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Section VII. G.: What records must affected facilities keep and report to support output-based allocations?
data. For example, if you intend to update allowance allocations for the year 2006 using output,
sources would need to measure and record output data beginning no later than May 1, 2002. You
then would be able to calculate and allocate allowances in the year 2003, consistent with the NOx
Budget Trading Program procedure of allocating NOx allowances at least three years ahead.
E. What records must affected facilities keep and report to support output-based allocations?
The records a facility must keep and report depends on the monitoring option you choose
(Options #1, #2, or #3 from section VII.B. "How detailed or prescriptive should output monitoring
and reporting requirements be in my State rule?", pp. 144-150), the monitoring approach (the
simplified approach or the boiler efficiency approach to monitoring thermal output from section VI.,
"Where could facilities monitor electric and thermal output?", pp. 55-141), and the data collection
frequency you specify.
Monitoring Plan
See section VII.F., "What should a source be required to report in a monitoring plan?" for
a description of information to be reported in a monitoring plan (pp. 153-155).
Data Reported to the State
The first issue you should resolve is whether output data you receive should be raw hourly
data, or should be some summary data (daily, weekly monthly or ozone season totals) based on
hourly records. While other options exist, data that is based on hourly values recorded in a
datalogger or computer and kept as records is consistent with the current monitoring requirements
and is also consistent with the data used for sales of electric and steam. Because of these reasons,
we recommend that hourly data be either reported or kept as records for at least three years from the
date of the record's creation.
Under Option #1 for monitoring and reporting (the detailed option) you would probably
require reporting of hourly data and some summary values. Monthly or ozone season output values
will give you the data you need for allocations. If you require data to be reported for each hour, you
may want to have companies report for calendar quarters so that you do not need to review data from
an entire ozone season at once. Under Options #2 and #3 (the simplified option and the intermediate
option), you would likely get ozone season or monthly output data. In this case, it may be easier for
you to require a single report at the end of the ozone season, unless companies already are sending
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you quarterly reports for other requirements. Under all options, we believe that you should require
that the data reported be calculated from hourly data. This is because reporting hourly data will be
consistent with sales data and because we believe that hourly data captures the variability of output
processes sufficiently to ensure accurate data. For example, thermal output data are calculated from
measurements of steam or water flow rate, temperature, and pressure information, which vary over
the course of an hour.
We recommend that you require facilities that receive output-based allocations to keep
records of hourly data and totals for the ozone season for electric generation and thermal output.
Companies should keep this information for each location (unit or generator or facility) where the
output is measured. You also could request the supporting data kept on site (or at the company's
offices). You also could decide if you want net output data, gross output data, or both.
Output information
For each electric generating unit, for each non-emitting electric generating system, or for each plant:
Keep hourly records of the gross or net electric generation in MWh.
For each electric generation unit that cogenerates and for each non-electric generating unit that
produces steam:
Keep hourly records of the net or gross thermal output, in mmBtuout. (See section VIE.,
"How do I calculate output data from supporting data?", pp. 138-141, for how to calculate
thermal output.)
• Keep hourly records of the steam pressure, temperature and calculated enthalpy, in mmBtuout.
(See section VI.E, "How do I calculate output data from supporting data?", pp. 138-141, for
how to calculate enthalpy.)
• Keep hourly records of the net or gross steam flow rate after steam has been diverted for
generating any electricity, in thousands of pounds of steam per hour (klb/hr).
Keep hourly pressure (psi) and temperature (°F) readings for any location that is not under
saturated steam conditions.
• Keep hourly pressure (psi) readings for any location under saturated steam conditions.
These records may be kept on site or at a corporate office, provided that the company can provide
these records to inspectors during the day of an inspection or audit.
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Section VII.F.: What should a source be required to report in a monitoring plan?
Quality assurance and certification test data
If you choose Option #1 for monitoring output (the detailed option ), you will need to require
both reporting and record keeping for QA/QC test results. The test results should include:
• Descriptions of the standard used to test the equipment, e.g., NIST traceable, ANSI C12.16,
IEEE 57.13
Actual values recorded or determined under each test.
• Tables or calculations if necessary to compute accuracy.
• Results of the test, pass or fail.
Date and time of test.
F. What should a source be required to report in a monitoring plan?
Output Monitoring Plan
If you decide to require that sources submit an output monitoring plan, we suggest that the
description of the output monitoring system be included in the hardcopy monitoring plan submitted
for emission monitoring system approval.
Under Option #1
If you choose to use Option #1 for monitoring and reporting (the detailed option) or if you
choose to use Option #3 for monitoring and reporting (the intermediate option), you would probably
require sources to submit an output monitoring plan. The descriptions should include at a minimum
the following information.
• A diagram of the electrical or steam system for which output is being monitored.
If you require monitoring of gross electric output, the diagram should contain all affected
units and all generators served by each affected unit and the relationship of units to
generators. If a generator served by an affected unit is also served by a non-affected unit, the
non-affected unit and its relationship to each generator should be indicated on the diagram
as well. The diagram should indicate where the gross electric output is measured.
If you require monitoring of gross thermal output, the diagram should include all input
energy streams and output energy streams connected to each boiler. For a complex situation,
this would be all streams to and from a group of boilers which serve a common steam
system. This would include steam out, boiler feedwater return, and make-up water energy
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Section VII.F.: What should a source be required to report in a monitoring plan?
streams. The diagram should include estimated average flow rates in Ib/hr so that a mass
balance of all streams may be performed which satisfies the law of conservation of mass
(e.g., the sum of all input streams in Ib/hr = the sum of all exit streams in Ib/hr) In addition,
each steam will have an estimated temperature, pressure and phase indicator (L = liquid, S
= saturated steam, SS = superheated steam) and an enthalpy estimate in Btu/lb. The diagram
will also indicate all flow meters, temperature or pressure sensors, or other equipment used
to calculate gross thermal output.
• If you require monitoring of net electric output, the diagram should contain all affected units
and all generators served by each affected unit and the relationship of units to generators.
If a generator served by an affected unit is also served by a non-affected unit, the non-
affected unit and its relationship to each generator should be indicated on the diagram as
well. The diagram should indicate where the net electric output is measured and should
include all electrical inputs and outputs from to plant. If net electric output is determined
using a billing meter, the diagram should show the billing meters used to determine net sales
of electricity and should show that all electricity measured at the point of sale is generated
by affected units.
If you require monitoring of net thermal output, the diagram should include all steam or hot
water coming into the net steam system, including steam from affected and non-affected
units, and all exit points of steam or hot water from the net steam system. In addition, each
input and output stream will have an estimated temperature, pressure and phase indicator (L
= liquid, S = saturated steam, SS = superheated steam) and an enthalpy in Btu/lb. The net
steam system should identify all useful loads, house loads, parasitic loads, any other steam
loads and all boiler feedwater return. The diagram will represent all energy losses in the
system as either usable or usable losses. The diagram will also indicate all flow meters,
temperature or pressure sensors or other equipment used to calculate gross thermal output.
If a sales agreement is used to determine net thermal output, the diagram should show the
monitoring equipment used to determine the sales of steam.
The monitoring plan should provide a description of each output monitoring system. The
description of the output monitoring system should include a written description of the output
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Section VII. G.: What Certification, Quality Assurance and Quality Control procedures should be required for
output monitoring?
system, the equations used to calculate output. For net thermal output systems descriptions and
justifications of each useful load should be included.
The monitoring plan should provide a description and a data flow diagram of how data from
each component of the output system is collected and how the data is transferred to the data
acquisition and handling system for determining output. This is not necessary for billing meters used
to determine output, if you intend to let a company report the information from its billing data
records. In that case, it may be more appropriate for the monitoring plan to show the flow of data
from the billing meter to the company's system for collecting and recording data from the billing
meter.
Under Option #3
If you choose to use Option #3 for monitoring and reporting (the intermediate option), you
should also require the NOx authorized account representative (NOx AAR) to submit the following
additional information in the monitoring plan:
A detailed description of all quality assurance quality control activities which will be
performed to maintain the output system. In the case where billing meters are used to
determine output, you do not need to require QA/QC activities beyond what the company
already performs. Also, current transformers and potential transformers do not require
QA/QC testing, and thus do not need a list of QA/QC procedures in their monitoring plan.
A certification statement by a professional engineer stating that the output monitoring system
meets an accuracy of 10% of the reference value, or that each component monitor for output
meets an accuracy of 3% of the full scale value with the engineer's stamp and the
certification of the NOx AAR that this is true.
G. What Certification, Quality Assurance and Quality Control procedures (QA/QC) should
be required for output monitoring?
Initial certification of accuracy
If you choose to require initial certification of output monitoring systems, we suggest that
sources send an initial certification of the accuracy of their output measurement equipment to their
permitting authority no later than May 1, 2002. This will give sources time to verify the accuracy
of their equipment before the recording of data (i.e., prior to the ozone season in 2002) that will be
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Section VII. G.: What Certification, Quality Assurance and Quality Control procedures should be required for
output monitoring?
used to develop allowance allocations for the year 2006 under the Part 96 model rule. If you choose
to start allowance allocations based upon output after the year 2006, sources would need to certify
the accuracy of their output measurement equipment no later than May 1 of the year that is four years
before the year for which you first allocate NOx allowances using output data.
Any output measurement equipment used as a billing meter in commercial transactions does
not require certification or testing requirements. To qualify as a billing meter, the measurement
device must be used to measure electric or thermal output for commercial billing under a contract.
The facility where the measurement device is located must have different owners from the owners
of the party purchasing the electric or thermal output. The billing meter must record the hourly
electric or thermal output. Any electric or thermal output values that the facility reports must be the
same as the values used in billing for the output.
Test specifications
You must decide whether to specify system accuracy requirements, or component accuracy
specifications for output monitoring systems, or both. (See below in this section under "System
accuracy determination"., p. 158, for a discussion of what we mean by an output monitoring
system.) A system accuracy of 10% of the reference value would be an acceptable accuracy criteria.
For a simple output monitoring system, such as a single electric meter on the terminals of a
generator, the component and system would be the same and the accuracy of the system would equal
the accuracy of the individual component (10% of reference value). However, for a net thermal
output system on a non-electric generating unit, the system might consist of two or more steam flow
sensors, several temperature sensors, and several pressure sensors. In this case, to achieve a 10%
accuracy for the system the individual components should have a more stringent accuracy
specification. A simple calculation used to estimate the error associated with multiple components
whose individual errors contribute to a system error is the following statistical equation.
F — I
system ~ I / ^component
( all components
Where
Ecomponent= maximum error asociated with each component of a system
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Section VII. G.: What Certification, Quality Assurance and Quality Control procedures should be required for
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Esystem= maximum theoretical error of the system.
Using this equation we find that two components with error of 10% can lead to a system error
of 14.1% in a worst case scenario. Three components could have 17.3% error and so on. A system
with 11 components with 3% error each would have a maximum system error of 9.9% using the
above equation. It is likely that many steam systems will have at least 11 separate components such
as flow meters , temperature sensors. While other choices are possible, a 3% accuracy for each
component would be an acceptable accuracy for up to 11 individual components when a system
accuracy can not be readily determined.
Any individual component equipment reading output must be capable of measuring to within
3.0 percent of full scale for that piece of equipment. Most of the existing technologies for measuring
output are capable of reading to this level of accuracy21.
System accuracy determination
A monitoring system is a collection of component pieces of equipment which are used
together to get a measurement in the units of measure that you require under a regulation. An
example of an emissions monitoring system is a system for measuring NOx emission rate in
Ib/mmBtu, which includes a NOx pollutant concentration monitor, a CO2 or O2 diluent monitor, and
a data acquisition and handling system. An output monitoring system might consist of the following
components:
All wattmeters and a data logger that a company uses together to calculate the final net or
gross electric output data that you will use to calculate allocations.
• All flowmeters for steam or condensate, temperature measurement devices, absolute pressure
measurement devices, and differential pressure devices for measuring thermal energy and a
data logger. These are all the measurement devices that a company uses together to calculate
net or gross thermal output data that you will use to calculate allocations.
If you decide to adopt a system approach to accuracy based on a professional engineering
21See Chapter 6 of Flow Measurement Engineering Handbook, 3rd Edition, by R.W.
Miller (McGraw Hill, 1996). Also, the Massachusetts Department of Environmental Protection
has pointed out that existing measurement technologies can meet an accuracy level of 3 percent.
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Section VII. G.: What Certification, Quality Assurance and Quality Control procedures should be required for
output monitoring?
analysis as described above in sections VII.B "How detailed or prescriptive should output monitoring
and reporting requirements be in my State rule?" and VII.F., "What should a source be required to
report in a monitoring plan?" (pp. 148, 155, respectively), then the description should include a
determination of how the system accuracy of 10% is achieved using the individual components in
the system.
Test procedures and standards for individual components
The following table lists existing consensus standards that include instructions for calibration
or testing of individual equipment to measure steam flow or electricity. We suggest that sources
follow these consensus standards, where possible. However, this list is not comprehensive. You
should also allow companies the flexibility to petition to use another method of sufficient accuracy,
especially if they are methods from standard-setting or professional organizations. Consensus-based
industry standards are acceptable from the following organizations:
• American Gas Association (AGA)
• American National Standards Institute (ANSI)
• American Society of Mechanical Engineers (ASME)
• American Society for Testing and Materials (ASTM)
• Institute of Electrical and Electronics Engineers (IEEE) or
• Instrument Society of America (ISA)
Table VII-1: Consensus Standards for Assuring Accuracy
of Output Measurement Equipment
Eauioment tvoe
Electric generation
Solid-state kilowatt meters
Rotating kilowatt meter
Electromechanical kilowatt meter
Current transformers
Potential transformers
Number or name of standard
ANSI C12. 16 or ASME PTC 19.6
ANSIC12.10, ANSIC12.13, ANSIC12.15, or
ASME PTC 19.6
ANSIC12.10, ANSIC12.13, ANSIC12.15, or
ASME PTC 19.6
IEEE/ANSI 57.13, ANSI C12.ll or ANSI C93.
IEEE/ANSI 57.13. ANSI C12.ll or ANSI C93.
1
1
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Section VII. G.: What Certification, Quality Assurance and Quality Control procedures should be required for
output monitoring?
Equipment tvpe
Steam
Pressure taps
Flow venturi
Orifice plate
Flow nozzle
Vortex meters
Turbine meters
Water (condensate)
Orifice plate
Coriolis meters
Pressure
Pressure transmitters
Differential pressure transmitters
Temperature
Temperature transmitters
Thermocouples
Resistance Temperature Detectors
Number or name of standard
AGA Report 3, ASME PTC 19.2, or ASME
MFC-3M
ASME MFC-3M for initial installation
AGA Rpt. 3, ASME MFC-3M for initial
installation
ASME MFC-3M for initial installation or ASME
PTC-6
ASME MFC-6M
ASME MFC-4M; AGA Rot. 7
AGA Rpt. 3 or ASME MFC-3M for initial
installation
ASME MFC-9M or ASME MFC-1 1M
ASME PTC 19.2
ASME PTC 19.2
ASME PTC 19.3
ASME PTC 19.3
ASME PTC 19.3
Some of these methods require that the equipment be tested outside of the plant or require
that the generating system or unit not operate during the test. Obviously, this could be inconvenient
for sources. It is reasonable to consider other alternative procedures for checking the accuracy of
equipment that do not require removing equipment from the plant. Any alternative procedures
would need to provide you with reasonable confidence that the equipment are reading to within 3.0
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Section VII. G.: What Certification, Quality Assurance and Quality Control procedures should be required for
output monitoring?
percent of the actual output provided by a reference reading.
In addition to the consensus standards for particular technologies, sources can check various
kinds of transmitters (e.g., temperature or pressure transmitters) against standards traceable to the
National Institute of Standards and Technology (NIST). Section 2.1.6.1 of Appendix D of 40 CFR
Part 75 gives procedures for testing transmitters using NIST traceable standards.
Frequency of testing
Certain types of equipment only require an initial certification of calibration and do not
require periodic recalibration unless the equipment are physically changed:
• potential transformers
• current transformers
primary element of an orifice plate (However, the accompanying pressure and temperature
transmitters will require periodic retesting.)
Any output measurement equipment used as a billing meter in commercial transactions
should not need additional requirements for periodic quality assurance testing. A meter that is
sufficiently accurate for commercial transactions should also be sufficiently accurate for providing
data to support allocations.
For other types of equipment, we suggest that sources either recalibrate or reverify the meter
accuracy at least once every two years (i.e., every eight calendar quarters), unless a consensus
standard allows for less frequent calibrations or accuracy tests.
Consequences of failing a QA test
If testing a piece of output measurement equipment shows that the output readings are not
accurate to 3.0 percent or less of the full scale, then the source must retest the measurement
equipment and meet that requirement. The data should be consider invalid, prospectively, for
purposes of determining allocations. Data would remain invalid until the output measurement
equipment passed an accuracy test or were replaced with another piece of equipment that passes the
accuracy test. The source would need to omit the invalid data and report either zero or an output
value that is likely to be lower than a measured value (see section VII.H., "How would a source
substitute missing data for output?", p. 161)
How to correct a test failure
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Section VII. H.: How would a source substitute missing data for output?
The source must retest the measurement equipment and demonstrate that it meets the
accuracy specification you set (e.g., accurate to 3.0 percent or less of full scale for a component or
accurate to 10.0 percent or less of the reference readings for an output monitoring system).
Alternatively, the source could replace the failing equipment with other equipment that meets this
accuracy specification.
Documentation
The source will need to keep the records described above in section VII.F., "What records
must affected facilities keep and report to support output-based allocations?" (pp. 153-155).
H. How would a source substitute missing data for output?
If you choose to require missing data substitution procedures, we suggest it be of a very
simple and easy to implement nature. The easiest approach is to assume that a source has no output
during any missing data period. Other options include using the average of the values before and
after the outage as the substitute value or using a minimum value for estimating output.
I. What other monitoring requirements must facilities meet if they are not fossil fuel-fired?
All facilities receiving output-based allocations must measure, quality-assure, record, and
report information on output.
Sources that are not fossil fuel-fired
If you include sources emitting NOx that are not fossil fuel-fired, then you will need to add
requirements for the owner or operator of those sources to monitor, record and report NOx mass
emissions and source operating information (e.g., hours of operation). A source emitting NOx would
have to account for its NOx emissions if it is allocated NOx allowances. Companies can monitor
NOx, heat input, and output from these sources in the same way as for fossil fuel-fired units. The
discussions in the rest of section VII, "Requirements for Sources: How should companies monitor,
record, and report output data to support updating output-based allocations?" (pp. 142-162) also
apply to non-fossil fuel-fired sources.
Facilities that do not emit NOx
If you choose to allocate NOx allowances to facilities or generating systems that do not emit
NOx, such as hydroelectric or nuclear power plants, they will need to measure, quality-assure,
record, and report information on electric output. The discussions in the rest of section VII.
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VII.I. What other monitoring requirements must facilities meet if they are not fossil fuel-fired!
"Requirements for Sources: How should companies monitor, record, and report output data to
support updating output-based allocations?" (pp. 142-162) also apply to non-emitting generating
systems. In addition, these sources would need to keep records of hours of operation during the
ozone season. (The discussion in section VII.F. "What records must affected facilities keep and
report to support output-based allocations?", pp. 153-155, assumes that fossil fuel-fired units are
already monitoring their hours of operation, as required by 40 CFRPart 75.)
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Section VIII.A.: What are potential sources of output data?
VIII. Data Sources: Where do I get the data for an output-based allocation?
A. What are potential sources of output data?
There are three main sources of electric generation data and one source of thermal output
data:
Electric generation data
*• Collect data directly from facilities in your state.
> Get data from EPA. Quarterly emission reports under the Acid Rain Program contain gross
electric generation data for many power plants in the Program, starting in 1995. Some power
plants choose to report steam flow to EPA instead of gross electric generation, so this is not
a complete source of gross generation data. Furthermore, these data are not quality-assured
by the Agency. For more information on data available from the Acid Rain Program, you
can check the Acid Rain Program's Web site (http://www.epa.gov/acidrain/edata.html) or
call the Acid Rain Hotline at (202) 564-9620.
> Get data from the Energy Information Administration (EIA). EIA collects electric generation
for certain utility and non-utility generators. These data were previously collected on EIA
forms 759, 767, and 86722 and will continue to be collected on EIA forms 759, 767, 860B
and 900. Form 759 provides net electric generation for utility plants (not units or generators)
on a monthly basis for each year during the 1990s23. Form 767 provides net electric
generation for utility generators connected to boilers24 for each month during 1997 and
earlier. Form 767 information is not available for turbines or combined cycle systems.
Form 860B provides annual gross electric generation from non-utility generators25 during
22Electric generation on form 867 for non-utility generators is confidential for specific
plants. This form was discontinued in 1997 and was replaced by forms 860B and 900.
23If each of the utility's plants has a total nameplate capacity of less than 50 MW, then the
utility only needs to report annually instead of monthly.
24 Utilities will report electric generation for plants with a total nameplate capacity of 100
MW or more.
25 These include qualifying facilities under the Public Utilities Regulatory Policies Act
and exempt wholesale generators under the Energy Policy Act. Plants with a nameplate capacity
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Section VIII. B: What should I consider when choosing a source of output data?
1998 and later. Form 900 provides monthly net (or gross) electric generation from non-
utility generators26 during 1999 and later. For more information about the appropriate
contact people at EIA for these forms, you can check EIA's Web site
(http://www.eia.doe.gov/contacts/main.html) or you can contact the National Energy
Information Center at infoctr@eia.doe.gov, Telephone: (202) 586-8800.
Thermal output data
> Collect data directly from facilities in your state.
B. What should I consider when choosing a source of output data?
Here are some factors you will want to consider when deciding from where to get your output
data.
Data for electric generating units or for non-electric generating units
If you intend to allocate allowances on the basis of output to non-electric generating units or
cogeneration units, it will be necessary for you to collect thermal output data directly from sources
in the short term.
Data for conventional power plants (not cogeneration facilities)
If your state has only electric generating units, and none of them are cogenerators, you will
only need electric generation data. In this instance, it may be possible to use any of the three data
sources. Note that EIA's electric generation for non-utility generators is treated as confidential and
is not available for years before 1998.
Size of affected sources in your State
EPA's data are not and will not be available for electric generating units serving generators
of 25 MW or less. In addition, EPA's gross generation data are not currently available for simple
combustion turbines that were built before November 15,1990. Some data from EIA forms are not
available for plants with a total nameplate capacity less than 100 or 50 MW, or at least not available
on a monthly basis.
of 1 MW or greater must file this form.
26 These include qualifying facilities under the Public Utilities Regulatory Policies Act
and exempt wholesale generators under the Energy Policy Act. Non-utility electricity generating
plants with a nameplate capacity of 50 MW or greater must file this form.
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Section VIII. B: What should I consider when choosing a source of output data?
Use of gross or net generation data
EPA's current generation data are gross electric output data for many, but not all, utility units
in the Acid Rain Program. EIA' s generation data are net generation values for utility generators and
are a mixture of net and gross generation values for non-utility generators. If you collect your own
data, you can request either gross or net generation data.
Level of data for allocations plant vs. generator vs. unit
EPA generation data are at the unit level. EIA form 767 provides generation data for each
generator. EIA forms 759, 860B, and 900 provide generation data only for entire plants. Plant-level
data would need to be apportioned to individual units at a plant to create allocations for each unit.
Time interval of data
Most of EIA's generation data are monthly data, which you can sum for May through
September to obtain the total output for the ozone season.
If you choose to use existing gross electric output data27 for the Acid Rain Program, you will
have access to hourly data. However, you will need to sum the hourly values to calculate the ozone
season total electric output. We advise states to take this approach with caution because extracting
these data from the electronic data reporting (EDR) format could be costly and time consuming.
The steam load data that some sources report to EPA for the Acid Rain Program are hourly
data. However, because this information is steam flow in Ib/hr without temperature, pressure, or
enthalpy data, it does not give you the information you need to determine thermal output.
Degree of quality assurance and consistency
Sources are not currently required to perform quality assurance testing on equipment used
to measure output. This is true, whether the data are reported to EPA, to EIA, or to you. Some
sources follow voluntary standards from the American National Standards Institute (ANSI) or the
Institute of Electrical and Electronics Engineers (IEEE). Therefore, some of the data are highly
accurate, but this is not consistently true.
You can request data in a standard format. EIA has standard forms that sources are required
to submit. EPA has a standard electric format for reporting gross MW data. However, sources have
27 Sources report these data in record type 300 of EPA's electronic data reporting format.
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Section VIII. B: What should I consider when choosing a source of output data?
the option of reporting either gross unit load data (MWe) or gross steam flow rate data to EPA.
Although there is a standard format for reporting the data, the data themselves are not
necessarily being reported consistently. This could be improved by giving consistent interpretations
of reporting instructions and by providing more consistent quality assurance of the data.
Availability of data in electronic form
Data from EIA form 759 are available in electronic files on EIA's Web site. Data from the
Acid Rain Program are readily available on files on the Acid Rain Program Web site. You can also
request other data files directly from EIA.
Time when data are available for the public
It generally takes EPA six months to review data sufficiently before making them publicly
available. EIA form 759 is usually ready within six months of the end of the year. Data from other
EIA forms may take longer to become publicly available. The quickest way to obtain data may be
to ask sources directly.
Use of your staff resources
A State collection of data on paper can be time and resource intensive. If you have relatively
few sources in your state and if almost all of your sources are electric generating units, you may be
able to take advantage of electronically available data from the Federal government.
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Section IX.: What provisions of my State rule may need to be changed to account for output-based NOx allowance
allocations?
IX. Rule Changes: What provisions of my State rule may need to be changed to account for
output-based NOx allowance allocations?
You may need to change the following provisions or sections of your rule to account for
output-based NOx allowance allocations:
> Definitions
*• Measurements, abbreviations and acronyms
*• Applicability
> NOx allowance allocations
> Monitoring
In Appendix A to this guidance document, you will find example language that you may use in your
State rule. The example language is based upon the language in the model rule for the NOx Budget
Trading Program under the NOx SIP call at 40 CFR part 96.
You may need to make the following sorts of changes for each of these sections or
provisions:
Definitions (§96.2) -Add definitions for output, electric output, thermal output, net output, and gross
output, as appropriate to your regulation. This will depend on the location you choose for
monitoring output and the sources you choose to give allocations to using output (see section III "For
which kinds of facilities does this guidance help me develop output-based allocations?", pp. 44-45
above and section V, "Where should sources determine output to be used for allocations?", pp. 49-54
above). Your definitions will determine the monitoring approach to be used, which in turn
determines the formulas to be used for allocation. In addition, if you decide to issue allowances to
all generation sources, you will need language to describe generating systems that are non-fossil fuel-
fired or that are non-emitting generating systems. If you include sources that are not fossil fuel-fired,
you may want to revise the definition of a NOx Budget unit to include boilers, turbines, or combined
cycle systems that combust any fuel. See the example definitions in Appendix A (pp. 171-172).
Measurements, abbreviations and acronyms (§96.3)-Add abbreviations for the units of measure for
output: MWh (megawatt-hour) and mmBtuout or mmBtu output (measured million British thermal
units of thermal output)
Applicability (§96.4)-You will need to revise this section or provision if you decide to issue
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Section IX: What provisions of my State rule may need to be changed to account for output-based NOx allowance
allocations?
allowances to all generation sources, rather than just fossil-fuel sources. NOx-emitting electric
generating systems, including fossil fuel-fired or non-fossil fuel-fired units, will need to meet the
requirements for NOx Budget units. These include the requirements to hold allowances covering
emissions and to monitor and report NOx emissions and output data. Any NOx-emitting sources
that are not fossil fuel-fired will need to meet the same requirements as fossil fuel-fired units. Non-
emitting generating systems will need to meet the requirements for owners of a general allowance
account and requirements for monitoring and reporting output data. If you handle applicability
through your definitions, review your definitions to see if they still are appropriate.
NOx allowance allocations (§96.42)-You will be making most of your rule revisions in this section.
You may need different calculation formulas and procedures for adjusting the amounts of the
allowance allocations so that the total amount equals the appropriate portion of your trading program
budget. Also, you will need to address whether to update allocations for your facilities and, if so,
how often to update allocations for your facilities. Formulas for calculating thermal output must be
consistent with the monitoring approach you define.
Monitoring (§§96.70 through 96.76)-See section VII, "Requirements for Sources: How should
sources monitor, record, and report output data to support updating output-based allocations?" (pp.
142-162). You will need to define the monitor installation, quality assurance, recordkeeping, and
reporting requirements for all sources receiving output-based allocations. Depending on whether you
plan to allocate based on output to electric generating units only or to both electric generating units
or non-electric generating units, this section of your rule will need to specify which kinds of units
must measure, record, and report output data.
If you choose to include all generation sources instead of fossil-fuel fired sources only, then
you will need to add requirements for the owner or operator of a non-fossil fuel-fired source to
monitor, record and report emissions and source operating information. See section VII.I. of this
document, "What other monitoring requirements must facilities meet if they are not fossil fuel-
fired?" (pp. 161-162).
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X. How do I learn more about this guidance?
X. How do I learn more about this guidance?
A. Who do I contact if I have questions about this guidance?
If you have questions about this guidance, contact Margaret Sheppard at EPA's Clean Air
Markets Division28 (Telephone: 202-564-9163; email: sheppard.margaret@epa.gov). If you have
specific questions or suggestions related to output monitoring and reporting, contact either Margaret
Sheppard or George Croll (Telephone: 202-564-0162; email: croll.george@epa.gov) at EPA's Clean
Air Markets Division.
B. How do I find out more about the NOx SIP Call and the NOx Budget Trading Program?
EPA's information about the NOx SIP call is available on the Regional Transport of Ozone
Web site (http://www.epa.gov/ttn/rto/sip/index.html). This site includes a number of resources,
including Federal Register notices, fact sheets, supporting technical work, emission inventories, and
responses to frequently-asked questions. The Federal Register notice with the final NOx SIP call
is entitled "FR version of the 110 NOx SIP call - Parts 1-4 (zipped)" and dated October 30, 1998.
If you have specific questions about the NOx SIP call, you may contact Kimber Scavo of
EPA's Office of Air Quality, Planning and Standards (Telephone: 919-541-3354; email:
scavo.kimber@epa.gov). If you have specific questions concerning the NOx Budget Trading
Program, contact Sarah Dunham of the Clean Air Markets Division (Telephone: 202-564-9087;
email: dunham.sarah@epa.gov).
C. How did EPA create this guidance?
In the final NOx SIP call, we committed to work together with stakeholders to design an
output allocation system that could be used by States as part of their trading program rules in their
SIPs. We said that we would develop a proposed system for output-based allocations in 1999 and
finalize an output-based option in 2000. Today's guidance develops the final system for output-
based allocations that we committed to in the NOx SIP call.
EPA formed the Updating Output Emission Limitation Workgroup as a stakeholder
workgroup to advise us in addressing issues to be covered in guidance to States. The Updating
Output Emission Limitation Workgroup is a workgroup of the Clean Air, Energy and Climate
28
Formerly the Acid Rain Division.
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X. How do I learn more about this guidance?
Change Subcommittee of the Clean Air Act Advisory Committee. Workgroup members include
representatives of the electric power industry, district energy groups, industrial boiler owners, the
natural gas supply industry, environmental groups, State environmental agencies, labor unions, and
other organizations. From December 1998 through December 1999, we held a series of meetings
and conference calls.
You can find information on the work of the Updating Output Emission Limitation
Workgroup on the workgroup's Web site (http://www.epa.gov/acidrain/noxsip/workgrp.htm). On
the site, you will find a list of workgroup members and their affiliations, lists of questions that we
posed to the workgroup, responses by workgroup members, issue papers, the first draft of this
guidance document, and meeting minutes. Some of these documents are referred to in the guidance.
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Appendix A: Sample rule language to account for output-based allocations Definitions
Appendix A: Sample rule language to account for output-based allocations
Note that throughout these examples, some phrases are in italics. These indicate possible decisions
that you will need to make. For example, the definitions of "non-emitting generating system" and
"unit" below will apply only if you intend to allocate to all sources of electric generation instead of
to fossil fuel-fired units.
Definitions
"Electric output" means the electric generation (in MWh/time) from an electric generating
device. With respect to a unit, "electric output" means the electric generation (in MWh/time) from
an electric generating device served by the unit and that is attributed to the unit.
"Gross output" means the total output of energy from a process before making any deductions
for energy output used in any way related to the production of energy through that process.
"Net output" means the final output of energy from a process after deducting any energy
output consumed in any way related to generating energy through that process. Examples of output
to be deducted include thermal output lost through radiation to the outside, thermal output used in
thermal recovery, or thermal or electric output used within the plant to operate the unit, generator,
fuel handling system, pumps, fans, or pollution control equipment29. Output used to produce a useful
material product besides the thermal output or electric output, such as thermal energy used to dry
paper, does not need to be deducted.
{include this definition, if you intend to allocate NOx allowances to all electricity generating
.sysfews/'Non-emitting generating system" means the portion of a facility for generating electricity
that uses an energy source not involving combustion of fuel or NOx emissions, such as hydroelectric,
nuclear, geothermal, or wind power, and that uses an electric generator with a nameplate capacity
greater than 25 MWe.
"NOx Budget unit" means a unit that is subject to the NOx Budget Trading Program
emissions limitation under § 96.4 or § 96.80.
29 If you intend to include the power used to operate pollution control equipment as part
of the electric output used to calculate allocations, remove "pollution control equipment" from
this part of the definition.
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Appendix A: Sample rule language to account for output-based allocations Definitions
"Thermal output" means the thermal energy (in mmBtuout/time) that is produced through a
process and is used for industrial, commercial, heating, or cooling purposes after the subtraction of
heat for boiler feed, feedwater preheating, or combustion air preheating.30
"Unit" means a stationary boiler, combustion turbine, or combined cycle system that is
fossil fuel-fired.31
Measurements, abbreviations, and acronyms
MWh-megawatt-hours of electric output
mmBtuout-measured million British thermal units of thermal output
30 Note that this definition only applies when you measure thermal output using the boiler
efficiency approach, as described in section VI. of this document (pp. 68-69, 84-91, and 124-
137). If you choose to use the simplified approach for monitoring thermal output, then the
definition of thermal output should read as follows:
"Thermal output" means the thermal energy (in mmBtuout/time) that is produced
through a process and is used for industrial, commercial, heating, or cooling
purposes after the subtraction of heat for boiler feed or combustion air preheating.
31 If you intend to allocate NOx allowances to all electricity generating systems, revise the
definition of unit as follows:
"Unit" means a stationary boiler, combustion turbine, or combined cycle system
that combusts fuel.
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Appendix A: Sample rule language to account for output-based allocations Case 1
Subpart E - NOx Allowance Allocations
Note that throughout these examples, some phrases are in italics. These indicate possible decisions
that you will need to make. For example, if you want to use net generation, substitute in the phrase
"net" in each place where the example language states "{specify net or gross}''
The example language in Cases 1 and 3 allows for the situation where a State has already prepared
initial allocations for 2003 through 2005 based on heat input and intends to update allocations based
on output starting with the year 2006. Cases 2 and 4 consider the situation where a State has
prepared initial allocations for 2003 through 2005 based on output and intends to update allocations
based on output starting with the year 2006. In all cases, allocations are adjusted to fit sector
budgets, rather than the entire trading program budget. Also, there is a 5% set-aside for new units
in all cases.
The dates in all cases are based upon the timing in part 96, the model trading rule for the NOx SIP
call. The timing in your rule will depend on when you adopt a final rule as part of your SIP and on
the deadline for sources to comply with emission reductions
Casel
(1) You initially allocate to both EGUs and non-EGUs for 2003 through 2005 based on heat
input
(2) You update allocations to EGUs based on output and to non-EGUs based on heat input
beginning in 2006
§ 96.42 NOx allowance allocations.
(a) Basis for allocation. The permitting authority will calculate NOx allowance allocations
for each NOx Budget unit under § 96.4 [or non-emitting generating system] as follows:
(1) For a NOx allowance allocation for 2003 through 2005 under §96.41(a):
(i) The permitting authority will use the average of the two highest amounts of the unit's heat
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Appendix A: Sample rule language to account for output-based allocations Case 1
input (in mmBtu) for the control periods in 1995, 1996, and 1997 if the unit is under §96.4(a)(l), or
the unit's heat input for the control period in 1995 if the unit is under §96.4(a)(2); or
(ii) For a unit under §96.4(a)(l) that commences operation on or after May 1, 1997, or for
a unit under §96.4(a)(2) that commences operation on or after May 1, 1995, the permitting authority
will use the unit's heat input in accordance with paragraph (d) of this section.
(2) For a NOx allowance allocation for any year after 2005 under §96.41(b):
(i) The permitting authority will use the {specify net or gross} electric and thermal output for
the unit under §96.4(a)(l) [or the non-emitting generating system], and heat input for the unit under
§96.4(a)(2) for the control period in the year that is four years before the year for which the NOx
allocation is being calculated; or
(ii) For a unit [or non-emitting generating system] that commences operation on or after May
1 of the year that is four years before the year for which the permitting authority allocates, the
permitting authority will determine allocations in accordance with paragraph (d) of this section.
(3) The permitting authority will determine the unit's heat input:
(i) In accordance with 40 CFR part 75; or
(ii) Based on the best available data reported to the permitting authority for the unit, if the
unit was not otherwise subject to the requirements of 40 CFR part 75 for the control period.
(4) The permitting authority will determine the {specify gross or net} thermal and electric
output for the unit [or non-emitting generating system] using {insert source ofdata-e.g., net electric
generation data from the Energy Information Administration, gross electric generation data in
accordance with subpart H of 40 CFR part 75, or the best available data reported to the permitting
authority for the unit or non-emitting generating system.}
(b) Allocation to units under §96.4(a)(l)[and non-emitting generating systems]. For each
control period in 2003 through 2005, the permitting authority will allocate NOx allowances to all
NOx Budget units under §96.4(a)(l) in [the State] {substitute name of your State} that commenced
operation before May 1, 1997 in accordance with paragraphs (b)(l) through (b)(3) of this section.
For each control period after 2005, the permitting authority will allocate NOx allowances to all NOx
Budget units under §96.4(a)(l) [or non-emitting generating systems] in [the State] {substitute name
of your State} that commenced operation before May 1 of the period used to calculate heat input or
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electric and thermal output under paragraph (a) of this section, in accordance with paragraphs (b)(4)
through (b)(6) of this section.
(1) For 2003 through 2005, the permitting authority will allocate NOx allowances to all NOx
Budget units under §96.4(a)(l) in [the State] {substitute name of your State} that commenced
operation before May 1, 1997.
(2) For 2003 through 2005, the permitting authority will allocate NOx allowances to each
NOx Budget unit under §96.4(a)(l) in an amount equaling 0.15 Ib/mmBtu multiplied by the unit's
heat input under paragraph (a) of this section, divided by 2,000 Ib/ton. Each allocation will be
rounded to the nearest whole number of NOx allowances, as appropriate.
(3) The permitting authority will adjust the initial allocations under paragraph (b)(2) of this
section so that the total number of NOx allowances allocated for 2003, 2004, or 2005 equals 95
percent of the number of tons of NOx emissions in the State trading program budget apportioned to
units under §96.4(a)(l), if these numbers are not already equal. This adjustment will be made by:
multiplying each unit's allocation for 2003, 2004, or 2005 by 95 percent of the number of tons of
NOx emissions in the State trading program budget apportioned to units under §96.4(a)(l), dividing
by the total number of NOx allowances allocated for the year under paragraph (b)(2) of this section,
and rounding to the nearest whole number of NOx allowances, as appropriate.
(4) For each control period after 2005, the permitting authority will allocate NOx allowances
to all NOx Budget units under §96.4(a)(l) [and to all non-emitting generating systems] in [the State]
{substitute name of your State} that commenced operation before May 1 of the period used to
calculate {specify net or gross} electric and thermal output under paragraph (a)(2) of this section.
(5) For each control period after 2005, the permitting authority will allocate NOx allowances
to each unit under §96.4(a)(l) [and to each non-emitting generating system] in an amount equaling:
1.5 Ib/MWh multiplied by the {specify net or gross} electric output under paragraph (a) of this
section and divided by 2,000 Ib/ton, plus 0.24 lb/mmBtuout32 multiplied by the {specify net or gross}
32Use the value of 0.24 Ib/mmBtu output if you assume a typical boiler efficiency of 70%
and if you require sources to use the boiler efficiency approach for measuring thermal output, as
described in section VI. of this document (pp. 68-69, 84-91, and 124-137). If you decide to use
the simplified approach for monitoring output and a typical boiler efficiency of 70%, then this
number should be 0.22 Ib/mmBtu. If you want to assume a different typical boiler efficiency, see
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thermal output under paragraph (a) of this section and divided by 2,000 Ib/ton. Each allocation will
be rounded to the nearest whole number of NOx allowances, as appropriate.
(6) The permitting authority will adjust the initial allocations under paragraph (b)(5) of this
section so that the total number of NOx allowances allocated for each control period after 2005
equals 98 percent of the number of tons of NOx emissions in the State trading program budget
apportioned to units under §96.4(a)(l), if these numbers are not already equal. This adjustment will
be made by: multiplying each unit's allocation for a control period after 2005 by 98 percent of the
number of tons of NOx emissions in the State trading program budget apportioned to units under
§96.4(a)(l) divided by the total number of NOx allowances allocated under paragraph (b)(5) of this
section, and rounding to the nearest whole number of NOx allowances, as appropriate.
(c) Allocation to units under §96.4(a)(2). For each control period under § 96.41, the
permitting authority will allocate NOx allowances to all units under §96.4(a)(2) in [the State] {insert
name of State} that commenced operation before May 1 of the period used to calculate heat input
under paragraph (a) of this section. The permitting authority will allocate NOx allowances in
accordance with the following procedures:
(1) The permitting authority will allocate NOx allowances to each NOx Budget unit under
§96.4(a)(2) in an amount equaling 0.17 Ib/mmBtu multiplied by the heat input under paragraph (a)
of this section, divided by 2,000 Ib/ton. Each allocation will be rounded to the nearest whole number
of NOx allowances, as appropriate
(2) The permitting authority will adjust the unadjusted allocations under paragraph (c)(l) of
this section so that the total number of NOx allowances allocated equals 95 percent in 2003, 2004,
and 2005, or 98 percent thereafter, of the number of tons of NOx emissions in the State trading
program budget apportioned to units under §96.4(a)(2), if these numbers are not already equal. This
adjustment will be made by: multiplying each unit's for a control period by 95 percent in 2003,2004,
or 2005, or by 98 percent thereafter, of the number of tons of NOx emissions in the State trading
program budget apportioned to units under §96.4(a)(2), dividing by the total number of NOx
allowances allocated under paragraph (c)(l) of this section, and rounding to the nearest whole
section II. A. to calculate your own allocation factor (pp. 23-31).
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number of NOx allowances, as appropriate.
(d) For each control period under § 96.41, the permitting authority will allocate NOx
allowances to NOx Budget units under § 96.4 [or non-emitting generating systems] in [the State]
{insert name of your State} that commenced operation, or are projected to commence operation, on
or after May 1 of the period used to calculate heat input or electric and thermal output under
paragraph (a) of this section, in accordance with the following procedures:
(1) The permitting authority will establish one allocation set-aside for each control period.
Each allocation set-aside will be allocated NOx allowances equal to 5 percent in 2003, 2004, and
2005, or 2 percent thereafter, of the tons of NOx emissions in the State trading program budget,
rounded to the nearest whole number of NOx allowances, as appropriate.
(2) The NOx authorized account representative of a unit under paragraph (d) of this section
may submit to the permitting authority a request, in writing or in a format specified by the permitting
authority, to be allocated NOx allowances for no more than five consecutive control periods under
§ 96.41, starting with the control period during which the unit commenced, or is projected to
commence, operation and ending with the control period preceding the control period for which it
will receive an allocation under paragraph (b) or (c) of this section. {If including non-emitting
generating systems, include the follow ing sentence: The NOx authorized account representative of
a non-emitting generating system under paragraph (d) of this section may submit to the permitting
authority a request, in writing or in a format specified by the permitting authority, to be allocated
NOx allowances for no more than five consecutive control periods under § 96.41, starting with the
later of the control period in 2006 or the control period during which the non-emitting generating
system commenced, or is projected to commence, operation and ending with the control period
preceding the control period for which it will receive an allocation under paragraph (b) or (c) of
this section. The NOx allowance allocation request must be submitted prior to May 1 of the first
control period for which the NOx allowance allocation is requested and after the date on which the
permitting authority issues a permit to construct the unit [or non-emitting generating system].
(3) In a NOx allowance allocation request under paragraph (d)(2) of this section, the NOx
authorized account representative for a unit under §96.4(a)( 1) [or a non-emitting generating system]
may request NOx allowances for a control period in the following amount:
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(i) For a control period in 2003, 2004, or 2005, the requested number of NOx allowances
must not exceed 0.15 Ib/mmBtu, multiplied by the unit's maximum design heat input (in mmBtu/hr),
multiplied by the number of hours remaining in the control period starting with the first day in the
control period on which the unit operated or is projected to operate, and divided by 2,000 Ib/ton.
(ii) For a control period in 2006 or thereafter, the requested number of NOx allowances must
not exceed 1.5 Ib/MWh multiplied by the nameplate capacity (in MW) of the unit [or non-emitting
generating system]', multiplied by the number of hours remaining in the control period starting with
the first day in the control period on which the unit operated or is projected to operate, and divided
by 2,000 Ib/ton.
(4) In a NOx allowance allocation request under paragraph (d)(2) of this section, the NOx
authorized account representative for a unit under §96.4(a)(2) may request NOx allowances for a
control period. The requested number of NOx allowances must not exceed 0.17 Ib/mmBtu
multiplied by the unit's maximum design heat input (in mmBtu/hr), multiplied by the number of
hours remaining in the control period starting with the first day in the control period on which the
unit operated or is projected to operate, and divided by 2,000 Ib/ton.
(5) The permitting authority will review, and allocate NOx allowances pursuant to, each NOx
allowance allocation request under paragraph (d)(2) of this section in the order that the request is
received by the permitting authority.
(i) Upon receipt of the NOx allowance allocation request, the permitting authority will make
any necessary adjustments to the request to ensure that, for a unit under §96.4(a)(l) for non-emitting
generating system]', the control period and the number of allowances specified are consistent with
the requirements of paragraphs (d)(2) and (3) of this section and, for a unit under §96.4(a)(2), the
control period and the number of allowances specified are consistent with the requirements of
paragraphs (d)(2) and (4) of this section.
(ii) If the allocation set-aside for the control period for which NOx allowances are requested
has an amount of NOx allowances not less than the number requested (as adjusted under paragraph
(d)(5)(i) of this section), the permitting authority will allocate the amount of the NOx allowances
requested (as adjusted under paragraph (d)(5)(i) of this section) to the unit for non-emitting
generating system].
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Case 1
(iii) If the allocation set-aside for the control period for which NOx allowances are requested
has a smaller amount of NOx allowances than the number requested (as adjusted under paragraph
(d)(5)(i) of this section), the permitting authority will deny in part the request and allocate only the
remaining number of NOx allowances in the allocation set-aside to the unit [or non-emitting
generating system].
(iv) Once an allocation set-aside for a control period has been depleted of all NOx
allowances, the permitting authority will deny, and will not allocate any NOx allowances pursuant
to, any NOx allowance allocation request under which NOx allowances have not already been
allocated for the control period.
(6) Within 60 days of receipt of a NOx allowance allocation request, the permitting authority
will take appropriate action under paragraph (d)(5) of this section and notify the NOx authorized
account representative that submitted the request and the Administrator of the number of NOx
allowances (if any) allocated for the control period to the unit [or non-emitting generating system].
(e) For a unit [or non-emitting generating system] allocated NOx allowances under paragraph
(d) of this section for a control period, the Administrator will deduct NOx allowances under §
96.54(b) or (e) to account for the actual utilization or output of the unit [or non-emitting generating
system] during the control period. The Administrator will calculate the number of NOx allowances
to be deducted to account for the unit's actual utilization or output using the following formulas and
rounding to the nearest whole number of NOx allowances as appropriate, provided that the number
of NOx allowances to be deducted shall be zero if the number calculated is less than zero:
NOx allowances deducted for actual utilization for a unit under §96.4(a)(l) for a control period in
2003, 2004, or 2005 = (NOx allowances allocated for control period) - (Actual control period heat
input x 0.15 Ib/mmBtu -2,000 Ib/ton);
NOx allowances deducted for actual output for a unit under §96.4(a)(l) [or a non-emitting
generating system] for a control period in 2006 or thereafter = (Unit's NOx allowances allocated for
control period) - ( Unit's actual control period {specify net or gross} electric output x 1.5 Ib/MWh
-2,000 Ib/ton and actual control period {specify net or gross} thermal output xO.24 lb/mmBtuout33
33 Same as footnote 32.
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-2,000 Ib/ton); and
NOx allowances deducted for actual utilization for a unit under §96.4(a)(2)= (NOx allowances
allocated for control period) - (Actual control period heat input x 0.17 Ib/mmBtu -2,000 Ib/ton)
where:
"NOx allowances allocated for control period" is the number of NOx allowances allocated
to the unit [or the non-emitting generating system] for the control period; and
"Actual control period heat input" is the heat input (in mmBtu) of the unit during the control
period; and
"Actual control period {specify net or gross} electric output" is the {specify net or gross}
electric output in MWh of the unit [or non-emitting generating system] during the control period;
and
"Actual control period {specify net or gross} thermal output" is the {specify net or gross}
thermal output in mmBtuout of the unit during the control period.
(f) After making the deductions for compliance under § 96.54(b) or (e) for a control period,
the Administrator will notify the permitting authority whether any NOx allowances remain in the
allocation set-aside for the control period. The permitting authority will allocate any such NOx
allowances to the units under §96.4 [andthe non-emitting generating systems] in [the State] {insert
name of your State} using the following formula and rounding to the nearest whole number of NOx
allowances as appropriate:
Unit's [or non-emitting generating system 'sj share of NOx allowances remaining in allocation set-
aside = Total NOx allowances remaining in allocation set-aside x (NOx allowance allocation - State
trading program budget excluding allocation set-aside)
where:
"Total NOx allowances remaining in allocation set-aside" is the total number of NOx allowances
remaining in the allocation set-aside for the control period;
" NOx allowance allocation" is the number of NOx allowances allocated under paragraph (b) or (c)
of this section to the unit for non-emitting generating system] for the control period to which the
allocation set-aside applies; and
"State trading program budget excluding allocation set-aside" is the State trading program budget
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Appendix A: Sample rule language to account for output-based allocations Case 1
for the control period to which the allocation set-aside applies multiplied by 95 percent if the control
period is in 2003, 2004, or 2005 or 98 percent if the control period is in any year thereafter, rounded
to the nearest whole number of NOx allowances as appropriate.
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Appendix A: Sample rule language to account for output-based allocations Case 2
Case 2
(1) You initially allocate to both EGUs and non-EGUs for 2003 through 2005 based on heat
input
(2) You update with allocations to both EGUs and non-EGUs based on output beginning in
2006
§ 96.42 NOx allowance allocations.
(a) Basis for allocation. The permitting authority will calculate NOx allowance allocations
for each NOx Budget unit under § 96.4 [or non-emitting generating system] as follows:
(1) For a NOx allowance allocation for 2003 through 2005 under §96.41(a):
(i) The permitting authority will use the average of the two highest amounts of the unit's heat
input (in mmBtu) for the control periods in 1995, 1996, and 1997 if the unit is under §96.4(a)(l), or
the unit's heat input for the control period in 1995 if the unit is under §96.4(a)(2); or
(ii) For a unit under §96.4(a)(l) that commences operation on or after May 1, 1997, or for
a unit under §96.4(a)(2) that commences operation on or after May 1, 1995, the permitting authority
will use the unit's heat input in accordance with paragraph (d) of this section.
(2) For a NOx allowance allocation for any year after 2005 under §96.41(b):
(i) The permitting authority will use the {specify net or gross} electric and thermal output for
the unit [or the non-emitting generating system] for the control period in the year that is four years
before the year for which the NOx allocation is being calculated; or
(ii) For a unit [or non-emitting generating system] that commences operation on or after May
1 of the year that is four years before the year for which the permitting authority allocates, the
permitting authority will determine allocations in accordance with paragraph (d) of this section.
(3) The permitting authority will determine the unit's heat input:
(i) In accordance with 40 CFR part 75; or
(ii) Based on the best available data reported to the permitting authority for the unit, if the
unit was not otherwise subject to the requirements of 40 CFR part 75 for the control period.
(4) The permitting authority will determine the {specify gross or net} thermal and electric
output for the unit [or the non-emitting generating system] using {insert source ofdata-e.g., net
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Appendix A: Sample rule language to account for output-based allocations Case 2
electric generation data from the Energy Information Administration, gross electric generation data
in accordance with subpart H of 40 CFR part 75, or the best available data reported to the
permitting authority for the unit [or the non-emitting generating system].}
(b) Allocation to units under §96.4(a)(l)[and non-emitting generating systems]. For each
control period in 2003 through 2005, the permitting authority will allocate NOx allowances to all
units under §96.4(a)(l) in [the State] {substitute name of your State} that commenced operation
before May 1, 1997 in accordance with paragraphs (b)(l) through (b)(3) of this section. For each
control period after 2005, the permitting authority will allocate NOx allowances to all NOx Budget
units under §96.4(a)(l) [or non-emitting generating systems] in [the State] {substitute name of your
State} that commenced operation before May 1 of the period used to calculate heat input or electric
and thermal output under paragraph (a) of this section, in accordance with paragraphs (b)(4) through
(b)(6) of this section.
(1) For 2003 through 2005, the permitting authority will allocate NOx allowances to all NOx
Budget units under §96.4(a)(l) in [the State] {substitute name of your State} that commenced
operation before May 1, 1997.
(2) For 2003 through 2005, the permitting authority will allocate NOx allowances to each
NOx Budget unit under §96.4(a)(l) in an amount equaling 0.15 Ib/mmBtu multiplied by the unit's
heat input under paragraph (a) of this section, divided by 2,000 Ib/ton. Each allocation will be
rounded to the nearest whole number of NOx allowances, as appropriate.
(3) The permitting authority will adjust the initial allocations under paragraph (b)(2) of this
section so that the total number of NOx allowances allocated for 2003, 2004, or 2005 equals 95
percent of the number of tons of NOx emissions in the State trading program budget apportioned to
units under §96.4(a)(l), if these numbers are not already equal. This adjustment will be made by:
multiplying each unit's allocation for 2003, 2004, or 2005 by 95 percent of the number of tons of
NOx emissions in the State trading program budget apportioned to units under §96.4(a)(l), dividing
by the total number of NOx allowances allocated for the year under paragraph (b)(2) of this section,
and rounding to the nearest whole number of NOx allowances, as appropriate.
(4) For each control period after 2005, the permitting authority will allocate NOx allowances
to all NOx Budget units under §96.4(a)(l) [and to all non-emitting generating systems] in [the State]
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Appendix A: Sample rule language to account for output-based allocations Case 2
{substitute name of your State} that commenced operation before May 1 of the period used to
calculate {specify net or gross} electric and thermal output under paragraph (a)(2) of this section.
(5) For each control period after 2005, the permitting authority will allocate NOx allowances
to each unit under §96.4(a)(l) [and to each non-emitting generating system] in an amount equaling:
1.5 Ib/MWh multiplied by the {specify net or gross} electric output under paragraph (a) of this
section and divided by 2,000 Ib/ton, plus 0.24 lb/mmBtuout34 multiplied by the {specify net or gross}
thermal output under paragraph (a) of this section and divided by 2,000 Ib/ton. Each allocation will
be rounded to the nearest whole number of NOx allowances, as appropriate.
(6) The permitting authority will adjust the initial allocations under paragraph (b)(5) of this
section so that the total number of NOx allowances allocated for each control period after 2005
equals 98 percent of the number of tons of NOx emissions in the State trading program budget
apportioned to units under §96.4(a)(l), if these numbers are not already equal. This adjustment will
be made by: multiplying each unit's allocation for a control period after 2005 by 98 percent of the
number of tons of NOx emissions in the State trading program budget apportioned to units under
§96.4(a)(l) divided by the total number of NOx allowances allocated under paragraph (b)(5) of this
section, and rounding to the nearest whole number of NOx allowances, as appropriate.
(c) Allocation to units under §96.4(a)(2). For each control period in 2003 through 2005, the
permitting authority will allocate NOx allowances to all units under §96.4(a)(2) in [the State]
{substitute name of your State} that commenced operation on or after May 1, 1995, in accordance
with paragraphs (c)(l) through (c)(3) of this section. For each control period after 2005, the
permitting authority will allocate NOx allowances to all NOx Budget units under §96.4(a)(2) in [the
State] {substitute name of your State} that commenced operation before May 1 of the period used
to calculate heat input or electric and thermal output under paragraph (a) of this section, in
accordance with paragraphs (c)(4) through (c)(6) of this section.
34Use the value of 0.24 Ib/mmBtu output if you assume a typical boiler efficiency of 70%
and if you require sources to use the boiler efficiency approach for measuring thermal output, as
described in section VI. of this document (pp. 68-69, 84-91, and 124-137). If you decide to use
the simplified approach for monitoring output and a typical boiler efficiency of 70%, then this
number should be 0.22 Ib/mmBtu. If you want to assume a different typical boiler efficiency, see
section II. A. to calculate your own allocation factor (pp. 23-31).
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Case 2
(1) For 2003 through 2005, the Department will allocate NOx allowances to all NOx Budget
units under §96.4(a)(2) in [the State] {substitute name of your State} that commenced operation
before May 1, 1997.
(2) For 2003 through 2005, the permitting authority will allocate NOx allowances to each
NOx Budget unit under §96.4(a)(2) in an amount equaling 0.17 Ib/mmBtu multiplied by the heat
input under paragraph (a) of this section, divided by 2,000 Ib/ton. Each allocation will be rounded
to the nearest whole number of NOx allowances, as appropriate
(3) For 2003 through 2005, the permitting authority will adjust the initial allocations under
paragraph (c)(2) of this section so that the total number of NOx allowances allocated equals 95
percent in 2003, 2004, or 2005, or 98 percent thereafter, of the number of tons of NOx emissions in
the State trading program budget apportioned to units under §96.4(a)(2), if these numbers are not
already equal. This adjustment will be made by: multiplying each unit's allocation in 2003, 2004,
or 2005 by 95 percent of the number of tons of NOx emissions in the State trading program budget
apportioned to units under §96.4(a)(2), dividing by the total number of NOx allowances allocated
under paragraph (c)(2) of this section, and rounding to the nearest whole number of NOx allowances,
as appropriate.
(4) For each control period after the year 2005, the permitting authority will allocate NOx
allowances to all NOx Budget units under §96.4(a)(2) in [the State] {substitute name of your State}
that commenced operation before May 1 of the period used to calculate {specify net or gross} electric
and thermal output under paragraph (a)(2) of this section.
(5) For each control period after 2005, the permitting authority will allocate NOx allowances
to each unit under §96.4(a)(2) in an amount equaling: 0.24 lb/mmBtuout35 multiplied by the {specify
net or gross} thermal output under paragraph (a) of this section and divided by 2,000 Ib/ton, plus 1.5
Ib/MWh multiplied by the {specify net or gross} electric output under paragraph (a) of this section
and divided by 2,000 Ib/ton. Each allocation will be rounded to the nearest whole number of NOx
allowances, as appropriate.
(6) The permitting authority will adjust the initial allocations under paragraph (c)(5) of this
35 Same as footnote 34.
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section so that the total number of NOx allowances allocated for each control period after 2005
equals 98 percent of the number of tons of NOx emissions in the State trading program budget
apportioned to units under §96.4(a)(2), if these numbers are not already equal. This adjustment will
be made by: multiplying each unit's allocation for a control period after 2005 by 98 percent of the
number of tons of NOx emissions in the State trading program budget apportioned to units under
§96.4(a)(2) and dividing by the total number of NOx allowances allocated under paragraph (c)(5)
of this section, and rounding to the nearest whole number of NOx allowances, as appropriate.
(d) For each control period under § 96.41, the permitting authority will allocate NOx
allowances to NOx Budget units under § 96.4 [or non-emitting generating systems] in [the State]
{insert name of your State} that commenced operation, or are projected to commence operation, on
or after May 1 of the period used to calculate heat input or electric and thermal output under
paragraph (a) of this section, in accordance with the following procedures:
(1) The permitting authority will establish one allocation set-aside for each control period.
Each allocation set-aside will be allocated NOx allowances equal to 5 percent in 2003, 2004, and
2005, or 2 percent thereafter, of the tons of NOx emissions in the State trading program budget,
rounded to the nearest whole number of NOx allowances, as appropriate.
(2) The NOx authorized account representative of a unit under paragraph (d) of this section
may submit to the permitting authority a request, in writing or in a format specified by the permitting
authority, to be allocated NOx allowances for no more than five consecutive control periods under
§ 96.41, starting with the control period during which the unit commenced, or is projected to
commence, operation and ending with the control period preceding the control period for which it
will receive an allocation under paragraph (b) or (c) of this section. {If including non-emitting
generating systems, include the follow ing sentence: The NOx authorized account representative of
a non-emitting generating system under paragraph (d) of this section may submit to the permitting
authority a request, in writing or in a format specified by the permitting authority, to be allocated
NOx allowances for no more than five consecutive control periods under § 96.41, starting with the
later of the control period in 2006 or the control period during which the non-emitting generating
system commenced, or is projected to commence, operation and ending with the control period
preceding the control period for which it will receive an allocation under paragraph (b) or (c) of
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this section.} The NOx allowance allocation request must be submitted prior to May 1 of the first
control period for which the NOx allowance allocation is requested and after the date on which the
permitting authority issues a permit to construct the unit [or non-emitting generating system].
(3) In a NOx allowance allocation request under paragraph (d)(2) of this section, the NOx
authorized account representative for a unit under §96.4(a)( 1) [or a non-emitting generating system]
may request NOx allowances for a control period in the following amount:
(i) For a control period in 2003, 2004, or 2005, the requested number of NOx allowances
must not exceed 0.15 Ib/mmBtu, multiplied by the unit's maximum design heat input (in mmBtu/hr),
multiplied by the number of hours remaining in the control period starting with the first day in the
control period on which the unit operated or is projected to operate, and divided by 2,000 Ib/ton.
(ii) For a control period in 2006 or thereafter, the requested number of NOx allowances must
not exceed 1.5 Ib/MWh multiplied by the nameplate capacity (in MW) of the unit [or non-emitting
generating system]', multiplied by the number of hours remaining in the control period starting with
the first day in the control period on which the unit operated or is projected to operate, and divided
by 2,000 Ib/ton.
(4) In a NOx allowance allocation request under paragraph (d)(2) of this section, the NOx
authorized account representative for a unit under §96.4(a)(2) may request NOx allowances for a
control period in the following amount:
(i) For a control period in 2003, 2004, or 2005, the requested number of NOx allowances
must not exceed 0.17 Ib/mmBtu multiplied by the unit's maximum design heat input (in mmBtu/hr),
multiplied by the number of hours remaining in the control period starting with the first day in the
control period on which the unit operated or is projected to operate, and divided by 2,000 Ib/ton.
(ii) For a control period in 2006 or thereafter, the requested number of NOx allowances must
not exceed 0.24 lb/mmBtuout,36 multiplied by the maximum design heat input of the unit (in
mmBtu/hr), divided by an efficiency factor of 0.70,37 multiplied by the number of hours remaining
36
Same as footnote 34.
37This efficiency factor of 0.70 is appropriate for use with the boiler efficiency approach
for measuring output, as described in section VI. of this document (pp. 68-69, 84-91, and 124-
137). If you decide to use the simplified approach for monitoring thermal output and a typical
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in the control period starting with the first day in the control period on which the unit operated or is
projected to operate, and divided by 2,000 Ib/ton.
(5) The permitting authority will review, and allocate NOx allowances pursuant to, each NOx
allowance allocation request under paragraph (d)(2) of this section in the order that the request is
received by the permitting authority.
(i) Upon receipt of the NOx allowance allocation request, the permitting authority will make
any necessary adjustments to the request to ensure that, for a unit under §96.4(a)(l) [or non-emitting
generating system]', the control period and the number of allowances specified are consistent with
the requirements of paragraphs (d)(2) and (3) of this section and, for a unit under §96.4(a)(2), the
control period and the number of allowances specified are consistent with the requirements of
paragraphs (d)(2) and (4) of this section.
(ii) If the allocation set-aside for the control period for which NOx allowances are requested
has an amount of NOx allowances not less than the number requested (as adjusted under paragraph
(d)(5)(i) of this section), the permitting authority will allocate the amount of the NOx allowances
requested (as adjusted under paragraph (d)(5)(i) of this section) to the unit for non-emitting
generating system].
(iii) If the allocation set-aside for the control period for which NOx allowances are requested
has a smaller amount of NOx allowances than the number requested (as adjusted under paragraph
(d)(5)(i) of this section), the permitting authority will deny in part the request and allocate only the
remaining number of NOx allowances in the allocation set-aside to the unit [or non-emitting
generating system].
(iv) Once an allocation set-aside for a control period has been depleted of all NOx
allowances, the permitting authority will deny, and will not allocate any NOx allowances pursuant
to, any NOx allowance allocation request under which NOx allowances have not already been
allocated for the control period.
boiler efficiency of 70%, then this "efficiency" factor should be 77% or 0.77. If you use the
simplified approach to monitoring output and assume a different boiler efficiency, divide the heat
input-based allocation factor of 0.17 Ib/mmBtu by the thermal output-based factor from Table II-
1 in section II.A., p.29, to compute the appropriate "efficiency" factor.
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(6) Within 60 days of receipt of aNOx allowance allocation request, the permitting authority
will take appropriate action under paragraph (d)(5) of this section and notify the NOx authorized
account representative that submitted the request and the Administrator of the number of NOx
allowances (if any) allocated for the control period to the unit [or non-emitting generating system].
(e) For a unit [or non-emitting generating system] allocated NOx allowances under paragraph
(d) of this section for a control period, the Administrator will deduct NOx allowances under §
96.54(b) or (e) to account for the actual utilization or output of the unit [or non-emitting generating
system] during the control period. The Administrator will calculate the number of NOx allowances
to be deducted to account for the unit's actual utilization or output using the following formulas and
rounding to the nearest whole number of NOx allowances as appropriate, provided that the number
of NOx allowances to be deducted shall be zero if the number calculated is less than zero:
NOx allowances deducted for actual utilization for a unit under §96.4(a)(l) for a control period in
2003, 2004, or 2005 = (NOx allowances allocated for control period) - (Actual control period heat
input x 0.15 Ib/mmBtu -2,000 Ib/ton);
NOx allowances deducted for actual output for a unit under §96.4(a)(l) [or a non-emitting
generating system] for a control period in 2006 or thereafter = (Unit's NOx allowances allocated for
control period) - ( Unit's actual control period {specify net or gross} electric output x 1.5 Ib/MWh
-2,000 Ib/ton and actual control period {specify net or gross} thermal output x 0.24 lb/mmBtuout38
-2,000 Ib/ton); and
NOx allowances deducted for actual utilization for a unit under §96.4(a)(2) in 2003,2004, or 2005=
(NOx allowances allocated for control period) - ( Actual control period heat input x 0.17 Ib/mmBtu
-2,000 Ib/ton); and
NOx allowances deducted for actual output for a unit under §96.4(a)(2) for a control period in 2006
or thereafter (NOx allowances allocated for control period) - (Actual control period {specify net or
gross} thermal output x 0.24 Ib/mmBtu39 -2,000 Ib/ton and actual control period {specify net or
gross} electric output x 1.5 Ib/MWh - 2,000 Ib/ton)
38 Same as footnote 34.
39 Same as footnote 34.
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where:
"NOx allowances allocated for control period" is the number of NOx allowances allocated
to the unit [or the non-emitting generating system] for the control period; and
"Actual control period heat input" is the heat input (in mmBtu) of the unit during the control
period; and
"Actual control period {specify net or gross} electric output" is the {specify net or gross}
electric output in MWh of the unit [or non-emitting generating system] during the control period;
and
"Actual control period {specify net or gross} thermal output" is the {specify net or gross}
thermal output in mmBtuout of the unit during the control period.
(f) After making the deductions for compliance under § 96.54(b) or (e) for a control period,
the Administrator will notify the permitting authority whether any NOx allowances remain in the
allocation set-aside for the control period. The permitting authority will allocate any such NOx
allowances to the units under §96.4 [and the non-emitting generating systems] in [the State] {insert
name of your State} using the following formula and rounding to the nearest whole number of NOx
allowances as appropriate:
Unit's [or non-emitting generating system 'sj share of NOx allowances remaining in allocation set-
aside = Total NOx allowances remaining in allocation set-aside x (NOx allowance allocation ^ State
trading program budget excluding allocation set-aside)
where:
"Total NOx allowances remaining in allocation set-aside" is the total number of NOx allowances
remaining in the allocation set-aside for the control period;
" NOx allowance allocation" is the number of NOx allowances allocated under paragraph (b) or (c)
of this section to the unit for non-emitting generating system] for the control period to which the
allocation set-aside applies; and
"State trading program budget excluding allocation set-aside" is the State trading program budget
for the control period to which the allocation set-aside applies multiplied by 95 percent if the control
period is in 2003, 2004, or 2005 or 98 percent if the control period is in any year thereafter, rounded
to the nearest whole number of NOx allowances as appropriate.
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Case 3
You initially allocate and periodically update allocations to EGUs based on output and to
non-EGUs based on heat input
§ 96.42 NOx allowance allocations.
(a) Basis for allocation. The permitting authority will calculate NOx allowance allocations
for each NOx Budget unit under § 96.4 [or non-emitting generating system] as follows:
(1) For a NOx allowance allocation for 2003 through 2005 under §96.41(a):
(i) The permitting authority will use the average of the two highest amounts of the unit's [or
non-emitting generating system's] {specify net or gross} electric output (in MWh) and {specify net
or gross} thermal output (in mmBtu output) for the control periods in 1995, 1996, and 1997 if the
unit [or non-emitting generating system] is under §96.4(a)(l), or the unit's heat input for the control
period in 1995 if the unit is under §96.4(a)(2); or
(ii) For a unit under §96.4(a)(l) [or non-emitting generating system] that commences
operation on or after May 1, 1997, the permitting authority will use the unit's [or non-emitting
generating system's] {specify net or gross} output, in accordance with paragraph (d) of this section.
For a unit under §96.4(a)(2) that commences operation on or after May 1, 1995, ther permitting
authority will use the unit's heat input, in accordance with paragraph (d) of this section.
(2) For a NOx allowance allocation for any year after 2005 under §96.41(b):
(i) The permitting authority will use the {specify net or gross} electric and thermal output for
the unit under §96.4(a)(l) for the non-emitting generating system], and heat input for the unit under
§96.4(a)(2) for the control period in the year that is four years before the year for which the NOx
allocation is being calculated; or
(ii) For a unit for non-emitting generating system] that commences operation on or after May
1 of the year that is four years before the year for which the permitting authority allocates, the
permitting authority will determine allocations in accordance with paragraph (d) of this section.
(3) The permitting authority will determine the unit's heat input:
(i) In accordance with 40 CFR part 75; or
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(ii) Based on the best available data reported to the permitting authority for the unit, if the
unit was not otherwise subject to the requirements of 40 CFR part 75 for the control period.
(4) The permitting authority will determine the {specify gross or net} thermal and {specify
gross or net} electric output for the unit [or non-emitting generating system] using {insert source
ofdata-e.g., net electric generation data from the Energy Information Administration, gross electric
generation data in accordance with subpart H of 40 CFR part 75, electric generation data in
accordance with subpart H of 40 CFR part 75, or the best available data reported to the permitting
authority for the unit or non-emitting generating system.}
(b) Allocation to units under §96.4(a)(l)[and non-emitting generating systems]. For each
control period in 2003 through 2005, the permitting authority will allocate NOx allowances to all
NOx Budget units under §96.4(a)(l) [or non-emitting generating system] in [the State] {substitute
name of your State} that commenced operation before May 1, 1997. For each control period after
2005, the permitting authority will allocate NOx allowances to all NOx Budget units under
§96.4(a)(l) [or non-emitting generating systems] in [the State] {substitute name of your State} that
commenced operation before May 1 of the period used to calculate electric and thermal output under
paragraph (a)(2) of this section. The permitting authority will calculate NOx allowance allocations
as follows:
(1) The permitting authority will allocate NOx allowances to each unit under §96.4(a)(l)
[and to each non-emitting generating system] in an amount equaling: 1.5 Ib/MWh multiplied by the
{specify net or gross} electric output under paragraph (a) of this section and divided by 2,000 Ib/ton,
plus 0.24 lb/mmBtuout40 multiplied by the {specify net or gross} thermal output under paragraph (a)
of this section and divided by 2,000 Ib/ton. Each allocation will be rounded to the nearest whole
number of NOx allowances, as appropriate.
(2) For the control periods 2003, 2004, and 2005, the permitting authority will adjust the
40Use the value of 0.24 Ib/mmBtu output if you assume a typical boiler efficiency of 70%
and if you require sources to use the boiler efficiency approach for measuring thermal output, as
described in section VI. of this document (pp. 68-69, 84-91, and 124-137). If you decide to use
the simplified approach for monitoring output and a typical boiler efficiency of 70%, then this
number should be 0.22 Ib/mmBtu. If you want to assume a different typical boiler efficiency, see
section II. A. to calculate your own allocation factor (pp. 23-31).
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initial allocations under paragraph (b)(l) of this section so that the total number of NOx allowances
allocated for 2003, 2004, or 2005 equals 95 percent of the number of tons of NOx emissions in the
State trading program budget apportioned to units under §96.4(a)(l), if these numbers are not already
equal. This adjustment will be made by: multiplying each unit's allocation for 2003, 2004, or 2005
by 95 percent of the number of tons of NOx emissions in the State trading program budget
apportioned to units under §96.4(a)(l) divided by the total number of NOx allowances allocated
under paragraph (b)( 1) of this section, and rounding to the nearest whole number of NOx allowances,
as appropriate.
(3) For each control period after 2005, the permitting authority will adjust the initial
allocations under paragraph (b)(l) of this section so that the total number of NOx allowances
allocated for each control period after 2005 equals 98 percent of the number of tons of NOx
emissions in the State trading program budget apportioned to units under §96.4(a)(l), if these
numbers are not already equal. This adjustment will be made by: multiplying each unit's allocation
for a control period after 2005 by 98 percent of the number of tons of NOx emissions in the State
trading program budget apportioned to units under §96.4(a)(l) divided by the total number of NOx
allowances allocated under paragraph (b)(l) of this section, and rounding to the nearest whole
number of NOx allowances, as appropriate.
(c) Allocation to units under §96.4(a)(2). For each control period under § 96.41, the
permitting authority will allocate NOx allowances to all units under §96.4(a)(2) in [the State] {insert
name of State} that commenced operation before May 1 of the period used to calculate heat input
under paragraph (a) of this section. The permitting authority will allocate NOx allowances in
accordance with the following procedures:
(1) The permitting authority will allocate NOx allowances to each NOx Budget unit under
§96.4(a)(2) in an amount equaling 0.17 Ib/mmBtu multiplied by the heat input under paragraph (a)
of this section, divided by 2,000 Ib/ton. Each allocation will be rounded to the nearest whole number
of NOx allowances, as appropriate.
(2) The permitting authority will adjust the unadjusted allocations under paragraph (c)(l) of
this section so that the total number of NOx allowances allocated equals 95 percent in 2003, 2004,
and 2005, or 98 percent thereafter, of the number of tons of NOx emissions in the State trading
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program budget apportioned to units under §96.4(a)(2), if these numbers are not already equal. This
adjustment will be made by: multiplying each unit's for a control period by 95 percent in 2003,2004,
or 2005, or by 98 percent thereafter, of the number of tons of NOx emissions in the State trading
program budget apportioned to units under §96.4(a)(2), dividing by the total number of NOx
allowances allocated under paragraph (c)(l) of this section, and rounding to the nearest whole
number of NOx allowances, as appropriate.
(d) For each control period under § 96.41, the permitting authority will allocate NOx
allowances to NOx Budget units under § 96.4 for non-emitting generating systems] in [the State]
{insert name of your State} that commenced operation, or are projected to commence operation, on
or after May 1 of the period used to calculate heat input or electric and thermal output under
paragraph (a) of this section, in accordance with the following procedures:
(1) The permitting authority will establish one allocation set-aside for each control period.
Each allocation set-aside will be allocated NOx allowances equal to 5 percent in 2003, 2004, and
2005, or 2 percent thereafter, of the tons of NOx emissions in the State trading program budget,
rounded to the nearest whole number of NOx allowances, as appropriate.
(2) The NOx authorized account representative of a unit for non-emitting generating system]
under paragraph (d) of this section may submit to the permitting authority a request, in writing or in
a format specified by the permitting authority, to be allocated NOx allowances for no more than five
consecutive control periods under § 96.41, starting with the control period during which the unit for
non-emitting generating system] commenced, or is projected to commence, operation and ending
with the control period preceding the control period for which it will receive an allocation under
paragraph (b) or (c) of this section. The NOx allowance allocation request must be submitted prior
to May 1 of the first control period for which the NOx allowance allocation is requested and after
the date on which the permitting authority issues a permit to construct the unit for non-emitting
generating system].
(3) In a NOx allowance allocation request under paragraph (d)(2) of this section, the NOx
authorized account representative for a unit under §96.4(a)( 1) for a non-emitting generating system]
may request NOx allowances for a control period. The requested number of NOx allowances must
not exceed 1.5 Ib/MWh multiplied by the nameplate capacity (in MW) of the unit for non-emitting
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Appendix A: Sample rule language to account for output-based allocations Case 3
generating system]', multiplied by the number of hours remaining in the control period starting with
the first day in the control period on which the unit operated or is projected to operate, and divided
by 2,000 Ib/ton.
(4) In a NOx allowance allocation request under paragraph (d)(2) of this section, the NOx
authorized account representative for a unit under §96.4(a)(2) may request NOx allowances for a
control period. The requested number of NOx allowances must not exceed 0.17 Ib/mmBtu
multiplied by the unit's maximum design heat input (in mmBtu/hr), multiplied by the number of
hours remaining in the control period starting with the first day in the control period on which the
unit operated or is projected to operate, and divided by 2,000 Ib/ton.
(5) The permitting authority will review, and allocate NOx allowances pursuant to, each NOx
allowance allocation request under paragraph (d)(2) of this section in the order that the request is
received by the permitting authority.
(i) Upon receipt of the NOx allowance allocation request, the permitting authority will make
any necessary adjustments to the request to ensure that, for aunit under §96.4(a)(l) for non-emitting
generating system], the control period and the number of allowances specified are consistent with
the requirements of paragraphs (d)(2) and (3) of this section and, for a unit under §96.4(a)(2), the
control period and the number of allowances specified are consistent with the requirements of
paragraphs (d)(2) and (4) of this section.
(ii) If the allocation set-aside for the control period for which NOx allowances are requested
has an amount of NOx allowances not less than the number requested (as adjusted under paragraph
(d)(5)(i) of this section), the permitting authority will allocate the amount of the NOx allowances
requested (as adjusted under paragraph (d)(5)(i) of this section) to the unit for non-emitting
generating system].
(iii) If the allocation set-aside for the control period for which NOx allowances are requested
has a smaller amount of NOx allowances than the number requested (as adjusted under paragraph
(d)(5)(i) of this section), the permitting authority will deny in part the request and allocate only the
remaining number of NOx allowances in the allocation set-aside to the unit [or non-emitting
generating system].
(iv) Once an allocation set-aside for a control period has been depleted of all NOx
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Case 3
allowances, the permitting authority will deny, and will not allocate any NOx allowances pursuant
to, any NOx allowance allocation request under which NOx allowances have not already been
allocated for the control period.
(6) Within 60 days of receipt of a NOx allowance allocation request, the permitting authority
will take appropriate action under paragraph (d)(5) of this section and notify the NOx authorized
account representative that submitted the request and the Administrator of the number of NOx
allowances (if any) allocated for the control period to the unit for non-emitting generating system].
(e) For a unit for non-emitting generating system] allocated NOx allowances under paragraph
(d) of this section for a control period, the Administrator will deduct NOx allowances under §
96.54(b) or (e) to account for the actual utilization or output of the unit for non-emitting generating
system] during the control period. The Administrator will calculate the number of NOx allowances
to be deducted to account for the unit's actual utilization or output using the following formulas and
rounding to the nearest whole number of NOx allowances as appropriate, provided that the number
of NOx allowances to be deducted shall be zero if the number calculated is less than zero:
NOx allowances deducted for actual output for a unit under §96.4(a)(l) for a non-emitting
generating system] = (Unit's NOx allowances allocated for control period) - ( Unit's actual control
period {specify net or gross} electric output x 1.5 Ib/MWh ^2,000 Ib/ton and actual control period
{specify net or gross} thermal output x 0.24 lb/mmBtuout41 -^2,000 Ib/ton); and
NOx allowances deducted for actual utilization for a unit under §96.4(a)(2)= (NOx allowances
allocated for control period) - (Actual control period heat input x 0.17 Ib/mmBtu -^2,000 Ib/ton)
where:
"NOx allowances allocated for control period" is the number of NOx allowances allocated
to the unit for the non-emitting generating system] for the control period; and
"Actual control period heat input" is the heat input (in mmBtu) of the unit during the control
period; and
"Actual control period {specify net or gross} electric output" is the {specify net or gross}
electric output in MWh of the unit for non-emitting generating system] during the control period;
41Same as footnote 40.
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and
"Actual control period {specify net or gross} thermal output" is the {specify net or gross}
thermal output in mmBtuout of the unit during the control period.
(f) After making the deductions for compliance under § 96.54(b) or (e) for a control period,
the Administrator will notify the permitting authority whether any NOx allowances remain in the
allocation set-aside for the control period. The permitting authority will allocate any such NOx
allowances to the units under §96.4 [and the non-emitting generating systems] in [the State] {insert
name of your State} using the following formula and rounding to the nearest whole number of NOx
allowances as appropriate:
Unit's [or non-emitting generating system 'sj share of NOx allowances remaining in allocation set-
aside = Total NOx allowances remaining in allocation set-aside x (NOx allowance allocation + State
trading program budget excluding allocation set-aside)
where:
"Total NOx allowances remaining in allocation set-aside" is the total number of NOx allowances
remaining in the allocation set-aside for the control period;
" NOx allowance allocation" is the number of NOx allowances allocated under paragraph (b) or (c)
of this section to the unit for non-emitting generating system] for the control period to which the
allocation set-aside applies; and
"State trading program budget excluding allocation set-aside" is the State trading program budget
for the control period to which the allocation set-aside applies multiplied by 95 percent if the control
period is in 2003, 2004, or 2005 or 98 percent if the control period is in any year thereafter, rounded
to the nearest whole number of NOx allowances as appropriate.
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Case 4
You initially allocate and periodically update allocations to both EGUs and non-EGUs based
on output
§ 96.42 NOx allowance allocations.
(a) Basis for allocation. The permitting authority will calculate NOx allowance allocations
for each NOx Budget unit under § 96.4 [or non-emitting generating system] as follows:
(1) For a NOx allowance allocation for 2003 through 2005 under §96.41(a):
(i) The permitting authority will use the average of the two highest amounts of the unit's [or
non-emitting generating system rs] {specify net or gross} electric output (in MWh) and {specify net
or gross} thermal output (in mmBtu output) for the control periods in 1995, 1996, and 1997 if the
unit [or non-emitting generating system] is under §96.4(a)(l), or the unit's {specify net or gross}
thermal output (in mmBtu output) and {specify net or gross} electric output (in MWh) for the control
period in 1995 if the unit is under §96.4(a)(2); or
(ii) For a unit under §96.2(a)(l) [or non-emitting generating system] that commences
operation on or after May 1, 1997, or for a unit under §96.4(a)(2) that commences operation on or
after May 1, 1995, the permitting authority will use the unit's [or non-emitting generating system's]
electric output or thermal output in accordance with paragraph (d) of this section.
(2) For a NOx allowance allocation for any year after 2005 under §96.41(b):
(i) The permitting authority will use the {specify net or gross} electric and thermal output for
the unit for the non-emitting generating system] for the control period in the year that is four years
before the year for which the NOx allocation is being calculated; or
(ii) For a unit for non-emitting generating system] that commences operation on or after May
1 of the year that is four years before the year for which the permitting authority allocates, the
permitting authority will determine allocations in accordance with paragraph (d) of this section.
(3) The permitting authority will determine the {specify gross or net} thermal and electric
output for the unit [or the non-emitting generating system] using {insert source ofdata-e.g., net
electric generation data from the Energy Information Administration, gross electric generation data
in accordance with subpart H of 40 CFR part 75, electric generation data in accordance with
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Appendix A: Sample rule language to account for output-based allocations Case 4
subpartHof40 CFRpart 75, or the best available data reported to the permitting authority for the
unit [or the non-emitting generating system].}
(b) Allocation to units under §96.4(a)(l)[and non-emitting generating systems]. For each
control period in 2003 through 2005, the permitting authority will allocate NOx allowances to all
NOx Budget units under §96.4(a)(l) [or non-emitting generating systems] in [the State] {substitute
name of your State} that commenced operation before May 1, 1997. For each control period after
2005, the permitting authority will allocate NOx allowances to all NOx Budget units under
§96.4(a)(l) [or non-emitting generating systems] in [the State] {substitute name of your State} that
commenced operation before May 1 of the period used to calculate electric and thermal output under
paragraph (a)(2) of this section. The permitting authority will calculate NOx allowance allocations
as follows:
(1) For each control period, the permitting authority will allocate NOx allowances to each
unit under §96.4(a)(l) [and to each non-emitting generating system] in an amount equaling: 1.5
Ib/MWh multiplied by the {specify net or gross} electric output under paragraph (a) of this section
and divided by 2,000 Ib/ton, plus 0.24 lb/mmBtuout42 multiplied by the {specify net or gross} thermal
output under paragraph (a) of this section and divided by 2,000 Ib/ton. Each allocation will be
rounded to the nearest whole number of NOx allowances, as appropriate.
(2) For 2003 through 2005, the permitting authority will adjust the initial allocations under
paragraph (b)(l) of this section so that the total number of NOx allowances allocated for 2003,2004,
or 2005 equals 95 percent of the number of tons of NOx emissions in the State trading program
budget apportioned to units under §96.4(a)(l), if these numbers are not already equal. This
adjustment will be made by: multiplying each unit's allocation for 2003,2004, or 2005 by 95 percent
of the number of tons of NOx emissions in the State trading program budget apportioned to units
under §96.4(a)(l), dividing by the total number of NOx allowances allocated for the year under
42Use the value of 0.24 Ib/mmBtu output if you assume a typical boiler efficiency of 70%
and if you require sources to use the boiler efficiency approach for measuring thermal output, as
described in section VI. of this document (pp. 68-69, 84-91, and 124-137). If you decide to use
the simplified approach for monitoring output and a typical boiler efficiency of 70%, then this
number should be 0.22 Ib/mmBtu. If you want to assume a different typical boiler efficiency, see
section II. A. to calculate your own allocation factor (pp. 23-31).
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paragraph (b)(l) of this section, and rounding to the nearest whole number of NOx allowances, as
appropriate.
(3) For each control period after 2005, the permitting authority will adjust the initial
allocations under paragraph (b)(l) of this section so that the total number of NOx allowances
allocated for each control period after 2005 equals 98 percent of the number of tons of NOx
emissions in the State trading program budget apportioned to units under §96.4(a)(l), if these
numbers are not already equal. This adjustment will be made by: multiplying each unit's allocation
for a control period after 2005 by 98 percent of the number of tons of NOx emissions in the State
trading program budget apportioned to units under §96.4(a)(l) divided by the total number of NOx
allowances allocated under paragraph (b)(l) of this section, and rounding to the nearest whole
number of NOx allowances, as appropriate.
(c) Allocation to units under §96.4(a)(2). For 2003 through 2005, the Department will
allocate NOx allowances to all NOx Budget units under §96.4(a)(2) in [the State] {substitute name
of your State} that commenced operation before May 1, 1995. For each control period after the year
2005, the permitting authority will allocate NOx allowances to all NOx Budget units under
§96.4(a)(2) in [the State] {substitute name of your State} that commenced operation before May 1
of the period used to calculate electric and thermal output under paragraph (a)(2) of this section. The
permitting authority will calculate NOx allowance allocations as follows:
(1) The permitting authority will allocate NOx allowances to each unit under §96.4(a)(2) in
an amount equaling: 0.24 lb/mmBtuout43 multiplied by the {specify net or gross} thermal output under
paragraph (a) of this section and divided by 2,000 Ib/ton, plus 1.5 Ib/MWh multiplied by the {specify
net or gross} electric output under paragraph (a) of this section and divided by 2,000 Ib/ton. Each
allocation will be rounded to the nearest whole number of NOx allowances, as appropriate.
(2) For 2003 through 2005, the permitting authority will adjust the unadjusted allocations
under paragraph (c)(l) of this section so that the total number of NOx allowances allocated equals
95 percent in 2003, 2004, or 2005, of the number of tons of NOx emissions in the State trading
program budget apportioned to units under §96.4(a)(2), if these numbers are not already equal. This
43Same as footnote 42.
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adjustment will be made by: multiplying each unit's allocation in 2003,2004, or 2005 by 95 percent
of the number of tons of NOx emissions in the State trading program budget apportioned to units
under §96.4(a)(2), dividing by the total number of NOx allowances allocated under paragraph (c)(l)
of this section, and rounding to the nearest whole number of NOx allowances, as appropriate.
(3) For each control period after 2005, the permitting authority will adjust the initial
allocations under paragraph (c)(l) of this section so that the total number of NOx allowances
allocated for each control period after 2005 equals 98 percent of the number of tons of NOx
emissions in the State trading program budget apportioned to units under §96.4(a)(2), if these
numbers are not already equal. This adjustment will be made by: multiplying each unit's allocation
for a control period after 2005 by 98 percent of the number of tons of NOx emissions in the State
trading program budget apportioned to units under §96.4(a)(2) and dividing by the total number of
NOx allowances allocated under paragraph (c)(l) of this section, and rounding to the nearest whole
number of NOx allowances, as appropriate.
(d) For each control period under § 96.41, the permitting authority will allocate NOx
allowances to NOx Budget units under § 96.4 [or non-emitting generating systems] in [the State]
{insert name of your State} that commenced operation, or are projected to commence operation, on
or after May 1 of the period used to calculate electric and thermal output under paragraph (a) of this
section, in accordance with the following procedures:
(1) The permitting authority will establish one allocation set-aside for each control period.
Each allocation set-aside will be allocated NOx allowances equal to 5 percent in 2003, 2004, and
2005, or 2 percent thereafter, of the tons of NOx emissions in the State trading program budget,
rounded to the nearest whole number of NOx allowances, as appropriate.
(2) The NOx authorized account representative of a unit [or non-emitting generating system]
under paragraph (d) of this section may submit to the permitting authority a request, in writing or in
a format specified by the permitting authority, to be allocated NOx allowances for no more than five
consecutive control periods under § 96.41, starting with the control period during which the unit [or
non-emitting generating system] commenced, or is projected to commence, operation and ending
with the control period preceding the control period for which it will receive an allocation under
paragraph (b) or (c) of this section. The NOx allowance allocation request must be submitted prior
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to May 1 of the first control period for which the NOx allowance allocation is requested and after
the date on which the permitting authority issues a permit to construct the unit [or non-emitting
generating system].
(3) In a NOx allowance allocation request under paragraph (d)(2) of this section, the NOx
authorized account representative for a unit under §96.4(a)( 1) [or a non-emitting generating system]
may request NOx allowances for a control period. The requested number of NOx allowances must
not exceed 1.5 Ib/MWh multiplied by the nameplate capacity (in MW) of the unit [or non-emitting
generating system]', multiplied by the number of hours remaining in the control period starting with
the first day in the control period on which the unit operated or is projected to operate, and divided
by 2,000 Ib/ton.
(4) In a NOx allowance allocation request under paragraph (d)(2) of this section, the NOx
authorized account representative for a unit under §96.4(a)(2) may request NOx allowances for a
control period. The requested number of NOx allowances must not exceed 0.24 lb/mmBtuout,44
multiplied by the maximum design heat input of the unit (in mmBtu/hr), divided by an efficiency
factor of 0.70,45 multiplied by the number of hours remaining in the control period starting with the
first day in the control period on which the unit operated or is projected to operate, and divided by
2,000 Ib/ton.
(5) The permitting authority will review, and allocate NOx allowances pursuant to, each NOx
allowance allocation request under paragraph (d)(2) of this section in the order that the request is
received by the permitting authority.
(i) Upon receipt of the NOx allowance allocation request, the permitting authority will make
any necessary adjustments to the request to ensure that, for a unit under §96.4(a)(l) for non-emitting
44
Same as footnote 42.
45 This efficiency factor of 0.70 is appropriate for use with the boiler efficiency approach
for measuring output, as described in section VI. of this document (pp. 68-69, 84-91, and 124-
137). If you decide to use the simplified approach for monitoring thermal output and a typical
boiler efficiency of 70%, then this "efficiency" factor should be 77% or 0.77. If you use the
simplified approach to monitoring output and assume a different boiler efficiency, divide the heat
input-based allocation factor of 0.17 Ib/mmBtu by the thermal output-based factor from Table II-
1 in section II.A., p. 29 to compute the appropriate "efficiency" factor.
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generating system]., the control period and the number of allowances specified are consistent with
the requirements of paragraphs (d)(2) and (3) of this section and, for a unit under §96.4(a)(2), the
control period and the number of allowances specified are consistent with the requirements of
paragraphs (d)(2) and (4) of this section.
(ii) If the allocation set-aside for the control period for which NOx allowances are requested
has an amount of NOx allowances not less than the number requested (as adjusted under paragraph
(d)(5)(i) of this section), the permitting authority will allocate the amount of the NOx allowances
requested (as adjusted under paragraph (d)(5)(i) of this section) to the unit [or non-emitting
generating system].
(iii) If the allocation set-aside for the control period for which NOx allowances are requested
has a smaller amount of NOx allowances than the number requested (as adjusted under paragraph
(d)(5)(i) of this section), the permitting authority will deny in part the request and allocate only the
remaining number of NOx allowances in the allocation set-aside to the unit [or non-emitting
generating system].
(iv) Once an allocation set-aside for a control period has been depleted of all NOx
allowances, the permitting authority will deny, and will not allocate any NOx allowances pursuant
to, any NOx allowance allocation request under which NOx allowances have not already been
allocated for the control period.
(6) Within 60 days of receipt of a NOx allowance allocation request, the permitting authority
will take appropriate action under paragraph (d)(5) of this section and notify the NOx authorized
account representative that submitted the request and the Administrator of the number of NOx
allowances (if any) allocated for the control period to the unit [or non-emitting generating system].
(e) For a unit [or non-emitting generating system] allocated NOx allowances under paragraph
(d) of this section for a control period, the Administrator will deduct NOx allowances under §
96.54(b) or (e) to account for the actual output of the unit [or non-emitting generating system]
during the control period. The Administrator will calculate the number of NOx allowances to be
deducted to account for the unit's actual output using the following formulas and rounding to the
nearest whole number of NOx allowances as appropriate, provided that the number of NOx
allowances to be deducted shall be zero if the number calculated is less than zero:
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NOx allowances deducted for actual output for a unit under §96.4(a)(l) [or a non-emitting
generating system] = (Unit's NOx allowances allocated for control period) - ( Unit's actual control
period {specify net or gross} electric output x 1.5 Ib/MWh -^2,000 Ib/ton and actual control period
{specify net or gross} thermal output x 0.24 lb/mmBtuout46 -^2,000 Ib/ton); and
NOx allowances deducted for actual output for a unit under §96.4(a)(2)= (NOx allowances allocated
for control period) - (Actual control period {specify net or gross} thermal outputx 0.24 lb/mmBtuout47
-^2,000 Ib/ton and actual control period {specify net or gross} electric output x 1.5 Ib/MWh + 2,000
Ib/ton)
where:
"NOx allowances allocated for control period" is the number of NOx allowances allocated
to the unit for the non-emitting generating system] for the control period; and
"Actual control period {specify net or gross} electric output" is the {specify net or gross}
electric output in MWh of the unit [or non-emitting generating system] during the control period;
and
"Actual control period {specify net or gross} thermal output" is the {specify net or gross}
thermal output in mmBtuout of the unit during the control period.
(f) After making the deductions for compliance under § 96.54(b) or (e) for a control period,
the Administrator will notify the permitting authority whether any NOx allowances remain in the
allocation set-aside for the control period. The permitting authority will allocate any such NOx
allowances to the units under §96.4 [and the non-emitting generating systems] in [the State] {insert
name of your State} using the following formula and rounding to the nearest whole number of NOx
allowances as appropriate:
Unit's [or non-emitting generating system 's] share of NOx allowances remaining in allocation set-
aside = Total NOx allowances remaining in allocation set-aside x (NOx allowance allocation + State
trading program budget excluding allocation set-aside)
where:
46 Same as footnote 42.
47 Same as footnote 42.
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"Total NOx allowances remaining in allocation set-aside" is the total number of NOx allowances
remaining in the allocation set-aside for the control period;
" NOx allowance allocation" is the number of NOx allowances allocated under paragraph (b) or (c)
of this section to the unit [or non-emitting generating system] for the control period to which the
allocation set-aside applies; and
"State trading program budget excluding allocation set-aside" is the State trading program budget
for the control period to which the allocation set-aside applies multiplied by 95 percent if the control
period is in 2003, 2004, or 2005 or 98 percent if the control period is in any year thereafter, rounded
to the nearest whole number of NOx allowances as appropriate.
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Appendix B: Glossary of terms used in this guidance
Appendix B: Glossary of terms used in this guidance
add-on pollution controls -a pollution reduction control technology that operates independent
of the combustion process. Examples: selective catalytic reduction, scrubber
adjusted allocation-an allocation that has been increased or decreased in proportion to a unit,
source or generator's share of all operation from a group of units or sources with a budget. For
example, an electric generating unit's initial allocation could be increased if the sum of the initial
allocations for all units in the EGU sector was less than the budget for the EGU sector. Each unit
would then have its allocation increased so that it would have the same fraction of the EGU sector
budget as it has a fraction of total electric generation in the EGU sector in the state.
- American Gas Association
allocation-the number of NOx allowances the permitting authority assigns to a unit or a set-
aside. Section 96.2 of the model rule for the NOx Budget Trading Program defines an allocation as
"the determination by the permitting authority or the Administrator of the number of NOx
allowances to be initially credited to a NOx Budget unit or an allocation set-aside."
allowance-an authorization to emit up to one ton of a pollutant during the control period of
the specified year or of any year thereafter. For the NOx Budget Trading Program, the authorization
is from the permitting authority or the Administrator to emit up to one ton of NOx.
y47V57-American National Standards Institute
y4,SME-American Society for Mechanical Engineering
^ZM-American Society for Testing and Materials
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Appendix B: Glossary of terms used in this guidance
auxiliary /oaJ-electric generation used internally as part of operations of the unit, fuel feed
equipment, fans, belts, or generator.
baseline period-the period of time from which historical operating information comes, which
is then used as the basis for allocations. Section 96.42 of the model rule for the NOx Budget Trading
Program under the NOx SIP call uses the control periods of 1995, 1996, and 1997 as the baseline
period for allocations for 2003, 2004, and 2005.
boiler-an enclosed fossil or other fuel-fired combustion device used to produce heat and to
transfer heat to recirculating water, steam, or other medium.
boiler efficiency— a measure of the efficiency of a steam generating system which calculates
efficiency as the energy imparted to the steam from combustion (mmBtu) divided by the boiler heat
input due to combustion of fuel (mmBtu). A monitoring system which determines the energy
imparted to the steam leaving the boiler tubes by calculating the balance of energy on thermal energy
leaving and entering the boiler measures boiler efficiency.
boiler efficiency approach- an approach to monitoring thermal output that determines the
energy imparted to the steam leaving the boiler tubes by calculating the balance of energy on thermal
energy leaving and entering the boiler through steam or hot water output and boiler input water. This
approach assumes that efficiency is calculated using an energy balance that subtracts hot water or
steam's energy from the thermal energy leaving a boiler, and is divided by the boiler heat input from
combustion of fuel.
boiler feedwater return or feedwater-the condensed water entering a boiler to be reheated
that previously came from the boiler. This condensate return adds thermal energy to water going into
the boiler.
Btu/kWh- British thermal units per kilowatt-hour
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buss bar-the point where electricity leaves a power plant to go to the grid.
combined cycle system—& system comprised of a combustion turbine, one or more heat
recovery steam generators, and steam turbines configured to improve overall efficiency of electricity
generation or steam production.
CEMS or continuous emission monitoring systems-- Equipment for continuously measuring
and recording characteristics of pollutants in stack gas, such as the NOx concentration, NOx
emission rate in Ib/mmBtu, stack flow rate, or NOx mass. In section 96.2 of the model rule for the
NOx Budget Trading Program for the NOx SIP call, CEMS are "the equipment required under
subpart H of [40 CFR part 96] to sample, analyze, measure, and provide, by readings taken at least
once every 15 minutes of the measured parameters, a permanent record of nitrogen oxides emissions,
expressed in tons per hour for nitrogen oxides...." Under the NOx SIP call, CEMS must meet the
applicable requirements of 40 CFR part 75.
cement kiln-a device which heats and processes cement.
CFR-Code of Federal Regulations
Cogeneration unit-a unit that produces electric energy and useful thermal energy for
industrial, commercial, or residential heating or cooling purposes, through the sequential use of the
original fuel energy.
CHP or combined heat and power or Cogeneration—producing electric energy and useful
thermal energy for industrial, commercial, or residential heating or cooling purposes, through the
sequential use of the original fuel energy.
CT or combustion turbine— an enclosed fossil or other fuel-fired device that is comprised of
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a compressor, a combustor, and a turbine, and in which the flue gas resulting from the combustion
of fuel in the combustor passes through the turbine, rotating the turbine.
condensate-water that is created when steam condenses.
DAHS or data acquisition and handling system— the computerized system for receiving,
calculating, recording, and reporting emissions and operating data in appropriate units of measure.
Section 96.2 of the model rule for the NOx Budget Trading Program defines DAHS as "that
component of the CEMS, or other emissions monitoring system approved for use under subpart H
of [40 CFR part 96], designed to interpret and convert individual output signals from pollutant
concentration monitors, flow monitors, diluent gas monitors, and other component parts of the
monitoring system to produce a continuous record of the measured parameters in the measurement
units required by subpart H of [40 CFR part 96].
EDR or electronic data reporting— EPA's standardized format for electronic data reporting.
EGU-e\ectric generating unit. For purposes of this document, a fossil fuel-fired unit that
serves an electric generator greater than 25 MWe and produces electricity for sale.
EJA- Energy Information Administration
electric output—the electric generation (in MWh) from an electric generator.
°F-degrees Fahrenheit
fossil fuel— natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived
from such material.
fossil fuel-fired-burning mostly fossil fuels. Section 96.2 of the model rule for the NOx
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Budget Trading Program defines fossil fuel-fired as "with regard to a unit:
(1) The combustion of fossil fuel, alone or in combination with any other fuel, where fossil fuel
actually combusted comprises more than 50 percent of the annual heat input on a Btu basis during
any year starting in 1995 or, if a unit had no heat input starting in 1995, during the last year of
operation of the unit prior to 1995; or
(2) The combustion of fossil fuel, alone or in combination with any other fuel, where fossil fuel is
projected to comprise more than 50 percent of the annual heat input on a Btu basis during any year;
provided that the unit shall be "fossil fuel-fired" as of the date, during such year, on which the unit
begins combusting fossil fuel. "
grid-a system for transmitting or distributing electricity.
gross output—the total energy output of a process before making any deductions for any
energy output consumed in any way related to producing energy through that process.
heat input-thermal energy going into a process through combustion of fuel. Section 96.2 of
the model rule for the NOx Budget Trading Program defines heat input as "the product (in
mmBtu/time) of the gross calorific value of the fuel (in Btu/lb) and the fuel feed rate into a
combustion device (in mass of fuel/time), as measured, recorded, and reported to the Administrator
by the NOx authorized account representative and as determined by the Administrator in accordance
with subpart H of [40 CFR part 96], and does not include the heat derived from preheated
combustion air, recirculated flue gases, or exhaust from other sources."
heat rate-the efficiency of producing electricity from combustion of fuel, in Btu/kWh.
house load-electric generation or thermal energy generation used internally within the facility
where the electricity or thermal energy is generated.
HRSG or heat recovery steam generator-^ device for recovering heat left after generating
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electricity with a turbine and using the recovered heat to produce steam.
IEEE-Institute of Electrical and Electronics Engineers
industrial boiler or turbine-a. boiler or turbine used to provide thermal energy, or in some
cases electricity, to operate an industrial process.
institutional boiler or turbine-a boiler or turbine used to provide thermal energy, or in some
cases electricity, to operate a process for a non-industrial institution, such as a hospital, government
office, or school.
Ar/Mzr-thousands of pounds per hour
Ib/mmBtu heat input pounds of pollutant per measured million British thermal units of heat
input
lb/mmBtuout-pounds of pollutant emitted per measured million British thermal units of
thermal output
/&/MJ^7z-pounds of pollutant per megawatt-hour
make up water-relatively cold water that is mixed with any returned condensate before
feeding water into the boiler.
mmBtu million British thermal units
model rule or model rule for the NOx Budget TradingProgram-the optional model rule EPA
prepared for States that would comply with the NOx SIP call by joining the NOx Budget Trading
Program, found at 40 CFR part 96.
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MJ^Tz-megawatt-hour
nameplate capacity-the maximum electric generation an electric generator has been designed
to sustain. Section 96.2 of the model rule for the NOx Budget Trading Program defines nameplate
capacity as "the maximum electrical generating output (in MWe) that a generator can sustain over
a specified period of time when not restricted by seasonal or other deratings as measured in
accordance with the United States Department of Energy standards."
net output—the final output of a process after deducting any output consumed in any way
related to producing energy through that process. Examples of output to be deducted include thermal
output lost through radiation to the outside, thermal output used for air or feedwater preheating, or
thermal or electric output used within the plant to operate the unit, generator, fuel handling system,
pumps, fans, or emission control equipment. Output used to produce a useful material product
besides the thermal output or electric output, such as thermal energy used to dry paper, does not need
to be deducted when calculating net output.
new source set-aside-^ portion of allowances taken from a State budget for distribution to
new sources instead of to existing sources.
MST-National Institute for Standards and Technology (formerly the National Bureau of
Standards).
non-EGU or non-electric generating unit-for purposes of this guidance, an industrial or
institutional boiler or turbine.
non-emitting electric generating system or non-emitting generating system—the portion of
a facility for generating electricity that uses an energy source not involving combustion of fuel or
NOx emissions, such as hydroelectric, nuclear, geothermal, or wind power, and that uses an electric
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generator.
TVOx-oxides of nitrogen (e.g., NO, NO2)
NOx Budget Trading Program-trie multi-state nitrogen oxides air pollution control and
emission reduction program established under the NOx SIP call as a means of mitigating the
interstate transport of ozone and nitrogen oxides, an ozone precursor.
NOx SIP ca//-EPA's requirement that States revise their State implementation plans to
control NOx mass emissions in order to reduce interstate transport of ozone. See 63 FR 57355,
October 27, 1998, Finding of Significant Contribution and Rulemaking for Certain States in the
Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone.
OTC-Ozone Transport Commission
OTC NOx Budget Program-^ program organized by the Ozone Transport Commission for
controlling NOx emissions in thirteen northeast States and the District of Columbia. EPA
administers some portions of the program, such as allowance and emissions tracking.
output monitoring system—& collection of component pieces of equipment which are used
together to get a measurement of electric or thermal output in the units of measure required under
a regulation. An output monitoring system might consist of the following components:
• All wattmeters and a data logger that a company uses together to calculate electric output
data for a unit (or facility).
All flowmeters for steam or condensate, temperature measurement devices, absolute pressure
measurement devices, and differential pressure devices for measuring thermal energy and a
data logger that a company uses together to calculate thermal output data for a unit (or
facility).
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ozone season-the period from May 1 through September 30 of each year, inclusive.
parasitic loads-loads that are used within a plant to operate equipment that does not
contribute to the final product being sold. Examples of parasitic loads are electric loads used to
operate fuel handling and preparation equipment, pumps, compressors, motors, fans, or pollution
control equipment, or thermal loads used in operating pumps or compressors.
psi-pounds per square inch
2^-quality assurance. The process of checking the quality of data, including tests on
monitoring equipment.
saturated steam-steam at a temperature and pressure close to that of the normal boiling point
for water such that the steam will easily condense. This is the normal state for water vapor under
atmospheric pressure conditions. Industrial and institutional boilers typically produce saturated
steam, while utility boilers typically produce superheated steam.
scrubber-a flue gas desulfurization system for controlling SO2 emissions.
sector budget-the portion of the State budget associated with the electric generating unit
sector or the non-electric generating unit sector.
simplified approach— a simplified approach to monitoring output that measures the energy
output of steam exiting a boiler without compensating for the energy already in the water entering
the boiler. Under this approach a pseudo-efficiency may be determined by dividing the energy in
the steam leaving the boiler by the heat input from combustion of fuel. This pseudo-efficiency does
not take account of the law of conservation of energy and may result in an efficiency of greater than
1. A monitoring system using a simplified approach measures the total energy of steam exiting a
boiler and does not require measuring or subtracting thermal energy in the boiler feedwater
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(condensate) return.
source-a plant or facility that produces air pollutants. Section 96.2 of the model rule for the
NOx Budget Trading Program defines a source as " any governmental, institutional, commercial, or
industrial structure, installation, plant, building, or facility that emits or has the potential to emit any
regulated air pollutant under the Clean Air Act. For purposes of section 502(c) of the Clean Air Act,
a "source," including a "source" with multiple units, shall be considered a single "facility."
State budget-the total number of tons of NOx emissions proj ected for each State in year 2007
under the NOx SIP call.
Superheated steam or supersaturated steam-steam at a temperature and pressure sufficiently
higher than that for the normal boiling point for water that the steam will not condense. Utility
boilers typically produce superheated steam so that the steam will not condense in the steam turbine
that runs the electric generator.
thermal output—the thermal energy from a heat source (in mmBtuout/time) that is available
for use in another process after the subtraction of heat for boiler feed or combustion air preheating
or other heat recovery for combustion
trading budget-the portion of the State budget used to allocate NOx allowances under the
NOx Budget Trading Program.
unadjusted allocation-the tonnage initially calculated for a unit, source, or generator using
an emission rate and operational data, before adjusting to the total number of allowances available
for allocation.
unit-a fossil fuel-fired stationary boiler, combustion turbine, or combined cycle system.
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Appendix B: Glossary of terms used in this guidance
Updating Output Emission Limitation Workgroup-the stakeholder workgroup that has
advised EPA during development of this guidance document. The workgroup reports to the Clean
Air, Energy and Climate Subcommittee of the Clean Air Act Advisory Committee.
updating allocation-an allocation that the permitting authority recalculates and uses to
redistribute allowances using more current operational data.
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Index
Index
Subject Page number
adjusting unadjusted allocations to fit a State budget 34-39
by sector budgets for EGUs and for non-EGUs 34-36
example adjusting EGUs, non-EGUs to sector budgets by output 34
to fit the entire State trading budget 37
allocating to some sources on output and to others on heat input 40-43
calculating unadjusted allocations using heat input for non-EGUs 40
example adjusting EGUs by output, non-EGUs by heat input 41
fitting unadjusted allocations to sector budgets 40
allocation factor 25
for electric output 25
for thermal output measured by the boiler efficiency approach 26
for thermal output measured by the simplified approach 27
American Gas Association (AGA) 158, 159
American National Standards Institute (ANSI) 158
American Society for Testing and Materials (ASTM) 158
American Society of Mechanical Engineers (ASME) 158, 159
auxiliaries loads 50, 51
boiler efficiency approach to monitoring thermal output
difference from simplified approach 56, 92
monitoring thermal output from cogenerators under 118-137
use for example allocation calculations 31
calculating electric output 141
calculating the unadjusted allocation 31
for sources that produce more than one form of output 32
for electric output 31
for thermal output 32
calculating entalpy 138-141
calculating thermal output 138-141
cement kilns 31, 44, 208
CHP-see cogeneration
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Index
Subject Page number
cogeneration
applicability of guidance for 44
as either electric or non-electric generating units 55
as electric generating units 21
description of 55, 142, 208
difficulties in monitoring gross thermal output 52
example of calculating allocation with electric & thermal output 33, 35, 36
FIGURE 4 93, 115
FIGURE 5 94, 116
FIGURE 6 95, 117
monitoring electric and thermal output from 55, 92-137
monitoring examples under the boiler efficiency approach 133-137
monitoring examples under the simplified approach 110-114
recordkeeping requirements 152
combined cycle system (combined cycle cogenerator) 46, 56, 57, 59, 103, 107, 108, 113, 125, 126, 128,
130, 131, 167, 172
description of 208
FIGURE 6 95, 117
monitoring examples 113-114, 136-137
monitoring thermal output from 57
not included on EIA form 767 163
primary approach to monitoring thermal output 58, 106, 128
combined heat and power-see cogeneration
combustion turbine 46, 56, 58, 94, 103, 106, 111-113, 125, 134-136, 172-173,208
description of 208, 215
EPA gross generation data not available for all CTs 164
FIGURE 5 94, 116
monitoring examples 112-114, 135-137
monitoring thermal output 106, 111, 125, 134, 135
primary approach to monitoring 106, 112, 129
conventional power plants 55, 62
allocations based on electric output only 55
FIGURE 1 61
monitoring example 67
core source categories in the model NOx trading rule 44
detailed monitoring option (Option #1) 144
information to go in monitoring plan 153
quality assurance and certification test data under, 153
time period for output data to be reported 151
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Index
Subject Page number
electric generating unit 21, 46
adjustment of allocations by sector 25, 35, 40
allocation of allocations by sector, based on output 34-43
allocation factor based on electric output 25
as a "core source" in the trading program 44
data available for 166, 168
description of 209
measuring electric output from 46, 60-62
recordkeeping requirements 144, 152, 164
electric output
definition of 171
government sources of data, 163
monitoring of 60-67
Energy Information Administration (EIA)
approach to thermal output data 68
net and gross electric output data available 165
electric output data available for non-utility generators 164
net electric output data available for utilities 53
sample rule language referencing data from 174, 182, 192, 198
size of sources reporting to 164
time period for output data reported 165
facility(ies)
allocating NOx allowances to 47
usage of term in guidance 46
formulas to calculate NOx allowance allocations based on output 23
from electric output 23
from thermal output 23
other ways to determine a factor for thermal output 29
fossil fuel-fired 21, 26, 34, 44, 45, 64, 162, 168, 171, 172, 209-210
generators)
allocating NOx allowances to 47
gross electric output
description of 51
monitoring approaches and locations 61, 65
gross output 46, 49, 51-55, 152, 167, 171
defining in a State regulation 167
definition of 171
issues to consider when deciding between net and gross output 50-54
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Index
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gross thermal output
description of 51
difficulties in monitoring 52-54
monitoring approaches and locations 96, 118
house loads 50, 51
Institute of Electrical and Electronics Engineers (IEEE) 158
Instrument Society of America (ISA) 158
intermediate option for monitoring output (Option #3)
approaches to determining gross thermal output 148
information to go in monitoring plan 155
time period for output data to be reported 151
location for installing output measurement equipment 55, 60-137
mechanical work 31, 45
missing data substitution procedures 161
National Institute of Standards and Technology (MIST) 153, 160
net electric output
description of 50
monitoring approaches and locations 62
net output
definition of 171
difficulties in monitoring 52-54
net thermal output
description of 51
difficulties in monitoring 52-54
non-electric generating unit (non-EGU)
adjustment of allocations by sector 25, 34, 37
adjustment of allocations by sector, based on output 34
allocation factor for non-EGUs based on heat input 25
as a "core source" in the trading program 44
calculating allocations based on heat input 40- 42
definition of 212
monitoring thermal output 46, 58, 68-91
recordkeeping requirements 152, 164, 168
typical design heat input rate 28
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Index
Subject Page number
non-emitting generating system
changes to definitions to account for 167
changes to monitoring requirements to monitor output from 161
definition of 171, 212
rule changes for allowance and monitoring of output for 168
rule changes to account for 168
similarity to monitoring at a fossil, conventional power plant 67
non-fossil fuel-fired sources
rule changes to account for 168
NOx Budget Trading Program 4, 21, 22, 25, 31, 44, 45, 47, 151, 167,
169, 171, 213
under EPA's section 126 rule 21
NOx SIP call 3, 4, 25, 30, 31, 44, 47, 167, 169, 213
output measurement equipment
consensus standards for 158
initial certification 155
test specifications 156
use of existing equipment 150
output-based emission limitations 20
description of 20
output-based allowance allocations under a cap and trade program 21
pollution control devices
and power losses 50
impacts of using allocations based on net or gross output 53
potential impact of different NOx allowance allocation methods
for sources that produce more than one 21
primary approach
description of 55
Table VI-1: Summary of Common Approaches to Monitoring Output 58
process heaters 44
simplified approach to measuring thermal output
difference from boiler efficiency approach 56
simplified approach to monitoring thermal output
difference from boiler efficiency approach 92
monitoring thermal output from cogenerators under 96
monitoring thermal output from steam generator under 79
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Index
Subject Page number
simplified option for monitoring output (Option #2) 147
time period for output data to be reported 151
steam generator
approaches for determining net thermal output 71-73, 81-83
approaches to determining gross thermal output 73-75, 83-85
FIGURE 2 Steam Generator 71, 81
FIGURE 3 Steam Generator (Industrial Boiler with Reheat) 72, 82
monitoring example under simplified approach 79
monitoring example under the simplified approach 79, 80
monitoring examples under boiler efficiency approach 90, 91
monitoring thermal output 68-91
steam reheat
FIGURE 3 Steam Generator (Industrial Boiler with Reheat) 72, 82
need for monitoring return lines 92
monitoring examples 80, 91
steps to ensure consistent and accurate monitoring 142
thermal output
definition of 172
government sources of data, 164
unit(s)
allocating NOx allowances to 46
definition of 172, 215
usage of term in guidance 46
Updating Output Emission Limitation Workgroup 4, 6, 26, 30, 169, 170, 216
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